IR 05000336/1998219
| ML20195J541 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 06/10/1999 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20195J482 | List: |
| References | |
| 50-336-98-219, NUDOCS 9906210041 | |
| Download: ML20195J541 (97) | |
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{{#Wiki_filter:r < U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION j Report No.: 50-336/98-219 ' Docket No.: 50-336
License No.: DPR-65 l . Licensee: Northeast Nuclear Energy Comp'any ] Facility: Millstone Unit 2 Location: Millstone Nuclear Power Station 156 Rope Ferry Road i Waterford, Connecticut 06385 l Dates: December 14-18,1998, January 26-29, February 8-19, and March 1-5,1999 Inspectors: Paul Narbut, Team Leader James Houghton James Luehman John Nakoski Stephen Tingen James Leivo, Contractor - Parameter, Inc.
Approved by: Peter S. Kottay, Chief Independent Corrective Action Verification Program inspections Office of Nuclear Reactor Regulation
. Enclosure 1
9906210041 990610 PDR ADOCK 05000336 G PM . e
, TABLE OF CONTENTS EXEC UTIVE S UM MARY..................................... .i ....... 1.0 Introduction................... .............................
2.0 Corrective Action................................................ 1 2.1 Inspection Report Findings.................................... 1 2.2 NRC Sample of NNECO CRs and UIRs Reviewed as Acceptable by Parsons...................................... 28 2.3 Independent NRC Sample of NNECO CRs and UIRs.............. 33 2.4 Parsons Discrepancy Reports.................................. 49 3.0 Topical Reviews................................................... 79 3.1 Electrical Separation and Fuse Control............................ 79 3.2 Translation of Design Basis Calculation Assumptions into Plant Procedures 81 3.3 Commercial Grade Dedication Program....... ..................83 3.4 Review of High Energy Line Break (HELB) Program inside Containment..
3.5 Calculation Program.......................................... 84 3.6 Vendor Information Contro!..................................... 85 3.7 Drawing Control............................................ 86 3.8 Environmental Oualification.................................. 87 4.0 C on cl u sio n...................................................... 8 8 5.0 Entrance and Exit Meetings........................................ 88 Appendix A - Summary of inspection Results........ ..A-1 ...................... Appendix B - Exit Meeting Attendees........................................ B-1 Appendix C - List of Acronyms............................................ C-1
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d . ' , . , EXECUTIVE SUMMARY A team from the U. S. Nuclear Regulatory Commission (NRC), Office of Nuclear Reactor ii Regulation, performed an inspection of the Millstone Nuclear Power Station Unit 2 facility licensed to Northeast Nuclear Energy Company (NNECO). The inspection was performed on December 14-18,1998, January 26-29, February 8-19, and March 1-5,1999, when the team , examined the licensee's corrective action implementation. This inspection was one part of an ongoing, multifaceted, NRC evaluation of the Independent Corrective Action Verification Program'(ICAVP) conducted at Unit 2. In accorde1ce with SECY-97-003, " Millstone Restart Review Process," the team evaluated the adequacy of the licensee corrective actions.
- The team examined the licensee's corrective actions for the inspection findings in Inspection Report (IR) 50-336/95-201, Special Inspection [one item only-SIL 27]; IR 50-336/98-201, Tier 3 Inspection; IR,50-3RMS-202, Reactor Building Closed Cooling Water System Out-of-Scope inspection; IR 50-336/98-203, Auxiliary Food Water in-Scope inspection; and IR 50-336/98-213, Tier 2 inspection. irs 50-336/97-201, 97-211, and 97-212 were also within the scope of this inspection but had no findings and, therefore, no corrective actions or further inspection were required.
' The team examined the actions taken by NNECO to correct problems identified by Parsons Power Group, Inc (Parsons), [the independent ICAVP contractor), and documented on Parsons' discrepancy reports (DRs) during their ICAVP review of' Millstone documents and activities. No Significance Level 1 or 2 discrepancies had been identified by Parsons, therefore, the team concentrated on the review of a sample of 54 of 75 Significance Level 3 DRs. The sample was large enough to provide confidence that the corrective actions taken in response to the remaining DRs were also adequate. Additionally, the team reviewed a sample of 10 of lesser significance Level 4 DRs. The sample selected is shown in the attached tables.
- The team also reviewed a sample of the actions taken by NNECO to correct problems identified by NNECO since January 1,1996. This included Condition Reports (CRs), Adverse Condition Reports (ACRs), and Unresolved item Repods (UIRs).
Parsons had reviewed a sample of 30 CRs, ACRs, and UIRs completed by NNECO in 1998 (95 total) to assess the effectiveness of the NNECO corrective action program. Parsons concluded i ' that NNECO's corrective action program was adequate. The team evaluated 8 of the 30 CRs, ACRs, and UIRs reviewed by Parsons and verified that Parsons had done an adequate review.
. The team also examined 21 CRs and ACRs, in addition to 17 UIRs that had not been reviewed by Parsons to provide an independent assessment of the licensee's corrective actions for issues identified by NNECO during their CMP.
In addition, the team revienwed selected topical areas to provide a broader review of areas where the ICAVP had a number of discrete findings. These topical areas included electrical separation and fuse control, translaton of the design basis into plant procedures, commercial grade dedication, high energy line break in containment, calculation controls, vendor information control, and drawing control. The team vonfied that the licensee's corrective actions were ! appropriate and will enhance the existing programs.
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E ' /^ , ' _ ' Overall, the team found that NNECO's implementation of corrective actions during the CMP was acceptable, in that conditions adverse to quality were identified and corrected in accordance with Criterion XVI, " Corrective Action," of Appendix B, Part 50, of the Code of Federal ' Regulations. The team found that the corrective actions were adequate. Generally, the root .cause evaluations were comprehensive, the extent of the problem was adequately explored, and the corrective actions matched the root causes and the extent of condition.
However, the team determined that four violations of NRC requirements had occurred. These violations are being treated as Noncited Violations (NCV's), consistent with Appendix C of the Enforcement Policy. Three of the NCVs were issued as a result of our followup of unresolved items identified in previous ICAVP inspections. One of the NCVs was a new instance of an - ineffective correchvo action. Specifically, the team had examined the corrective actions for a previous violation.fThe or!ainal inspection finding, Violation 50-336/98-202-05, was issued because the sampling flow to the Reactor Building Closed Cooling Water System radiation ~
monitors was not adequately controlled by operations to match the assumptions for flow made in j ' setting the radiation monitor's alarm setpoint. The corrective action taken by the licensee l , . consisted of reperforming the radiatibn monitor's setpoint calculation. However, the revised ' calculation was still not adequate. During the inspection, the licensee took an additional , corrective action. The team was able to assess the additional actions taken in response to the j NCV and found them to be acceptable.
i Nine additional violations were identified as a result of the licensee's efforts during the CMP, because of this, the NRC exercised enforcement discretion in accordance with Section Vll.B.2 of the Enforcement Policy and refrained from issuing citations for potential Severity Level IV violations.- The team examined the areas characterized as trends by Parsons in their final report in areas of - calculation controls and accuracy, drawings, and component information. The types of errors identified in these trends, even when viewed collectively, did not suggest that a further . expansion of the ICAVP scope would likely have identified errors that would call into question conformance with the design and licensing bases.
The violations identified during this inspection are categorized as equivalent to ICAVP Significance Level 3 findings. In a letter to the licensee dated January 30,1998, NRC stated that if the reviews conducted by either NRC or the ICAVP contractor confirmed an ICAVP Significance Level 3 finding, NRC staff would consider expanding the ICAVP scope, taking into - consideration the effectiveness of the licensee's corrective actions. During this inspection, the team determined that the licensee had taken effective corrective actions for ICAVP Significance , Level 3 findings identified by NRC and the ICAVP cortractor. The corrective actions resulted in i an appropriate expansion of the scope of the licensee's CMP and provided confidence that similar issues, if present, would likely have been found. Therefore, further expansion of the ICAVP scope was'not warranted.
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E> , 1.0 Introduction A team from the U.S. Nuclear Regulatory Commission (NRC), Office of Nuclear Reactor Regulation, performed a corrective action implementation inspection of the Millstone Nuclear Power Station Unit 2 facility, licensed to the Northeast Nuclear Energy Company (NNECO). In cconducting this inspection, the NRC team relied upon NRC Inspection Procedures 92701, " Followup," and 92702, " Followup on Corrective Action for Violations and Deviations."
2.0 Corrective Action i . To assess the effectiveness of the licensees's corrective action program, the team examined the ] following areas for the adequacy of tie corrective actionsi a 2.1 Inspection Repod Findings
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Scope of Review - ' i , The team reviewed the 52 issues identified in the ICAVP inspection reports. The reports were " Inspection Report (IR) 50-336/96-201, Special inspection (Significant items List item No. 27); IR . 50-336/98-201, Tier 3 Inspection; IR 50-336/98-202, Reactor Building Closed Cooling Water ~ System Out-of-Scope inspection; 1R 50-336/98-203, Auxiliary Feed Water in-Scope inspection; and IR 50-336/98-213,. Tier 2 inspection. irs 50-336/97-201,97-211, and 97-212 were also applicable but had no findings and, therefore, no inspection was required. The issues reviewed - included escalated enforcement items (Eels), violations (VIOs), unresolved items (URis), i inspector followup items (lFis), and noncited violations (NCVs).
The team verified that (1) licensee management had assigned responsibility for implementing - corrective actions, including necessary changes in procedures and practices, (2) corrective ' actions were appropriate and implemented, (3) the licensee had performed a root-cause ' analysis when appropriate and identified and corrected repetitive deficiencies, (4) operability and ' reportability determinations were appropriate, (5) licensee had expanded the scape of corrective actions to include applicable related systems, equipment, procedures, and personnel _ actions . when appropriate,' and (6) deferred items and interim resolutions were acceptable, and corrective actions were scheduled for implementation before the appropriate mode of operation - was entered.
'2.1.2 Findings I r c2.1.2.1. (Closed) VIOLATION 50-336/96-201-09. eel 50-336/96-201-09. and Significant items List (SIL) Item No. 27. Failure to Ensure that Adeauste Design Control Measures Were
L Estabhshed for Venfving and Checkina the Accuracy of the information in the Design Basis Documentation Packages (DBDPs) This issue involved the licensee's f:llure to maintain its DBDPs accurately. Since the 1996 i inspection, the licensee phased out almost all of the DBDPs and implemented an alternative program, Design Basis Summaries (DBSs). The DBS program controls changes more formally i using Design Change Notices (DCNs). The DBS program was described by procedure U2-PI-29, Revision 2, " Development of Millstone Unit 2 Design Basis Summary Documents.' ' The DBS documents were developed independently of the DBDP. documents.
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' Additionally, the licensee established a procedure to retire the DBDPs, Nuclear Group Procedure (NGP) 5.28, " Design Basis Documentation Packages," which required that potential design discrepancies be identified and that a condition report (CR) be issued before retiring the DBDP.
. The team reviewed the licensee's status for retiring DBI'Ps and concluded that the licensee's actions were adequate. Of the 15 system DBDPs,13 were retired and 2 were deferred until the next refueling outage. The team considered that the deferred retirements of the two DBDPs were acceptable.
. The licensee also maintained its quality controlled document called Safety Functional Requirements Manual (SFRM). The SFRM document provides critical attributes of systems that are necessary for accident mitigation, safe shutdown of the plant, and control of radioactive releases. Inspection Report 50-336/98-213 states that the SFRM was not being updated in a timely manner. The licensee consequently committed (CR M2-98-2,355 and AR 98015411-08) to update the SFRM prior to Mode 4. The licensee also committed to review the systems calculations to ensure that the calculations support the SFRM and reflect the existing plant ' configuration and operating procedures (AR 98015411-09). The team considered the update schedule acceptable.
The team noted that 49 of the DBSs had been issued, and that 5 DBSs had been deferred until after startup. The team considered that deferring five DBS documents was acceptable.
' The team considered the licensee's corrective actions to be adequate and addressed the NRC concems.
2.1.2.2 (Closed) VIO 50-336/98-201-01: Failure to Perform Leakaae Testina of Safetv-Related Valves The violation stated that required periodic leak testing was not performed on Emergency Core Ceoling System (ECCS) containment sump isolation valves 2-CS-16.1A&B or on Refueling Water Storage Tank (RWST) suction isolation valves 2-CS-14A&B and 2-CS13.1 A&B.
For corrective action, the licensee added Category A leak testing requirements for valves 2-CS16.1A&B and 2-CS-14A&B to procedure " Millstone Unit 2 inservice Test Program for Pumps and Valves," Revision 5, Change 1, dated September 30,1998. However, the licensee identified valves 2-CS-13.1 A&B as Category B valves that do not require leak tightness to perform their safety function. They documented their decision in Revision 2 to the " Pump and Valve Bases Document," for the Refueling Water Storage Tank System.
The team considered the licensee's corrective actions to be adequate.
- 2.1.2.3 (Closed) NOV 50-336/98-201-02: Failure to Imolement Adeauste Corrective Actions This violation contained three examples for which the licensee had completed or scheduled all conective actions.
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) " . lo the first example, the team noted that the licensee continued to have problems with corrosion of the 316L stainless steel material of the service water (SW) pump's PSC columns over several years. The team observed that the root cause of the problem was never determined, nor were the other SW pumps evaluated. The licensee acknowledged the violation and committed to inspect pumps B and C fer corrosion and to perform the necessary evaluation of the findings.
Inspections of the pumps showed some evidence of corrosion, f r which necessary repairs were
made. The definitive cause for the various corrosion sites could not be positively determined; however, the columns for each pump were coated. Based on the findings for the two pumps, the licensee determined that an inspection of the "A" SW pump would be appropriate.
Inspection of the "A" pump had not yet been completed during the inspection; however, the licensee committed to evaluate the res(Jits in a manner similar to its evaluation of the B and C . pumps.
The licensee determined that the corrective action program did not identify the corrosion problems as a recurring problem owing to deficiencies in the old program. The old program contained no' mechanisms to identify adverse trends in similar equipment. With procedure RP4, " Corrective Action Program," in place, the licensee concluded that it has provided plant ' _ personnel with the ability to track and trend recurring problems, determine root causes, and take corrective actions.
' In the second example, the team noted that improper washers were used to secure the channel , i head covers on the B and C Reactor Building Closed Cooling Water (RBCCW) hett exchangers. The team obscrved that when work was performed earlier on the A heat exchanger, the licensee had noted that the channel head fastener washers were improper. The . problems with the "B" and "C" heat exchangers were not found after the problem was identified j on the "A" heat exchanger because no corrective action document, which would have examined extent of the condition, was issued. When the problem on the "A" heat exchanger was noted, it was documented only on an Autornated Work Order (AWO), which resulted in fixing the problem on that one heat exchanger. The licensee had attributed the problem largely to an incorrect ir:terpretation of the procedures by maintenance personnel. The maintenance personnel incorrectly concluded that no corrective action document (Nonconformance Report or Condition Report) was required if a field condition that deviates from design does not require an engineering disposition. Subsequently, the licensee replaced the washers on the "B" and "C" ' heat exchangers and briefed maintenance personnel on the need to issue a corrective action document in futi're similar circumstances to ensure that the extent of condition is evaluated.
' In the third example, the licensee installed bypass jumper 2-92-157 to remove the AC ground / - fault alarm from the Inverter 4 common alarm. The jumper successfully removed the alarm condition, but no action was taken to identify and correct the condition that caused the alarm.
The licensee issued CR M2-98-1811 to address this issue.- The licensee found that radiation moniters, which were not electrically isolated from the inverter, were the source of the grounds - that caused the alarm. The licensee corrected the grounds. To prevent future similar occurrences, Design Engineering Standard 97-02, Revision 1, was issued and procedure RAC-12, " Safety Evaluation Screens and Safety Evaluations," was enhanced.' The team reviewed the corrective actions taken for each of the three examples and found them to be acceptable.
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2.1.2.4 (Closed) VIO 50-336/98-201-03. Imoroner Reactor Buildina Closed Coolina Water (RBCCW) Heat Exchanaer Relief Valve Setooint This violation was issued because the relief valves for the RBCCW heat exchangers had relief setpoints that did not meet the requirements of the American Society of Mechanical Engineers (ASME) Code, Section Vill, Article UG-134(a).
To resolve this concern, the licensee changed the setpoints for the three RBCCW heat i exchanger relief valves (2RB-303A/B/C) from 165 pounds per square inch gauge (psig) to 150 , psig (the proper design pressure) by Design Change Request (DCR) M2-97016, Revision 01, ' dated July 1,1998. The licensee's corrective actions were considered acceptable by the team.
2.1.2.5 (Closed) VIO 50-336/98-201-04: Failure to imolement Desian Control Measures for Desian Drawinas in Accordance with 10 CFR Part 50. Accendix B. Criterion ill This issue involved the failure to update the B and C high-pressure safety injection (HPSI) pump drawings to indicate that the seal material was changed. in its response to the violation dated October 8,1998, the licensee stated that drawings were revised to recognize that the B and C HPSI pump seats were replaced with a different material.
' . The team reviewed Drawings 25203-29168, HPSI Pumps P-41-A, P-41-B, and P-41-C; Sheet 6, Revision 4,25203-29168; Seal Piping for HPSI Pumps P-41-A, P-41-B, and P-41-C; Sheet 11, Revision 4, and 25203-29168; Durametalic Mechanical Seal HPSI Pumps P-41-A, P-41-B, and P-41-C; Sheet 21, Revision 3. This review verified that the drawings were revised to recognize the correct pump seal material. The team concluded that this corrective action was acceptable.
I 2.1.2.6 (Closed) NOV 336/98-201-05: Failure to Imolement Desian Control Measures for Desian Chanaes.
This violation contained five examples, and the licensee agreed with all except the first. In that first example, the licensee was cited for failing to provide evidence that calculational inputs were properly prepared and/or verified. Specifically, the attachments to pipe support calculation M2 2505194-01649-C2, Revision 0, had many missing signatures. The attachments were sometimes not signed by the preparer and sometimes not signed by the reviewer, and the reviewer's signature was sometimes provided by someone other than the reviewer. The attachments totaled 576 of the 582 pages of the calculation. The licensee stated during the inspection, and in response to the violation, that objective evidence of design input verification had been provided by the independent review signature on the calculation's cover sheet. The team considered that using a single signature to endorse nearly 600 pages of design input was a possible vulnerability. However, the team found no specific errors in the input material.
Consequently, this stem is considered closed.
In the second example, the team had identified that certain cantilevered cable trays'iocated in the containment building exceeded the maximum permissible design spsns. The licensee acknowledged that the cable trays were not in accordance with the design and, as corrective action, a calculation was performed that concluded the trays were acceptable. Furthermore, the licensee performed a review for other similar examples and found none.
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i in the third example, the team had identified that Engineering Evaluation M2-EV-96-0061, Revision 0, contained statements that were unsupported by calculations or studies. Specifically, the calculation stated that fault current available over the entire length of the power circuit was adequate to trip any breaker with an instantaneous trip setting, up to and including the high setting. Also, the calculation stated that coordination reviews of 480 volt motor control center (MCC) circuits and upstream devices were based on the largest breaker installed. As corrective action for the first statement, the licensee prepared Calculation 98-ENG-02773E2 which verified the adequacy of the fault current available. In response to the second statement, the licensee included Calculation PA 84-065-753 GE as a reference,
in the fourth and fifth examples, the licensee failed to verify the adequacy of the design of temporary modifications to the plant through the use of Jumpers. In both cases, the jumpers had been removed and the plant returned to the normal configuration. These examples, along with the other examples, were found by the licensee during their CMP. Additional examples had been found by Parsons and NRC during the ICAVP. These findings prompted the licensee to revise extensively procedure WC-10, " Temporary Modifications."
The team considered the licensee's actions to be adequate.
2.1.2.7 (Closed) VIO 50-336/98-201-06. Failure to Perform Adeouate 10 CFR 50.59 Evaluations The violation noted two examples where minor changes were made to Final Safety Analysis Repor: (FSAR) drawings, but a safety evaluation for those changes was not performed as is required by 10 CFR 50.59, " Changes, Tests, and Experiments."
In its response to the violation, the licensee stated the cause of the violation was inadequate adherence to its procedures for safety evaluations and personnel error. As corrective action, the licensee committed to conduct a review of other safety evaluations to identify any other examples, and to revise its standing generic safety evaluation to include additional examples.
The licensee had concluded that the minor changes made should have been covered by, and referenced to, their generic safety evaluation for minor drawing changes. Additionally, the licensee committed to revise its procedure RAC-12, " Safety Evaluation Screens and Safety Evaluations." Furthermore, the licensee committed to conduct enhanced training for safety evaluations. As an interim measure, the licensee instituted a quality review board to review site- ~ generated design changes and to ensure that proper safety screenings were performed.
The team reviewed the licensee's corrective actions taken. The licensee wrote CR M2-98-2507, which documented the actions taken, including revision of the safety evaluations for the two examples in the violation. The licensee also reviewed minor drawing changes made since 1996 to verify that they properly referenced the generic safety evaluation. The licensee found and corrected an additional number of safety screenings that failed to require a safety evaluation.
The team verified that engineering personnel performing safety evaluations had been trained by revi, ewing a sample of training records. Additionally, the team reviewed the corrective actions deferred until after restart and considered them to be reasonable.
The team considered the licensee's corrective actions to be adequate.
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p ' 2.1.2.8 ~ (Closed) VIO 50-336/98-201-07. Failure to Follow Procedure SP-EE-261 for Chanaes Made to Control Room PanelI aha!s j i The violation noted that certain replacement recorders did not have an intemal light and that, under reduced lighting conditions, operators would need to open the recorder and remove the fan-folded paper to review the traces. In addition, the inspection identified inconsistent and nonconforming labels for control board indicators.
I ) 'In response, the licensee determined that the recorders would not be powered or required under station blackout conditions. They noted that for loss-of-offsite-power conditions, the plant computer would be available for trending the variables, and the recorders would provide a digital display of the current values. On that basis, the team agreed that an intamal light was not necessary for these recorders. The licensee issued DCN DM2-00-0532-98 to revise labeling to
conform to the requirements of specification SP-EE-261, " Design Standards for Modification of Control Panels'at Connecticut Yankee, Millstone Units 1,2, and 3," Revision 3. The licensee determined that the human factors (HF) review process had not evaluated differences between . the initial and modified HF design. Consequently, the licensee modified the review process to ? require a second HF review of the implemented modification by a knowledgeable person, implementation of the DCN is a Mode 4 restraint, trackable under DCR M2-07035 and AWO M2-98-06254.
' The team considered tae licensee's corrective actions to be adequate.
2.1.2.9' (Closed) VIO 50-336/98-201-08: Four Examples of Failure to Imolement Dasian Control Measures Wdhout Ensurina the Suitability of the New Eauioment for its Intended Use The first example involved the installation of nonquality assurance (QA) bushings in the safety-relateo switchgear for the 'C" service water pump. The cause of this violation, weak procedures and weak procedure implementation, is discussed in more detail in this report. As corrective action, the licensee replaced the non-QA bushings with safety related parts per Work Order M2-98-08457 ' The team reviewed this corrective action and considered it accertable.
The second example involved performing an inadequate safety evaluation (SE) for PDCR 2-50-93, Changes to 120 Vac Vital System. SE-2-050-93 failed to evaluate the electrical circuit ' changes introduced by the installation of transformers. The licensee attributed the cause of the violation to weaknesses in th( safety evaluation program. The licensee identified other safety evaluation program deficiencies during the current extended outage and implemented programmatic corrective actions, including procedural improvements, training, and improved oversight.- in its response to the. violation, the liconses stated that corrective actions had been taken.
, . Specifically, the licensee performed calculation 96-ENG-01499E2, "MP2120 Vital Bus System-Voltage Drop Calculation," Revision 1, to verify the adequacy cf the power sources for inverters INV3 and INV4. Also, the licensee performed calculation 99-ENG-02798E2, " Maximum and Minimum Available Fault Current at Altemate Source input to Static Switches VS3 and VS4,* Revision 0, to verify that the transformers did not adversely impact the 120 Vac vital distribution system. Additionally, the licensee performed calculation 98-ENG-02773E2, "Available Fault i
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. Current at Selected Molded Case Circuit Breakers," Revision 0, to assess the available fault current at the breakers on the four vital bus panels. Furthermore, the licensee performed technical evaluation M2-EV-98-0113, "120 VAC Vital Bus Coordination Study," dated July,1998, to determine if a lack of coordination existed which could result in a failure to isolate the 120 Vac
vital bus system from downstream electrical faults. This study concluded that a modification was I required. The modification issued and performed was DCR M2-98008, "120 V Vital Fuse Replacement / Installation to Resolve Coordination issues," Revision 1, which replaced the fuses and fuse holders for some of the circuits powered from the 120 Vac vital buses. The modification ensured that any electrical faults would be isolated from the 120 Vac vital buses.
The third example involved the failure of a modification request, PDCR 2-009-95, "120 VAC Vital System Electrical Isolation Changes," to provide an adequate evaluation of the impact of the change of the power supplies to the safety-related circuits for the "A" and "B" hydrogen analyzers. The licensee attributed this violation to failure to adequately document the technical basis for the actions taken. The licensee had identified.veaknesses with the design program as a generic issue. One of the corrective actions was to change the design change process to improve documentation. Because the modification that was implemented, DCR M2-96051, " Hydrogen Monitoring / Post Accident Sampling System Modification," replaced the hydrogen analyzers, including the power supply; no additional corrective action was required. DCR M2- ' 96051 provided an adequate evaluation of the new power supplies.
The fourth example involved inadequate electromagnetic interference (EMI) evaluations in modification PDCR 2-039-94 associated with the auxiliary f3edwater automatic initiation system , (AFAIS) and modification DCR M2-97-077 to the inadequate core cooling monitoring system (ICCMS). In its response, the licensee stated that EMI evaluations would be performed for these modifications, and that corrective actions would be implemented if required. The licensee attributed this violation to poor engineering judgment. The licensee had strengthened the design change process, and the current design practice is to specify EMI requirements. As corrective action, the licensee performed evaluations for the EMI effects for the two cited modifications. The team reviewed evaluations engineering record correspondence (ERC) 25203-ER-0363, " Millstone Unit 2 AFAIS EMI Compatibility," dated December 4,1998, and ERC 25203-ER-97-0027, " Millstone Unit 2 ICCMS EMI Compatibility," dated December 8.1998. The evaluations concluded that the AFAIS and ICCMS are not susceptible to electromagnetic emission from the plant environment, and that EMI emission from this equipment will not adversely affect other plant equipment.
The team concluded that the corrective action for this violation was adequate.
2.1.2.10 (Closed)IFl 50-336/98-201-09: Refuelina Water Storace Tank (PWST) Leakagg Evaluation This issue involved the potential for fluid in the containment sump to leak into the RWST through valve 2-CS-28 during the recirculation phase of an accident. The team reviewed Technical Evaluation M2-EV-98-0142, "RWST Back Leakage," dated August 1,1998. The evalu0 tion concluded that pressure in the containment during the recirculation phase of an accident would . not create a significant differential pressure across 2-CS-28; and, therefore, fluid in the
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,, -. . . . .. ... i / containment sump would not leak into the RWST through 2-CS-28. The team agreed with the Technical Evaluation M2-EV-98-0142 conclusion that leakage through 2-CS-028 would not occur.
, 21.2.11 - (Closed) IFl 50-336/98-201-10: Review of Pumo Raa! Que!dication.
This item identified that, when ECCS pump seals were changed from Teflon to ethylene propylene, the qualification of this new material for that application was not adequately - demonstrated. In response to this finding, the licensee prepared Technical Evaluation M2-EV-98-0097, Revision 1. Subsequently, the licensee also provided the team with Technical Evaluation M3-EV-97-0319, Revision 0, that was performed to justify the use of similar material in a post-loss-of-coolant accident (LOCA) environment in Millstone Unit 3 (Reference . URI 50-423/97-206-05). The team considered that the information provided in the two evaluations provided an adequate basis for a conclusion that the material was acceptable for its specified use in Unit 2.
2.1.2.12 (Closed) IFl 50-336/98-201-11: CanaNav of MCCs to Withstand Hiah Enerov Line Break (HELB) Overoressure f The inspection team had questioned the structural capability of safety-related MCCs B51 and B61 to withstand the overpressure from the most severe HELB. In response, during that inspection, the licensee had issued a calculation change notice (CCN) to resolve the issue by documenting the basis for the extemal design pressure that was used as design input to the - calculation. The basis of the design load had not been citar in the calculation. The licansee identified the apparent cause as inattention to detail during preparation of the calculation. The CCN addressed the structural capability of the MCCs and the basis for the 0.5 pounds per square bch (psi) overpressure by clarifying the basis for the value. The design inputs, methodology,' and results of the calculation were not affected. Because it was a documentation problem, the team accepted the licensee's conclusion that the condition appeared to be an isolated case. The team reviewed CCN 01 with Calculation 80-199-090 GD, " Encapsulation of Safety Related MCCs B51, B61, B52," Revision 3, and found that the CCN provided the calculation with traceability as the basis for the 0.5 psi extemal pressure that was used as a design input. The team considered the licensee's ccm.ctive actions to be adequate.
2.1.2.13 (Closed) NCV 50-336/98-201-12: Facure to Classify an instrumentation Chanae as an Unreviewed Safety Question (USQ) - This NCV documented a failure to classify the digital upgrade of the AFAIS as an USQ requiring NRC approval before implementation. As noted in NRC IR 50-336/98-201, Section 4.2.1.1, the ' licensee had issued the modification before the NRC issued its guidance on analog-to-digital upgrades in Generic Letter (GL) 95-02, "Use of NUMARC/EPRI Report TR-102348, ' Guideline on Licensing Digital Upgrades'in Determining the Acceptability of Performing Analog-to-Digital Replacements under 10 CFR 50.59." Given that the issue was highly visible at the time the upgrade was performed, the failure to inform the NRC that the licensee planned to use a digital replacement, and the failure to follow the guidance provided in GL 95-02 that would have classified this upgrade as a USQ, a noncited violation was issued to document the historic noncompliance with the requirements of 10 CFR 50.59. No corrective actions were required to close this issue, and therefore NCV 50-336/98-201 12 is closed.
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i ' i i-2.1.2.14 (p!osed) URI 50-338/98-201-13. RMudion of RMundant Post-Accident Monitorina Channels from Four to Two Channels was not in Accordance with Licensina Basis This URI item noted that the licensee's reduction of Regulatory Guide (RG) 1.97, Category 1 (safety-related and seismically qualified) post-accident monitoring indicators, from four channels to two channels, was technically adequate but inconsistent with the licensing basis reflected in
FSAR Table 7.5-3. Table 7.5-3 identified four channels of Category 1 indication, meaning that the indication channels would be designed and qualified as safety-related from sensor to panel display. The licensee had two Category 1 channels and two nonsafety-related channels for a total of four channels.
. After the URI item was identified by NRC, the licentee submitted Letter B17244, dated May 10, 1998, describing the basis for the reduction. The letter cited an April 9,1984, correspondence to the NRC, stating that a third safety-related channel would be required only if failure of one channel resulted in an information ambiguity that could lead the operators to defeat or fail the channel to accomplish a required safety function, andif one of four measures could provide , altemative information. The four specified measures were (1) cross-checking with an independent channel that monitored a related variable, (2) providing the operator with capability to perturb the measured variable to determine which channel had failed, (3) using portable instrumentation, or (4) using analysis. Letter, B17244, also stated that, in each case, a third safety related channel was not necessary. Furthermore, the letter stated that the attemative indications were not required to be Class 1E. The letter stated that 1E was not required because the licensing documents included specific discussion regarding the operator using the non-Class 1E displays to validate the Class 1E displays. To clarify these points, during the inspection the licensee prepared ERC 25203-ER-99-0082, dated February 12,1999. The team considered the ERC to be a thorough and comprehensive documentation of the specific basis for the commitments. On that basis, the team considered the corrective actions to be adequate.
The team considered the licensee's failure to properly update FSAR Table 7.5-3 to reflect the reduction from four to two redundant RG 1.97 indication channels to be a violation of 10 CFR 50.71(e), which requires, in part, that the licensee periodically update the FSAR.
