IR 05000275/1992031
| ML20059C877 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 08/21/1993 |
| From: | Richards S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| References | |
| OLA-2-I-MFP-105, NUDOCS 9401060171 | |
| Download: ML20059C877 (26) | |
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/i NUCLEAR REGULATORY COMMISSION "1I i
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REGION V
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1450 M ARl A LANE cum CREEK CAUFORNIA 945% 5%e '93 C 28 "6 :17 h December 11, 1992 l
Pacific Gas and Electric Company i Q"y Nuclear Power Generation, Bl4A i 77 Beale Street, Room 1451
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P. O. Box 770000 ,
San Francisco, California 94]77 i
k Attention: Mr. G. M. Rueger, Senior Vice President and General Manager i
Nuclear Power Generation Business Unit ,
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't Subject: NOTICE Of VIOLATION
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NRC INSPECTION REPORT N05. 50-275/92-31 AND 50-323/92-31 h This refers to the routine inspection conducted by D. Corporandy, J. Melfi, ke Miller, 9, C.199 Myers, ad 8. Olson during the period frc~ Scptember 29 through hovember f This inspection examined your activities as authorized by
' NRC License Nos. DPR-80 and DPR-82. At the conclusion of the inspection, the inspectors discussed their findings with members of the PGAE staf Areas examined during this inspection are described in the enclosed inspection h repor Within these areas, the i"spection consisted of selective
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examinations of procedures and representative records, interviews with personnel, and observations by the inspector ! Based on the results of this inspection, it appears that certain of your activities were not conducted in full compliance with NRC requirements, as set l ' forth in the enclosed Notice of Violation (Notice), and in the enclosed inspection report (Paragraph fa. In Octrber 1991, at the close of the Unit 2
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outage, you correctly identified and reported an inadequate program to control j loose material in the Unit 2 containment. However, NRC inspectors identified
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l similar materials in the Unit I containment at the close of the Octrber 1992
' outage, indicating that your corrective actions had not ac ressed this weakness in a sufficiently comprehensive manner. Before completion of this
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inspection, the inspectors confirmed that your organization has taken or initiated corrective actions which satisfactorily address this concern before the next scheduled outage. Consequently, a written response to the enclosed Notice is not required.
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A non-cited violation was also noted, involving documentation and periodic verificstion of jumpers, as discussed in Paragraph 13 of the enclosed repor Since the criteria of the NRC Enforcement Policy were satisfied, this
violation was not cite An area of noteworthy strength was identified. Concerning outage safety, your Unit I shutdown safety requirements appeared to have been well developed and implemente Operations and outage management appeared to have maintained a l
' very high level of safety system availability and configuration control during the outage. You are encouraged to maintain this high level of safet .
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p"*% UNITED STATES RECEIVED v
? 4 NUCLEAR REGULATORY COMMISSION NUCLEAR REGULATORY
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%, ,f WALNUT CREEK, CAUFOnNIA 94596-5368 DE 161992
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December 11, 1992 M HD DISTRIBUTION CHRON I RMS ONLY Pacific Gas and Electric Company .
Nuclear Power Generation, B14A l 77 Beale Street, Room 1451 i P. O. Box 770000 San Francisco, California 94177 !
Attention: Mr. G. M. Rueger, Senior Vice President and General Manager Nuclear Power Generation Business Unit Subject: NOTICE OF VIOLATION NRC INSPECTION REPORT NOS. 50-275/9?-31 AND 50-323/92-31 This refers to the routine inspection conducted by D. Corporandy, J. Helfi, M. Miller, C. Myers, and B. Olson during the per;od from September 29 through November 9, 1992. This inspection examined your activities as authorized by NRC License Nos. DPR-80 and DPR-82. At the conclusion of the inspection, the inspectors discussed their findings with members of the PG&E staf Areas examined during this inspection are described in the enclosed inspection repor Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observations by the inspector Based on the results of this inspection, it appears that certain of your activities were not conducted in full compliance with NRC requirements, as set forth in the enclosed Notice of Violation (Notice), and in the enclosed inspection report (Paragraph 6). In October 1991, at the close of the Unit 2 outage, you correctly identified and reported an inadequate program to control loose material in the Unit 2 containment. However, NRC inspector:, :dentified s.milar materials in the Unit I containment at the close of the October 1992 outage, indicating that your corrective actions had not addressed this weakness in a sufficiently comprehensive manner. Before completion of this inspection, the inspectors confirmed that your organization has taken or initiated corrective actions which satisfactorily address this concern before the next scheduled outage. Consequently, a written response to the enclosed Notice is not require A non-cited violation was also noted, involving documentation and periodic verification of jumpers, as discussed in Paragraph 13 of the enclosed repor Since the criteria of the NRC Enforcement Policy were satisfied, this violation was not cite An area of noteworthy strength was identifie