The failure to update the FSAR was considered to be a violation. This Severity Level IV violation is being treated as a NCV consistent with Appendix C of the NRC Enforcement Policy - (NCV 50-336/98-219-01).
. Following the inspection, the licensee issued FSAR CR 99-MP2-40, dated March 15,1999, which updated the FSAR appropriately.
2.1.2.15 (Closed) NCV 50-336/98-201-14: Five Solenoid Valves Were Not Qualified for Harsh Environment The licensee had identified five solenoid valves that had not been properly qualified for harsh environment and was incExpcieting corrective actions to resolve the qualification issues before Mode 4 operation.~ Licensee self-assessment ESAR-PGRM-96-002 and CR M2-96-0666 had identified that there had been a lack of plant-wide awareness training, auditable documentation, -
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w o. ' and long-term program staffing in addition to inadequate procedural controls. During the
- resulting upgrade of the electrical environmental qualification (EEQ) program, several issues were identified involving EEQ splices and connections, and the NCV addressed these issues.
' Subsequently, the licensee prepared Minor Modification'(MMOD) M2-98038, "EEQ Upgrade ' Generic Modification," Revision 0, April 29,1998, and three associated Design Change Notices . (DCNs) to bring the valves into conformance with 10 CFR 50.49 EEQ program requirements.
The team concluded that DCNs DM2-00-1239-98 and DM2-00-0948-98, dated October 26, - 1998, completed for four of the five valves, were technically sound and included appropriate SE
- screenings. The remaining DCN, DM2-00-2054-98 for valve 2-SI-628, was not issued but will be implemented before Mode 4 operation. The team considered the licensee's corrective actions to be adequate.
, 2.1.2.16 (Closed) NCV 50-336/98-201-15: Conden==4 Stor=aa Tank (CST) Desian Code of Record . This item dealt with the fact that the FSAR Tables 1.2-1 and 4.2-4 did not describe the proper ' design codes for the condensate storage tank (CST).
. The licensee issued FSAR CR 97-MP2-97, dated June 30,1998, to include the proper code references for the CST in the FSAR tables. The team considered the corrective actions to be adequate.
' . 2.1.2.17 (Closed) NOV 50-336/98-202-01: Three Examoles of Inadanuate RBCCW Test Procedures During the inspection of the RBCCW system, documented in IR 50-336/98-202, the team identified, as a violation, that the licensee had (1) not incorporated all of the design' requirements for testing of backup air accumulators for the RBCCW system valves 2-RB-13.1 A/B; (2) failed to establish periodic flow balance testing of the RBCCW system; and (3) failed to provide "as-found" visual inspection acceptance criteria for the periodic inspection and cleaning of the m RBCCW heat exchangers.
' The licensee issued CRs M2-98-0590, CR M2-98-1820, and CR M2-98-0596 to document the conditions and to develop corrective actions. The corrective actions planned or taken by the licensee included (1) revising the postmodification test plan for the RBCCW backup air accumulators to include the design sizing calculation (97-ENG-01823-M2, ' Verification of Accumulator Size for Valves 2-RB 13.1 A and 13.1B") assumptions that the accumulator is sized to be capable of maintaining the valves closed for 90 minutes with an initial pressure of 90 psig and a final pressure of 60 psig; (2) incorporating changes into the periodic testing procedure for - these accumulators (SP 2604X, " Instrument Air Accumulator Check Valve Test," Revision 0, issued January 16,1999);(3) performing a flow balance of the RBCCW system before restart . from the current outage; (4) developing procedures (EN 21241, " Reactor Building Closed Cooling Water System Facility 1 Flow Balance Verification," Revision 0, dated December 31, 1998, and EN 21242, " Reactor Building Closed Cooling Water System Facility 2 Flow Balance Verification," Revision 0, dated December 31,1998) that verify RBCCW flow balance before ' r e
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J - , l ' restart following~ every refueling outage, and (5) changing Maintenance Form 2701J-96, " Service - Water Cooled Heat Exchangers Subject to GL 89-13," Revision 5, to include appropriate i acceptance criteria for the service water system cooled heat exchangers "as found" conditions.
.j The team reviewed CRs M2-98-0590, M2-98-1820, M2-98-0596; DCN DM 2-00-0525-98, approved April 1,1998, that revised the test plan for the RBCCW accumulator modification; Revision 0, to SP 2604X; Revision 0, to EN 21241 (EN 21242 was an identical procedure for the i
- other facility); and changes made to Maintenance Form 2701J-96, Revision 5.
] , The team found that the CRs provided acceptable corrective action plans to address the specific issues identified in the violation and explored the extent of condition to assess the impact on . q other systems. Design Change DM 2-00-0525-98 adequately revised the post modification i testing of the RBCCW valves backup air accumulators to be censistent with the design sizing assumptions. Surveillance procedure SP 2604X, Revision 0, F..vvided adequate guidance to . periodically test the RBCCW valves backup air accumulators. EN 21241 provided adequate ' guidance to periodscally verify the flow balance of Facility 1 of the RBCCW system, and the team concluded, since EN 21242 was an identical procedure for Facility 2, that EN 21242 provided j adequate guidance to verify periodically the flow balance of Facility 2 of the RBCCW system.
..) The changes made to Maintenance Form 2701J-96 provided adequate "as found" acceptance criteria.
{L -- l W The team determined that the corrective actions taken were reasonable to resolve the conditions
identified in the violation and should prevent recurrence of the specific issues. Further, the corrective actions adequately addressed the extent of the condition as it relates to other systems. Based on the team's review, NOV 50-336/98-202-01 is closed.
' 2.1.2.18 (Closed) VIO 50-336/98-202-02: Two Examples of Failure to Correct Conditions Adverse to Quality j in the first example, the violation noted inadequate corrective action to relieve pressure spiking in the RBCCW system. The inadequate corrective action was implemented by CR M2-97-0489, ' "RBCCW System Design Pressure Exceeded at Low Flows," dated March 27,1997. The CR ] stated that RBCCW system pressure could exceed design pressure during pumps shifts. As corrective action, the licensee had revised procedure OP 2330A, "RBCCW System," to alleviate the pressure spiking. However, the violation noted that the procedure was not tested for
effectiveness at low flows and was inconsistent with the FSAR Section 9.4.4.2 description of , RBCCW pump shifting.
. In its response, the licensee attributed the cause of the violation to personnel error. Additionally, the licensee stated that the licensee's operations strategy for minimizing pressure spikes during i ' pump swapping would be testing in accordance with test procedure SPROC EN 98-2-04, "RBCCW System Peak Pressure and Shutdown Cooling Heat Exchanger Flow Test." The test ' ' evaluated the planned pump shifting methodology, evaluated the system peak pressure response during pump shifting / check valve slamming, assessed the ability of the new soft- ' i seated relief valves to rosest if they lifted, and determined whether an optimal flow range existed for perfonning pump shifts. The licensee planned to revise OP 2330A if the testing demonstrated that a change was necessary and planned to issue an FSAR CR to reflect accurately. system operation during pump shifting.
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i l I The team reviewed the test data from the performance of SPROC EN 98-2-04, Revision 0,
- Change 1. The test required that the RBCCW pumps be shifted at different system flow rates, monitored system pressure and check valve accelerations, and verified relief valve lifting and reseating. The testing demonstrated that check valve closure acceleration rates and pressure spikes were lower when the pumps were shifted at system flow rates of 6000 to 7000 gallons per minute (gpm) versus 5000 gpm. The operating procedure, OP 2330A, Revision 18, Change
! 6, was issued to instruct operators to shift pumps at flows between 6000 and 7000 gpm to , minimize check valve slam and pressure spikes. The team noted that one relief valve lifted and _ resented during the test when the pumps were shifted at 5000 gpm. Relief valves did not lift
when pumps were shifted between 6000 and 7000 gpm.
-) Several short-duration large pressure spikes were identified during the test. The licensee issued technical evaluation (TE) M2-EV-99-0064, "RBCCW Pump Swapping Water Hammer," dated March 26,1999, which evaluated the pressure spikes that occurred during the test and i - concluded thei the pressure spikes were within the piping code stress allowables.. The TE provided recommendations for eliminating the pressure spikes. during routine pump shifting evolutions. At the close of the inspection, the licensee was in the process of incorporating these i recommendations into operating procedures. Additionally, the team reviewed FSAR CR 98-MP2-147, which revised the FSAR to describe more accurately RBCCW pump shifting evolutions.
j , . The second example in the violation involved the failure to revise Technical Specification (TS) 3.8.1.1 to be consistent with 10 CFR Part 50, " General Design Criterion 17," safety bus's
switchyard power requirements. The violation noted that the licensee had issued Licensee Event Report (LER) 95-035, dated October 5,1995, reporting that operating procedures had not required operators to enter a TS limiting condition for operation action statement when they had less than two power paths from the switchyard to the onsite safety busses. The violation noted that the licensee had revised the procedure at that time, but had not identifed the need for a j corresponding TS change.
' As corrective action for the second example, the licensee issued a license amendment request to the NRC to revise TS 3.8.1.1 on July 17,1998.
The team found the licensee's corrective action for this violation to be adequate.
2.1.2.19 (Closed) NOV 50-336/98-202-03: Valve identification Conflict NRC identified that valve 2-RB-402, a safety-related component in the RBCCW system, was also identified on drawings and in the Production Maintenance Management System (PMMS) as 2-CH-223, which was classified as a nonsafety-related component. After this issue was identified, the licensee issued cond!! ion report (CR) M2-98-0915, which concluded that the I correct designation for the valve in question was 2-RB-402 and that it should be classified as safety-related.' Furthermore, the licensee performed walk downs of systems to compare valve designations with drawings and found no similar discrepancies. Subsequently, the drawings with the incorrect designation were changed, and 2-CH-223 was deleted from the PMMS. The i team verified that the valve was deleted from the PMMS database and that the drawings had j been updated.- The tes,m found the licensee's action to be adequate.
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. , ' 2.1.2.20 (Closed) VIO 50-336/98-202-04. Failure to Follow Prar= dure - ] This violation involved five examples of failure to follow procedure.
The first example involved an instance where the cabling for the two redundant RBCCW pump trains was not properly separated in accordance with the licensing and design basis requirements.. These required either 18 inches of horizontal separation or barriers. As corrective action, the licensee retrieved portions of their 10 CFR 50, Appendix R, submittals and NRC SE reports that justified the lack of barriers based on credit for wet pipe fire suppression in the area of interest. The licensee also noted the capability or safe shutdown even with a fire in - both redundant cable trays. The licensee documented this[ justification in ERC 25 i 0358, dated December 22,1998. The team found the licensee's justification for the lack of ' barriers for this example to be acceptable. Notwithstanding the acceptability of this specific configuration, the licensee prepared DCR M2-98084 to address the extent of condition with an ongoing program to walk down and review additional cable tray installations where minimum separation distancewere not satisfied. This effort had identified other separation discrepancies. Fur root cause, the licensee concluded that installation of tray covers and barriers had not been documented on original design drawings, and the lack of this design information resulted in loss of configuration control for barriers and tray covers. To implement corrective actions and prevent recurrence, the licensee planned to revise cable tray plans to document installation of existing tray covers and the installation of fire barriers. The licensee - had scheduled the restoration of the barrier and cover configurations prior to Mode 4 operation.
) The team considered the licensee's corrective actions in progress under DCR M2-98084 and tracked by AR 98017285-02 to be acceptable. To further assess the licensee's corrective actions for additional cable tray separation discrepancies, the team also inspected the electrical separation progam and disposition of Significance Level 3 DR-0680, wherein Parsons had ' - identified numerous additional examples of discrepant barrier configurations. The team's inspe_ction of these programmatic areas is documented separately in this report.
The second example involved failure to classify RBCCW tubing and nstrumentation for pressure ' indicators PI 6324 and PI 6325 as seismic and safety-related. The licensee attributed the cause . of this violation to Mechanical Equipment Parts List (MEPL) Program deficiencies. MEPL is the licensee's program for identifying the proper quality and seismic classifications for components and parts.. The licensee had previously identified broad program deficiencies with MEPL and implemented corrective actions. In its response to the violation, the licensee stated that evaluation MEPL MP2-98-0878, "MEPL Determination," dated January 31,1998, was issued to reclassify Pl4324 and PI-6325 and associated tubing as Category 1, and that the PMMS was updated to reflect the new classification.
The third example involved HPSI seal and bearing cooling water piping that had not been installed in accordance with drawings. The licensee attributed the cause of the violation to . inattention to detail and inadequate documentation of the design details and changes that occurred during installation. The licensee had identified other cotifiguration control deficiencies during the current extended outage and implemented corrective actions.- In its response to the violation, the licenses stated that modification DCN DM2-00-1498-98, * Incorporate As-built Drawing Changes," dated September.16,1998, had been issued to correct the drawings 25203-22200, Sheets 4913125E and 491315F.
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p - The fourth example involved recent HPSI bearing and seal cooling water modifications where piping supports were not installed in accordance with their drawings. The licensee attributed the cause of this violation to an unclear support installation procedure. In its response to the violation, the licensee stated that modification DCN DM2-00-1919-98, " Additional Documentation for RBCCW Small Bore Piping Supports," dated December 2,1998, was revised to reflect the as-built conditions and Revision 2 to Specification SP-ME-730, " Library of Prequalified Load Rated Pipe Supports," was issued to specify that support installations on small bore piping must comply with the requirements of the instructions.
The fifth example involved failure to update the FSAR. The RBCCW mass flow rate of i 2,410,000 pounds per hour corresponding to the 3500 gpm flow rate stated in FSAR Table 9.3.1 was incorrect. As corrective action, the licensee issued FSAR CR 98-MP2-104, dated November 20,1998, to correct the FSAR.
' The team reviewed the corrective actions for this violation and considered them to be l acceptable.
2.1.2.21 (Closed) VIO 50-336/98-202-05: Failure to Translate Desian into Procedure for Radiation Moritor This violation noted that the flow rate assumed in the setpoint analysis for the RBCCW radiation monitor, RM-6038, was not assured by operating procedures and practice. In its response to the violation, the licensee stated that a calculation would be developed to determine new RM-6038 alarm setpoints, and that the procedure for controlling changes to the Radiological Effluent Monitoring Off-Site Dose Control Manual (REMODCM) would be revised to ensure more appropriate reviews of setpoints, including interdisciplinary reviews.
The team reviewed the revised calculation PERM-02665-R2, " Millstone Unit Two RBCCW Radiation Monitor Setpoint," dated November 19,1998, and NGP 6.09, Changes to the REMODCM, Revision 6, and concluded that these corrective actions were inadequate.
The team reasoned that, during normal operation, two trains of RBCCW are aligned to RM-6038. Since operators did not attempt to balance the flow of RBCCW between the two trains to RM-6038, calculation PERM-02665-R2 was performed as a bounding calculation. The calculation assumed the extreme condition that only one train of noncontaminated RBCCW was providing flow to RM-6038 when the other train of RBCCW became contaminated as a result of a leak. The calculation assumed that fluid in the two trains of RBCCW would mix, and RM-6038 ) would alarm when both trains of RBCCW became contaminated. The team concluded that the . calculation was inadequate because it did not consider the transport time of contamination from the contaminated train of RBCCW to the r oncontaminated train of RBCCW. The team I considered that the transport time of contamination between the two trains was required to be considered in determining whether offsite release limits in 10 CFR Part 20 could be exceeded before RM-6038 alarming.
Additionally, the team reviewed Section E.7 of the REMODCM, Revision 12, that was revised to show that the new RM-6038 setpoints were based on the results of calculation
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. - PERM-02665-R2. - The licensee's review of Revision 12 to the REMODCM failed to identify that ' the new RM-6038 setpoints were inadequate. The team concluded that the revision to NGP 6.0g to ensure more appropriate interdisciplinary reviews was inadequate.
The failure to take effective corrective action is considered a violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action." This Severity Level IV violation is being treated _ as a NCV consistent with Appendix C of the NRC Enforcement Policy (NCV 50-336/98-219-02).
Because of the duration of th;s inspection, the licensee had the opportunity to take additional corrective action for the original violation and also for the new violation regarding ineffective corrective action._ The licensee performed a root cause investigation in CR M2-98-3753, which concluded that the causes of this ineffective corrective action were a lack of a defined process or procedure for performing radiation monitor setpoint calculations, ineffective teamwork between engipeering organizations, and ineffective calculation review by interfacing organizations.
' As corrective action, calculation PERM-02665-R2, Revision 1, was issued assuming a minimum RBCCW flow rate of 1 gpm from each train of RBCCW to RM-6038, and new RM-6038 setpoints - were calculated. Additionally, the licensee issued Design Control Manual (DCM), Chapter 5, Revision 6, Change _10, to strengthen the calculation validation and review process. A new procedure, EN 21235, " Millstone Unit 2 Radiation Monitor High Radiation Setpoints," Revision 0, was issued to specify the requirements for developing radiation monitor setpoints. Procedures
- OP 2669A-2, " Unit 2 Auxiliary Building Rounds," Revision 26, Change 4, and OP 2611C/D-2,
"RBCCW System Alignment Checks, Facility %", Revision 26, Change 5, were revised to require RBCCW flows to RM-6038 to be routinely monitored and to specify the new RM-6038 setpoints.
Additionally, the licensee performed a review of the basis of other effluent radiation monitor setpoints in the REMODCM to ensure there were not similar failures and to consider the effects
- of system design and operation on setpoint calculations. The licensee completed this review, and the review identified that the setpoints for radwaste radiation monitors RM-9049, RM-9116, and CND-245 might be less conservative than desired. The licensee issued CR M2-98-3703 to
'~ - evaluate this condition.
The team reviewed 'the corrective actions for the original and new violations and concluded that ' they were adequate.
2.1.2.22 (Closed) NOV 50-336/98-202-06: RBCCW Alarm Resoonse Procedure Inconsistencies - The NOV stated that the RBCCW system-related Alarm Response Procedures (ARPs) contained numerous inconsistencies, widely differing levels of detail, and poor integration with ' operating and abnormal procedural instructions.
In its response to the violation, the licensee stated that the corrective actions would be to modify Abnormal Operating Procedure (AOP) 2564 (loss of RBCCW) and relevant RBCCW ARP window instructions to clarify actions and ensure consistency between the documents; to - continue to review feedback from operator training sessions with regard to consistency between all ARPs and AOPs; and to determine necessary procedure modifications.
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l: . The licensee issued CR M2-98-0880, "RBCCW SSFI ID Discrepancies in System Alarm ' Response Procedures," on March 31,~ 1998.' The CR identified specific tasks to modify RBCCW-related AOPs and ARPs, and review other ARPs during the biannual reviews of AOPs and EOPs.
- The team reviewed 1 revised AOP and 12 ARPs and concluded that the licensee had - adequately addressed the issue of consistency between the ARPs and the AOP for the RBCCW system.
Furthermore, the team reviewed procedure DC 1, " Administration of Procedures and Forms," Revision 7, that provided the instructions for issuing feedback from the procedure users. DC 1
provided adequate controls to facilitate feedback as a method of ensuring continued procedural adequacy.
As stated in CR M2-98-0880, one of the tasks to be completed was to add a requirement to l review the ARP and AOPs for consistency during the biannual review of the AOPs and EOPs.
This task is being tracked by Action Request (AR) 98006818 03. The licensee had started this task and planned to continue the reviews and updates after staitup on a routine basis,- , ' consistent with the scheduled biannual reviews. The team considered the licensee's corrective actions to be adequate.
, 2.1.2.23 (Closed) VIO 50-336/98-202-07: Failure to Maintain Uo-to-date Drawinas This violation involved the team's observation that one set of drawings in one controlled document library was not up to date. The licensee's actions included updating the noted drawings and confirming that there were no other uncontrolled drawings in all the controlled document libraries. The team reviewed the licensee response to the violation and the corrective actions and determined that the corrective actions were acceptable.
) 2.1.2.24 Closed) VIO 50-336/98-202-08. Failure to identify an Unreviewed Safety Question - WSQ) When Electrical Seoa ation Criteria for Intemal Panel Wirina Was Relaxed from 12 Inches to 6 inches This violation had been issued because the licensee had reduced the separation criteria without obtaining NRC approval for USQ. Licensee evaluation M2-EV-970060, " Technical Evaluation for Separation Evaluation - Main Control Room Panel C01," Revision 0, January 23,1998, had resolved licensee-identified discrepancies for cases where 12 inches of separation, described in FSAR 8.7.3.1,' had not been maintained. The licensee had resolved these discrepancies by L relaxing the criterion from 12 to 6 inches. However, this relaxation from the previously accepted licensing basis had not been submitted to NAC's Office of Nuclear Reactor Regulation (NRR) for review and acceptance.
As corrective action, the licensee revised the safety evaluation for DCR M2-96068, S2-EV-97-0018, Revision 1, to consider fully the effect of the separation change and submitted a license amendment request to reduce the acceptable separation distance. This request was accepted by NRC staff via license amendment 224.
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, For root cause, the licensee concluded that the licensee's technical staff did not have an . adequate understanding that, even if a change _was deemed safe, a USQ existed if the change represented a deviation from licensing basis criteria previously accepted by NRR. For extent of - condition, the licensee identified and reviewed other design changes that had been initiated since FSARCR MP2-98-018 had been approved September 3,1997, and that used the 6-inch separation criterion as prescribed by SP-EE-0016, Revision 1. The licensee also revised its procedure for performing USQ reviews, RAC 12, to strengthen the guidance conceming plant . changes. - Additionally, the licensee initiated training for the procedure revision.
. The team found the licensee's corrective actions acceptable.
2.1.2.25 (Closed) URI 50-336/98-202-09, Failure ta Resolve a Failure Scenario - Reactor Buildina Closed Coolina Water u<tsCCW) Svstem Water Hammer Analysis Due to Pumo Restad.. This unresolved item (URI) noted that LER 97-015-00fied identified a LOCA scenario that might ~ , result in severe voiding and water hammer of RBCCW piping to the containment air recirculation - (CAR) coolers. The scenario involved a delayed manual start of the RBCCW pump if the automatic start somehow failed. The delayed start scenario was a more severe scenario than the voiding and water hammer resulting from the automatic start. The team had noted that the ' delayed-start scenario had somehow not been studied arid had not been assessed. The licensee had inadvertently closed their tracking documents for this scenario.
The licensee performed a root cause and extent-of-condition analysis for this error and concluded that it was an isolated occurrence. The licensee provided specific counseling to the groups involved.
' Subsequently, as corrective action, the licensee wrote CR M2-98 5663, dated March 1,1998, that reopened the issue. Engineering analysis in 25203-ER-98-0328, Revision 1," Revision to EOPs for Manual Restart of an idle RBCCW Pump Following an Accident," dated December 9,1998, established the basis for EOP changes. Subsequently issued were EOP 2532, Revision 16; EOP 2536, Revision 15; and EOP 2540B, Revision 10. These were issued to provide suitable controls for the manual start of RBCCW pumps if the pumps failed to start automatically.
' Additionally, the licensee determined that the piping would be overstressed if the manual restart scenario were to occur, but the scenario would not result in catastrophic failure of RBCCW - piping and containment penetrations. The team examined the licensee's calculations for this matter. The team reviewed the licensee corrective actions and considered them acceptable.
The failure to take appropriate corrective action for the delayed pump start scenario is considered to be a violation of 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action."
. This Severity Level IV violation is being treated as a NCV consistent with Appendix C of the NRC Enforcement Policy (NCV 50-336/98-219-03).
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r- / ' 2.1.2.26 (Closed) IFl 50-336/98-202-10A: Minor Abnormal Ooeratina Procedure (AOP) Error.
j AOP 2580, " Degraded Voltage," Revision 1, contained a note that incorrectly stated that if
under-voltage occurred on either 4160V bus 24C or 24D, then both busses would shed loads , l and both diesel generators would start. In fact, undervoltage on a given 4160V bus should only result in shedding the corresponding bus and starting its associated diesel generator. As noted < in the inspection report, the note was not a procedure step, and the team concluded this was a l minor error in an otherwise logical and complete procedure and would not affect operator action or execution of the procedure. On that basis, the team concluded this was an isolated case and i of no safety significance. To correct the note, the licensee issued AOP 2580 Revision 2, Change 1, effective April 23,1998. The team determined that the corrective actions were adequate.- 2.1.2.27 (Closed) IFl 50-336/91)-202-10Bi Balance of Plant Setooint On!culations The report identified the lack of documented setpoint calculations for some safety-related instrumentationi This did nut affect plant safety. The licensee had stated that the plant ' predated, and did not implement, most guidance on setpoint methodology used by newer plants.
However, the licensee intended an dnhancement to the specsfication to include ultimate heat
sink parameters. All other setpoints were covered by original design calculations and their a revisions. The licensee also planned to revisit these other setpoints in the future and address those setpoints in each emergency operating procedure or in the Instrumentation and Control (l&C) procedure ? Basis" document in the form of an updated setpoint calculation. The licensee indicated that this would be done to all safety setpoints that were not included in reactor protection system or engineered safety feature activation system (ESFAS) setpoints. In 1997, the licensee had added the basis document to the procedures format. At the time of the inspection, only a limited number of procedures had been modified to the new format. The recalculation of original setpoint calculations would be done in accordance with their nuclear steam supply system vendor owners group program described in Combustion Engineering Owners Group letter, CEOG-98-037, dated January 30,1998. During the originalinspection, the licensee had issued a DCN, DM2-00-0448-98, dated March 12,1998, to add balance-of- . plant setpoints to the specification.
During this inspection, the team reviewed the corrective actions specified in CR M2-98-2480, that had been written as a result of the IFl. The actions included modifying and enhancing specification SP-M2-IC-019, Revision 1, dated November 11,1998, " Millstone Unit 2 l&C Setpoints," by adding a new Section 1.3.6," Balance of Plant Setpoints," to describe the philosophy for processing balance of plant instrument setpoints and their design bases; and issuing Engineering Work Roquest (EWR) M2-98-171, dated December 11,1998, "l&C Uncertainties in Non RPS/ESFAS Tech Specs" to provide engineering support to the EOP.
' The team considered the licensee's actions aporopriate.
2.1.2.28 (Closed) IFl 50-336/98-202-11: Pine Suono,t Calculations Not Available Onsite This item dealt with the fact that the licensee did not have many original pipe support stress calculations on site and available for review. The licensee subsequently retrieved the calculabons for many of the supports from Bechtel Corp., which originally performed them. The
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E, - licensee was in the process of incorporating those calculations into the plant calculation data base. The licensee also stated that, for a certain number of supports, the original calculations
- would not be found. Technical Evaluation M2-EV-98-0180, Revision 0, dated September 30, 1998, was performed to provide assurance that the suppotts, for which the original calculations were missing, would perform their intended safety functions. This was, in part, accomplished by sampling various supports that the licensee concluded would experience the most severe loads.
By verifying that the calculations for such supports were adequate and the installed conditions were within the design bases, the licensee concluded it had an adequate basis for concluding that supports, for which calculations were missing and had yet to be reconstructed, were ' acceptable. Having addressed the immediate technical concem, the licensee is continuing its efforts to incorporate calculations into the plant calculation database. The team considered the - licensee's action to be adequate.
2.1.2.2g (Closed) IFl 50-336/98-202-12: Imorecise Valve Lineuo Procedures ' This item noted that certain valve lineup procedures for the RBCCW system had numerous ' , valves with a nonspecific rew od posiition of "Open/ Closed." The licensee stated that this was done because the required valve position was dependent on the particular combination of pumps and heat exchangers that was in use. A series of notes in the procedures along with the knowledge of thw supervisor issuing the lineup were relied upon to ensure that a correct valve i lineup was performed. In response to this finding, the licensee revised the valve lineup procedures for the RBCCW (OPS Form 2611 C-2, Revision 23, Change 2, and OPS Form 2611 D-2, Revision 26) to include separate valve lineups for each combination of pumps and heat exchangers. In addition, the licensee has reviewed other system valve lineup procedures and is in the process of revising those that specify "Open/ Closed" as a required position (reference AR ' 97011684). The team found the licensee's actions to be adequate.
2.1.2.30 (Closed) IFl 50-336/98-202-13: Plant Labelina Errors This item concemed a few examples of minor valve labeling deficiencies where old style labels i had not been removed when new improved labels were installed. The licensee's corrective action was to correct the identified discrepancies. The team examined a sample of safety related piping including the identified discrepancies and found that the dicerepancies had been corrected. No new discrepancies were noted. The team determined that the corrective actions were acceptable.' 2.1.2.31 (Closed) IFl 50-336/98-202-14: The Position for Certain RBCCW Valves Was Not ProperIV Indicated on Drawinos ' ~. This item concemed the observation that the RBCCW piping and instrumentation diagram (P&lD) drawings did not show the normal position for certain RBCCW valves. To address this ' issue, the licensee issued CR M2-98-0915, which resulted in a DCN that corrected the valve positions on P&lD Drawing 2503-26022, Sheet 1. The team verifiext that DCN DM 2-00-0597-98 corrected the valve position discrepancies noted by the team followup item. The team found the , ' licensee's actions to be adequate.
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- i 2.1.2.32 (Closed) IFl 50-336/98-202-15 Ra#ad RBCCW Valves Were Not included in Operations Procedures This item dealt with the observation that RBCCW valves on the containment air recirculation units were sealed, but that the condition was not reflected in the valve lineup procedures. The licensee determined that the valves had been sealed in response to a previous NRC violation (336/96-08-07), but the valve lineup procedures had not been updated to reflect those changes.
The licenses subsequently revised the procedures, and the team verified that the procedures have been properly updated. The team considered the licensee's actions to be adequate.
_ 2.1.2.33 (Closed) IFl 50-336/98-203-01: Potential Am* v Feedwater System (AFW) Overoressure on Turbine Driven Auxiliary Feedwater (TDAFW) Pumo Oversneed This item dealt with the fact that the developed head for the TDAFW pump in an overspeed condition could be as high as 1,820 psig, which was greater than the piping design pressure (1600 psig) for piping and greater than the valve design pressure (1400 psig).
, The licensee evaluated the AFW system piping and component design pressure for the short . period of overpressure (less than 1 percent of the operating time) because of potential TDAFW pump overspeed in Engineering Evaluation M2-EV-98-0182. The licensee concluded that the piping, valves, and pump could withstand the short period of higher pressure (1820 psig) as, allowed by the ANSI B31.1 Code allowable pressure variation. The licensee revised " Piping Class Summary EBD 7604-MS-1" for AFW piping to include the maximum service pressure condition of 1820 psig. Additionally, calculation M2 PR101-222-EM, Revision 1, evaluated piping stresses, and concluded that the affected valves were qualified for a maximum pressure transient of 1900 psig. The team considered tnat the corrective actions were acceptable.
2.1.2.34 (Closed) URI 50-336/98-203-02: InadeauMa Auxiliary Feedwater (AFW) Pumo Performance Testina Accectarice Criteria . This item'noted that, for the three AFW pumps, the test acceptance criteria could be more stringent than the pump performance assumed in the design basis calculation. Second, the item noted that testing did not account for instrument uncertainties.
As corrective action, the licensee evaluated the applicability of instrument accuracy to motor-driven AFW pumps for consistency with the turbine driven pump in Engineering Record Correspondence (ERC) 25203-ER-0301, Revision 4. The ERC provided pump differential pressure values, that were equivalent, but updated for the previous pump discharge pressure values and issued Technical Specdication Change Request (TSCR) 2-18-98, dated January 4, 1999.- Procedure changes were made to the AFW pump IST procedures, SP 2610A and SP 26108, ' The team found the licensee's corrective actions to be acceptable.
e.. - 2.1.2.35 (Closed) URI 50-336/98-203-03. URl 50-336/203-04. and CR 98-2503: AFW Backuo Air System and AFW Components not Qualified for Accident Environment Based on its review of High Energy Line Break outside the containment and the specific NRC findings, the licensee issued LER 98-C19, " Potential Inability to Close Auxiliary Feedwater Regulator Valves After a High Energy Line Break." As corrective actions, the licensee issued DCR 99005 " Auxiliary and Main Feedwater Control and Isolation issues," and DCR 99006 ' Backup Bottled Air Supply Upgrade to Auxiliary Feedwater Valves." The team reviewed the DCRs, walked down the hardware modifications that were in progress, and concluded that, when completed, the modifications the, licensee had in progress would address the concems raised. LER 98-019 will be left open pending completion of the DCRs and closure of.
. CR 99-0712, which tracks the upgrading of various AFW valve components to QA Category 1 status.' '~ The licensee's corrective actions were considered to be adequate.
2.1.2.36 (Closed) URI 50-336/203-04 AFW Backun Air System and AFW Comoonents Not Qualified for Accident Environment.
This item was discussed and closed in the paragraph above.
2.1.2.37 (Closed) IFl 50-336/98-203-05. Effect of Cable Trav Overfill on Cable Amoacity In UlR 2271, the licensee had identified that 480 Vac cables listed in FSAR Table 8.7-2 might have lower ampacities than described in the FSAR table because the outside diameters of the installed cable were smaller than described in the FSAR. The item was left as a followup item because the licensee had not completed analyses of this condition during their inspection. The licensee subsequently completed their calculations to demonstrate that the existing cable tray overfill conditions were acceptable and updated the FSAR to remove the detailed tables and to clarify the commitments to AIEE-IPCEA " Power Cable Ampacities"(joint publications S-135-2, P-46-426,1962); IPCEA Publication P-54-440, and NEMA Publication WC 51-1972.
The team performed a programmatic review of the assumptions, methodology, and results of seven ampacity calculations. The calculations used acceptable methodology and demonstrated that conductor temperatures would remain below 90 *C in a 50 *C ambient environment.' The team considered the licensee's ampacity analyses to be acceptable.
- 2.1.2.38 (Closed) IFl 50-336/98-203-06. Adeausev of 10 CFR 50 Amndix R Exemption Reauest for Fire Area R-3 (Turbine Buildina Elevation 14-feet. 6-inches) The kilowup item concemed hydrogen lines in fire area R-3, which had not been identified or , sva! ated in the licensee's exemption request for this area. The exemption request was oiiginally sent to justify having redundant equipment and cables in the same fire area. The rationale used was a fire hazards analysis that claimed a lack of intervening combustibles. The team was concemed that the presence of the hydrogen lines and the potential for a hydrogen - fire or explosion had not been evaluated.
,e X
'In response to this concem, the licensee prepared a comprehensive engineering evaluation, FP-EV-98-0056, Revision 0, " Technical Evaluation for Fire Protection Separation Between Auxiliary Feedwater System Valves 2-FW-43A and 2-FW-43B, Millstone Unit 2.' The evaluation addressed the potential hazard imposed by the hydrogen lines. The new analysis showed the configuration to be acceptable because except for the piping associated with hydrogen metering, the piping was double-walled; the lines closest to the AFW regulating valves ! and equipment were vent lines from relief valves; the lines normally pressurized with hydrogen were well above the AFW valves or otherwise sufficiently distant to preclude direct impingement ~ from a hydrogen flame; the large volume of the turbine building would dissipate any leaks or breaks such that an explosive mixture would not result; and the actual combustible loading inventory presented by the hydrogen (even if the total inventory were released to the area) was substantially less than the combustible loading already evaluated for the cables and other fixed or transient combustibles in the area. This was true for the inventory presented by the hydrogen supply as well as for the hydrogen in the main generator. In addition, the licensee was adding an excess flow check valve in the hydrogen line to isolate the supply from a break in the line and was increasing the fire suppression provided to the area. These actions were being tracked .under DCN DM2-00-168198, MMOD M2-98071, DCN M2-00-1916-98, and EWR M2-98066.
On the basis of their technical evaluation, the licensee concluded that the exemptioi1 request remained valid and that no additional submittal to NRR was required.
The team found the licensee's technical evaluation and comrbitted actions to be acceptable.
2.1.2.39 (Closed) IFl 50-336/98-203-07. Inadeauate Material Condition of Turbine-Driven Auxiliary Feedwater Pumo Speed Control Circuit Comoongnig During a walkdown of the turbine-driven auxiliary feedwater pump (TDAFWP) room, the ) inspection had identified that the connections to the speed-setting circuit resistors had evidence of rust and moisture accumulation and were in an unlabeled resistor enclosure. Furthermore, the enclosure did not have drain holes and was vented on one side. Also, the normally de-energized speed setting motor was warm to the touch, suggesting a sneak circuit.
The licensee subsequently determined that the cause of the heat was a failed contact in the
' manual speed switch. The cause of the degraded conditions was determined to be moisturo accumulation in the enclosure. As corrective action, the licensee replaced the degraded resistors and switch and provided weep holes and a label for the enclosure.
The team considered the licensee's corrective actions to be acceptable.
2.1.2.40 (Closed) IFl 50-336/98-203-08. Incomplete Calculations for the Condensate Storaae 18Dh.
This followup item concemed calculations for the condensate storage tank (CST). The team noted that there was no calculation that combined the effects of free field stresses on the tank with the local stresses. Calculation 17272.02-NM(B)-007 determined the local stresses at the nozzle-shell intersection, and Calculation 90-032 423-EC, determined the free field stresses in the tank.
e l ' As corrective action, the licensee issued calculation 17272.02-NM(B)-007, Revision 03, (CR M2-98-2710) to account for the combined stresses.
Also, the team noted that the loadings for pipe support 413063 are in three directions, but the ' analysis in the applicable piping stress problem accounted for only two of the three loadings.
As corrective action, the licensee initiated CR M2-98-2969 (AR 98016116-01) to track the re-j evaluation of pipe support 413063. These actions are scheduled to be completed before plant . heat up (Mode 4).
) . I ^ The team considered the corrective actions for the CST to be adequate.
2.1.2.41 (Closed) eel 50-336/98-203-09: Anoarent Violation for Failure to Perform Reauired 10 CFR Part 50.56 Evaluation This issue involved the failure of the licensee to perform a safety evaluation for a licensee prepared technical specification (TS) clarification for TS Section 3.7.1.2(1). The licensee's TS clarification was in error and violated the TS requirements because it did not require entry into . TS 3.0.3 when one auxiliary feedwater path was not available. In its response to this eel dated December 7,1998, the licensee stated that the TS clarification for Section 3.7.1.2(1) had been , corrected and revised to require entry into TS 3.0.3. Additionally, the licensee stated that - procedure EN 21224, " Safety Evaluations," was revised to require the performance of a j 10 CFR 50.59 safety evaluation screening when processing TS clarifications. Also, the licensee ! stated that all the issued TS clarifications would be reviewed to determine whether any were not , in accordance with the licensing basis or were an unreviewed safety question.
i The team reviewed TS Clarification 3.7.1.2(1), Revision 1, and verified that it was revised to require the unit to be shut down in accordance with TS 3.0.3 when one AFW flow path is inoperable. Also, the team reviewed the safety evaluation screening for TS 3.7.1.2(1) and _ considered it to be adequate. Additionally, the team verified that the revised TS clarification was in accordance with the unit's licensing basis and was not an unreviewed safety question. The i team reviewed the revised procedure, EN 21224, and verified that the procedure was changed to require a 10 CFR 50.59 safety evaluation screening for TS Clarifications. The team also reviewed the. licensee's records and verified that the licensee had completed the review of i i all the current TS clarifications. The licensee's review did not identify any condition that was not j in accordance with the licensing basis or any unreviewed safety questions. The team concluded ' that the corrective actions were acceptable.
2.1.2.42 (Closed) URI 50-338/98-203-10: Ooeration of AFW with Valves 2-MS-201 or 2-MS-201 Closed i This item noted that Steps'4.14 and'4.19 of Operating Procedure (OP) 2322, " Auxiliary Feedwater System," provided instructions and allowed continued power operations of the reactor with one of the two steam supplies to the turbinea$ riven auxiliary feedwater (TDAFW) pump (2-MS-201 or 2-MS-202) closed The procedure required that the operator take specific manual actions in areas outside the control room before starting the TDAFW pump. The manual ' !
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[ < ( actions involved operating valves to drain any accumulated condensate from the turbine steam , ~ supply piping. The licensing and design bases for Millstone Unit 2 require that the TDAFW i pump be started from the control room within 10 minutes after a loss-of-feedwater event.
During this inspection, the licensee determined that the operator actions required to place the TDAFW pump on line would take longer than 10 minutes. Consequently, the team concluded that Steps 4.14 and 4.19 of OP 2322, Revision 23, Change 5, were inadequate because they ' allowed the reactor to be placed in a condition outside to its licensing bases. Technical ' Specification 6.8.1 requires written procures be established, implemented, and maintained for plant operation.~ The failure of OP 2322, Revision 23, Change 5, to provide adequate ' instructions for operation with 2-MS-201 or 2-MS-202 closed was identified as a violation of TS 6.8.1 (NCV 50-336/98-219-04).
This violation is in the licensee's corrective action program (CR M2-M2-99-0597). As corrective action to this new violation, the licensee revised OP 2322 to require that operators declare the l TDAFW pump inoperable and that they enter the appropriate TS action statement when 2-MS-201 or 2-MS0202 is fully closed. The licensee issued CR M2-99-0597 to determine the extent of
condition of this issue. The team reviewed OP 2322, Revision 24, Change 1, and considered it i acceptable.
= The team concluded that the corrective actions for the unresolved item and the new violation were adequate.
' 2.1.2.43 (Closed) IFl 50-336/98-203-11: Thermal Bindina and Pressure Lockina of Auxiliary Feedwater Turbine Driven AFW Pumo Steam Sunolv Valves This followup item noted that valves 2-MS-201 and 2-MS-202, the steam supply valves for the turbine-driven AFW pump, were susceptible to pressura locking and thermal binding. To address this problem with pressure locking and thermal binding, licensee procedure OP 2322 instructed operatom to open these valves every 8 hours when the valves were closed. The team had questioned the basis and justification for cycling these valves every 8 hours.
i The licensee's corrective action (CR M2-98-2822) revised procedure OP 2322, Revision 2, i dated October 7,1998, by incorporating steps to prevent pressure locking and thermal binding for these valves without periodic cycling. The valves would be closed electrically and then cracked,open manually 6 tums. The licensee provided justification for cracking the valve open
in Engineering Record Correspondence 25203-ER-0350, Revision 0, dated December 22,1998, j " Steam Valves to Turbine Driven Auxiliary Foodwater Pumps,2-MS-201 and 2-MS-202."
l The te'am found the corrective action acceptable to prevent pressure locking and thermal ] binding.
I , 2.1.2.44 (Closed) IFl 50-336/98-203-12: Dedicated Operator for 2FW-56A/B.
This followup item concemed procedure OP 2322, " Operation of tlw Auxiliary Foodwater (AFW) System," which allowed, as an altamative action, the use of a reactor plant operator to manually . close the AFW feed bypass valves,2FW-56A or B, if the main AFW feed valves,2-FW-43A or j B, became inoperable. This would be an unusual condition where the main feed valves were , 24- ) . (
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I - . closed and the normally closed bypass valves were open to provide a flowpath. Closure of these valves is necessary during a main steam line break accident to isolate the AFW feed supply from the faulted steam generator. The team was concemed that the area would not be accessible for manual actions during a high-energy line break (HELB) event.
As corrective action, the licensee reviced the OP 2322 safety evaluation to evaluate the effect of ) a HELB in the turbine building on a reactor plant operator stationed at 2-FW-56A or B. The j safety evaluation, dated October 13,1998, concluded that, although the bypass valve would not i be accessible, an altemative valve, the AFW header cross-connect valve,2-FW-44, could be j shut from the control room to isolate the path.
) ' ' The team agreed with the licensee's conclusions.
- 2.1.2.45 (Closed) IFl 50-336/98-203-13: Inconsistent Secunty Measures This followup item dealt with the team's concem that security measures for certain AFW-related - valves were inconsistent. As corrective action, the licensee reviewed its security commitments made in response to the NRC's 1989 " Regulatory Effectiveness Review." The licensee concluded that all of its regulatory commitments in this area were being met. However, the licensee did conclude that certain security and operating procedures for dealing with potential tampering with critical AFW-related valves in the turbine building could be enhanced. The team j reviewed the three procedures that were changed as part of this effort. The team found the changes (as contained in SEP 5056, Revision 17, Change 1, " Alarm Response" SEP 5019, Revision 21, Change 3, " Application of Compensatory Measures"; and ARP 2590D, Revision 1, Change 4, " Alarm Response for Control Room Panel, C-05,") were responsive to the team's { concems.
The team considered the licensee's acM o be adequate.
j I 2.1.2.46 (Closed) Unresolved item 50-336/98-203-14: Testino of_ Condensate Storace Tank j (CST) Relief Valves and Ruoture Disks This, issue involved inservice testing (IST) requirements for the CST relief valves, 2-CN-571 and 2-CN-572, and CST rupture disks,2-PSE-7201 A/B/C/D. These components were not originally j - included in the licensee's IST program; however, during the CMP, the licensee identified that these components should be included in the IST program. The team reviewed Assessment TS2-97-003, " Millstone Unit 2. IST Program," dated July 17,1997. This Assessment identifed
that 2-CN-571,2-CN-572, and 2-PSE-7201 A/B/C/D should be included in the IST Program. The team reviewed the Millstone Unit 2 inservice Pump and Valve Testing Bases Document, Revision 2, and verified that 2-CN-571,2-CN-572, and 2-PSE-7201 A/B/C/D were added to the IST program and that the test requirements were adequate.
. The team considered the licensee's actions to be adequate. Based on the information provided, the team determined that the item was resolved and was not a violation.
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F'. / - 2.1.2.47 (Closed) VIO 50-336/98-213-01: Failure to Translate Accident Analyses Assumptions.
Inouts. or Results into Plant Procedures This violation noted that the some of the critical design characteristics (CDCs) established in - calculations performed for the accident analysis in FSAR, Chapter 14, had not been correctly . - translated into plant procedures and acceptance criteria. Four examples were identified.
, The first example irivolved the main steam line break (MSLB) containment analysis. A critical design characteristic was the containment free net volume, which was assumed to be 1,899,000 cubic feet in the analysis. However, the implementing procedure, EN 21065, Revision 3, " Containment Mass Tracking," dated April 3,1998, tracked the available free volume but did not include an acceptance limit t'cr the minimum allowed volume of 1,899,000 cubic feet.
~ The second example involvec 'he rod drop times assumed ir, some analyses. The analyses - assumed the Control Element Assembly (CEA) release time was < 0.5 seconds and rod motion ~ . occurred in < 2.25 seconds. The two individual values were not verified in plant test procedures. However, it Was noted that existing testing enveloped the two values.
The inird example involved the fallute to have a procedure requirement to ensure that the main - feedwater (FW) regulating bypass valve remaine. /1 a closed position when the reactor was above 25 percent power. This was a key assumption in the containment pressure analysis done for the MSLB accident.
The fourth. example involved the failure to have consistent values for the maximum allowed AFW j temperature. The MSLB analysis assumed the maximum Auxiliary Feedwater (AFW) system j temperature was 100 degrees Fahrenheit (100F). However, procedure OP 23198, " Condensate Storage and Surge System /' stated the maximum allowable condensate storage tank (CST) temperature was 120 *F). Operations Form 2669A-1, " Unit 2 Turbine Building Rounds, Outside Areas," also indicated a maximum CST temperature of 120 'F. The CST is the water supply for the AFW system.-
In responding to the violation, the licensee stated that the root cause was inadequate interface among organizations and failure to implement change management effectively. Also, the i licensee noted that some engineering groups worked to differing procedures. The licensee - corrective actions controlincluded changing and updating the Safety Functions Requirements ' Manual (SFRM) and enhancements to the design control manual (DCM). A k;f addition to the DCM was a clarification of the requirement to perform a screening evaluation for key calculations. Additionally, personnel were trained in the new requirements.
The corrective action for the four examples included writing condition reports to track the corrective actions, revising procedures as appropriate, and performing reviews to verify that other CDCs had been properly implemented.
- The team reviewed the licensee's design control program corrective actions and the specific corrective actions applicable to the four examples and considered them to be adequate.
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~ 2.1.2.48 (Closed) IFl 50-336/98-213-02: CEA Vendor Technical Manual Recommendations Nqt Incoroorsted into Control Element Drive Mechanism (CEDM) Maintenance Procedures < The team had identified that certain periedic checks recommended by the vendor technical manual had not been incorporated into the plant maintenance procedures for the CEDMs. After
reviewing this issue, the licensee agreed that the coil current trace measurements of i Section 6.1.1.4 of the vendor manual should be taken yearly and that the acceptance criteria . discussed in Sections 6.1.2.1.3 and 6.1.2.2.2, of the vendor manual should be in plant . procedures.
. ~ The team verified that the licensee,' under AWO M2-99-01675, took CEDM coil stack resistance measurements to establish baseline data for future checks. The licensee also committed to the creation of a maintenance procedure to periodically perform coil current traces and to incorporate the criteria of Sections 6.1.2.1.3 and 6.1.2.2.2 of the vendor manual into procedure IC 2421C, " Reactor Vessel Head Removal, installation and Testing." The last two actions were
j not completed at the time of in)pection, but were being tracked under AR 98015718, Tasks 3 i and 4, and have been deferred until after startup. The team concluded that, while the new test and the inclusion of the criteria into picnt procedures are important for trending of the long-term equipment performance, the deferral of these actions is acceptable because TS 3.1.3.4 and 4.1.3.4 will ensure that the control element assemblies are operable.
The team considered the licensee's actions to be adequate.
2.1.2.49 (Closed) IFl 50-336/98-213-03 Adeouacy of Ranoe of a Test Gauce Used for i Pressurizer Pressure Transmitter Calibration j This item identified a concem about surveillance procedure SP 2402B, Revision 6, " Pressurizer Pressure Calibration," because the procedure allowed the use of either a 0 to 2500 or 0 to 3000 psig test gauge to calibrate the 1000 to 2500 psia plant pressure transmitters PT-102A/B/C/D.
The team was concemed that the use of the 0 - 2500 psig test gauge would be questionable, since measurements at 2500 psig might not be in the usable range of the test gauge. The licensee had previously issued CR M2-98-1500 to address other measuring and test equipment (M&TE) problems. The licensee addressed the team's IFl by adding AR 98016123 to the CR action plan. Subsequently, the AR concluded that the licensee's calibration process was consistent with industry practice and that no further action need be taken. After reviewing the details of the licensee's test gauge calibration procedure, the team agreed that the surveillance procedure satisfied the requirements of ASME B40.1 using either test pressure gauge because the O to 2500 psig test gauge could be considered calibrated to the full scale value of 2500 psig.
However, in reviewing the licensee's procedure MTE 1121, Rev. O, " Pressure Gauge Calibration,"_ used for calibrating the test gauges, the team identifed a new problem. The team noted that the procedure did not fully conform to ASME B40.1-1991, "G9 ages - Pressure Indicating Dial Type - Elastic Element," for a different reason. The licensee's procedure met the' standard's requirements for subjectmg the gauge to full-scale pressure before conducting the calibration. However, the licensee's procedure did not invoke the standard's requirement to perform the calibration within 10 minutes of the full-scale pressure test. However, the licensee stated that the calibrations were performed promptly after the pressure tests. The team
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[ , . considered that departing from the 10-minute requirement would have little or no effect on the calibration results. During the inspection, the licensee prepared CR M2-98-3757 to add this requirement to the procedure.
The team considered the failure of procedure MTE 1121 to conform to ASME B40.1 to be a minor violation of 10 CFR 50 Appendix B, Criterion V, " Instructions, Procedures, and Drawings,' l which requires that procedures shall be appropriate to the circumstances. The procedure was not appropriate in that it failed to include the standard's requirements to perform the calibration within 10 minutes of the full scale pressure test. This violation constituted a violation of minor significance and was not subject to formal enforcement action.
) 2.1.2.50 (Closed) NCV 50-336/98-213-04: Utilization of DO NOT USE Procedures (Update-Unit ) 2 Significant items List 8) This noncited violation concemed the large number of procedures which were in a DO NOT ' USE status. This was an NRC inspection issue in previous years when the licensee had failed to perform the required biennial procedure reviews and had put a large number of procedures
it;to DO NOT USE status. Additionally, the team had noted that some of the DO NOT USE . procedures were being used in operator training in the simulator. The licensee wrote Lettet B17442, " Millstone Nuclear Power Station, Unit No. 2 Update Conceming the Emergency Operating Procedure Revision Process," dated October 30,1998. In the letter, the licensee ' informed the NRC about their decision not to update its procedures during the evolving and changing plant design basis pursuant to the problem discoveries in their CMP. In the letter, the licensee committed to revise the procedures before startup and provide the operators with any necessary additional training before startup. The licensee also established a key performance indicator (KPI), a management performance tracking tool, to track the number of procedures in inactive status. The licensee wrote two CRs to address the problem, CR M3 98-3781 for all station procedures and CR M2 98 2414 for Unit 2 operator training and examinations. The licensee also wrote Action Request (AR) 98015374 02 to assess the problem and take ) appropriate actions. The resultant actions were to revise the current administrative procedures to require the licensee staff to initiate a condition report when a procedure is put into DO NOT i USE status. The licensee stated that the purpose of that change was to ensure that management would be aware of decisions made to place procedures into DO NOT USE status.
- The team determined that the corrective actions were acceptable.
, 2.2 NRC Sample of NNECO CRs and UIRs Reviewed as Acceptable by Parsons 12.2.1 Scope of Review - . The NRC team sampled 8 of the 30 NNECO CRs and UIRs that had been reviewed by Parsons in its corrective action review of NNECO.
2.2.2 Findings , The team agreed with Parsons' conclusions regarding the acceptability of the corrective actions taken by NNECO for each of the sampled items discussed below.
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i ' 2.2.2.1 (Closed) CR M2-97-2834 - Ooeration of Low-Pressure Safety Iniection (LPSI' Pumps on Minimum Flow for Extended Periods of Time The licensee identified an instance in which the LPSI pumps were run for an extended period of time on recirculation to raise the temperature in the Refueling Water Storage Tank (RWST).
The licensee determined that running centrifugal pumps for longer than 15 to 30 minutes on ] recirculation, with flows much less than 25 percent flow, can cause long-term degradation of the pumps. They concluded that operation of centrifugal pumps in such a manner should be avoided whenever possible. As an immediate corrective action, all licensed operators were j - trained on the issue. As a long-term corrective action, the licensee actions include revision of
_ operating procedures for the centnfugal pump, when the procedures are due for their periodic review. The revisions will caution operators about long-term pump operation relying strictly'on _ recirculation flow. Operating Procedure 2310, " Shutdown Cooling System," had been changed . to include such a caution.' The team reviewed Revision 21 of that procedure and found the guidance adequate.. The licensee is tracking revision of the remaining procedures under AR 97029716. The team considered the licensee's actions appropriate, since the potential consequence of running the pumps on recirculation is long-term degradation concem rather , than a concem regarding operable equipment, an immediate and reliance on operator training ' during the interim period (time it will take to review and change all affected procedures) was considered a reasonable approach.
2.2.2.2 (Closed) CR M2-97-2875: Errors in Electrical Calculation for Anoendix R Loading During preparation of a new calculation,97-ENG-01946E2, to address electrical cross-tie ! capabilities.to Unit 1, the licensee had discovered that the LPSI pump had not been accounted for as a load, and that the miscellaneous loads energized during the cross-tie were greater than i ' assumed in the Appendix R loading calculation. This challenged the conclusion that the Unit 1 diesel generator was capable of supplying Unit 2, Appendix R, loads.
The calculation containing the errors was PA 83-156-776GE, " Millstone Unit % Appendix R Backfeed - Worst Case Loading Analysis," Revision 0, March 17,1987. The licensee concluded , that some of the calculations prepared during that period were less conservative, less thorough, and not rigorously documented. The licensee replaced the calculation with a Unit 2 specific calculation,97-ENG-01946E2, " Millstone Unit 2 Cross-Tie to Millstone Unit 1 Load Limit Analysis," Revision 00, February 18,1998. This calculation established the maximum allowable J capacity of the electrical cross-tie between Unit 2 and Unit 1. The ampacity of the cross-tie was-shown to be adequate for the required steady-pW. Ioading for the Unit 2 LOCA, Appendix R, - arid station blackout scenarios. The team reviewed the assumptions and methodology for the new calculation and found them to be reasonable.- The team considered the licensee's actions to be adequate.
j 2.2.2.3 (Closed) CR M2-97-2899: Manual Operator Actions Durina a Loss-of-Coolant-Accident (LOCA). Potential Floodina of Enaineered Safetv Features (ESF) Rooms Due to Pios Failure and Isolation of RBCCW Followina Safety Iniection Actuation Sianal (SIAS) and the Sump Recirculation Actuation Signal (SRAS) This licensee identified finding involved three issues.
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i . The first issue involved Section 6.3.2.1 of the FSAR, which stated that no manual operator actions were required to be performed during a LOCA. This conflicted with Section 6.3.3.1 of the FSAR that states that manual operator action was required to close the emergency core cooling system (ECCS) pump minimum flow valves when transferring from the injection phase to . the recirculation phase of an accident. As corrective action, the licensee issued FSAR CR 98-M2-114 to change Section 6.3.2.1 to clarify that manual operator actions are not required during the injection phase of a LOCA. The team reviewed Supplement No. 2 to the Millstone Unit 2 Safety Evaluation dated August 1,1975, which stated that it was acceptable for operators to close the ECCS pump minimum flow valves manually when transferring from the injection phase to the recirculation phase of an accident.
The second issued involved the A ESF room, which was susceptible to flooding if there was a , main feedwater line break in the west piping penetration room. A previous licensee analysis concluded that this was not a concem because the blowout panel in the west piping penetraticn room would rupture during a line break and the water would not be directed to the A ESF room.
However, a recent licensee calculation identified that the pressure in the west piping penetration room would not be high enough to blow out the rupture disk. As corrective action, the licensee issued Technical Evaluation Number M2-EV-98-0194, "intemal Flooding Effects on the A Engineering Safeguards Feature Room," Revision 0, which concluded that flooding of the A ESF room would not occur because water from the west piping penetration room would flow to the i . turbine building in lieu of the A ESF room.
l The third issued involved Section 9.4.3.2 of the FSAR, which stated that the RBCCW system was automatically aligned for post accident cooling by the SlAS and SRAS. However, section 6.5.2.1 stated that RBCCW was manually isolated from nonvital loads inside containment. The licensee was concemed that the inability to quickly isolate the non-vital loads might adversely affect the ability of the RBCCW system to remove heat from critical components following an accident. However, the licensee concluded that if the nonvital loads in containment were not isolated, the RBCCW would be able to perform its function until the point in time when spent fuel pool cooling was placed into service. Since spent fuel pool cooling is not required to be placed into service until 8 hours after accident, the evaluation concluded that operators have adequate time to isolate the containment nonvital loads.
The team considered the licensee's analysis to be adequate.
2.2.2.4 (Closed) CR-MP2-98-0016: Hiah PreeW Safety iniection (HPSI) System Valves 2SI-659 and -660 Were Not Seismically Qualified to Their Licensina and Desian Bases - This item dealt with the fact that the manufacturer's stress report for the valves used a horizontal seismic acceleration of 1.5g and a vertical seismic acceleration of 1.0g. However, Bechtel Specification 7604-M-409B, " Miscellaneous Nuclear Control Valves," and FSAR Section 13.13.3 required the valves to be qualified to 3.0g in any direction.
, The licensee's review identified that 1.5g vertical and 1.0g horizontal were conservative values for the valve locations. The Bechtel Specification (3.0g in any direction) was conservative and - did not represent the accelerations expected for the valves. The actual acceleration for the valves was 0.17g. -The licensee issued FSAR CR 98 MP2-57 to correct the FSAR. The licensee's corrective actions were considered adequate.
e 2.2.2.5: (Closed) CR M2-98-0431: The Unit 2 Quality Assurance Graded System Review Process Did Not include the Unit 1 Discharae Stack Instrumentation in the subject CR, the licensee noted that the Unit 2 procedure, PI-7, " Graded System Review" did not include the Unit i stack structure, stack flow, and radiation monitoring instrumentation within the scope of review. However, the licensee concluded the Unit 1 instrumentation should , ' have been included since it was used to monitor Unit 2 discharges. The licensee also noted that Specification SP-EE-012, " Design Specification for Regulatory Guide 1.97 Instrumentation - Millstone Unit 2 - Standard Specification" did not include the Unit i stack flow and radiation monitoring instrumentation as Regulatory Guide 1.97 equippient.
For corrective action, the licensee issued design change DCN DM2-00-1079-98, dated July 17,1998, updating the licensing basis, design basis, and documentation for the Enclosure Building Filtration System to include the Unit 1 main stack flow and radiation monitoring instrumentation. Additionally, the licensee issued DCN DM2-00-0816-98, dated May 13,1998, to update Instrumentation Specification SP-M2-EE-012 (Rev. 2, Change 01) and to include radiation monitor RM-1705-79, located in the Unit 1 main stack. Also, the licensee updated FSAR Table 7.5-3, Note 11 to include RM-1075-79.
The team considered the licensee's corrective actions to be adequate.
2.2.2.6 (Closed) CR-MP2-98-0461: Potential for Vortexina in Refuelina Water Storace Tank (RWST) The licensee had identified that during a small break loss-of-coolant-accident (LOCA) at the time of the Sump Recirculation Actuation Signal (SRAS), there might be insufficient pressure inside j the containment to close containment spray check valves 2-CS-14A/B which, in tum, could lead to a drain down of the RWST and a condition of vortexing in the RWST. The licensee noted that after a SRAS initiation signal, the RWST header isolation valves 2-CS-13.1 A/B must be closed manually to isolate the RWST. Emergency Operating Procedure (EOP) 2532 instructs operators to close 2-CS-13.1 A/B but does not specify a time constraint, creating the possibility that the RWST could be drained to a point of vortex initiation. Vortexing, in tum, could cause air entrainment in the ECCS pumps and a consequent inability to remain operable.
' The licensee reviewed the potential for RWST vortexing, including a review of applicable Emergency Operating Procedures (EOPs). The licensee noted that antivortexing devices had been previously installed in the RWST, eliminating the chances of vortexing until the RWST was i essentially empty. Also, the licensee determined that the EOPs were sufficient as written to
c ensure that there would be timely manual valve closure. Additionally, the licensee conducted training to reinforce the EOP 2532 requirements for timely manual cicsure of the RWST header i isolation valves. The team considered the licensee's corrective actions to be adequate.
2.2.2.7 (Closed) UlR 3129: No Calculation or Test Procedure to Demon.imie that the Enclosure Buildina Filtration Reaion (EBFR) Neaative Pressure Limit of 2 inches Water Gauge (WG) was Met The FSAR, Section 6.7.2.1, stated that the maximum negative pressure in the enclosure building .with two fans in operation was 2 inches WG. The licensee identified that there was no
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n h calculation that established this value. Likewise, the licensee could not find a test procedure - that demonstrated that two fans in operation would not exceed the FEAR limit.
As corrective action, the licensee performed Calculation 97-EBF-02000-M2, Revision 1, dated May 8,1998, " Enclosure Building In-leakage and Negative Pressure." The calculation concluded that both fans operating in parallel produce a negative pressure of 0.5-inch WG, . which is. safely below the design pressure of 2.0-inch WG. Additionally, the licensee found - preoperational test T2314GP for the Enclosure Building Filtration System (EBFS), Revision 1, dated July 9,1975, that demonstrated, with single-fan and two-fan operation, the maximum negative pressure (the two-fan case) was approximately a 1-inch WG.
The licensee issued Technical Evaluation M2-EV-98-0095, Revision 0, dated May 1,1998, -" Single Failure of Dampers 2-AC-1 and 2-AC-11 Impact on Enclosure Building Integrity - Millstone Unit 2," and concluded that these single failure scenarios were outside the original - licensing and design basis. Even though these items were outside the licensing basis, the licensee took technical corrective actions. The licensee implemented design change (PDCR 2-041-95) that eliminated the 2-AC-1 single failure. Further, the licensee determined that the original design calculations for the enclosure building, which assumed a 2-inch WG negative pressure and a 140-mile-per-hour (mph) wind equaled a negative 9.75-inch WG, and, therefore, bounded the consequences of a 2-AC-11 failure. Alec, in August 1998, the licensee revised FSAR Section 6.7.2.1, " System Description," to clarify the maximum EB negative pressure as
' ' 9.75-inch WG.
The team considered the licensee corrective actions to be adequate.
2.2.2.8 - (Closed) UIR 3317: The Effects of a Premature Auxiliary Feedwater Actuation Initiation ' Sianal (AFAIS) Were Not Evaluated During its configuration management program (CMP), the licensee identified a concem i regarding the effects of premature initiation of the AFAIS. The plant's design basis required , a 180-second delay of the initiation signal for a Main Steam Line Break (MSLB) accident. The licensee identified that a single failure could start the auxiliary feedwater (AFW) pumps and j open the regulating valves too early. Likewise, they noted that if an MSLB occurred when AFW , was already in use, with both motor driven pumps running and the regulating valves less than i fully open, initiation of AFAIS would fully open the valves.
The licensee concluded that the cause of the problem was an inadequate evaluation, during the . MSLB analysis in 1992. As corrective action, the licensee prepared Engineering Evaluation M2-EV-97-013, " Ear 1y initiation of Auxiliary Feedwater to Affected Steam Generator Following MSLB Accident," March 14,1997. The licensee had the NSSS vendor perform a sensitivity analysis (ABB Calculation 006-ST97-C024, "MP-2 Containment Related Main Steam Line Break Analysis for FSAR Update," Revision 0, August 10,1998) that showed that initiation of AFW flow as early as time zero in the design basis MSLB scenario had no adverse impact on the containment i pressure analysis. Therefore, no design modification or further action was required for this , issue. The team considered the corrective actions to be adequate.
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rv1 , . L 2.3 Indeoendent NRC Samole of NNECO CRs and UIRs 2.3.1 Scope of Review.
The team picked a sample of NNECO CRs and UIRs from the all the CRs and UIRs written as a , result of the licensee's CMP from 1996 to July 1998. The team selected 21 CRs and 17 UIRs using judgment to select a more risk-significant sample.
2.3.2 ' Findings-2.3.2.1 [Qggad) ACR 07958: HELB Door Seals on Motor Control Center Enclosures Are inadeauate On March 19,1996, the licensee identified that design' basis information for the environmental enclosures for motor control centers (MCCs) B51 and 861 had not been maintained and was not retrievable. This had resulted in a deterioration of the enclosures, which had been installed in 1981 to protect the MCCs from the effects of a HELB environment. The licensee's investigation in February 1997 concluded that the root causes were an inadequate corrective action program to track issues raised with the enclosures, lack of an environmental protective barrier inspection and maintenance program, and inadequate management expectations. The licensee replaced the deficient doors and door seals, and EWR 2-94-236 was approved to enhance the auxiliary building ventilaticn and MCC enclosure air conditioning units. The new air conditioning units had been installed at the time of the inspection. The licensee also revised the corrective action program and related procedures as documented in Procedure RP 4, and issued Procedures U2 EN 7, "HELB Barrier inspection," Revision 0, dated November 10,1998 and U2 EN 8, "HELB Barrier Maintenance and Repair," Revision 0, dated November 10,1998, l . The team considered the licensee's corrective actions acceptable.
2.3.2.2' (Closed) CR M2-96-0252 and LER 96-029-01: Imorocer Peakina Factors Used in an Analysis . i During the review performed to investigate the improper removal of the reactor startup rate trip L (ACR M2-96-0154), the licensee discovered their contractor, Siemens Inc. had used incorrect peaking factors in the analysis, which justified removing the startup rate trip. As result of the i problem, Siemens did additional analysis that showed the conclusion of the original analysis ) i l remained the same when the correct peaking factors were applied. The licensee submitted LER ! 96-029-01, which fully discussed the improperly justified removal of the startup rate trip as well as the discovery of the incorrect peaking factors. The team considered the licensee's actions to
be adequate.
2.3.2.3 - (Closed) CRM2-97-0183: The Auxiliary Feedwater (AFW) System Pumo Turbine - Exhaust Line Seismic Qualification was Not Confirmed The licensee identified that they did not have seismic qualification documentation for the AFW l pump P-4 turbine exhaust line. The AFW pumps, drivers, piping, and supports are described in - FSAR Table 1.4-1 as Seismic Class 1. The licensee performed an engineering review and evaluation (Engineering Record Correspondence 25203-ER-97-014, Revision 2, dated
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April 22,~ 1997) of the exhaust line and determined that it was not required to meet full seismic i requirements but would remain functional after a seismic event and would not inhibit the operation and function of the AFW turbine-driven pump. The team considered the licensee's evaluation and conclusion to be acceptable.
l 2.3.2.4 (Closed) Condition Report (CR) M2-97-0363: Emeroency Diesel Generator (EDG) ' Lube Oil System Not Filled and Vented Prior to Restoration . . The licensee identified that when operators were restoring an EDG to service after maintenance, , ' they erroneously aligned the EDG to automatically start before the lube oil system had been fully filled and vented. However, the licensee noted that testing of the EDG was required before it -
was declared to be operable. Furthermore, the licensee discovered the error before declaring the EDG operable. The licensee wrote the CR because the situation was a near-miss !n that the EDG could have been damaged if it had automatically started without sufficient lube ( il. ~ The
licensee. attributed the root cause of this event to insdequate work instructions becauu the work instructions did not sequence the removal of isolation tags and the opening of valves prior to j restoring all support systems. As corrective action, OP 2346A, EDG Operation, was revised to require that the lobe oil system be filled and vented before aligning the EDG for automatic start.
The team reviewed Sections 4.3 and 4.14 of OP 2346A, Revision 21, and verified that the i corrective actions were implemented. The team concluded that the corrective action was , adequate.
2.3.2.5 ' (Closed) CR M2-97-0520: Reactor Protection System (RPS) Channels Failed Response Time Testina
- The licensee's CR noted that RPS Channel B failed time response testing during surveillance
test procedure validation. Likewise, Channel A failed time response testing, and this was ' identified in CR M2-97-0485.
, Subsequently, the licensee determined that the problems were caused by the test assumption that the time response of the Foxboro Spec 200 electronics was negligible, and they had not been included in the time response testing of the RPS. As corrective action, a Technical Requirements Manual Change Request (TRMCR) 98-2-22 was issued on November 16,1998, to account for the additional compononts and time in the RPS time response testing.
Aiditionally, LER 96-024-02,' dated December 15,1998, was issued to update the response times previously reported.
The team considered the licensee's actions adequate.
2.3.2.6 - Closed) CR M2-97-0589 and LER 97-016-00. Uodate - Unit 2 Sionificant items List . 8.8 : Turbine-Driven Auxiliarv Feedwater (AFW) Pumo Was Not Tested in Accordance wdh Technical Specifications (TS) During tho' CMP, the licensee identified that site procedures did not incorporate TS requirements for TS 4.7.1.2a.1 that demonstrate that the turbine-driven AFW pump will start from the control room, and TS 4.7.1.2a.3 to demonstrates that the turbine-driven AFW pump can run for 15
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{ l minutes..TS 4.0.4 requires the TSs 4.7.1.2a.1 and 4.7.1.2a.3 be performed prior to entering L Mode 3.' As corrective action, the licensee revised the applicable procedure to require that the j
- pump be started from the control and operated for 15 minutes before entering Mode 3.
l l The licensee attributed the root cause of this event to an inadequate program to ensure that l-surveillance procedures fully implemented TS requirements. During the CMP, TSs were
i reviewed to ensure that surveillance procedures fully implemented TS requirements.
The team reviewed SP2610B, TDAFP Operability and Operational Readiness Tests," Revision 11, Change 1, and 26108-2, TDAFP Flow Verification, Revision 4, Change 1, and verified that the procedures were revised to start the turbine-driven AFW pump from the control . room and operate the pump for 15 minutes before entering Mode 3. The team concluded that these corrective actions were acceptable.
The failure to test the turbine <lriven AFW pump in accprdance with TSs was considered a violation. However, after consultation with the Director, Office of Enforcement, it was i determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's Enforcement Policy, and a formal Notice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than Severity Level ll; (3) not willful; and (4) plant restart requires NRC concurrence.
Discretion is appropriate because a formal restart plan is currently providing a broad-based evaluation of Millstone readiness for restart that will confirm that the licensee has taken corrective action for this issue. Therefore, further enforcement action is not necessary to achieve remedial action. This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-05).
2.3.2.7 (Closed) CR M2-97-0649 and LER 97-020-00/01: Valves Not Tested in Accordance - with TS 4.1.2.1a , TS 4.1.2.1a requires that the power-operated valves in the boron injectior$ flow path be exercised weekly. During the CMP, the licensee identified that the B HPSI pump suction valves,2-SI-411,2-SI-412, 2-SI-653 and 2-SI-655, were not exercised weekly when the B HPSI pump was the designated boron injection flow path in Modes 5 and 6, and when the reactor was ' defueled. As corrective action, the licensee revised the applicable procedure to require that these valves be exercised weekly.
' The root cause of this event was attributed to an inadequate program to ensure surveillance procedures fully implemented TS requirements. During the CMP, TSs were reviewed to ensure 7that surveillance procedures fully implemented TS requirements.
The team reviewed SP 2601F, " Borated Water Sources, Flowpath Verification and BA Comp' nent IST, Modes 5,6 and Defueled," Revision 1, and verifed that the procedure was o . revised to exercise 2-SI 411,2-SI-412,2-SI-653 and 2-SI-655 weekly when the B HPSI pump
. was the designated boron injection flow path. The team concluded that these corrective actions were acceptable.
The failure to exercise the valves in the B HPSI pump boron injection flowpath in accordance with TSs was considered a violation. However, after consultation with the Director, Office of
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p u a Enforcement, it was determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's Enforcement Policy and a formal Netice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Severity Level ll; (3) not willful; and (4) plant restart requires NRC concurrence. Discretion is appropriate because a formal restart plan is currently i . providing a broad-based evaluation of Millstone readiness for restart that will confirm that the ' licensee has taken corrective action for this issue. Therefore, further enforcement action is not necessary to achieve remedial action. This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-06).
2.3.2.8 '- (Closed) CR M2-97-1125: Low-Pressure Safety Iniection (LPSI) Iniection Valves Not Surveilled
The licensee noted that TS 4.5.2.e required that the throttled positions of the throttle valves I listed in TS Table 4.5-1 be checked after the valves were repositioned following maintenance.
The TS also required a routine check overy 18 months., The licensee noted that LPSI injection valves,2-SI-615,2-SI-625,2-SI-635, and 2-SI-645, were listed in Table 4.5-1 as throttle valves.
- However, following flow balance testing, the licensee had determined that the valves did not i
need to be throttled. Instead, the licensee throttled upstream valve 2-SI-306. The requiredi i positions of valves 2-SI-615,2-SI-625,2-SI-635, and 2-SI-645 were changed to full open in the licensee procedures. The licensee identified that they had not revised the TSs or performed a 10 CFR Part 50.59 evaluation for these changes to procedure. The licensee determined the root cause to be weaknesses in the design change and 10 CFR 50.59 processes.
As corrective action, the licensee strengthened its design change and 10 CFR 50.59 processes.
The team reviewed DCM, Revision 6, Change 10, and Procedure RAC 12, " Safety Evaluation Screens and Safety Evaluations," Revision 1. The team verified that the design change and 10 CFR 50.59 processes were strengthened in those documents. The licensee also prepared TS Change Request Form 2-4-99, dated February 26,1999, to submit to the NRC for approval to revise TS 4.5.2 to clarify the position of 2-SI-615,2-SI-625,2-SI-635,2-SI-645, and 2-SI-306.
The team reviewed the 10 CFR 50.59 evaluation for the TS change request and concluded that it was adequate.
The team concluded that the corrective actions adequately resolved CR M2-97-1125.
2.3.2.9 (Closed) CR M2-97-1871: The Reactor Buildina Closed Coolina Water (RBCCW) - System Pumo C Trioned when Valve 2-RB-4.1E Failed in Ooen Position ' While performing post-maintenance testing for valve 2-RB-4.1E, following replacement of the valve solenoid, the valve unexceptedly failed in the full open position, which caused the pump to trip. The licensee determined that the solenoid had been installed with two electrical leads swapped, which caused the valve to fail in the full open position. In response to this event, the licensee performed a root cause analysis and concluded that the event was isolated because all other similar new solenoids were successfully installed. The analysis concluded that the goveming work control procedures were adequate but may have been misunderstood by certain electricians. A group training session was conducted with the electricians to explain the - expectations of the procedures. The team considered the licensee's actions to be adequate.
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- 2.3.2.10 (Closed) CR M2-07-2020: Enaineered Safety Actuation System (ESAS) Test was Not Performed in Accordance with TS 4.3.2.1.3 . TS 4.3.2.1.3 requires that all channels of the ESAS be periodically tested. During the CMP, the licensee identified that the surveillance procedure that accomplished TS 4.3.2.1.3 did not specify which channel of ESAS to test; therefore, not all ESAS channels.were tested at the frequency ' specified by TS 4.3.2.1.3. As corrective action, the licensee revised the ESAS test procedures to specify which channel to test.
The root cause of this event was attributed to an inadequate program to ensure that surveillance procedures fully implemented TS requi~rements. During the CMP, TSs were reviewed to ensure that surveillance procedures fully implemented TS requirements.
The team reviewed SP 3403HA, "ESAS Channel A Time Response Testing," Revision 0, Change 3; SP 3403HB, "ESAS Channel B Time Response Testing," Revision 0, Change 11; SP 3403HC, "ESAS Channel C Time Response Testing," Revision 0, Change 1, and SP 3403HD, "ESAS Channel D Time Response Testing,' Revision 0, Change 9. The team verified that the procedures specified which channel to test and that the procedures required the ESAS channels to be tested at the frequency specified in TS 4.3.2.1.3, and the team concluded that these corrective actions were acceptable. The licensee included this event in Licensee Event Report (LER) 96-024-02, " inadequate ESAS and RPS Response Time Surveillance Testing."
The failure to perform testing in accordance with the TS was considered a violation. However, after consultation with the Director, Office of Enforcement, it was determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's Enforcement Policy, and a formal Notice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Severity Level 11; (3) not j willful; and (4) plant restart requires NRC concurrence. Discretion is appropriate because a ' . formal restart plan is currently providing a broad-based evaluation of Millstone readiness for j restart that will confirm that the licensee has taken corrective action for this issue. Therefore, further enforcement action is not necessary to achieve remedial action. This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-07).
i 2.3.2.11 (Closed)'CR M2 97-2673 and LER 97-036-00 Inadeauate Trisodium Phosphate ' (TSP) Volume i The licensee discovered that an error was made in calculating the volume of TSP necessary to j maintain post-accident recirculation water pH at greater than 7.0. Specifically, they discovered that a computational error resulted in the volume of TSP required by TS, and the volume actually provided in the containment, being inadequate to meet the design requirements. As corrective actions for this condition, the licensee increased the amount of TSP in the containment, reported the discovery of this problem in an LER dated December 17,1997, and , submitted a proposed license amendment to change the TSP volume specified in the TS (Letter B17143, dated April 13,1998). The team found the licensee's actions to be appropriate.
The failure to ensure the design had been adequately maintained was considered a violation.
However, after' consultation with the Director, Office of Enforcement, it was determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's Enforcement Policy ..
a
and a formal Notice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Severity Level ll; (3) not willful; and (4) plant restart requires NRC concurrence. Discretion is appropriate because a formal restart plan is currently providing a broad-based evaluation of Millstone readiness for restart that will confirm that the licensee has taken corrective action for this issue. Therefore, further enforcement action is not necessary to achieve remedial action.
' This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-08).
. 2.3.2.12 (Closed) CR M2-97-2674 and LER 50-336/97-022-03: The Emeroency Diesel Generators (EDGs) Fuel Oil Day Tank Siaht Glasses Were Not Desianed Properly for a Seismic Event The licensee identified a concern that the EDGs fuel oil day tank sight glasses might not be operable after a seismic event. The licensee performed a seismic analysis,97-ENG-02069-C2, Revision 0, dated December 12,1997, " Diesel Day Tank T-48A & T-48B Sightglass Piping Supports," and concluded that the piping supports for the sight glasses needed to be strengthened for a seismic event. The licensee consequently issued design changes and completed modifications to the pipe supports in early 1998. The licensee also issued LER 50-336-97-022 Supplement 03, reporting to NRC that the FDGs,were potentially inoperable. The team considered the licensee's corrective actions to be adequate.
The failure to design the EDG sightglass supports for a seismic event was considered a ' violation. However, after consultation with the Director, Office of Enforcement, it was determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's , Enforcement Policy, and a formal Notice of Violation will not be issued because the violation was i (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Severity Level ll; (3) not willful; and (4) plant restart requires NRC concurrence.
Discretion is appropriate because a formal restart plan is currently providing a broad-based evaluation of Millstone readiness for restart that will confirm that the licensee has taken I corrective action for this issue. Therefore, further enforcement action is not necessary to achieve remedial action. This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-09).
2.3.2.13 (Closed) CR M2-97-2693: Containment Purae Valves Not Surveilled in accordance with TS 4.6.1.1a TS 4.6.1.1a requires that containment purge valves, 2-AC-04, 2-AC-05, 2-AC-06, and 2-AC-07,
' be checked closed and deenergized on a monthly bases when in Modes 1, 2, 3, and 4. During the CMP, the licensee identified that the containment purge valves were not surveilled in accordance with TS 4.6.1.1a. As corrective action, the licensee revised TSs to clarify surveillance requirements for the containment purge valves and revised procedures to surveil the valves monthly in Modes 1, 2,- 3, and 4.
The root cause of this event was attributed to an inadequate program to ensure that surveillance procedures fully implemented TS requirements. During the CMP, TSs were reviewed to ensure ~ that surveillance procedures fully implemented TS requirements.
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o The team reviewed TS 3.6.3.2, Amendment 216, dated June 16,1998, and verified that the TS specifically addressed containment purge valve monthly surveillance requirements. The team reviewed SP 2605A, " Verifying Containment Integrity," Revision 4, Change 3, and verified that the procedure specifically addressed containment purge valve TS surveillance requirements for checking the valves closed and deenergized on a monthly basis. The team concluded that , - these corrective actions were acceptable. The licensee included this event in LER 96-022-03, "TS Violations."
The failure to perform surveillance testing in accordance with the TS was considered a violation.
However, after consultation with the Director, Office of Enfqrcement, it was determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's Enforcement Policy, and a formal Notice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Seventy Level ll; (3) not willful; and (4) plant restart requires NRC concurrence. Discretion is - appropriate because a formal restart plan is currently providing a broad-based evaluation of. Millstone readiness for restart that will confirm that the licensee has taken corrective action for this issue.~ Therefore, further enforcement action is not necessary to achieve remedial action.
This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-10).
2.3.2.14 (Closed) CR M2-97-2749 and LER 97-037-01 - Service Water Pioina Liner Material Lodaed in EDG Heat Exchanaer During an inspection of an EDG heat exchanger, the licensee found pieces of the service water piping liner lodged in the heat exchanger. In response to this event, the licensee performed a number of corrective actions. The material was removed from the EDG cooling system, and an intemalinspection of the service water system was performed to locate the source of the plastic liner material. in addition, the licensee inspected the rest of the service water piping to identify . any additional areas of damaged liner that could potential ly cause the degradation of other systems served by service water.
The licensee's inspections identified numerous areas where the liner was damaged. Based on the inspection results, the licensee performed a root cause investigation of this event (dated July 30,1998) that concluded that the liner was damaged due to inadequate bonding at j interfaces between the primer and the plastic coating, between the primer and the base metal ' and between the plastic coating and flange interface material. The licensee determined that the inadequate bonding was due to a number of programmatic breakdowns during the installation process.
' Based on the results of the root cause investigation and an understanding that the programmatic problems occurred during the initial liner installation, the licensee repaired an extensive amount of damaged liner. The repair involved stripping defective plastic coating, using an epoxy on the exposed metal surface, and overlapping epoxy onto a roughed portion of the sound plastic liner.
Because the damage and the subsequent repair method resulted in a coating different from that originally licensed, the licenses concluded, in accordance with 10 CFR 50.59, that an .
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. . unreviewed safety question existed.' A proposed license amendment dated July 2,1998, was submitted to NRC by the licensee, and NRC approved the amendment in a letter dated December 18,1998.
The team considered the licensee's action to be adequate.
2.3.2.15 (Closed) CR M2-98-0481: Some Comoonents of Valve 2-RB-13.1B Were Not included in the Environmental Qualification (EQ) Proaram , The licensee noted that the solenoid and limit switches for air-operated valve 2-RB-13.1B had been originally assumed to operate and fulfil their safety functions before they were exposed to a harsh environment. Therefore, erroneously, they had not been included in the licensee's EQ program. The licensee concluded that the solenoid and limit switches should be added to the EQ program because the components were required to operate in a harsh environment. In ' addition, the licensee noted that the associated control cable for this valve did not have EQ data available.
As corrective action, the licensee issued Supplement 1 to existing Licensee Event Report (LER) 97-028, dated September 2,1998, to report the matter to the NRC. Additionally, the licensee issued and completed MMOD M2-98032, Revision 0, dated April 8,1998, that replaced ' the solenoid valve, limit switches, and associated field wiring (including the control cable) with qualified components. The team considered the licensee's actions to be adequate.
2.3.2.16 (Closed) CR-M2-98-0748 and LER 98-005-01: Hiah Enerav Line Break (HELB) Interactions May Cause Loss of Both Trains of the Reactor Buildina Closed Coolina Water system (RBCCW) The licensee identified that the original HELB program did not include postulated breaks of Safety injection (SI) system lines inside the containment. The licensee issued LER 98-005 and Supplement 01 to report the potential for SI pipe whip interaction with RBCCW lines (both trains) which could cause the RBCCW system to become inoperable. They also reported four additional potential interactions due to pipe whip or jet impingement that could result in a loss of containment integrity. The licensee idntified the cause of the omission was inadequate consideration of HELB requirements in the original facility design. The licensee performed engineering study ERC 25203-ER-98-0273, Revision 0, dated October 21,1998, " Leak-Before . Break," to justify the conclusion that the Si piping would leak and that the leak would be detected before the piping broke and caused damage.. The licensee submitted a, letter to the NRC requesting that the leak-before-break philosophy be accepted for these lines. The licensee's proposal was accepted by the NRC in a letter dated November 9,1998. The team considered the licensee's actions adequate.
The failure to properly account for high-energy line breaks in containment was considered a violation. However, after consultation with the Director, Office of Enforcement, it was - determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's t Enforcement Policy, and a formal Notice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Severity Level ll; (3) not willful; and (4) plant restart requires NRC concurrence.
. Discretion is appropriate because a formal restart plan is currently providing a broad-based
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, . evaluation of Millstone readiness for restart that will confirm that the licensee has taken l corrective action for this issue. Therefore, further enforcement action is not necessary to achieve remedial action. This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-11).
, 2.3.2.17 (Closed) CR M2-98-1287: Reactor Buildina Closed Coolina Water (RBCCW) Pumo I Pressure Switches not Qualified for HELB Environment j .The licerisee ider.tified that RBCCW pump pressure switch electrical seals were not qualified for a HELB environment. The location of the switches had originally been designated a non-HELB environment. The licensee had previously written LER 97-031 to generally report potential
effects of HELB events on safety-related equipment as a result of inadequate review during the _ original HELB analysis. The licensee determined that a revision to the LER was not required per the guidance of NUREG 1022, Section 5.1.6. The licensee prepared MMOD M2-98038, DCN. DM2-00-1488-98, which installed qualified conduit seals for the pressure switches.
1The team considered the licensee's corrective actions to be acceptable.
12.3.2.18 (Closed) CR M2-98-2503 Air Suoolv for AFW Flow Reaulatino Valves was not Qualified for HELB Environment This licensee item concemed the same issues as'NRC unresolved item (URI) 50-336/98-203- ' 03. (See URI 50-336/203-03 earlier in this report for the reasons for closure of this item.)
. 2.3.2.19 (Closed) CR-M 2-98-2780: A Modification to the Back-uo Air Suoolv for Feedwater Valves Assumed an incorrect Environmental Temoerature for Harsh Environment l The licensee had identified that the Main Steam Line Break /High Energy Line Break , (MSLB/HELB) analysis resulted in predicted temperatures as high as 326 *F, while the . modification to the backup air system for feedwater valves used a maximum harsh environment
temperature of 220 *F. The licensee issued LER 98-019 to report the condition and closed the
- subject CR administratively to CR M2-98-2503, which addresses a broader scope of HELB analysis problems documented in an unresolved item by NRC (URI 98-203-03). Therefore, the subject CR is considered administratively closed. The technical resolutions for this issue were addressed in the discussion of URI 98-203-03 earlier in this report.
2.3.2.20 (Closed) CR M2-98-2826: The Auxiliary Feedw;;;;(AFW) Flow Reoulatina Valves i Control Eauioment Was Not Shown to be Environmentally Qualified for the Hiah-Energy Line Break (HELB) Environment ) The licensee wrote this CR in response to previous unresolved inspection item URI 50-336/98-203-03. The inspection team had questioned,the environmental qualification of control equipment for the AFW flow regulating valves (electro-pneumatic signal converters and positioners) for a HELB environment resulting from a break in the turbine-driven AFW pump room..nThe team had postulated that the effects of this break could propagate through the relief hatch above the room and affect this equipment, defeating the ability to control steam generator level for safe shutdown following this event.
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- Subsequently, the licensee wrote a second broader CR dealing with similar HELB lasues, CR M2-98-2503, and closed the subject CR to it. Also, the licensee issued LER 98-019, identifying that corrective action would be taken to review AFW components and initiate
- upgrades as required, to ensore compatibility of system design with HELB conditions. During this inspection the team noted that the licensee's corrective actions were being developed and L would involve changes to_ the environmental qualification analyses and, possibly hardware changes. Therefore, the team closed CR M2-98-2826 administratively to CR M2-98-2503 and ~ URI 50-336/98-203-03.' The NRC evaluated the licensee's corrective actions in its evaluation of - the licensee's completion of CR M2-98-2503 and URI 98-203-03 discussed earlier in this report.
2.3.2.21 (Closed) UlR 192 and LER 96-029-00': Inadeouate Justification for the Removed Reactor Startuo Rate Trio L n 1978,~ design change PDCR 2-48-78 removed the reactor startup rate even though it was i , credited for protection against rod withdrawal events at low power for certain early fuel cycles.
The. licensee discovered this error in 1996 and wrote Adverse Condition Report (ACR) M2-96-0154 to confirm that the startup rate trip was no longer relied on for reactor protection.
As a result of the ACR, Siemens performed an analysis that verified that reliance on the startup rate trip was unnecessary and Final' Safety Analysis Report Change Request (FSARCR) 97-MP2-19 was issued to make that clear. From a historical perspective, Combustion Engineering . (Siemens predecessor) apparently did rely on the startup rate trip protection for a small spectrum of rod withdrawal events during a number of early fuel cycles. Some of these early fuel cycles occurred after the startup rate trip had been removed. Subsequent cores relied only on the variablo overpower trip to protect the reactor core during rod withdrawal events. The licensee reported this historical issue in LER 96-029-00. The team considered the licensee's actions to be appropriate.
The failure to ensure that the design basis had been adequately maintained was considered a violation. However, after consultation with the Director, Office of Enforcement, it was determined that enforcement discretion can be exercised pursuant to Vll.B.2 of the NRC's Enforcement Policy, and a formal Notice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Severity Level ll; (3) not willful; and (4) plant restart requires NRC concurrence.
Discretion is appropriate because a formal restart plan is currently providing a broad-based evaluation of Millstone readiness for restart that will confirm that the licensee has taken - corrective action for this issue. Therefore, further enforcement action is not necessary to achieve remedial action. This violation is noncited because enforcement discretion pursuant to i Vll.B.2 was exercised (NCV 50-336/98-219-12).
! 2.3.2.22 (Closed) UIR 230: FSAR Chapter 14 MSLB Analysis Should Use 1700 aom runout flow to the Affected Steam Generator after an AFAS sianal" ' The licensee identified that different sections of the FSAR assumed different maximum AFW flows to the affected steam generator after a MSLB.- However, the licensee had completed a i recent modification that installed flow limiting venturis in the AFW system (DCR M2-97-017).
This modification will limit the AFW flow to the affected steam generators to approximately 660
- gpm. The acceptability of that flowrate is demonstrated in Calculation 006-ST97-C-024, Revision 00, "MP2 Containment Related Main Steam Line Break Analysis for FSAR Update.' The I
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, licensee also prepared changes to the FSAR (FSAR CRs 145 and 175) to reflect the new maximum assumed AFW flow to the affected steam generators..The FSAR changes will be issued when final closeout of the DCR is complete and NRC approval of the related license , amendment request is received.
The team reviewed the licensee's corrective actions, both accomplished and planned, and found nthem acceptable.
2.3.2.23 (Closed) UIR 272: Calculations Supportina the Accident Analysis for Low Reactor . ' Qggiant Flow Should Assume the Maximum Main Steam Safety Valve (MSSV) Setooint.
The licensee's URI stated that the analysis performed to_ support the FSAR Chapter 14 accident analysis for low reactor coolant flows and the effects on the departure from nucleate boiling ratio should have used the maximum setpoint for MSSVs.,The item stated that it was not clear what setpoint was used in the analysis.
. - Subsequently,' the licensee received written assurance from Siemens'inc. (who had performed the analysis) that the analysis, Notebook E-5747-595-5, " Millstone 2 Cycle 12 Loss of Flow," used the maximum MSSV setpoint of 1113 psia. The team reviewed the applicable portion of the Siemens proprietary calculation for the proper a pplication of the maximum MSSV setpoint and considered the response to be adequate. The Leam considered the licensee's actions for this item to be adequate.
2.3.2.24 (Closed) UIR 464: Containment Hydrooen Monitor Isolation Valves . The licensee noted that, after a postulated accident, and assuming a failure of the direct current . (DC) bus controlling the valves, the valves isolating the two redundant hydrogen analyzers from ' the containment would not be able to open and establish a flow path for monitoring hydrogen ' -
- concentration in the containment.
As corrective action, the licensee installed a new hydrogen monitoring system (see UIR 466, . below). Additionally, the licensee issued and implemented design change DCR M2-96054, I .. Revision 0, dated March 27,1997, ' Hydrogen Monitor Containment isolation Valve i Repowering," the design change that revised the power source of the two outboard containment { isolation valves, 2-AC-12 and 2-AC-47.. The team considered the licensee's actions to be , adequate.
i 2.3.2.25 (Closed) UIR 466: Post Accident Samolina System (PASS) Cannot Draw Samoles of Containment Air Wdhin The Reauired Post-Accident Time Frame The licensee noted that the design of the PASS system did not allow samples of containment atmosphere to be taken within 3 hours M certain LOCA scenarios. The sample requirements ~ were established in accordance with the provisions of NUREG 0737.
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The licensee reported the problem'in LER 336/96-009, " Post LOCA Containment P'ressure Prevents Timely Extraction of Post Sampling System Air Sample and Hydrogen Sample," dated
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March 3,1996, and in LER 336/96-010,-" Inadequate Flow Through Containment Hydrogen L Monitors Due to The Pressure Regulators," dated March 25,1996.
- As corrective' action, the licensee issued modification DCR M2-6051, Revision 0, dated September 10,1997, to provide a two-train hydrogen monitoring system that was not limited by . the pressure regulator setpoint to a containment pressure of.510 psig. This pressure limitation was removed from Emergency Operating Procedure (EOP) 4448 after the modification was installed.
The team reviewed the licensee corrective actions and found them acceptable.- . L 2.3.2.26 (Closed) UIR 497: Control Room Air Conditionino System (CRACS) Poes!ble Sinale Failure UlR 497, issued July 24,1996, identified that damper 2-HV-210 (CRACS filtration fans inlet damper) was the single damper that supplied both control room air conditioning filter fans. A - mechanical failure of 2-HV-210 which prevented the damper from opening could render both ' trains of CRACS inoperable. As originally designed,2-HV-210 was a fail-open, normally closed
- damper that must open.for the accident recirculation mode. The accident recirculation mode is an automatic system response used to protect the habitability of the control room from airbome radioactive contamination by closing the control room fresh air intake and recirculating the air
. Inside the control room through clean-up filters. After about 7 days in the accident recirculation mode, when' conditions permit, the CRACS is realigned to the emergency fresh air intake mode to replenish the control room atmorphere. In the emergency fresh air intake mode,2-HV-210, is required to be in the closed position.
To correct this issue, the licensee determined that 2-HV-210 would be changed to a normally open, fail open damper. This decision was based primarily on the fact the damper was required to be open to support the automatic switchover to the accident recirculation mode of operation in the event a control room isolation was required to maintain control room habitability. The 'i licensee concluded that in the event that the damper failed in the open position, sufficient time . was available to either correct the failure or to manually reposition the damper to support realigning CRACS to the emergency fresh air intake mode.
The tem reviewed DCR M2-97012, " Single Failure of CRACS Damper 2-HV-210 and d Permanently Closing Cross-Tie Damper 2-HV-213," Revision 0, dated July 14,1997, and the j supporting Safety Evaluation (SE) S2-EV-97-00-0049, dated July 7,1997. Based on these i ' reviews, the team concluded that the modification of CRACS to change 2-HV-210 from normally closed to normally open resolved the potential for the single-failure of the damper to render both i trains of CRACS inoperable, without adversely impacting system safety functions. However, the change required a revision to the FSAR to document the change in failure mode of 2-HV-210.
The team reviewed FSAR Change Request (FSARCR) 97-MP2-39, which was submitted to Operations on January 5,1998, and that documented the change in the failure mode of ~ 2-HV-210, and determined it adequately described the proposed change.
The issue identified in UlR 497 was isolated to the potential single failure vulnerability of CRACS ' due to both trains of the filtration fans being supplied through a common isolation damper (2-HV-210) and did not appear to apply to other safety-related heating, ventilation, and air-
< ar . conditioning (HVAC) systems. The team concluded that the corrective actions to resolve the potential single failure vulnerability of the CRACS as a result of damper 2-HV-210 supplying both filter fans were reasonable and adequately resolved the issue identified in UlR 497.
2.3.2.27. (Closed) UlR 539: The Coordination Study for the Turbine Batterv Distribution System was not Retrievable ,
- The licensee identified that a coordination study for the turbine battery electrical distribution system (nonsafety-related) was not retrievable. Subsequently, the licensee issued Calculation 97-ENG-01964E2,."125 Vdc Turbine Load Center 201D Coordination," Revision 00, dated January 9,1998. The team verified that the turt>ine battery distribution system did not support any safety-related Icads or loads required to support safe shutdown for a design basis fire,
' therefore, coordinated protection was not a. safety or licensing basis issue. The team - considered the licensee actions to be adequate.
2.3'2.28 (Closed) UlR-786: Available Net Positive Suction Head (NPSH) for Containment Sorav . Purnos ' ' a The licensee noted that the FSAR stated the NPSH available for the containment spray (CS) pumps was calculated to be 27 feet during the recirculation phase of a LOCA. They also noted that the CS pump specification stated that a NPSH of 21 feet was required for pumping 1350 gpm at 350 *F.
The licensee concluded that with 4-feet of water in the containment sump, the NPSH available was only 25 feet.
As corrective action, the licensee issued Calculation 98-ENG-02339M2, Revision 0, "Available Net Positive Suction Head Calculation for Containment Spray Pumps at MP2," dated February 2,1998. The calculation superseded the earlier Bechtel Calculation,1D10-2, which - assumed 189 *F sump water temperature. The new calculation accounted for head losses due to clogged sump screens, minimum water levels in the sump during recirculation, and a maximum sump water temperature of 212 *F. The calculation indicated that, in the expected condition, with the Low Pressure Safety injection (LPSI) pump tripped, the NPSH available was higher than the NPSH required at rubout for both pumps. In the abnormal condition,'without the LPSI pump tripped, the worst-case NPSH required (21. feet) was slightly higher than the NPSH
- available (20.33 feet).' At the 1350 gpm design flow, however, the NPSH required (18 feet) was more than the NPSH available.
- Additionally, the licensee issued modification DCR M2-99014, Revision A,' dated February 6,'1999, " Containment Spray Nozzle Replacement." The modification limited the containment spray flow to less than the pump's rubout flow, even with postulated continued operation of the LPSI pump.- This assured that the NPSH available was higher than the NPSH required. Additionally, Calculation 98-122, Revision 2, Change 1, dated February 16,1999, "MP2 Containment Spray Analysis," updated sump screen head losses and concluded that the L effect was not significant. The licensee also issued FSAR CR 98-MP2-191 clarifying the containment sump temperatures during recirculation mode and the assumptions used for NPSH.
The team considered the corrective actions to be adequate.
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, ^ 2.3.2.29 (Closed) UIR 929: Pressurizer Levelin Chapter 14 Analyses This UIR is one of a number of overlapping documents in which the licensee raised questions s about the bases, correctness, and consistency of the pressurizer level values contained in the accident analyses, the FSAR, and the TS and their bases.' As a result of the questions raised, the. licensee reviewed the pressurizer level values specified in the various documents and determined that all the values used were consistent and had adequate technical bases.
However, as a result of UIR 829, the licensee determined that the discussion in the technical specification bases, regarding the relationship between the volumetric requirement of Limiting Condition for Operation (LCO) 3.4.4.a, and the method used to comply with the surveillance requirement 4.4.4 (percent pressurizer level) could be enhanced. The licensee is tracking that . clarification of the bases under AR 98012968, Task 4. As it is only a bases clarification, the licensee has deferred action until after restart.
The team reviewed the licensee proposed corrective action and found it acceptable.
2.3.2.30 (Closed) UIR 1815i Manual Initiation and Flow Verification of AFW Durina Station Blackout UIR 1815, issued November 1,1996, raised a question regarding whether the emergency operating procedures (EOPs) required the operators to initiale AFW manually and confirm flow , to each of the steam generators during a station blackout to satisfy a commitment to the NRC made in a March 19,1981, letter. The team reviewed EOP 2530, " Station Blackout," Revision 4, approved May 31,1996, and determined adequate instructions were provided to the operator to l manually initiate AFW and verify flow to each of the team generators. The team considered , that UIR 1815 had been adequately resolved.
] l 2.3.2.31' (Closed) UIR 1816: Steam Generator Dry q[r.!m__p . The licensee noted that NRC correspondence, dated March 19,1981, required that steam ) generator dry out time be greater than 45 minutes.
The team noted that the licensee had closed the UIR by reference to other documents. The team reviewed the other documents, DR-0733 and CR M2-98-3599, dated December 4,1998, i " Requirements for Not Auto-Starting Turbine Driven AFW Pump Not Met." The DR and CR C addressed a problem with an older calculation, W2-517-254-RE, Revision 0, dated April 13,1981, "MP2 - Best Estimates S.G. Dry Out Times." The DR and CR noted the older - calculation did not account for the new steam generator geometry that might impact the dry out time.- As corrective action, the licensee superseded the calculation and issued a new calculation S-02837-S2, Revision 0, dated February 25,1999, "Millstma Unit 2 Steam Generator Mass,45 Minutes Post Trip With Loss of All Feedwater " The new calculation demonstrated that the i steam generator dry out time was greater than 45 minutes.
The team considered the licensee corrective actions to be adequate.
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2.3.2.32 (Closed) UIR 2587: Inadeauste Emeraency Diesel Generator System Run Time The licensee noted that IEEE Standard 308-1971 and FSAR Section 8.3 stated that the EDG
system was required to operate for a minimum of 7 days if normal power was lost. However, the j licensee noted that Northeast Utilities' calculation 94-ENG-1095M2, " Millstone Unit 2 - ) ) Emergency Diesel Generator Run Time," concluded that the system would only be able to operate for a period of 5.73 days.
As corrective action, the licensee revised FSAR Section 8.3.2.2 and Table 8.3-1 to clarify the { basis for the total operating time of 7 days. The licensee took credit for the cross-connect
between the two diesel oil supply tanks (T-48A and T-488) and the 17,700 gallon underground i diesel oil storage tank, The team considered the licensee's corrective actions to be adequate.
2.3.2.33 (Closed) UIR 2654: Auxiliary Feedwater (AFW) Flow Analysis Was incomolete The licensee noted that their analysis for AFW was not complete. They determined that they did not have calculations which showed AFW flow for all postulated steam generator pressures.
As corrective action, the licensee performed flow analyses for 1,2, and 3 AFW pump ooeration to one or both steam generators for several operating and accident conditions. Additionally, they performed runout flow analysis for the cases of one and two motor-driven pumps flowing to
a faulted steam generator. Also, the licensee analyted pump recirculation flow to verify the ' adequacy of the technical specification surveillance test. The flow analyses were documented in I calculation 97-ENG-02053-M2, " Millstone Unit 2 Auxiliary Feedwater System Analysis," Revision 2, dated February 24,1998.
The team considered the licensee's corrective action to be adequate.
, 2.3.2.34 (Closed) UIR 2679: Lack of a Record for Evaluation of the Emeraency Diesel Generator (EDG) Intake and Exhaust System Pioina for Tomado Wind and Missiles This licensee item identified that to satisfy 10CFR 50, Appendix A, General Design Criteria . (GDC) 2, both the EDG intake and exhaust systems on the roof of the auxiliary building must be evaluated for tornado wind and tomado missiles. The item noted that an evaluation of tornado
- wind and missiles for intake and exhaust piping could not be found.' For corrective action, the licensee issued Engineering Record Correspondence (ERC) 25203-ER-114, Revision 1, dated November 23,1998, "MP2 Licensing Basis for Protection from Tornado Missile Damage," which clarified tomado missile design requirements for Millstone Unit 2. Additionally, the licensee issued Calculation 77-619-58GM, Revision 1, CCN 01, dated December 5,1997, " Stress Analysis - Diesel Generator Exhaust Piping," which analyzed the EDG intake and exhaust systems and found the systems.to be adequate. The team considered the licensee's actions to be adequate.
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2.3.2.35 (Closed) UlR 2883: Emeroency Diesel Generator (EDG) Oversoeed Trio Marain The licensee noted that Safety Guide. /nd the FSAR state that, during recovery from transients caused by step load increases or resulting from the disconnection of the largest single load, the speed of the EDG should not exceed 75 percent of the difference between the nominal speed and the overspeed trip setpoint, or 115 percent of the nominal, whichever is lower. However, the licensee noted that their surveillance procedure, SP 2613A, did not envelop those requirements.- The procedure did not address speed measurements for rejection of the largest single load, and the total load rejection test did not assess the margin to the overspeed trip setpointc The licensee issued CR M2-97-1081 to document the corrective action taken. The licensee revised the FSAR Section 8.3.2.1 to describe an overspeed trip setpoint range of 112 to 117 percent of nominal in lieu of 112 to 115 percent. Additionally, the licensee issued surveillance procedure SP 2661, Change 1, and performed testing to the revised criteria.
' The team considered the licensee's corrective actions to be adequate.
2.3.2.36 (Closed) UIR 2949: Response Time Testina For Hiah Pressure Safety iniection System Was Not Documented During the review of test record Operations Form 2604P-1, "ESF Equipment Response Times," the licensee identified that the HPSI system response time acceptance criterion of less than or equal to 5 seconds was not required to be recorded in the procedure. A series of overlapping - procedures were used to do the time response testing of the HPSI system. The purpose of Operations Form 2604P-1 was to comoine the results of the overlapping procedures that test the ESF systems to ensure that all test acceptance criteria were met. Although the five-second HPSI criterion was not specified in Operations Form 2604P-1, the licensee reviewed the overlapping procedures that accomplished the testing and verified that the 5-second acceptance criterion was met. The team reviewed Revision 9 to Operations Form 2604P-1 and verified that the procedure was revised to require that the HPSI system response timo of 5 seconds or less be recorded.
The team considered that the corrective actions were acceptable.
2.3.2.37 (Closed) UlR 3251: Lack cf Documentation for the Chanae of the Auxiliary Feedwater Automatic initiation Sianal (AFAIS) Instrumentation from Non-safety Grade to Safety Grade The licensee identified that the'AFAIS instrumentation was originally installed as a non-safety control grade system to meet the short-term requirements of NUREG 0578. It wcs a long-term requirement to eventually upgrade the system to " safety grade." A 1980 design change, PDCR 2-12540, made the change to safety grade. However, the licensee could not find - documentation that defined the components affected, evaluated the seismic adequacy of the components and their supports, or updated the Production Maintenance Management System (PMMS) for the affected components.
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As corrective action, the licensee found two design changes that had been previously performed and had been updated in the PMMS. The changes were PDCR 2-110-80, dated January 21,1982, which added upgraded signal conditioning and logic circuitry for AFAIS; and PDCR 12-94-80, dated November 12,1980, which replaced steam generator level transmitters with seismic and LOCA-qualified transmitters. As additional corrective action, the licensee updated the PMMS for these design changes.
The team considered the licensee's corrective action to be adequate.
2.4 Parsons Discreoancy Reports 2.4.1 Scope of Review The team examined the actions taken by Northeast Utilities to correct problems identified by Parsons Power Group Inc and documented on Parsons' DRs during their ICAVP reviews of Millstone documents and activities. Since no Significance Level 1 or 2 discrepancies had been identified by Parsons, the team reviewed a sample of 8 of the total of 75 Significance Level 3 DRs. The sample was large enough to provide a 90-percent confidence level that the remaining unreviewed DRs were also adequate. The team also reviewed a small sample of lesser significance (Level 4) DRs.
2.4.2 Findings-Signific9nce Level 3 DRs The team found that the licensee had taken appropriate actions in response to the Significance Level 3 DRs reviewed as explained below: 2.4.2.1 (Closed) DR-0030: The Condensate Storaae Tank (CST) Was Not Designed for Tomado Wind Protection This Parsons item noted that FSAR Section 10.4.5.3 stated that the exposed portion of the steel CST is designed to withstand tomado wind pressure. Parsons identified that the licensee did not have calculations that demonstrated that the CST could withstand tomado winds for the exposed portion of the tank. The licensee initiated CR M2-97-2385 for corrective actions that resulted in five calculations that demonstrated the adequacy of the CST tank for tornado winds.
Additionally, the licensee issued FSAR CR 98-MP2-93 to revise FSAR Section 5.7.3.1.4 to update the CST tomado load analysis, and to revise Section 10.4.5.3 to reference Section 5.7.3.1.4. The team reviewed the licensee's corrective actions and considered them adequate.
2.4.2.2 (Closed) DR-0032: Failure to Adeaustelv Test Valves 2-CS-15 A/B Quarterly in Accordance with IST Reauirements Parsons identified that the partial stroke test being performed on valves 2-CS-15 A/B was inadequate to ensure partial stroke of the valves. Specifically, the test as performed concluded . that the valve partially stroked if a test pump could pass water through the valves. However, ' Parsons pointed out that the test failed to account for allowable valve seat leakage. Parsons .
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I reasoned that merely pumping an unmeasured volume of water past the valve may only demonstrata that some seat leakage exists rather than that partial stroke of the valve had been achieved.' The licensee agreed with the finding and determined that deletion of this test was the proper ) corrective action. The quarterly partial stroke test was being done on the valves along with disassembly of each valve on an every other refueling outage basis, as committed to the NRC in Relief Request (RR)-lWV-5 However, in accordance with Generic Letter (GL) 89-04, simply disassembling the valves is adequate if other testing is not practicable. Because other testing of the valves, given their location in the containment sump, was not practicable, disassembly alone was consistent with the GL and, therefore, acceptable.
The team reviewed the licensee's corrective actions and found them acceptable.
-2.4.2.3 (Closed) DR-0045: Procedures Do Not Reauire the Control Rod Assembly Shutdown Groups To Be Withdrawn Before Deboration Begins as Required by the FSAR Parsons identified that the plant operating procedures allowed deboration to begin before control rod assembly shutdown groups were withdrawn. That practice conflicted with FSAR Section 9.2.3.1. After review, the licensee agreed that there was a conflict between operating practice and the FSAR but noted that the FSAR was overly restrictive. Coraequently, the licensee changed the FSAR (FSAR CR 98-MP2 56) to delete a sentence M Section 9.2.3.1.
Parsons reviewed the licensee's basis for the deletion and concurred that the TS requirements for shutdown margin provided an adequate level of protection even without the FSAR restriction.
- The team concluded that the corrective actions taken were adequate.
2.4.2.4 (Closed) DR-0070: The Refuelina Water Stornoe Tank (RWST) Foundation Desian Uses a Maximum Allowable Bearina Capacity Eaual to 5000 Pounds per Souare Foot The Parsons DR identified a need to document the soil stratum under the RWST, the allowable bearing capacity, and the mat thickness. The licensee corrective actions were identified in CR M2-97-2528, AR 97026568-01 through -05. These actions included making changes to the descriptions in the FSAR clarifying the bearing pressure values for the RWST subsurface and foundation in FSAR Sections 5.7.1 and 2.7.5.1 (FSAR CR 98-MP2-109), and performing calculation Bechtel Y-II, Revision 2, dated August 3,1998, "MP2 - Refueling Water Storage Tank & Foundation." The team found the corrective actions to be acceptable.
~ 2.4.2.5 (Closed) DR-0113: Pressure Lockina of Containment Sumo isolation Valves ' Parsons noted that containment sump isolation valves 2-CS-16.1A and 2-CS-16.1B were required to open when they received a Sump Recirculation Actuation Signal (SRAS) during a LOCA. Parsons noted that the LOCA environmental conditions that the valves may see could challenge the functionality of the valve operators. They noted that both motor operators could fail, which wiuld result in loss of long-term core cooling and the operability of the containment spray system.
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l ' . Parsons noted three specific problemsc The first problem concemed the differential pressure across the valve disc and the effects on the required opening force. The increase in containment pressure during the LOCA results in an increase in the differential pressure across the valve disc and, consequently, the force required to open the valve. Parsons calculated that the force required would be higher than the valve operator's capability.
The second problem concemed the closing force required to provide a leak-tight valve. The closing force calculation for the leak tightness concluded that the contact stress required for leak j tightness was 4000 pounds per square inch (psi), while the calculated contact stress achieved . by the motor operator,691 pai, was less than required.
. The third problem concemed inadequate safety evaluations. Parsons noted that modification PDCR 2-23-95 drilled a hole in the valve inboard disc to prevent thermal binding. Another modification, PDCR 2-52-95, welded the hole shut to prevent a leak path through the valve.
Parsons considered the SE for these modifications to be inadequate. They observed that the
, i safety evaluation for PDCR 2-23-95, adding the hole, did not address leakage through
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downstream check valves 2-CS-15A and B. They observed that this could have resulted in flow from the RWST through valves 2-CS-16.1 A and B into the containment sump. Parsons noted that the safety evaluation did not consider the effects of reduced inventory in the RWST.
- Likewise, Parsons noted that the safety evaluation for PDCR 2-52-95 did not address the ability i of valves 2-CS-16.1 A and 8 to open after the LOCA increased containment pressure.
The licensee response and corrective actions for these three items was as follows: For the first concem regarding the differential pressure across the valve disc and the effects on
the required opening force, the licensee performed valve tests with a wide range of pressures up to a pressure of 144 psi. The test showed that the valves would open under the maximum LOCA pressure and remain operable. However, the licensee noted that the condition of the ~ . surfaces of the valve disk and seats could become rougher with time and usage. They noted i that this would increase the force required to open the valves. Consequently, they initiated a modification, DCR 97037, Revision 1, dated December 9,1998. The modification added a leakoff line, sealed with a rupture disk, on the valve bonnet. The ruptue disc was sized to limit , ' the valve bonnet pressure to 85 psig and prevent pressure lockirig in the future even with roughened valve seating surfaces. NRC issued a Safety Evaluation Report (SER), dated ) November 24,1998, which accepted the change. As part of DCR 97037, the licensee issued FSAR CR 98-MP2-98 and Technical Requirements Manual Change Request (TRM CR) 98-2-31 to recognize the rupture discs. Additionally, the licensee issued LER 97-034-00 to report the pressure locking problem.
For the second problem concoming the closing force required to provide a leak-tight valve, the . licensee issued Calculation 89-078-873ES, Revision 1,' dated December 7,1995, " Millstone Unit 2 Target Thrust Calculation for 2-CS-16.1 A and 2-CS-16.18." The calculation resulted in an acceptable determination of leak tightness.
< ' Regarding the third problem concoming inadequate safety evaluations, Parsons closed the item ! based on additional information showing that the licensee had discovered and corrected the (problem before Parsons identified it. For PDCR 2-52-95, the licensee issued a new safety evaluation in conjunchon with DCR 97037 and reviewed the pressure locking problem.
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= < . ' . . The team noted a technical omission during the review of pressure locking. The team noted that I the licensee had assumed that, through leakage, the valve bonnets had filled with water before the LOCA event. The team noted that the licensee had not analyzed the pressure created in the bonnet when the water, a noncompressible fluid, heated up during the LOCA. The team considered that a very high pressure would be reached. In response, the licensee stated that a more realistic assumption would be to assume a residual bubble of air in the bonnet.
Subsequently, the licensee issued Calculation M2-EV-99-0051, Revision 0, dated March 4, 1999, "CR M2-99-0591 Evaluation of Impact of Changes in input Data on Calculation T-01247-S2." The calculation concluded that the maximum pressure in the valve bonnet under-LOCA - conditions was 75 psig, which was less than the maximum design pressure of 235 psig for the 150-pound pressure-temperature rating of the valve.
The team considered the licensee's actions to be adequate.
! 2.4.2.8 (Closed) DR-0118: Reaulatory Guide 1.97 Deficiency ) , ' Parsons review identified that the licensee had not provided redundant control room indication ' for the condensate storage tank level. Additionally, the indication was not Class 1E powered, which was contrary to the licensee's commitments. The licensee's original RG 1.97 submittal did not identify this deviation and did not request relief. As corrective action, the licensee submitted a clarifying letter, B17556 dated January 12,1999, explaining the deviation from RG 1.97. The licensee took credit for non-Class 1E alarms and instruments and local non-Class 1E indication. The NRC responded and approved the deviation on March 17,1999.
The team considered the licensee's corrective actions acceptable.
2.4.2.7 (Closed) DR-0119: Seismic Sunoort for Air Accumulator Tanks T123A&B and T124A&B During a field walkdown, Parsons identified discrepancies with the air accumulator tanks that provide backup air supply to the minimum flow recirculation header isolation valves for the ESF pumps were (1) the applicable support calculation did not identify the air tanks or their locations; (2) the calculation described anchor bolts larger than the 3/8-inch anchor bolts actually installed; and (3) the tank supports utilized clamping that Parsons considered inadequate from a seismic qualification standpoint.
The licensee response and corrective actions were to (1) conclude that the applicable support calculation was a generic calculation used for multiple tanks and locations, and, therefore, the lack of location identification was considered to be nondiscrepant; (2) revise the applicable support caiculation to show that 3/8-inch-diameter anchor bolts were acceptable for all air _ accumulator tanks; and (3) perform a test that verified the adequacy of the clamping forces for the expected seismic loads.
Additionally the licensee issued FSARCR 98-MP2-172 to recognize the use of clamping as a ) seismic restraint for these tanks.
The team considered the licensee's corrective actions to be adequate.
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- 2.4.'2.8 (Closed) DR-0124: Discrepancy in HPSI Pioe Support H-10 on ISO 25203-20224.
Sheet 7 Parsons identified during a plant walkdown that the bolts holding the pipe strap of support H-10 near valve 2-SI-426 were loose. The licensee concurred with the Parsons finding and issued Automated Work Order (AWO) M2-97-11054 to tighten ths bolts. The team verified by inspection that the support was properly secured after completion of the AWO.
2.4.2.9 - (Closed) DR-0127: Problem with Steam Generator Level Instrument Tao Soan Parsons !dentified discrepancies in trip setpoint calculations and supporting documents for steam generator narrow range low level. When the steam generators were replaced in 1992, the upper shell portion containing the upper tap was reused. The lower tap on the new lower portion was lower than the original location. Based on available drawings and documents, Parsons initially concluded that the level calculated for the trip setpoint would exceed the analytical limit even without including loop uncertainties.
In investigating the DR, the licensee acknowledged several discrepancies in drawings and , ' calculations. The existing steam generator general arrangement and assembly drawings were not suitable for accurately determining the as-built tap locations, which led Parsons to conclude that the trip setpoint would exceed the analytical limit. The licensee subsequently made field measurements of the elevations and distances between upper and lower taps, confirming that the values used in Calculation PA 0963GE " Narrow Range Steam Generator Level-Loop Accuracy L-1113A,B,C,D & L1123A,B,C,D," Revision 1, included as-built distances that were within dimensional tolerances for the modified steam generators.
However, the licensee also acknowledged that there were two errors in the steam generator low-level liquid inventory value of 95,238 pounds-mass (Ibm). The 95,238 lbm value represented a two-phase liquid inventory that included 4,144 lbm of steam, which corresponded to 43 percent rather than 34 percent narrow range level. The licensee performed calculations showing that the revised inventory was still adequate to prevent steam generator dryout for a loss-of-feedwater event.
The licensee determined that the dimensional discrepancies resulted from failure to properly "as-build" the drawings and properly update the calculations during the steam generator replacement. The licensee identified the inventory calculation errors in LER-98-012 and identified the root cause to be miscommunication between the vendor and licensee during steam generator replacement.
The licensee had scheduled the revision of Drawing 25203-28408 Sheet 1022 to show the "as-built" dimensions between taps. This was not required for startup. Additionally, CR M2-9729 was issued November 24,1997, to provide corrective actions and revise Calculations PA 0963GE and 92-030-1254E2, " Steam Generator Low-Level Trip Setpoint Analysis L-1113A,B,C,D & L1123A,B,C,D." The licensee has scheduled the calculation revisions to be completed prior to Mode 4.
The team considered the licensee's corrective actions to be acceptable.
F I - ' 2.4.2.10 (Closed) DR-0131: Lack of Reauired Aooendix R Emeroency Liahtina Parsons identified that certain equipment required for safe shutdown following a fire, and the access and egress routes to that equipment, did not have the proper lighting as required by 10 CFR 50, Appendix R, Section lil. J. The licensee previously had identified other similar problems. As corrective action, the licensee decided that portable lighting would be used for all areas where required lighting would not be practical (long outdoor access and egress routes).
For other areas where adequate lighting was provided by other sources (security lighting), the licensee intended to request specific exemptions from NRC. For areas where lights were to be installed, the licensee initiated DCR M2-98029.
The team reviewed the licensee's exemption request dated July 31,1998 (Letter B17236), and specifically the discussion of 2-CS-13B which was an issue identified by Parsons. The team found that the exemption request adequately described the physical plant layout and the j ' rationale for relying on portable lighting to access 2-CS-138. Additionally, the team verified that i Appendix R lighting had been installed at 2-CS-138 as called for in the DCR. The team verified that the installed lighting would illuminate the ladder to the valve as well as the valve handwheel.
The team considered the licensee's corrective actions to be adequate.
- . 2.4.2.11 (Closed) DR-0137: ArW Cable Color Codina Discrepanci_gg During a field walkdown, Parsons identified some examples where cabling to AFW flow transmitters was not properly color coded. The licensee concluded that this was a result of errors made in an older design modification, PDCR 2-76-80. As corrective action, the licensee applied color coded tape at each end of the deficient cables, as was rsquired by their procedures for cable color coding. The team reviewed the licensee's implementing AWO M2-98-01230, -01306, and -02800. The licensee stated that, in the time period after the PDCR, the design change process and attention to detail has been enhanced. The team agreed, based
on the results of inspections of more recent modifications and reviews of other walkdown
' results. The team considered the licensee's actions to be adequate.
' 2.4.2.12 (Closed) DR-0158: Insufficient Ranae on a Pressure Indicator Parsons identified that TS 3.6.1.4 required that primary containment intemal pressure be , maintained between -12 and +57.17 inches of water, and that the pressure be verified every 12 hours. Procedure OP 2619A-1, " Control Room Daily Surveillance," required that containment i - intemal pressure be monitored at pressure indicator (PI)-8117 located in the control room.
Parsons noted that Pl-8117 indicates from -15 to +15 inches of water and operators were using other containment pressure indicators to comply with TS 3.6.1.4. As corrective action, the , . licensee replaced pressure transmitter PT-8117 with a transmitter capable of providing full range i . . Indication and PI-8117 was rescaled to provide full range indication. The team reviewed AWO - M2-98-05815 that accomplished the change and concluded that the corrective action was acceptable.
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o 2.4.2.13 (Closed) DR-0177: Hiah Pressure Safety Inlection (HPSI) Pioina Calcu!stion Discrepancies ' The Parsons review of HPSI piping Calculations TMR-004, -005, -006, and -007 identified I discrepancies involving maximum temperature, load combinations, pipe weights, valve weights, and a missing stress intensification factor. Specifically: (1) the calculations used a maximum temperature of 300*F which did not match the 550*F maximum temperature given in a controlling calculation for the area; (2) the calculations combined directional loads using the ' square-root-of-the-sum-of-the-squares (SRSS) method which was not consistent with normal practice; (3) the calculated weight and design weight for the 12-inch pipe insulation in calculations TMR-004 and -005 did not match; (4) the weight specified for valve SI-624 in the . isometric drawing in calculations TMR-004 and -005 did not match the weight value used in the calculations formulas or in the vendor drawing; and (5) a stress intensification factor was missing for a pipe tee in Calculations TMR-004 and -005.
- As corrective actions, the licensee took the following actions (1) revised the calculation to the proper maximum temperature; (2) issued FSAR CR 99-MP2-18, dated January 1,1999, to recognize the use of SRSS as a combination method; (3) to revise.the calculation to use the correct insulation weight and to include a reference for the actual insulation weight; (4) corrected the valve weight discrepancy; and (5) concluded that the absence of the stress intensification factor was nondiscrepant.
The team consideiad the licensee's corrective actions to be adequate.
l 2.4.2.14 (Closed) DR-0203: Emeroency Safety Features Pumo Room Sumo Hiah Water Level Alarm Switches Parsons noted that the NRC SE, dated March 2,1977, stated that a seismic Category 1 system provided alarms in the control room if the ESF pump room flooded. Parsons noted that the ESF pump room sump level alarm switch was not classified as seismic Category 1. Later, the licensee identified that, further, the alarm switches were not qualified to withstand the harsh environment that could exist following a design bases accident. As corrective action, the licensee replaced the sump high water level alarm switch in each ESF sump room with switches that were seismic Category 1 and are able to withstand the harsh environment.. The alarm . switches were replaced per DCR M2-98096, "ESF Room Sump High Water Level Alarm Switch Upgrade," Revision B.
~ The team concluded that these corrective actions were acceptable.
The team noted that the Millstone Unit 2 licensing and design basis provides for two separate water-tight ESF pump rooms, each of which contain redundant equipment. Each ESF room l sump has a high water level switch that alarms in the control room ESF room flooding occurs.
- Remote manual valves are available to isolate any piping leakage into the ESF room to tum off the source of further flooding. Although this was the licensing and design basis for the plant, the team identdied a vulnerability associated with this design if an ESF room sump high-level alarm switch failed to alarm in the control room.
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e The containment spray, HPSI, and low-pressure safety injection pumps share a common line for recirculation of minimum flow to the refueling water storage tank. This common line is located approximately 3 feet above the B ESF room floor and contains two air-operated valves, in , series. The valves fail open on loss of electricity or air to the valves. The vulnerability concerns these two valves in the B ESF pump room. Functionally, the valves are required to be open during the injection phase and closed during the recirculation phase of a design bases accident.
If flooding in the B ESF room were not detected, then the potential exists for the valves fail open when wet. This would result in a gradual loss of the reactor coolant inventory in the containment sump and a release of this water to the RWST, which is vented to atmosphere. The single ESF pump room sump level switch for pump room B is crucial to for notifying operators of a leak in the pump room, so that the source of leakage can be isolated before the valves become wet.
The team discussed this vulnerability with the licensee, and the licensee agreed to examine this vulnerability and to determine whether other design or operations strategy enhancements were possible. This vulnerability was identified as an team followup item. (IFl 50-336/98-219-13).
2.4.2.15 (Closed) DR-0212: Auxiliary Feedwater Inservice insoection Proaram Discrepancies Parsons identified that the boundaries defining the extent of nondestructive examination required to meet the inservice inspection program requirements were not clear for the AFW system.
As corrective action, the licensee issued DCN DM2-00-0646-98, dated May 15,1998, that , revised drawing 25203-26126, Sheet 4, to show the boundaries. In addition, the licensee issued procedure SP-21160, Revision 43, to correct the boundaries.
The team reviewed the licensee corrective actions and found them adequate.
2.4.2.16 (Closed) DR-0239: Installation of Pressurizer Pressure Instrument Tubina Parsons identified several instances of installation discrepancies for the four redundant channels of pressurizer pressure instrument lines. These included discrepancies in the use of three-directional tubing restraints, missing suppcrts, loose clamps, overspan conditions, unsupported risers, low-polni bowing of tubing, bent tubing, inadequate slope, and other as-found conditions what did not conform to drawings or installation criteria.
As corrective action, the licensco performed technical and operability evaluations of all of the conditions and corrected ibn most significant (Significance Level 3) conditions. These included most of the installation ceuditions. The licensee documented, as acceptable, discrepancies that they determined to have lower significance. The licensee prepared DCN DM2-00-1000-98, . dated December 12,1998, to correct the documents and the installation. The team performed a field inspection of a representative portion of the pressurizer instrument tubing at the root valves and in the upper region of the pressurizer, where many of the discrepancies had been locatedJ From the field inspection and discussion with the licensee regarding calculation 1-31, " Seismic Tubing for Pressurizer T-37," Revision 2, December 8,1998, the team confirmed that the licensee had corrected the bent and mis-sloped tubing, had replaced or reconfigured the tubing supports, and had analyzed critical portions of the routing.
The team considered the corrective actions to be acceptable.
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o . . 2.4.2.17 (Closed) DR-0251 Stress Analysis Discreoancies for Main Sbam Pioino to the , Auxi'iary Feedwater Pumo Turbine Parsons identified that some input used in the stress analysis for the main steam piping to the auxiliary feedwater pump turbine needed clarification. The identified discrepancies were (1) the seismic response spectra analysis did not contain the necessary documentation to enable a reviewer to verify that the correct seismic response curves were used; (2) the reviewer was unable to determine the critical damping value used in the seismic response spectra analysis; (3) the sessmic response spectra analysis did not contain the documentation needed to determine the directional combination method used; (4) the HELB locations had not been identified; and (5) the analysis did not have the correct weight for the operator on valve HV-4191.
The licensee response and corrective actions for items 1 and 2 were resolved with the issue of Revision 3 to the analysis; Item 3 was resolved with the issue of FSAR CR 99-MP2-18 that clarified the use of the square-root-of-the-sum-of-the-squares (SRSS) method for directional load combination; Items 4 and 5 were evaluated as nondiscrepant.
The team considered the licensee's corrective actions to be adequate.
2.4.2.18 (Closed) DR-0269: Fuse Control' Deficiencies - Electrical Penetration Protection During a walkdown, Parsons identified fuses that did not match the licensee's drawings or calculations. For a root cause, the licensee concluded that the original fuse control program 'was governed by Engineering Department instruction 2-ENG-3-07, which was incomplete and had not been controlled as a design document. The licensee attributed this to a lack of ownership and concluded that their fuse control program monitoring and evaluation had failed to identify these discrepancies. For the discrepancies identified by this DR, the licensee prepared CCN-1 to calculation PA91-004, Revision 0, which showed that the as-found fuses were adequate. Fuses protecting containment electrical penetrations were of particular interest, and for this reason, the licensee had prioritized CCN-1 as a Mode 6 restraint. The team reviewed the assumptions, methodology, and results of CCN-1 and found them to be acceptable. To address extent of condition, the licensee prepared Technical Evaluation M2-EV-99-0047, " Millstone Unit 2 Fuse Control, Assessment of Current Status, including improvement Opportunities," Revision 0, and the licensee was scheduled to verify that all installed safety-related fuses conformed to controlled design documents prior to Mode 4 operation.
The team considered the corrective actions to be acceptable.
~ 2.4.2.19 (Closed) DR-0289. Cable Trav Seoaration Deficiencies {_ Parsons identified a case where redundant Facility Z1 and Facility Z2 trays were horizontally separated by about 12 inches with no intervening barrier. The separation stated in the FSAR is either 18 inches of free' apace or an intervening barrier for lesser distances. The licensee concluded that this, and many other similar deviations discovered during the ICAVP, appeared to have existed and to have been undiscovered since onginal construction. The licensee ' indicated that the original cable tray plans and layouts did not identify barriers, possibly contributing to the lack of discovery. To address the extent of condition, the licensee was
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n, l ,. completing a comprehensive program to review and restore all barrier configurations to conform , l to the licensing basis and their engineering specification SP-M2-EE-016, " Electrical Separation L ' Specification - Millstone Unit 2," Revision 1. These actions were scheduled to be compft,ted l prior to Mode 4 operation. To document this effort and to help preclude recurrence, the licensee was scheduled to develop drawings documenting the barrier configurations. The licensee did not plan to complete the drawing update prior to Mode 4 operation.
l L The team reviewed the licensee's walkdown procedure EN 21230, "MP2 Electrical Walkdown l Verification," Revision 0; criteria; and results; and field inspected a sample of completed corrections to barrier installations. The field inspection included the cable vault, auxiliary ' building, and electrical penetration areas. The licensee had established a detailed tagging scheme to readily identify and disposition separation discrepancies.
The team considered the corrective a::tions acceptable.- 1 Following compilation of their walkdown results, the licensee issued LER 98-018, Revision 1, dated February 23,1999, identifying about 458 potential findings, of which 307 were determined to be nondiscrepant. The remaining 151 findings did not meet either (or both) of the vertical (48-inch) or horizontal (18-inch) spading criteria without installation of an intervening barrier.
, The licensee's failure to satisfy the licensing basis for separation was considered to be a violation of 10 CFR 50, Appendix B, Criterion Ill, " Design Control," which requires that the design bases are correctly translated into specifications, drawings, procedures, and instructions.
The licensee's installation of cable trays and barriers did not satisfy the licensing bases stipulated in FSAR 8.7.3.1, " Separation." However, after consultation with the Director, Office of - Enforcement, it was determined that enforcement discretion can be exercised pureuant to Vll.B.2 of the NRC's Enforcement Policy, and a formal Notice of Violation will not be issued because the violation was (1) based on licensee activities before events leading to the shutdown; (2) not classified higher than a Severity Level ll; (3) not willful; and (4) plant restart requires NRC concurrence. Discretion is apnropriate because a formal restart plan is currently providing a broad-based evaluation of Millstone readiness for restart that will confirm that the - licenses has' taken corrective action for this issue. Therefore, further enforcer.wr,i action is not necessary to achieve remedial action. This violation is noncited because enforcement discretion pursuant to Vll.B.2 was exercised (NCV 50-336/98-219-14).
2.4.2.20 (Closed) DR-0313: The Reactor Pretoction System (RPS) Trio Setooint for Reactor !- Coolant System (RCS) Low Flow Trio Function was Non-Conservative Parsons' had identified that the design basis, for the loss of forced reactor coolant (RC) flow and l for the RC pump rotor seizure, assumed a reactor trip signal is generated when flow in either l: RCS loop drops to approximately 88.3 percent of the initial loop flow value. However, Parsons noted that the accident analysis assumed the RPS trip happened when the total RCS flow for L both loops decreased to 91.7 percent. Parsons noted that, for a reactor coolant pump rotor seizure event, the flow in the affected loop would drop below 88.3% before total RCS flow '- - dropped to less than 91.7 percent. Therefore, Parsons concluded that the plant's trip setpoint was nonconservative relative to the analysis value.
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- As corrective action, the licensee did an evaluation and determined that for the reactor coolant
- pump rotor seizure event, the impact of the delayed trip on the minimum DNBR would not have ] resulted in exceeding the event acceptance criteria.
{ Additionally, the' licensee's review indicated that the contractor who had performed the analysis , used an incorrect model. As corrective action, the licensee issued CR-MP2-98-0223, increased monitoring of the contractor's methodology by an audit, and evaluated the impact of the contractor's incorrect model on the other FSAR events. The licensee evaluation showed that the effect of the modeling error was not significant, and the contractor's analysis remained valid.
Separately, Parsons noted that,' for the locked rotor event, the results of the analysis for the Departure from Nucleate Bolling Ratio (DNBR) was less than required and might not provide ' adequate fuel protection.
As corrective action, the licensee evaluated the event paing statistical setpoint methodology, demonstrated that the DNBR was above the fuel thermal margin limit, and demonstrated that the '
- DNBR acceptance criteria were likely'to be met even with the delayed reactor trip, The licensee concluded that the RPS was capable of performing its intended function but did not meet its licensing and design basis for this event.
The team considered the licensea's actions to be adequate.
- 2.4.2.21 (Closed) DR-0319: Refuelina Water Storaoe Tank (RWCT) Technical Soecificati2D Volume Was Not Adeaustelv Defined and Was incorrectly Acolied in Desian Calculations and Desion Bases . Parsons identified a number of instances where the specified (RW9T) volume was inconsistent with design assumptions.' After reviewing the various issues, the licensee agreed that . the 322,000 gallons (assumed to be the minimum usable voluma sssumed for calculation of time ' of initiation of recirculation referenced in FSAR Section 14.8.2.2.3) needed to be consistent with the value specified in Calculation 5-01357-S2, Revision 0, " Minimum Time to Recirculation Actuation Signal on Millstone 2". As corrective action, the licensee issued FS AR CR 98-MP2-175 which changed the FSAR value to a consistent value of 298,800 gallons, i The team reviewed the licensee's corrective actions and found them acceptable.
2.4.2.22 (Closed) DR-0328: Associated Circuits by Common Trav on the 120 VAC System.
Parsons noted that Section 8.6.1.1 of the FSAR stated that 120 Vac vital electrical power was supplied by four physically isolated and electrically independent inverters. Each of the two vital i battery banks powered two inverters.~ Parsons identified that the four inverters were not Lphysically isolated, as stated in the FSAR, because the power cables for the inverters powered by the same battery shared a common cable tray. As corrective action, the licensee revised Section 8.6.1.1 of the FSAR to clanfy that the inverters powered by the same battery were not physically isolated. The team reviewed FSAR CR 98-MP2-187 and accompanying safety evaluation, ' ' The team considered that the corrective action was adequate.
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i L 2.4.2.23 (Closed) DR-0352: The Unit 2 Hiah Enerav Line Break (HELB) Analysis Does Not Conform to the Current Licensina Basis for Locations Outside Containment The Parsons DR noted that the Unit 2 HELB Program described in Specification I ' SP-M2-ME-003, was not up to date with the Unit 2 licensing basis. The program did not include the c'ategory of arbitrary intermediate breaks, did not include Code reconciliation, and there were inconsistencies between the FSAR and the specification. For corrective action, the licensee j updated the specification, SP-M2-ME-003, Revision 1, dated April 28,1998, " Project Specific
Design Specification For Pipe. Rupture Analysis Criteria Outside The Reactor Building - Millstone i Unit 2."
Additionally, the licensee issued FSAR CR 98-MP2-3 to revise FSAR Sections ?.10.2 and 6.1.4.1.1.2 and to update the HELB program description. The team considered these { corrective actions to be adequate.
2.4.2.24 (Closed) DR-0360: Cable Color Codina not in Accordance with FSAR During field inspections, Parsons identified that the color coding of several instrumentation and ,, control cables in the control boards did not conform to the FSAR or to the licensee's engineering i specification SP-M2-EE-016, " Electrical Separation Specification - Millstone Unit 2," Revision 1.
The problem was limited to color coding discrepancies and did not involve installation or i
separation nonconformances. The licensee issued Engineering Record Correspondence i 25203-ER-98-0347 dated December 7,1998, to generate and assign an AWO to correct the discrepancies and restore conformance to SP-M2-EE-0016. The team considered the corrective actions acceptable. The licensee planned to defer the field work until after restart, because the discrepancy was limited to color code identification and was being tracked in the ' corrective action program.
' 2.4.2.25 (Closed) DR-0411: Enc!osure Buildina Filtration System Damoer Failures . l Parsons noted that if either damper 2-EB-60 or damper 2-EB-61 failed open, the Enclosure Building Filtration System (EBFS) would not be able to establish a negative 0.25-inch water j gauge pressure within 1 minu'.e of receipt of an EBFS start signal, as required by the licensing and design basis.
In response, the licensee initiated CR M2-98-3394, dated November 13,1998 to evaluate this discrepancy. The licensee's evaluation determined that the scenario was not a problem , because both trains would be operating, and a single failure of one of the dampers to close
would not affect systems capability to achieve a negative pressure of 0.25-inch water gauge within the one minutd period. The licensee demonstrated that the exiating TSs 3.9.14 and i '4.6.5.2.2 surveillance requirements provided adequate testing to demonstrate system capability.
The team agreed with the licensee's determination.
2.4.2.26 (Closed) DR-0412: Containment Purae Sunolv Air Flow Deficit Parsons identified two issues in DR-0412 related to the Containment Purge Supply System.
The first issue related to the actual purge air flow rate compared with the values used in several design calculations and as referenced in the FSAR. Specifically, the actual purge air flow was
determined. based on postmodification testing, to be 27,500 cubic feet per minute, whereas the .
- ' FSAR references a design flow of 32,000. (he 27,500 CFM is about 86 percent of the value used in the FSAR and outside of the acceptance band of plus or minus 10 percent of the required flow. The second issue relates to changes made to procedure EN 21063A, "HVAC Test and Balance,"in Revision 3. The revision removed the plus or minus 10 percent acceptance criteria for nonsafety systems and replaced it with engineering criteria that , determine when the the flow rate for these systems was acceptable even if the flows are outside the previous 10 percent acceptance criteria.
In its discussions with Parsons, the licensee agreed to specific actions to resolve the issues identified in DR-0412. The committed corrective actions were to investigate the need to change the FSAR based on the modification to the purge system described in PDCR 2-041-95; to evaluate which HVAC systems required definite acceptance criteria and formally document that evaluation; to identify and document the personnel qualifications necessary to perform the engineering determinations referenced in EN 21063A; and to perform a flow balance and test of the containment puFJe system before restart (this test was to be linked to DR-0412 and CR M2-98-1335. to identify that it is related to an ICAVP corrective action).
In reviewing the resolution of DR-0412, the team reviewed CR M2-98-1335, "lCAVP; ' Containment Purge Supply Air Flow Deficit;" FSARCR 98-MP2-144, which incorporated the proposed licensing bases changes to the containment purge system; ERC 25203-ER-98-0240, Revision 0, "Information Needed to Provide Acceptance Criteria to initiate New HVAC Procedure (s) to Test and Balance Non-Safety HVAC Systems", dated September 25,1998; ' Design Change Request (DCR) M2-97049, Revision 0, " Auxiliary Building Ventilation Modifications," dated November 14,1997; and Action Request (AR) 98009756 that provided tracking for the corrective actions associated with CR M2-98-1335.
- The team found that CR M2-98-1335 provided acceptable corrective action plans to address the specific issues identified in the DR and the extent of condition to assess the impact on other systems. The changes proposed to the FSAR in FSARCR 98-MP2-144 related to the containment purge system's ability to provide about one air exchange per hour appeared to be consistent with the originalintent of the system and adequately reflected the existing plant conditions. ERC 25203-ER-98-0240 identified four additional nonsafety-related HVAC systems
- that require specific acceptance criteria. The licensee planned to prepare test procedures for each of these systems (Main Exhaust system, Radwaste V'ntilation system, Fuel Handling Ventilation system, and Non-Radwaste Ventilation system - Fan F19) following restart. Each of ' these systems were scheduled to be flow balanced before restart from the current outage.
DCR M2-97049 provided adequate instructions to flow balance the Containment Purge system along with the [ Auxiliary Building] Main Exhaust system. AR 98009756 task 03 provided an adequate description of tha qualifications for the System Engineering Program. -The records maintained to support the System Engineering qualification were sufficient to demonstrate that an appropriate level of control was in place to support the licensee's position regarding the - performance of engineering determinations referenced in EN 21063A. The team determined that AR 98009756 task 02 adequately linked the performance of the flow balancing and testing of the main exhaust and purge supply system to CR M2-98-1335 and DR-0412, identifying the _ balancing and testing as satisfying an ICAVP issue.
The team determined that the corrective actions taken were reasonable to resolve the conditions . identified in the DR and should prevent recurrence of the specific issues. Further, the correcti.ve
'
l ' actions adequately addressed the extent of the condition as it relates to other systems. Based on the team's review DR-0412 has been adequately resolved and the corrective actions that were deferred until after restart were reasonable.- l-2.3.2.27 (Closed) DR-0414: Certain Line Desianations Were Not identified in the Production I Maintenance Manaaement System (PMMS) or Master Eauioment Parts List (MEPL) and Were Not in Accordance with FSAR Commitments Parsons noted that piping lines'4-HCD-3 and 6-HCD-3 (portions of the safety injection minimum flow recirculation lines) did not meet the requirements of FSAR Table 4.2-4, and lines %-CCB-10 ~ and 1-HCB-1 were not included in the PMMS or on the MEPL.
After review, the licensee concluded that 4-HCD-3 and 6-HCD-3 should have been included in Table 4.2-4. The reason those lines were not previously included in the table because at the time the table was created (in response to NRC FSAR Question 4.7), the lines were not considered safety-related. Subsequent to the initial startup of the plant (and after the table was in place), it was recognized that the piping in question needed to be classified as important to I.
safety and needed to meet seismic Category I requirements. This discovery was reported to the NRC via Reportable Occurrence Report 76-38/IT, dated June 25,1976, and a commitment was . made to upgrade the seismic qualification of the lines. The seismic upgrade was made by . PDCR 2-222-76. However, Table 4.2 4 was never revised to add the additional lines and their
qualifications.
As corrective action, the licensee issued FSARCR 98-MP2-171 updating the table to indicate that the classification and applicable code for lines 4-HCD-3 and 6-HCD-3 were Quality Group B and ASME Section lil, Class 2, and that the lines were designed in accordance with ANSI
- B31.1.0 and seismic Category I requirements.
With regard to lines %-CCB-10 and 1-HCB-1, the licensee determined that both were on the MEPL and were not presently required to be included in the PMMS, although the licensee had an enhancement effort under way to place all safety-related components into PMMS.
The team considered the licensee's corrective actions to be adequate.
2;4.2.28 (Closed) DR-0449: Inadeauate Seoaration of RG 1.97 Cateaorv 1 Indicators A walkdown by Parsons identified that RG 1.97 Category 1 indicators were touching redundant indicators as well as nonsafety-related indicators, contrary to licensing and design basis requirements. The licensee concluded that the apparent cause was inappropriate downgrading of the quality classification for RG 1.97 Category 1 indicators as a result of past quality classification evaluations.
-' The licensee had hreviously issued ACR M2-96-0609, dated November 11,1996, identifying ' several variables that did not meet design and qualification commitments to RG 1.97. The l ' licensee subsequently prepared Engineering Evaluation M2-EV-97-0028, identifying several L installation and qualification discrepancies with respect to RG 1.97. The licensee prepared DCR M2-97035, "RG 1.97 Upgrade," to upgrade the indicator hardware to Class 1E and to conform . the installation to RG 1.97 separation commitments. In closure of this DR, Parsons noted that , 62-l i- _
p ' i
the DCR did not address separation of safety and nonsafety indicators. The licensee issued DCN DM2-03-0213-98 to provide steel separation plates where necessary. The licensee had scheduled the modifications to be completed prior to Mode 4 operation.
. The team considered the corrective actions to be acceptable.
i - 2.4.2.29 (Closed) DR-0477: As-built Discreoancy for the HPSI Accumulator Tanks ' During a walkdown of plant equipment, Parsons noted that the HPSI accumulator tanks were . not installed in accordance with the configurations assumed in the support loading calculations.
' Specifically, Parsons noted that the bolting was smaller than assumed. They also noted that some of the tanks were installed in double (side-by-side) tank supports as opposed to single tank supports assumed in the calculation. Additionally, Parsons noted that the sizes of some of . the tanks were not the same as the sizes analyzed in the support loading calculation. Other discrepancies were noted, such as the support baseplate size and method of attachment to the structure.
The DR also questioned the acceptability of using friction clamps to restrain the tanks from vertical movement from seismic loads. This issue was resolved in DR-0401 as discussed next ) in this report.
i As corrective action, the licensee corrected the calculation to recognize actual field conditions.
The team verified that the calculations had been updated. No modifications were required.
, The team considered the licensee's corrective action to be acceptable.
2.4.2.30 (Closed) DR-0481: Adecuacy of Air Accumulator Supports as Seismic Restraints ! LThe Parsons DR questioned whether the pipe clamps used on the various air accumulators ' provided adequate vertical seismic loading support from clamping friction. The licensee performed analysis of the supports (Bechtel Calculation 4, CCN 01, dated March 24,1998, , ! " Millstone Unit 2 Seismic Supports for Air Accumulators") and conducted a visual inspection to ensure the supports were adequate. Additionally, the licensee issued FSAR CR 98-MP2-172 to . revise FSAR.Section 5.8.5.1 and to clarify the use of friction supports for lightly loaded safety- ] ' related components. The team found the corrective actions to be adequate.
2.4.2.31 (Closed) DR-0487: Evaluation of Hiah Pressure Safety Inlection (HPSI) Flows Not in i Accordance with the F nel Safety Analysis Report (FSAR) Parsons noted that the FSAR identified that the HPSI pump runout flow was based on two HPSI pumps and one containment spray pump operating from the same suction header, but that the HPSI flow' analysis, Calculation 97-122, did not analyze that case.
j - As corrective action, the licensee initiated CR M2-98-1385 to supersede eariier HPSI ' calculations.~ Additionally the licensee issued FSAR CR 98-MP2-191 to revise the description of i ' HPSI runout flow.L - . '
- The team considered the licensee's actions to be adequate.
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. f .. 2.4.2.32 (Closed) DR-0538: Measurina and Test Eauioment (M&TE) Proaram Discrepancies Parsons identified instances of improper use of a torque wrench tester, improper use of ! calibration ratios, failure to calibrate digital multimeters per vendor instructions, inadequate M&TE recordkeeping, and improper acceptance criteria used for the calibration of torque i ' wrenches. As corrective action, the licensee issued procedure WC 8, " Control and Calibration )
cf Measuring and Test Equipment," Revision 3, Change 3, to clarify torque wrench calibration ]
and calibration ratio requirements. Procedure MTE 1120, " Digital Multi Meter Calibration," Revision 0, was issued to provide instructions to calibrate digital multimeters per vendor instructions and Procedure DC-16, " Vendor Equipment Technical Information Program,". Revision 5, was issued to include M&TE vendor manuals. Responsible personnel were counseled to properly record M&TE data. The licensee reviewed M&TE vendor manuals to ensure applicable M&TE requirements specified in the manuals were incorporated into the M&TE program.
The team considered the corrective actions to be adequate.
2.4.2.33 (Closed) DR-0539: Discrepancy with IE Bulletin 80-11 Masonry Block Wall Proaram t - Parsons identified that the licensee had committed to stencil safety-related masonry block walls to identify them as safety related, but that many walls were not stenciled. In response to this DR, the licensee committed to a number of actions, including determining whether stenciling was a valid current commitment, determining where the stenciling had ever been done, and determining if the stenciling had been painted over, if the latter was the case, the licensee j committed to determine the cause, extent of condition, and appropriate corrective actions.
J After review, the licensee determined that the stenciling of the walls was still an active commitment. The licensee also determined that all applicable walls were originally stenciled.
However, due to inadequate controls after routine activities such as painting, stenciling was rarely reapplied. Consequently, about 80 percent (approximately 100) of the QA Category 1 block walls were determined to require at least some stenciling.
In 1997, Specification SP-M2-ME-0016 " Application of Protective Coating Materials Outside Containment," Revision 0 was developed. Paragraph 2.10.3.6 of the specification stated "Do not paint over tags, identification decals, or stencils..." Therefore, with the issuance of the - specification, the licensee considered that a plant control on stenciling was in place. However, as part of the corrective actions for this DR, the licensee planned to revise the specification to allow painting over stencils but also to contain controls for reestablishing stencils after the paint dries (AR 98013672-05). Additionally, Unit 2 procedure SP 21201, " Inspection of Safety Related Masonry Walls," contained a listing of all safety-related masonry block walls, which was to be updated to add the additional walls identified in " Technical Evaluation for Compartmental Pressurization and Intemal Flooding Effects Due to High Energy Line Break on Critical Walls," - (Evaluation No. M2-EV-98-0149, Revision 0). Furthermore, Millstone Common Engineering Procedure CEN 104C, Revision 0, also contains a listing of Unit 2 safety-related walls. The licensee planned to revise that procedure to delete the listing of Unit 2 walls and reference _ ' ' Procedure SP212201 instead.
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I - , . The licensee has deferred the procedural revisions discussed above as well as the actual restenciling of the walls until after startup. Because the Design Change Manual (DCM) contains adequate controls to ensure that unreviewed modifications are not made to block walls, the team has no technical problem with the licensee's deferral of those items. However, in its response to the Parsons DR, the licensee " committed to correct this condition prior to MP2 startup." When the team raised this point with licensee personnel, the licensee concluded that , its response to the DR was somewhat unclear, Specifically, the above statement was made in the response, but the meaning of closure was then qualified in the DR response by a list of actions that did not include completion of the procedural updates or the actual stenciling. Again, because the DCM contains adequate design controls, deferring the procedural updates and the stenciling until after startup was acceptable to the team.
The team considered the corrective actions to be adequate.
, 2.4.2.34 (Closed) DR-0603: Enclosure Buildino Filtration System Charcoa! Coolina Discrepancies in the DR, Parsons identified some discrepancies between the FSAR.(Section 6.7.4.1.1) and the applicable plant calculation (Calculation 97-EBD-01955-M2, Revision 0) as to the minimum required air flow necessary to maintain the charcoal filters below the desorption temperature and the maximum. calculated heat load on the charcoal filters. The licensee subsequently issued Revision 1 to the calculation, which revised the maximum calculated heat load on the filters and demonstrated that the system as designed was adequate to ensure that the charcoal filters are maintained well below the desorption temperature. Additionally, the licensee updated the FSAR to reflect the results of the new calculation (FSARCRs 98-MP2-94 and 113), providing ' consistency between the calculation of record and the FSAR.
The team reviewed the licensee's corrective actions and found them acceptable.
2.4.2.35 (Closed) DR-0606: Insufficient Exhaust Rate from the Exhaust Buildina Due to Presumed Failures in the Charcoal Coolina Tie-in Ductwork During review of the FSAR failure mode analysis for the EBFS, Parsons noted that the mest limiting consequences of certain duct failures were not considered. After reviewing this issue, the licenses concluded that, while Parsons was correct, the descriptions of the failure of passive components included in FSAR Sections 6.7.4.1.2 and 6.7.4.1.3 were beyond the design bases of the plant and should have not been included in the analysis to begin with. Therefore, the licensee concluded that the issue concoming whether the analysis should have evaluated other resulting conditions as identified by Parsons was a moot point. The licensee's action was to delete the two FSAR sections. The team verified that FSAR CR 98-MP2-94 made the required change. The team considered the licensee's actions to be adequate.
2.4.2.36 (Closed) DR-0612: Emeraency Diesel Generator (EDG) Pioe Sunoort Observations Parsons identified that supports were not installed on EDG starting air tanks drain line and that this condition did not conform to design drawings. The licensee determined that this issue did - not affect the operability of the EDGs. However, as corrective action, the licensee installed . supports on each of the EDG starting air tank drain lines in accordance with DM2-00-1675-98,
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I " Missing Supports on Air System Drain Lines off Starting Air Tanks, T-49A/B/C/D," dated , October 13,1998.
Parsons also identified that Pipe Support Drawing 25203-22200-525042 Revision 1, dated July 21,1975, was never updated for baseplate modifications. As corrective action, the licensee i issued modification DM2-00-1383-98, " Diesel Generator Air Intake, Baseplate Inconsistencies I with Pipe Support 525042 Design Drawing," dated October 30,1998,' which corrected the drawing.
l The team reviewed these corrective actions and considered them acceptable.
2.4.2.37 (Closed) DR-0629: Conflictina Information Presented in Final Safety Analysis Reoort LER 96-22-00, " Single Failure of Hydrogen Purge Valves Will Deenergize Heaters of Both Trains of Enclosure Building Filtration System" had been issued when the licensee determined l that a single-failure of the purge valve interlock to the EBFS would deenergize both trains of emergency charcoal filtration. As an interim corrective action, the licensee installed a bypass ' jumper that bypassed the interlock. As a long-term corrective action, DCR M2-97013 was < . subsequently implemented. The DdR removed the interlock and the temporary jumper. Also, ' Final Safety Analysis Change Request (FSAR CR) 97-M2-99 was issued to change the FSAR to reflect the DCR by revising FSAR Sections 6.7.2.1 and 6.7.3.1.
During Parsons' review, it was identified that other sections of the FSAR (Sections 6.6.4.1 and 6.6.4.2) still described both the interlock and bypass jumper as installed although the DCR
had been completed and the update of the FSAR had been finished. After reviewing this issue, the licensee agreed that the FSAR conflicted with the as-built design. As corrective action, , FSARCR 98-MP2-166 was issued, which correctly updated Section 6.6 of the FSAR.
' The team reviewed the FSARCR and concluded it appropriately addressed the issue.
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2.4.2.38 (Closed) DR-0630: Fuse Control-Discrepancies with Master Fuse List Parsons identified installed fuses in the emergency diesel generator system that did not match the licensee's master fuse list. Although the licensee had identified these types of discrepancies programmatically in their Engineering Self-Assessment ESAR-PRGM-97-027, " Fuse Control Program," and issued AR 97007498-08 to verify that installed fuses conformed to design documents, the licensee had not identified these speedic discrepancies. To address this DR, the licensee issued CR-M2-98-3047. The licensee attributed the cause as a lack of engineering documentation retrievable for these installed fuses and insufficient attention to fuses and their replacement from the late 1970s to the 1980s. To address extent of condition, the licensee prepared Technical Evaluation M2-EV-99-0047, " Millstone Unit 2 Fuse Control, Assessment of Current Status, including improvement Opportunities," Revision 0, which also showed that the existing fuses were adequate. The licensee had scheduled actions to verify that all installed i safety-related fuses conform to design before Mode 4 operation.
The team considered the corrective actions to be acceptable.
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e 2.4.2.39 (Closed) DR-0642* Inadeauste Classification and Qualification for Emeroency Diesel Generator (EDG) Systems Instrumentation - Parsons noted that the seismic qualification and classification of several instruments in EDG subsystems appeared to be discrepant. Parsons had several specific examples including the diesel fuel oil system, the diesel starting air system, and the jacket cooling water expansion tank instrumentation.
As corrective action, the licensee initiated condition reports (CRs). For the EDG fuel oil system ,
- instrumentation, the licensee issued CR M2-97-2068, dated September 18,1997, which
' downgraded the EDG fuel oil level instruments from Category 1 to non-Category 1. The licensee concluded the instruments had erroneously been upgraded in tt e past. Other minor ' - issues were also resolved in the CR. For the EDG starting air system instrumentation, the . licensee wrote CR M2-98-2319, dated August 12,1998. The licensee deferred actions until after startup but provided tracking mechanisms for theActions. For the EDG jacket cooling water expansion tank instrumentation, the licensee wrote CR M2-98-2803 to evaluate and i establish the required level of quality for the level switches and level gauge. The instruments , were listed as Category 1 but had no safety function.
The team reviewed the licensee corrective actions, including deferred actions. The team considered the licensee's actions to be adequate.
2.4.2.40 (Closed) DR-0677: Quality Classification Status for Certain Emeroency Diesel Generator (EDG) Components Parsons identified that 4160 Vac undervoltage sensing control circuits used for bus isolation and diesel generator loading contained both safety-related and nonsafety-related devices. They noted that failure of a nonsafety-related voltmeter could result in failure of the safety function of the circuit. Parsons also noted that the voltmeter selector switch would not serve as an isolation device because the switch could be left in a nonisolated position. As a root cause, the licensee ' concluded that quality classification for these' devices was inappropriately limited to the basic safety function of the circuit (e.g., sense undervoltage) and did not consider the effects of - failures of non-Q devices on the function of the circuit.
To address this concem, the licensee issued CR M2-98-2017 to reconcile the quality ) ' classifications for all of the diesel generator circuit components and cabling. The licensee reviewed all components involved in the EDG metering, relaying, excitation, and voltage regulation circuits to determine the quality status for all relays, meters, switches, cables, and transducers. ' Furthermore, they ensured that either qualified isolation devices were used to isolate the effects of non-Q devices or they justified the lack of an isolation device based on circuit failure modes and effects analysis. The licensee made completion of these actions a j Mode 4 restraint.
, The team cc>nsidered the corrective actions to be acceptable; j '
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m 2.4.2.41 (Closed) DR-0678: Potential for Pressure Boundary Breach Due to Instrument or Instrument Tubina Failure - Parsons identified three instruments in the auxiliary feedwater (AFW) system that were not functionally safety-related but served as AFW steam safety-related pressure boundaries, the PT-4190 (turbine-driven AFW pump steam pressure transmitter), PI-4190-1( turbine-driven AFW pump steam pressure gauge), and LS-4590 (steam drain pot level switch). Parsons noted that the licensee had failed to address the ability of these instruments to survive a design basis j seismic event without a breach of the pressure boundary. To address this concem, the licensee ! issued CR M2-98-3281 to perform an engineering evaluation and to ensure the instruments l were qualified with respect to pressure boundary integrity. The licensee performed Evaluation CD-3967 and upgraded LS-4590 to Quality Assurance (QA) Category 1, pressure boundary only. The licensee also determined that PT-4190 and PI-4190-1 had been installed as Seismic i Category 11. In the closure notes for CR M2-98-3281, the licensee identified that prior to Mode 4 ' operation, an evaluation would be issued showing that all of the instruments were sufficiently , rugged to withstand a seismic event and to retain their pressure integrity.
j , The team considered the corrective actions to be edequate.
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2.4.2.42 (Closed) DR-0694: Desian Inout Discreoandes - Fuel Handlina Accidents (FHAs) i . Parsons noted that some design inputs to the FHA analyses were nonconservative. Parsons considered that, with conservative inputs, the calculated releases might exceed the allowable values in the current analyses.
Parsons identified four discrepancies. First, they noted that the actual depth of water above the j damaged fuel assembly was slightly less than that assumed in the analysis. Also, they noted . ' that the iodine decontamination factor (DF) used in the analyses would not be achieved by using the minimum allowed spent fuel pool levels. They noted that the calculated releases would, therefore, be greater than those in the current analyses and might challenge the analyses acceptance criteria.
Second, they noted that the licensee had not provided a justification or basis for the number of fuel rods that they assumed would be damaged by dropping a fuel assembly. Therefore, Parsons questioned the validity of the licensee's assessment of the radiological consequences - of the event and their statement that the results were "well within" the 10 CFR 100 guidelines.
i Third, Parsens questioned the assumption of uniform mixing used in the FHA analysis. The licensee analysis used the entire containment free volume for diluting the activity prior to ! release. ' Parsons reasoned that uniform mixing was not accomplished, and, consequently, the activity released might exceed the calculated value and might not meet the acceptance criteria.
, i Fourth, regarding the cask drop accident, Parsons noted that the controlling dose was from ~ noble gases which were not affected by the charcoal filters of the EBFS. They also noted that the atmospheric dispersion factors associated with the discharge path through the Millstone ' ' Unit 1 (MP-1) stack were nonconservative. The licensee response and corrective actions for ! .these fouritems was as follows.
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i S
- . Regarding the' FHA, the licensee noted that if a damaged assembly rested at the highest point,
- on the top of the racks, the assumed DF of 100 was still be conservative. They noted that the DF for a depth of 23 feet was expected to be a minimum of 800. Based on subsequent -
discussions with Parsons, the significance level of this problem was down graded from 3 to 4.
The licensee committed to do reanalysis in accordance with CR M2-98-2112, AR 98020342-52,
l . after startup.
J . ' l l Regarding the number of assemblies assumed to be damaged, the licensee noted that the FHA analysis in the Spent Fuel Pool (SFP) assumed one damaged fuel assembly. However, they .j
noted that for the FHA in containment, the analysis assumed 14 damaged rods. The 14 ' , - damaged rods was part of the MP-2 licensing basis as documented in NNECO memorandum ' RAC-98-289, dated September 23,1998.' Based on discussion with Parsons, the significance - level was down graded from 3 to 4. The licensee committed to do a calculation in CR M2 98-2112, AR 9802034-53, after_startup.
- Regarding mi@g in containment, the licenses wrote CR M2-98-0507, dated February 25,1998.
Additionally. the licensee jvrote CR M2-98-2494, dated August 25,1998, to identify that the
containme1t particulate and gaseous radiation monitors were considered inoperable because they might not detect the activity released from an FHA. As an immediate action, the containment purge valves were shut. Additional specific corrective actions included voiding _ Calculation 78-772-19RA which nad assumed uniform mixing. Additionally the licensee issued Technical Evaluation M2-EV-98-0186, Revision 1, dated October 7,1998, " Evaluate Containment Atmosphere Mixing During Purge Activities." The evaluation concluded that with - both containment auxiliary recirculation fans (F-24A and F-248) operating, there would be - adequate mixing in the upper two-thirds of the containment. Since the previous calculation was based on 'one fan operating, the licensee considered the problem to be reportable.
Consequently, the licensee issued LER 98-021-00 on October 8,1998, to identify that - inadequate radiation monitoring (based on inadequate containment air mixing) occurred during previous refueling operations. Furthermore, the licensee revised Procedure OP 23148, Revision 17, Change 4, on November 3,1998, to require that both auxiliary recirculation fans be operating before initiating containment purge. Additionally, the !icensee issued calculation ~ a M2FHAIC-02701R2, Revision 0, dated September 28,1998,'MP-2 Fuel Handling Accident in Containment." The calculation used conservative assumptions for mixing and concluded that the offsite doses were. below limits and the control room doses were acceptable.
- The licensee noted that the_ cask drop accident was under revision. The licensee's preliminary estimates indicated that the dose rate at the radiation monitors was greater than 50 millirem per hour. At that dose rate, the licensee noted that the monitors would respond and switch ventilation to the EBFS. -The evaluation was being tracked by CR M2-98-2112, AR 98020342-54 and was deferred until after startup.
The team reviewed the licensee corrective actions for all four items, (the actions deferred until l . after startup). The team considered the licensee's actions to be adequate.
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- , I y 2.4.2.43 (Closed) DR-0701: Environmental Que;incetion of Turbine Driven AFW Pumo Soeed Control Components Parsons identified that electrical environmental qualification (EEQ) documentation for the turbine-driven auxiliary feedwater pump (TDAFWP) speed control circuit devices (resistor, governor motor, hand switches, and indicating lights) was not retrievable. The licensee concluded that the resistors had been added by Bechtel prior to startup, and that documentation
- of design changes prior to startup was limited and not generally retrievable. In addition, records of work done on the components before 1985 was not readily retrievable. To address the EEQ concem, the licensee performed Technical Evaluations M2-EV-99-0041, "TDAFW 1 Environmental Qualification Evaluation," Revision 0, and M2-EV-99-0043, " Terry Turbine Govemor Speed Changer Motor and Associated Motor Resistors," Revision 00, which used the current HELB environmental parameters, provided some additional margin for those parameters, and took credit for the intermittent thermal duty cycle for the speed-setting motors.
The evaluation showed that the devices in the TDAFWP room were qualified to the harsh environment.
~ The team found the technical evaluation acceptable. The as-found material condition of the resistors (located in the TDAFWP room) and the hand switch (located in a mild environment) i during IR 50-336/98-203 are dispositioned in IFl 50-336/98-203-07 presented earlier in this ' report.
2.4.2.44 (Closed) DR-0702 Safety Classification of Control Switches for TDAFWP Soeed Setting Parsons identified that control switches for the turbine-driven AFW pump speed-setting function appeared to have been procured as nonsafety-related and were used in a safety-related circuit.
To address this concem, the licensee reviewed the procurement history for the switches and concluded that they had been originally procured as QA Category 1 under the main control board specification and as a part of fire shutdown panel C10 per PDCR 2-54-86; In addition, the licensee performed a comprehensive work history review (documented in CR M2-98-2289) to reconcile parts-related maintenance practice from 1987 to 1998 as compared with 1998 standards. On that basis, the licensee concluded that procurement of the switches had been acceptable and revised the quality parts listing.
- The licensee had identified generic problems with QA classifications in MP2-CD-3444. The , licensee concluded that there had been ineffective controls and oversight of the update of the parts database, and that NGP 6.10 Rev. 8 (effective April 1,1997) currently implements strict j controls over database updates and quality classification evaluations.
The team considered the corrective actions to be acceptable. The as-found material condition of the hand switch is discussed in IFl 50-336/98-203-07 earlier in this report.
~ 2.4.2.45 (Closed) DR-0746: Color Coding of Under Voltaae Potential Transformer (PT) Winna For the under voltage pts that' sense loss of power on emergency buses 24C and 24D, Parsons identified potential problems with channel independence, lack of intomal separation, and lack of separation on the field side of the PT output fuses. Parsons reviewed the licensee's response to
i
e the DR and agreed that single-failure criteria levied by the licensing and design bases were
, satisfied, as were separation criteria (since credit was given for heat shrinkable tubing as a i barrier). However, Parsons concluded that the existing color coding for the wiring was not - correct.- The licensee issued CR M2-98-2792 identify'ing corrective action to color band the cables as necessary to satisfy the FSAR and to provide justification for the use of fuse blocks as barriers.
The licensee scheduled the corrective action to be completed prior to Mode 4 operation.
The team considered the < corrective action to be acceptables 2.4.2.46 (Closed) DR-0751: Nianual Actiorts To Support Design Bases Analysis Not Supported ) in Operating Procedures.
Parsons identified the potential for failure of the makeup valve from the condensate storage tank - (CST) to condenser hotwell valve 2-CN-241, to close during a design bases accident. The CST - provides a suction to the AFW pumps, and the failure of 2-CN-241 to close would divert an excessive amount of inventory from the CST. The licensee could not credit operator action to close 2-CN-241 because a HELB in the turbine building would prevent operators from entering the area to close the valve. As corrective action, the licensee modified the plant by providing a makeup water line to the condenser hotwell from an altamative source, the surge tank, and locking 2-CN-241 shut. The modification was performed in accordance with DCR M2-98073, " Cross Connect Piping Between CST and Condenser Hotwell," Revision A.
,- The team concluded the corrective actions to be adequate.
2.4.2.47 (Closed) DR-0759: Loss of Normal Feedwater (LONF) Analysis . Parsons identified five discrepancies with the LONF analysis. First, they noted that the reactor coolant system flow was assumed to be at the technical specification minimum flow rate ~ f 360,000 gpm, while the actual plant flow rate is approximately 387,000 gpm. Second, they o noted that the analysis assumed that 500 tubes were plugged per steam generator, whereas the installed steam generators have only one plugged tube.' Third, they noted that the main steam (MS) valves.and automatic depressurization valves (ADVs) were assumed not to operate, but they noted that the valves do operate following a reactor trip. Fourth, Parsons noted that the analysis assumed that the main steam safety valves (MSSVs) operated at the high end of the expected opening pressure range: nominal setpoint plus 3 percent drift.. They observed that, in contrast, the licensee allowed the valves to operate at the low and of the expected opening pressure range; nominal setpoint minus 3 percent drift. Fifth, Parsons noted that the analysis assumed that both AFW flow control valves were operable, but the analysis did include a scenario that assumed a failure of one control valve.
The licensee and Parsons agreed that item 4 was not discrepant..They agreed that items 1, 2, i and 3 were Significance Level 4 items. As corrective action, the licensee initiated CR M2-98-2804, dated September 17,11998, AR 9816002, to track their commitment to provide new or updated calculations prior to restart for items 1 through 3. A licensee contractor issued a report, EMF-98-015, Revision 01, dated December 1998, which resolved the concoms with items 1, 2, L and 3. For item 5, the licensee issued Calculation S-02835-S2, Revision 0, dated i '
i . . l L ~. [
February 24,1999," Loss of Normal Feedwater Flow Transient Wdh the Failure of an AFW Regulating Valve to Open." The calculation concluded that the single failure was bounded by the LONF scenario in FSAR Chapter 14.
The team reviewed the licensee's corrective actions and downgrade of items 1 through 3 from Significance Level 3 to 4 and found them to be adequate.
l 2.4.2.48 (Closed) DR-0761: Classification of Enclosure Buildino Filtration System ! Instrumentation and Control Components i in their review of the enclosure building filtration system, Parsons identified several i instrumentation and control components that had inceirectly received as nonsafety-related i classification. The licensee concluded that this was one of several instances of quality classification discrepancies. The licensee detemiined that the root cause was a lack of management support and inadequate monitoring. In response to this DR, the licensee issued CR M2-98-3355 to address the DR and performed quality classification determinations MP2-CD-3992, -3993, and -3995. The Quality Classification program was being strengthened by the licensee as a generic issue.
. The team considered the correctiva action to be acceptable.
2.4.2.49 (Closed) DR-0770: Failure of AFW System to Meet Chaoter 14 Accident Analysis in this DR, Parsons identified a single failure vulnerability in the Auxiliary Feedwater System (AFW). Specifically, they noted that a loss of the Facility 2125-volt DC bus could result in less AFW flow than assumed in the accident analysis, if the bus were lost, control power for , automatic start of the "B" motor-driven AFW pump and remote start of the turbine-driven AFW pump would be lost. In response to this finding, the licensee reported the issue to the NRC (LER 98-022-00, 01, and 02); reviewed the system for other vulnerabilities; and proposed a design change (DCR M2-98-95) which will modify the power supply to the turbine-driven AFW pump so it can be powered from either Facility 1 or 2 with 125-volt DC power. The team found the licensee's completed and proposed corrective actions to be acceptable. The licensee had scheduled completion of this item for restart. NRC will leave the LER as an open item for tracking completion of the power supply design change.
2.4.2.50 (Closed) DR-0773: Seauencer Desian Drawinas Were Not in Comoliance with the FSAR Parsons identified four instances where the FSAR description of the EDG sequencer appeared to be inconsistent with plant procedures and drawings. After discussions with the licensee, Parsons agreed that one of the items was nondiscrepant and another was previously identified by the licensee. The two other conditions identified involved problems with FSAR Figure 7.3.-3 , (drawing 25203-28150, Sheet 2). The licensee subsequently issued DCN DM2-00-0678-98 to update the drawing to address the issues identified by Parsons as well as other issues identified by the licensee. By procedure, the updates of the drawing will be incorporated into the FSAR in the next regular update.
The team reviewed the licensee' corrective actions and found them to be acceptable.
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' -,. . l - 2A.2.51 (Closed) DR-0781: CFBPS Discheice Isolation Damoer 2-AC-11 Following up on an issue identified in DR-0723, Parsons identified that operating procedure OP 2384 *ESAS Operation," Revision 11, specified the final position for damper 2-AC-11, following a Containment Isolation Actuation Signal (CIAS) as "open" while a number of other plant documents specified the final position of the damper as " closed". Furthermore, Parsons identified that OPS Form 2605 H-1 did not list damper 2-AC-11 as one of the dampers for which data are, required to ensure periodic testing of critical ESF functions. This raised a question as to whether the damper was periodically tested like other similar dampers.
> , After reviewing these issues, the licensee concluded that OP 2384 was, in fact, incorrect, and a procedure change was made to fix the error. Additionally, the licensee concluded that damper 2-AC-11 should have been periodically tested and added it to OPS Form 2605 H-1. A review of plant testing records by the licensee revealed that, while the damper has not been in a periodic test prograni, it has been occasionally tested incidental to other work. An example was a test done by Procedure No. T84-31, Revision 0, Change 1, "EBFS CIAS Contact Test," . following implementation of PDCR 2-32-84.
~ The team verified that OP 2834, Revision 13, Change 2, contained the correct final position for 2-AC-11 and verified that OPS Form 2605 H-1 Revision 9, Change 2, had damper 2-AC-11 on the list of components to be tested.
. The team considered the licensee's corrective action to be adequate.
. 2.4.2.52 (Closed) DR-0785: Sesmietion Discreoancies in Intemal Panel Wirina Parsons identified several discrepancies regarding separation of control board intomal wiring.
The licensee concluded that they had not performed an adequate reverification of separation distances. To address this concem and the extent of the condition, the licensee performed an evaluation of all wiring in panels containing safety-related wiring and was performing hardware changes (such as rerouting or restraining of wiring and addition of barriers) to restore conformance to the criteria stipuwed in the FSAR and SP-M2-EE-016, " Electrical Separation Specification - Millstone Unit 2," Revision 1. The licensee prepared comprehensive and detailed separation evaluations for the as-found conditions.
The licensee identified six instances of deviations that they justified as use-as-is by specific ~ ircuit analyses showing that redundant circuits were not compromised. Additionally, they c scheduled a revision to the FSAR to permit exceptions to the criteria on an individual basis with analysis and documentation. The change to FSAR 8.7.3.1 will state that lesser separation can . be accepted if the degree of hazard and mitigative measures do not degrade Class 1E safe
shutdown circuits and equipment below an acceptable level. - The licensee intends to evaluate i any exception to separation requirements under 10 CFR 50.59. The licensee stated that exceptions would not be taken between functionally redundant vital wiring or devices inside ' control panels.
' The team found this provision for analysis acceptable and consistent with IEEE Std 384-1981, "lEEE Standard Criteria for independence of Class 1E Equipment and Circuits," which is not a part of the Millstone 2 licensing basis but represents more current accepted industry practice, i
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p / The team reviewed the six deviation justifications documented by FSAR CR 99-MP2-51 and the I accompanying technical and safety evaluations. The deviations involved wiring for a nonvital maintenance jack system for plant communications associated with a Facility Z2/2 raceway system; a switch panel in the battery charger, where facility Z1 wiring was less than 6 inches from Facility Z5 wiring; the reactor trip switchgear, where nonvital Facility 1 wires were routed . with and in contact with Facility Z3 wires on the inboard side of the terminal blocks within the covered boxes (a similar configuration existed in the opposite trip switchgear cabinet); a Facility Z2 switch in control room panel C06, which was within 6 inches of four Facility Z1 switches; and nonseparate routing of nonvital Facility 1 wiring with non-vital Facility 2 wiring within fire detection panel C26. The team found the FSAR CR and the evaluations acceptable, . based on analyses showing that separation of redundant functions was not compromised.
, The team considered the corrective action to be acceptable.
' 2.4.2.53 (Closed) DR-0804: Seceredom Discrepancy within Pull Box . Parsons' identified that Facility'1 and 2 (nonsafety channels) wiring within a pull box was found to be touching, contrary to design and licensing basis requirements. This was field wiring to the motor-driven AFW pump discharge hressure transmitters, which have no safety function.
' The licensee concluded that the slack in the wiring resulted in crossing of the two cables within the pullbox.- The licensee fixed the installation to conform to FSAR and design criteria. The team reviewed the work order and found it acceptable. In addressing extent of condition, the licensee stated that this was an unusual situation. The installation was unusual in that a pull box ) was not really necessary, and flexible conduit would normally have been used. In response to ' the team's request, the licensee addressed extent of condition by generating a database report of CRs involving separation discrepancies. The team agreed that the report indicated that this ' type of separation nonconformance appeared to be unusual.
' The team considered the corrective action to be acceptable.
2.4.2.54 (Closed) DR-0820: EQ Documentation Technical Discrepancies Parsons identified two discrepancies in the EQ documentation that it reviewed. Specifically, they identified that there was no qualification documentation for the Mobil oils and greases used in EQ applications and there was no dccumentation to support the qualification of Raychem heat shrink splices used in applications that requred qualification for submergence. In response to the first issue, the licensee obtained an analysis supported by testing that demonstrated the qualification of the Mobil products (EEQ-TRA-255.0, "EEQ-TRA For Mobil Oils and Greases, Nutech QTR XMO-01-101", dated May 1989, Revision 0). To address the second issue, the licensee issued MMOD M2-99003, " Containment Valve Relocations to Address Post-LOCA Flood Levels," which relocated the splices at issue to a location above the post-LOCA flood level so that submergence qualification was no longer an issue.
The team reviewed the licensee's corrective actions and found them acceptable.
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ep 2.4.3 Findings-Significance Level 4 DRs The team found that the licensee had generally taken appropriate actions for the Significance Level 4 DRs reviewed as explained below. For Level 4 DR items, the licensee was not required to complete the actions prior to restart. The licensee was simply required to track the items formally to closure. As noted in the discussion of DR-0056 below, the licensee had not entered all commitments in their formal tracking system.
. . 2.4.3.1 ' (Closed) DR-0056: Auxiliary Feedwater (AFW) Initiation does not meet Licensina Basis ' . The problem described in this DR was that Section 7.9.4.2 of the FSAR described the timing, for different reactor power levels, of AFW initiation with an Anticipated Transient Without Scram (ATW) event, whereas the licensee's surveillance procedures did not use the same power level values. The licensee procedures allowed for a 5 percent power deadband when power levels were changing. The licensee committed to clarify thefSAR and ti implement corrective action by. CR M2-98-1892.
' , The team considered the committed action to be appropriate. The team looked for the tracking document for the action to update the FSAR. The team noted that AR 98012735-12, written to update the FSAR, was written February 8,1999, whereas the action had been committed in October 1998. The licensee stated that they had not written ARs for all Level 4 DR committed actions at the time the commitments had been made. The responsible licensee manager stated that he intended to do a review of all Level 4 DRs before restart and to write ARs for the committed actions that had not been captured in ARs. The team noted that the licensee had not written an AR to perform this review, and that using the manager's memory to ensure the action was taken was not a formal approach. On February 16,1999, the licensee wrote AR 99002357 to track the review of all Level 4 DR committed actions. The team considered the licensee's actions to be appropriate.
2.4.3.2' - (Closed) DR-0061: Turbine Drive Auxiliarv Feedwater (TDAFW) Pumo Repair and Test , ' Deficiencisa Parsons identified that a maintenance procedure did not include a requirement to measure the clearances, following machining of the wear ring for the TDAFW pump impeller, to casing wear ring. The licensee considered that measuring the clearances was within the skill-of-the-craft.
As corrective action, the licensee committed to revise Procedura MP 2703A11, "TDAFW Pump Overhaul," to include the requirement to measure the clearances following machining of the wear ring prior to the next use of the procedure. The corrective action was being tracked by CR M2-98-3042.
The team considered the corrective action to be adequate.
2.4.3.3 - (Closed) DR-0155: Check Valve Examination and Testino Deficiencies Parsons identified a number of apparent deficiencies in the procedures goveming examination . and testing of check valves. After the licensee reviewed the examples specifed in the DR and discussed the issues with Parsons, it was agreed that Parsons' overall concem would be addressed if Procedure EN 21221, Revision 0, " Check Valve Examination and Testing," was
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s ' rev sed to prevent higher priority valves from being downgraded to Priority 4.' This issue was classified as a Significance Level 4 issue. The team verified that the licensee had entered this issue into their corrective action system (CR M2-98-2880 and AR 98312679 Task 12). In reviewing the AR and the DR, the team noted the while the DR resolution committed the licensee to revise Procedure EN 21221 as discussed above, the AR only required evaluation of the need to revise the procedure. When the difference was pointed out to the licensee, the action to be taken under the AR was changed to be consistent with the agreed upon DR resolution.
The team found the licensee's final proposed corrective actions to be acceptable.
2.4.3.4 (Closed) DR-0574: Amoscity and Electrical Fmiecticri of Control Cables - Parsons questioned the ampacity and protechon of control cables used as power cables for low-power application in the 120-Vac vital distribution system. Parsons. noted that the FSAR Table 8.7-3 identifies size #12 and #10 AWG cable ampacities of 13 amperes and 18 amperes, respectively, in's tray and 25 amperes and 34 amperes in air, based on a 90 *C insulation rating
in a 50 *C ambient temperature condition.- However, they noted that FSAR Table 8.7-1 identified this type of cable as 70 *C insulation rating. Using National Electric Code methodology, the cables would have to be derated by about 70 percent or more. They concluded that loading was not a coacem, but the electrical overload protection of the cables might not be adequate.
, in response to this concern, the licensee retrieved a May 1,1979, memo from the cable manufacturer that supported a 40-year,90 'C rating. The licensee committed to revise the FSAR (CR 98-MP2-75) to reflect the updated rating.
The team considered the corrective action to be acceptable.
2.4.3.5 (Closed) DR-0636: Use of Heat-Shrinkable Tubina as Seoaration Barrier Parsons had written DR-0636 regarding lack of separation for internal panel wiring for control relays and related DR-0441, involving acceptability of the use of heat shrinkable tubing as a separation barrier.~ Parsons closed DR-0441, since the licensee had previously identifed the issue. The licensee stated that heat shrinkable (Raychem) tubing was acceptable at the time of Millstone's original license, and that this licensing basis had not been changed.
However, the team observed that no licensing document had been submitted to NRC describing the use of heat shrir,kable tubing as a separation device. Furthermore, the team noted that - FSAR Section 8.7.3.1 described a separation device as noncombustible, whereas heatt shrinkable tubing was nonflammable, not noncombustible.
The licensee stated that the use of heat shrinkable tubing as a separation barrier for low-energy (120 Vac and 125 Vdc) control circuits was a general practice at MP2, and that other DRs might also have been closed without recognizing this deviation from the FSAC. The team did not have a safety conoom because the licensee apparently limited this application to low-energy control circuits. Additionally, the licensee had the capability to achieve safe shutdown from locations id h l . outs e t e contro room pursuant to 10 CFR 50, Appendix R, without taking credit for heat shnnkable tubing as a fire barrier.
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,.,.... . . .. , . The licensee's certification of the heat shrinkable tubing was based on IEEE Std 383-1974, "lEEE Standard for Type Test of Class 1E Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations." The IEEE Std 383 flame test requires only that the cable under test ".~.. does not propagate fire even if its outer covering and insulation have been
- destroyed in the area of flame impingement." The flame test applied to heat shrinkable tubing demonstrates that the fire self-extinguishes when the source flame is removed. This does not demonstrate that the tubing is " noncombustible."
In response to the team's concern, the licensee determined that the original FSAR did not include the reference to "non-combustible barriers," and the original design basis identified on Drawing 25203-33001, Revision 4 dated April 12,1973, item 3.3, was for "non-flammable heat shrinkable tubing." This drawing was later incorporated into SP-M2-EE-0016, but the word "non-flammable" was inadvertently omitted from the specification text and incorporated erroneously as "non-combustible"in FSAR 8.7.3.1. During the inspection, the licensee prepared FSARCR 99-MP2 48 to revise FSAR 8.7.3.1 to state that heat shrinkable tubing was non-flammable. The team concluded that FSARCR 99-MP2-48 was consistent with the original licensing and design basia, and the safety evaluation demonstrated that the change does not involve an unreviewed safety question.
The remaining part of DR-0636 adequately dispositioned the isolation capability of the relays used as isolation devices.
- The team considered the licensee's corrective actions to be acceptable.
2.4.3.6 ' (Closed) DR-0651: Backdraft Damoer 2-AC-58 Was Not Functional and There Was a Lack of Post Modification Test Results for Damoers 2-AC-1.3.57 and 58 Parsons identified a number of potential problems with maintenance and modification of - ventilation dampers. After reviewing the licensee's response to the issues, Parsons agreed that some of the issues were covered by other DRs (0412 and 0585), and others were not problems (lubrication and exercising of the dampers).
The team agreed that the valid issues in the DR were covered by other DRs and, therefore, it could be closed.
2.4.3.7 - (Closed) DR-0693: Adeauacy of Protection of a 125-Vdc Branch Circuit ' Parsons questioned the adequacy of the protection of a 125-Vdc branch circuit. They identified that a size 10 AWG conductor was protected by a 30-ampere branch circuit breaker, and that licensee Calculation 7604-E-204-3 indicated that a 20-ampere breaker was required to protect size #10 AWG conductors. In addition, FSAR Table 8.7-3 stated that the maximum ampacity for size 10 AWG conductors routed in a cable tray was 18 amperes. Parsons was concemed that . the conductor would not be protected for sustained overload conditions, and this would be a deviation from the licensing basis. The circuit serves a solenoid valve, SV 4188.
As corrective action, the licenses demonstrated that the protection was adequate and within the licensing basis. However, the calculation needed to be revised to document the acceptability of a 30-ampere breaker.- The licensee issued CR M2-98-2384 to revise calculation 7604-E-204-3
to include an analysis justifying the use of a 30A breaker (versus a 20A breaker) and to verify that the 125-Vdc branch circuit breakers and conductor sizes were in accordance with the calculation.- The licensee scheduled these actions with a Mode 4 restraint.
' - The team considered the corrective actions to be adequate.
2.4.3.8 (Closed) DR-0731: Auxiliary Feedwater System Model Development and Flow Analysis Ca!chion Discreoancies Parsons noted some discrepancies in the auxiliary feedwater system model deveicpment calculation and the auxiliary feedwater system flow analysis (1) the valve flow coefficient (Cv) utilized for valves 2-FW-43A/B was incorrect;( 2) system flow analysis had not been performed for runout flow to a faulted steam generator with one operating AFW pump. Parsons noted that because the cavitating venturis were sized for two pump flow, a single active failure of an AFW pump could cause excessive runout of the remaining pump; (3) the low-level used for the CST ' was incorrect; (4) the calculations used a maximum CST temperature of 100 *F, while the Safety Functional Requirements Manual and Procedure OP 2322 showed a maximum CST temperature of 120 *F; (5) no conclusion was reached in the calculations as to the acceptability of the NPSH available versus NPSH required at the corresponding AFW flows; (6) the use of a Reynolds coefficient of roughness for clean commercia' pipe.was nonconservative because the < surface roughness would increase due to corrosion of the carbon steel pipe; and (7) the CST pressure of 14.7 psia used in the calculations did not agree with the CST pressure in another calculation.
The licensee evaluated items (4) and (5) as nondiscrepant. Items 1,2,3,6, and 7 were , downgraded to Level 4 (Parsons agreed with the licensee's evaluation that the calculation changes were minor).
CR M2-98-2522, dated August 17,1998 was initiated for review and tracking of the necessary minor calculation changes.
'The team considered that the licensee's downgrade of the noted items was appropriate. The team considered the corrective actions to be appropriate.
2.4.3.9 - (Closed) DR-0736: Auxiliary Feedwater (AFW) Nonseismic Process Instrumentation Connected to Safety-Related PIQ!Dg { . Parsons noted that various AFW system process instruments had been classified as not safety ) related and not seismically qualified, and that the instruments did not have root valves to isolate i them from the safety-related system. Parsons noted that the instruments could fail during a seismic event and, therefore, not maintain the system's pressure boundary. Also, Parsons noted the condition had not been evaluated with a hydraulic calculation and an operator response time analysis had not been performed.
i The licensee evaluation noted that the instrumentation was located in a seismic area but was of
rugged construction, which was acceptable from a licensing basis. The licensee described ' corrective action in CR M2-98-2952, which included plans for post-startup long-term enhancements. These actions included revising specification SP-ST-ME-944 to include the
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- Electric Power Research Institute (EPRI) NP-6895, " Guidelines for the Safety Classification of
- Systems, Components, and Parts used in Nuclear Power Plant Applications."
i , The team considered the licensee's corrective actions to be adequate.
2.4.3.10 (Closed) DR-0797: Unretrievable Analysis for ATWS Pressurizer Pressure Trio Setooint -
Parsons identified that an analytical limit had not been established for the Anticipated Transient without a Scram (ATWS) high pressurizer pressure setpoir)t. Calculation 92-030-1260 E2, Revision 1,- did not include the high pressurizer pressure setpoint associated with ATWS initiation. Instrument uncertainties for the RPS trip setpoint of <2400 psia might allow the ATWS trip (2400 pala) to occur before the RPS high pressurizer pressure trip. Should this occur, failure of the primary (RPS) trip might not be readily identified. Parsons also identifiexf that electromagnetic interference (EMI) effects on instrument uncertainty had not been considered.
The licensco prepared Technical Evaluation M2-EV-98-0173, " Comparison of ATWS-DSS and
Reactor Protection System High Pressurizer Pressure Trip Points," Revision O. Also, they issued Revision 3 to Calculation 92-030-1260E2 to include the ATWS-Diverse Scram System high pressurizer pressure trip setpoint calculation and appropriate analytical limits. The evaluation and calculation noted a maximum limit of 2380 psia for the RPS trip to ensure
adequate margin existed between the RPS and ATWS trip points and to preclude the ATWS j circuit from tripping before the RPS bistable. The existing setpoint was shown to be within the ' licensing and design basis. The EMI uncertainty issue was deferred for separate resolution with , DR-0765 after restart.
The team considered the corrective actions to be adequate.
3.0 TopicalReviews . The team examined selected technical areas to provide a broader review of areas where the ICAVP had a number of discrete findings. These reviews follow.
'3.1 Electrical Seoaration and Fuse Control in the ICAVP, both Parsons and NRC identified electrical separation discrepancies that were not i in compliance with the licensing and design basis and that required corrective action. These discrepancies included separation and barrier cor, figuration of cable trays (VIO 98-202-04, - Example 1, DR-0289, and DR-0680); separation between intemal panel or enclosure wiring (VIO 98-202-08, DR-0636, DR-0441, DR-0785, and DR-0804); separation of redundant RG 1.97 indicators (DR. 0449); channel color cod ~ing (DR-0137; DR-0360, and DR-0746); and Equipment independence or isolation (DR-0636 and DR-0677).
As described in detail in the narrative for DR 0680 and DR-0785,' the licensee performed comprehensive and detailed evaluations of cable tray separation and barrier configurations and of safety-related wiring intemal to panels and enclosures. At the time of the inspection, the licensee was completing modifications of the cable tray and barrier configurations to restore the , configuration to the licensing and design basis stipulated in FSAR 8.7.3.1, " Separation," and SP-
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M2-EE-016, " Electrical Separation Specification - Millstone Unit 2," Revision 1. The licensee . placed a Mode 4 restraint on completion of the corrective actions.' The team sampled the detailed evaluations and field inspected several implemented corrective actions in the cable . vault, auxiliary building, and electrical penetration areas. The licensee had established a detailed tagging scheme to readily identify and disposition cable tray separation discrepancies.
' Based on the extent of the licensee's evaluations, rationale for corrective actions, and implementation to date, th' team concluded that the licensee was adequately addressing the e ', extent of cable tray separation discrepancies. To document this effort and help preclude recurrence, the licensee was developing drawings to document the specific barrier configurations.
In the area of separation between intamal panel or enclosure wiring, the licensee was also completing modifications to address deviations identified for intomal wiring separation to restore the configuration to the licensing and design basis stipulated in FSAR 8.7.3.1 and l SP-M2-EE-016. The licensee placed a Mode 4 restraint on completion of the corrective actions.
. The team sampled the detailed evaluationc and reviewed two FSAR CRs and the safety ' . evaluations the licensee prepared. The licensee prepared these to support six deviations to internal wiring separation criteria stipulated in FSAR 8.7.3.1 and SP-M2-EE-016, and to clarify the use of heat shrinkable tubing as a separation barrier for certain applications. The team found the detailed evaluations and implementing corrective actions to be acceptable. Also, the team found the licensee's FSAR CR technical and safety evaluation to be acceptable for . justifying an FSAR amendment to permit individually analyzed exceptions to the criteria currently stipulated. The licensee will document the acceptability of these analyses in SP-M2-EE-016.
The change to FSAR 8.7.3.1 will stipulate that the acceptability of lesser separation would be based on the degree of hazard and mitigative measures demonstrating that the effects of lesser separation do not degrade Class 1E safe shutdown circuits and equipment below an acceptable level. The licensee will evaluate any such exception to separation requirements under 10 CFR 50.59. Exceptions could not be taken between functionally redundant vital wiring or devices inside control panels.
The team found this provision for analysis acceptable and consistent with IEEE Std 384-1981, "lEEE Standard Criteria for Independence of Class 1E Equipment and Circuits," which is not a part of the Millstone 2 licensing basis but represents more current accepted industry practice.
The team reviewed the six deviation justifications documented by FSARCR 99-MP2-51 and the - accompanying technical and safety evaluations. The team found these detailed analyses acceptable because the separation between functionally redundant circuits was not compromised. The licensee will also amend FSAR 8.7.3.1 via FSAR CR 99-MP2-48 to identify that nonfiammable heat shrinkable tubing may be used where spatial separation of 6 inches is not feasible to protect intomal wiring when approaching termination to a device. To support this amendment, the licensee determined that the original FSAR had not contained the current description of "non-combustible barriers or conduit" to be used when separation of six inches could not be attained. On that basis, the team agreed with the licensee's conclusion that FSARCR 99-MP2-48 was consistent with the original licensing basis and did not involve an unreviewed safety question. On the foregoing basis, the team concluded that the licensee was adequately addressing the extent of internal panel wiring separation discrepancies.
I Regarding the separation of redundant RG 1.97 indicators, the team concluded that the licensee was adequately addressing separation of redundant Category 1 RG 1.97 indicators.
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. . Regarding channel color coding, based on review of the licensee's corrective actions for DR-0137, DR-0360, and DR-0746, the team concluded that the licensee was adequately addressing channel color coding.
Regarding equipment independence and isolation, based on review of the licensee's corrective actions for DR-0636 and DR-0677, the team concluded that the licensee was adequately addressing equipment independence and isolation.
Regarding fuse control, Parsons identified several examples of fuses that did not match the licensee's drawings and calculations of record. Based on review of the licensee's corrective actions for DR-0269 and DR-0630, presented in cetail elsewhere in this report, the team concluded that the licensee was adequately addressing corrective actions and extent of condition for fuse control discrepancies. The licensee concluded that the original fuse control program was.govemed by Engineering Department Instruction ?-ENG-3-07, which was incomplete and not controlled as a design document. The licensee attributed this to a lack of ownership and concluded that their fuse control program monitoring and evaluation had failed to j identify these discrepancies. For the discrepancies identified by Parsons in DR-0269 for fuses { used to protect electrical penetrations, the licensee prepared CCN-1 to calculation PA91-004, Reviilon 0, which showed that the as-found fuses were adequate. Fuses protecting containment electrical penetrations were of particular interest, and, for this reason, the licensee had prioritized CCN-1 as a Mode 6 restraint. The team reviewed the assumptions, methodology, and results of CCN-1 and found them to be acceptable. In DR-0630, Parsons also identified discrepancies in many fuses installed in the emergency diesel generator system.
To address extent of condition, the licensee prepared Technical Evaluation M2-EV-99-0047, " Millstone Unit 2 Fuse Control, Assessment of Current Status, including improvement Opportunities," Revision 0, which showed that the existing fuses were adequate. The licensee will verify that all installed safety-related fuses conform to controlled design documents prior to Mode 4 operation. The team found these corrective actions to be acceptable for addressing j extent of the fuse control discrepancies.
3.2 Translation of Desian Basis Calculation Assumptions into Plant Procedures Violation 50-336/98-213-01 identified examples where the design bases as described in Chapter 14 of the FSAR had not been correctly translated into plant prounmres.and acceptance criteria.
As corrective action, the licensee revised their design requirements manual to strengthen i actions required for new calculations, to ined personnel, and updated and verified the accuracy ' of their design basis document, the SFRM. The SFRM identified and documented key system requirements that were reflected in the safety analyses performed for Chapter 14 of the FSAR.
The SFRM also provided the licensee staff with a design basis document to use when evaluating the impact of plant changes on the related-safety analysis. Technical Evaluation M2- , EV-99-0039, " Technical Evaluation For SFRM inspection," dated February 26,1999, and M2-EV-99-0027, " Review and Assessment of the SFRM," dated February 5,1999, described the reviews conducted by the licensee to validate the SFRM.
Additionally, violation 50-336/98-202-05, detailed earlier in this report, concerned a failure to have operating procedures consistent with the setpoint analysis for a radiation monitor.
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/ Technical Evaluation M2-EV-99-0027 docurnented the review of 50 safety-relatt.d systems that had undergone various changes as a result of the licensee's CMP and the resultant modifications.~ The review verified that any accident analysis parameters changed by the modifications were correctly reflected in the SFRM, FSAR, Design Basis Summarys (DBSs), calculations, and the TSs. The review identified discrepancies between the documents and the licensee issued condition reports to correct the discrepancies. The team reviewed the discrepancies identified by the licensee's review and concluded that they were not significant.
l To validate the accuracy of the SFRM, the team selected a sample of five items from the SFRM i for review. The review concluded that the five items were properly implemented into l procedures.- The team identified one discrepancy during this review, but the discrepancy was not associated with the SFRM. One of the specific minimum flow rates for the auxiliary feedwater motor-driven pumps listed in the SFRM had not been validated by preoperational testing. The licensee issued AR 99003187 to ensure that the minimum AFW flow rate would be validated befpre unit operation. The team considered that the corrective action was acceptable.
Also, the team selected 35 additional parameters from the SFRM and requested that the licensee verify that they were properly implemented into plant procedures. The licensee reviewed the 35 items and found thht one of the 35 items was not properly translated into procedures. The SFRM listed 50 'F as the minimum CST temperature and the plant i surveillance procedures listed 45 *F as the minimum CST temperature. The licensee concluded that this discrepancy did not adversely effect any safety conditions because the reactor core analysis conservatively assumed a CST temperature of 32 'F. The team noted that the purpose of the 45 *F requirement in the operations procedures was to instruct operators to energize heat trace to preventing freezing during cold weather conditions and the team concluded that. energizing heat trace at 45 'F in lieu of 50 *F was not a significant concern. The results of this review are documented in TE M2-EV-99-0039.
As a result of the first sample, the licensee selected an additional eight parameters from the SFRM for review. The parameters selected were similar to the discrepancy associated with the CST temperature in that they represented system conditions that were not specified in TSs. The results of this review indicated that the eight items were properly implemented into station procedures. The results of this review were documented in TE M2-EV-99-0039.
Incependently and concurrent with the above 6escribed efforts, the licensee's oversight personnel had selected a sample of 12 items from the SFRM for review. Their review identified one item that had not been properly incorporated into procedures. The SFRM listed that the minimum containment air recirculation (CAR) fan flow rate was 34,800 cubic feet per minute (cfm), which was based on Calculation 97-040, Revision 1.. Another calculation, Calculation 97-120, Revision 0, listed a different minimum CAR fan flow rate as 38,280.
' Procedure EN 210631, " Containment Air Recirculation System Ventilation Test," Revision 4, verified CAR fan flow to be between 34,800 and 38,280. The licensee concluded that this discrepancy was not significant because the differences between the two CAR flow rates did not significantly affect the heat transfer rate and, therefore, did not adversely affect containment temperature. The licensee issued CR-99-0882 was issued to correct this discrepancy. The results of this review were documented in TE M2-EV-99-0039.
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E Additionally, the team reviewed the improvements made to the DCM, Revision 6, Change 11.
The change instructed licensee personnel to review the SFRM during the plant modification process to ensure that FSAR Chapter 14 safety analysis assumptions were properly maintained.
The licensee briefed procedure writers on the SFRM and the need to ensure that implementing procedures were consistent with the parameters listed in the SFRM.
The team concluded that the licensee's actions to ensure that design basis calculation assumptions were properly translated into plant procedures had been adequate. The team also . concluded that the changes made to the design control manual and enhanced use of the SFRM should improve the licensee's performance in ensuring that plant procedures and acceptance - are consistent with safety analysis assumptions, and also should improve the interface among the nuclear engineering, design engineering, and technical support engineering organizations.
3.3 Commercial Grade Dedication Prooram l NRC Inspection Report 50-336/98-201, dated August 12,1998, discussed the results of the i NRC review of four commercial-grade dedications. This review identified c violation - (VIO 50-336/98-201-8) involving the installation of non-QA bushings in the safety-related switchgear for the C service water pump. The corrective action for this violation is discussed earlier in this report. Additionally, Parsons Engineering, the ICAVP independent contractor, i I reviewed 126 commercial grade dedication items, and the results of this review were documented in DR-0076. DR-0076 was classified as a confirmed Significance Level 4 condition, meaning the findings were valid but were of a minor nature. The reviews conducted by NRC and Parsons did not identify any equipment operability concerns. The team noted that the NRC identified violation and the majority of the discrepancies identified by the ICAVP - independent contractor were historical in nature in that they occurred before 1992.
The team noted that NRC Inspection Report 50-336/91-201, dated November 5,1991, documented the results of the 1991 NRC inspection of the licensee's program for the - procurement and dedication of commercial-grade items used in safety-related applications. This inspection concluded that the commercial-grade dedication program required increased J attention. Items identified during the inspection included procedural weaknesses, as well as implementation weaknesses, concoming the identification of appropriate design critera, safety functions, critical characteristics, and methods for verifying the critical characteristics. To evaluate further the extent of these weaknesses, the licensee performed a review of 143 commercial-grade items previously procured and installed at all three Millstone Units. After ' completing this review, the licensee determined that no operability concems existed, although some discrepancies were noted. Since no operability concems were identified by NRC or the licensee during the reviews of the commercial-grade dedication items, the licensee concluded that it was not necessary to review additional items. At that time, the licensee committed to implement changes to improve the commercial grade dedication process.
For this inspection, the team concluded that the licensee had satisfactorily addressed the discrepancies identified in DR-0076, and that the historical issues identifed in the DR were consistent with previous NRC and licensee findings.
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3.4 Review of Hioh Enerav Line Break (HELB) Prooram inside Containment The team reviewed the licensee's analysis applicable to the postulated HELB interactions inside L containment. The review included various documents applicable to HELB interactions, including ' licensee technical evaluations, submittals to the NRC, and one modification.
, The licensee's actions included performing screening evaluations and walkdowns of closed-loop systems inside containment. The licensee evaluated the systems for the potential for loss of containment isolation. - Previously, the licensee had studied the reactor building closed cooling water (RBCCW) system in response to Information Notice (lN) 89-55. The closed loop systems reviewed were addressed by licensee memorandum EN2-89-218, dated September 28,1989, " Loss of Containment Isolation Capability By a High Energy Line Break (HELB)." The evaluation identified unacceptable HELB interactions with 12-inch safety injection lines,12-inch shutdown cooling lines,12-inch pressurizer surge line, and the %-inch steam a generator blowdown sampling line.
. The licensee resolved the safety injection and shutdown cooling lines by applying ' leak-before-break (LBB) methodology, which was approved by a NRC safety evaluation. The steam generator blowdown sample line was resolved by issuing Modification DM2-00-1862r98 to relocate the steam generator line. The pressurizer surge line was resolved by submitting a i . request for the use of LBB methodology to the NRC.
j , The team found the licensee's corrective actions for the HELB interactions inside containment and the overall HELB program inside containment to be acceptable.
"3.5 Calculation Proaram - The team reviewed the licensee's program and procedures for performing calculations. The review included issues raised in Parsons letter, " Millstone Unit 2 Independent Corrective Action Verification Program (ICAVP)," dated January 1999, and the licensee's response letter B17614, ' . dated February 3,1999.
Parsons noted that some calculations had errors and invalid or undocumented assumptions.
Additionally, Parsons noted some inconsistencies between the licensing design basis and the engineering design basis. The inconsistencies included QA classifications and pressure boundary classifications. They also noted that some calculations and other plant records that supported the licensing design basis could not be readily identified or retrieved by the licensee.
Based on the number of Significance Level 4 discrepancy reports that were issued, Parsons ' concluded a trend that showed the processes for controlling calculations and analyses needed
to consider the cumulative effects of incremental changes. They noted that the DCM was silent on the need to document or track small incremental changes which individually can be judged to . be insignificant but collectively, over time, could exceed allowable limits.
The licensee response to the issues was provided in letter B17614 to NRC, dated February 3, 1999. The letter noted that errors and undocumented assumptions identifMxi for historical . calculations were being corrected. The licensee noted that a quality review board (QRB) was formed in July 1998, to review calculations for technical accuracy, assumption validity, and c reasonable inputs and outputs. The licensee noted that the QRB had proved to be effective in
. , proactively identifying errors and undocumented assumptions in ongoing work. Furthermore, the licensee noted that system level calculations had been brought up to current standards and tracked in a database). The DCM required cross-referencing of calculations, and the performance of that requirement was being checked as an ongoing practice by the QRB The .. licensee noted that the calculation control requirements in the DCM had been improved. Also,
- they noted that they were identifying and tracking key calculations. Key calculations identified the relative importance of a particular calculation with respect to key systems or the unit design bases. The licensee also noted that they had established rules for key calculations that limited
' the number of outstanding changes that could be issued before a revision must be processed.
. They added calculation status definitions for' installation Verified" and "On-Hold" (approved but not installed). In addition, the licensee noted that safety system design basis and licensing basis information had been recovered in accordance with their configuration management program (CMP). They also had initiated a program of system reviews, using a multidisciplined review group, to verify the completeness of calculation cross-references. Further, the licensee noted that they had begun a program of producing system design basis summary documents. They had,'in their initial response to DR-060g, provided a detailed description of configuration management controls that they believed adequately ensured that incremental changes would be tracked for cumulative impact on plant structures, systems, and components. The licensee noted that additional corrective action, to revise the DCM to more completely address the issue, was in progress.
The team reviewed the licensee's calculation program including the DCM, Chapter 5, Revision 6, Change 11, " Calculations," and the Quality Review Board functions described in memorandum MPA-98-29, Revision 7, dated December 7,1998, " Quality Review Board."
Additionally, the team sampled three calculations in the Passport documentation program. The team examined the ESAR 97-043, dated May 24,1997, " Calculations." Additionally, the team reviewed the list of key calculations in 25203-ER-0150, Revision 0, dated January 28,1999, j " List of Key Calculations." The team also reviewed CR M2-97-0829, dated May 20,1999, applicable to the technical adequacy and configuration control of calculations, and CR M2-98-3392, dated November 13,1998, applicable to the cumulative effects of incremental changes.
The licensee had revised the DCM to specifically address the effect of incremental changes and provided examples such as diesel generator loading, fire zone combustible loadings, and the cutting of reinforcing bar in structural concrete.
The team concluded that the licensee's calculation program was adequate.
3.'6 Vendor Information Control The team reviewed portions of the licensee's programs that control the use of technical information provided by equipment manufacturers (vendors). The program issues associated with control of vendor information, such as the Key Safety-Related Equipment List (KSREL) and Revision 1 of Station Procedure DC-16, " Vendor Technical Information Program," are being . reviewed by the NRC Resident Teams in conjunction with Significant items List (SIL) issue t - 50. The completion of that review, along with the review summarized below, will provide sufficient basis for concluding that the issues raised in Section 5.2.8 " Vendor Equipment -
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Technical Information Program" (page 5-21) of Parsons " Millstone Unit 2 Independent Corrective Action Verification Program Final Report". Revision 1, dated January 12,1999, (summarized in Section 1.4.3, item 3 of that report), have been adequately addressed.
The team first reviewed the DRs that formed the basis for the Parsons comments on control of ' vendor information and the licensee's letter to NRC dated February 3,1999, responding to the ' report's findings.
The team's look at the corrective actions being taken to resolve the individual DRs indicated that the licensee was taking appropriate action on those issues.- The Parsons question, conceming the level of detail required in vendor manuals was a recurring issue in the Parsons DRs. That issue was summarized in the last paragraph of Section 5.2.8 of the Parsons report. Looking at the DRs identified by Parsons, the team noted that a number of them documented the j comparison of manuals supplied by different vendors of similar equipment, noting discrepancies ' in the level of detail from one manual to the next.
i ~ The team considered that, although it may be desirable for all manuals to have a certain level of detail, nothing in Generic Letters (GL) 83-28 or 90-03 require a specific level of detail in vendor manuals. Vendors supply manuals that provide what the vendors consider to be a reasonable level of detail about the operation and maintenance of the supplied equipment. As stated in GL 90-03, a vendor program that covers every safety-related component is not considered practical. The team noted that the licensee's approach was to ensure that all information received from the vendors was incorporated into the appropriate vendor manuals, and that the vendor information was, in tum, evaluated for inclusion in plant proce(. es. The licensee stated that its position was that if it became necessary to repair or replace a component that did i not have sufficient information in its vendor manual, the licensee would then seek sufficient information and incorporate it into the vendor manual. The team considered the licensee's , approach to be acceptable.
In the licensee's response to the Parsons final report, the licensee credited the improvements . made in procedure DC-16, Revision 1, for addressing most of the other issues raised by the report. As stated earlier, the adequacy of the programmatic aspects of the Vendor Control Program are being reviewed under the SIL 3.7 Drawina Control The team examined information relevant to the concem stated in the Parsons final report concoming drawings that were being changed to match the as-found plant configuration without i documenting a determination of whether the plant configuration, the drawing, or some other document correctly reflected the approved design. In its February 3,1999, response to the ' Parsons report (Attachment 1 page 13-4), the licensee acknowledged that there was a documentation weakness in its configuration management work process. The licensee noted , _
that there was no explicit requirement to reference the design basis documents used when making a drawing change for a Category 8 (administrative) DCN. ' Consequently, in the many
cases where drawings had been properly updated to reflect an as-built condition that was also an approved design detail, it could have appeared that the drawings were simply changed to match the as-built configuration. In an effort to substantiate that the Parsons observation was, in fact, only a documentatum issue, the licensee performed the self-assessment referred to in its ,
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i response to the Parsons report. The team reviewed that self-assessment entitled, " Review of DCNs Not Related to a Parent Design Document" (Assessment Number U2-DE-98-014). The assessment concluded that the problem was simply one of documentation. The team questioned the validity of the licensee's conclusion, which was supported by only a small sample of Category 8 DCNs. However, the licensee stated that a similar assessment had been done on Unit 3 using a much larger sample. The team concluded that the licensee had adequately supported its conclusion.
Additionally, the licensee made a number of procedural changes to address this documentation weakness. As discussed in the licensee's response to the f' arsons final report, Design Control Manual (DCM) Chopter 3, Section 7.2.12, required that the proper reference to design f documents be provided to document the basis for a change incorporated via a Category 8 DCN.
{ in addition, Millstone 2 design engineering issued its Standard Guide 97-08, Revision 1, which ' reiterated the DCM requirement. Given the procedural enhancements, the team concluded that adequate controls were in place to ensure that, when drawings were updated to match an as-built configuration, the basis upon which that update made would be documented.
3.8 EnvironmentalQualification Parsons' review of the Unit 2 environmental qualification (EQ) program was limited because, at ) the time of its review, the equ!pment qualification records (EQR), the associated test report assessments (TRA), and the calculations necessary to support the qualification of much of the plant equipment were under revision and incomplete. Similarly, when NRC performed its Tier 1 and Tier 2 and 3 Independent Corrective Action Verification Program (ICAVP) inspections, some findings related to EQ were made, but no extensive review of the program was undertaken as the program was still being extensively revised.
I Since that time, the licensee has completed much of the remaining work in the EQ area. The licensee now has more than 90 EQRs to support the qualification of more than 600 plant components. Extensive walkdowns and inspections of the components in the program were completed, and the licensee brought in a consultant to review its efforts. With the progress the licensee made on the EQ program, NRC undertook two efforts to assess the readiness of the program to suppoit plant startup. First, under SIL ltem No.19, a review of the program was undertaken along with an evaluation of some specific findings in the EQ area. The results of those efforts will be documented in an NRC resident inspector report. Second, as part its corrective actions review effort, NRC's ICAVP team reviewed certain specific EQ-related ' findings to ascertain the effectiveness of corrective actions under the EQ program. The results of that review are discussed below.
Before reviewing any specific EQ findings, the team reviewed the Parsons discussion of EQ, which is on pages 3-88 and 3-89 of its " Millstone Unit 2 Independent Corrective Action Verification Program Final Report.". Of the three DRs mentioned in the discussion, the team chose to review DR-0820, which was the only Significance Level 3 DR of the group. The DR identified that the licensee did not have documentation to support the use of Mobil oils and greases in EQ applications and did not have documentation to support the use of Raychem heat shrink splices in submergence applications. The team found the licensee's corrective action for i that DR to be adequate. Other EQ-related findings examined by the team included Unresolved Items 50 336/98-204-03 and 04 as well as related licensee CR 98-2503. These items all
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) . involved the lack EQ qualification for AFW system components and support system components in the turbine building. The team found the licensee's corrective actions on the items to be ' adequate.- Detailed discussion of the closuie of the items and the related actions that remain to - be completed can be found in Section 2 of this report.
Given that the corrective actions for identified deficiencies in the EQ program were being resolved adequately, the team concluded that, with satisfactory completion of the review ofitems under the Sll, the Unit 2 EQ program will be acceptable to support plant startup.
!4.0 ~ Conclusion Overall, the team found that'NNECO's implementation of corrective actions during the CMP was acceptable in that conditions adverse to quality were identified and corrected in accordance with c Criterion XVI, " Corrective Action," of Appendix B to Title 10, Part 50, [ Code of Federal Regulations (10 CFR Part 50)].- Generally, the team found that the corrective actions were adequate. Generally, the root cause evaluations were comprehensive, the extent of the problem was adequately explored, and the corrective actions matched the root causes and the extent of condition.
The team examined the areas characterized as trends by Parsons Power Group, the independent ICAVP contractor. In their final report, they had characterized potential trends in
the areas of calculation controls and accuracy, and drawings and component information. The types of errors identified in these trends, even when viewed collectively, did not suggest that an expansion of the ICAVP scope would likely have identified errors that would call into question conformance with the design and licensing bases.
During this inspection, the NRC staff determined that NNECO has taken effective corrective actions for ICAVP Significance Level 3 findings identified by the NRC and the ICAVP contractor, and that these corrective actions represented an appropriate expansion of the scope of NNECO's CMP and provided confidence that similar issues, if present, would likely have been found. Therefore, expansion of the ICAVP scope was not warranted.
5.0 Entrance and Exit Meetinas After completing the onsite inspection, the team leader conducted an exit meeting with the licensee on March 18,1999.. The meeting was open for public observation. Appendix B presents a partial list of persons who attended the exit meeting.
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i-Appendix A - Sumrnary of Inspection Results Violations identified During the inspection . 5 'f [ [[j [[ .[[ T )dg[NfMi{gy' 50-336/98-219-01' NCV-URI 2.1.2.14 closed FSAR not updated for PAM j i 50-336/98-219-02 .NCV New Item 2.1.2.21 closed Failure to implement Adequate Corrective Actions for RBCCW Rad Monitor d 50-336/98-219-03 ~ NCV URI 2.1.2.25 closed Failure to implement Adequate Corrective Actions for CAR Cooler ' 50-336/98-219-04 NCV URI 2.1.2.42 closed inadequate Procedure for TDAFW Main Steam Valve 50-336/98-219-05 Enf Discr.
Licensee 2.3.2.6 closed Failure to Test AFW pump per TS Identified 50-336/98-219-06 Enf Discr.
Licensee 2.3.2.7 closed Failure to Test HPSI Valve per TS Identified ' 50-336/98-219-07 Enf Discr.
Licensee 2.3.2.10 closed Failure to Test ESFAS per TS Identified 50-336/98-219-08 Enf Discr.
Licensee 2.3.2.11 closed Failure to Revise TS for TSP Volume , Identified 50-336/98-219-09 Enf Discr.
Licensee 2.3.2.12 closed EDG Sightglass not Seismic i Identified ' 50-336/98-219-10 Enf Discr.
Licensee 2.3.2.13 closed Failure to Test Purge Valves per TS Identified 50-336/98-219-11 Enf Discr.
Licensee 2.3.2.16 closed Failure to Analyze HELB in Identified Containment 50-336/98-219-12 Enf Diser.
Licensee 2.3.2.21 closed Removal of SUR Trip without Identified Adequate Analysis 50-336/98-219-13 IFl New Item 2.4.2.14 open ESF Pump Room B Enhancement 50-336/98-219-14 Enf Discr.
Licensee 2.4.2.19 closed Failure to Maintain Cable Tray j Identified Separation
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/ Appendix B - Exit Meeting Attendees NNECO Attendees NAME ORGANIZATION Michael Ahern Manager, MP2 Design Engineering Martin Bowling Recovery Officer Joe Fougere Manager, ICAVP K. Gilligan MP2 Liaison, Nuclear Communications Paul Grossman Director, MP2 Engineering Gary Komosky Lead Engineer, MP2 ICAVP Fred Mattioli Supervisor!MP2 ICAVP Harry Miller Director, Regulatory Affairs > Raymond Necci Vice President, Nuclear Oversight and Regulatory Affairs J. Price MP2 Unit Director Steve Waino MP2 Design Engineering NRC Attendees Eugene Imbro Director, ICAVP, NRR > Peter Kottay Chief, ICAVP, NRR John Nakoski ICAVP, NRR i Paul Narbut Team Leader, ICAVP, NRR B-1
Appendix C - List of Acronyms . AC Alternating Current 'ACR Adverse Condition Report AFAIS Auxiliary Feedwater Automatic initiation Signal-AFW Auxiliary Feedwater System AOP - Abnormal Operating Procedure AR Action Request ARP ' Abnormal Response Procedure , 'ASME American Society of Mechanical Engineers - ATWS ' Anticipated Transient without a Scram AWO Automated Work Order CAR ' Containment Air Recirculation CCN Calculation Change Notice e i ' ' CDC Critical Design Characteristic CEA.
Control Element Assembly CEDM Control Element Drive Mechanism cfm cubic feet per minute i CFR Code of FederalRegulations ' CMP Configuration Management Plan CR Condition Report CRACS Control Room Air Recirculation System CS Containment Spray CST Condensate Storage Tank ' DBDP.
Design Basis Documentation Package DCM Design Control Manual DCN ' Design Change Notice DCR Design Change Record DR _ Discrepancy Report EAR Engineering Assessment Report ECCS Emergency Core Cooling System q EDG Emergency Diesel Generator eel Escalated Enforcement item EOP Emergency Operating Procedure EQ Environmental Qualification ERC Engineering Record Correspondence ESF Engineered Safety Feature ESFAS Engineered Safety Feature Actuation System FSAR Final Safety Analysis Report FSARCR Final Safety Analysis Report Change Request GDC General Design Criterion C-1 ,
. , ICAVP.
Independent Corrective' Action Verification Program IFl . Inspector Followup Item !
IN.
Information Notice
IR : ' Inspection Report ISFR integrated System Functional Review . IST - Inservice Test q 'LCO - Limiting Condition for Operation LER Licensee Event Report i LOCA Loss-of-Coolant-Accident LOP Loss-of-Power j l MMOD Minor Modification MOV Motor-Operated Valve - MSIV - Main Steam isolation Valve - q MSLB Main Steam Line Break j , M&TE Measuring and Test Equipment - NCV - Noncited Violation
NNECO.
Northeast Nuclear Energy Company NPSH Net Positive Suction Head . NRC U.S. Nuclear Regulatory Commission NSSS Nuclear. Steam System Supplier-PDR Public Document Room PMMS Production Maintenance Management System PM Preventive Maintenance.
( .OP Operations Procedure QSS Quench Spray System i RCP Reactor Coolant Pump , RCS Reactor Coolant System-RHR-Residual Heat Removal System RSS.
Recirculation Spray System RSST Reserve Station Service Transformer RWST Reactor Water Storage Tank- , ( l S&L-Sargent & Lundy - SGTR-Steam Generator Tube Rupture SI Safety injection S!L Significant items List SLCRS
- : Supplementary Leak Collection and Release System SP.
Surveillance Procedure _ . SRSS.
~ Square root of the sum of the squares SW Service Water C-2 < i
a k
' TDAFWP Turbine Driven Auxiliary Feedwater Pump . . TRM Technical Requirements Manual TS - Technical Specification TSC-Technical Support Center URI. Unresolved item USQ.
Unreviewed Safety Question - ' VIO Violation .
9 s + ' C-3 v . =.
- _
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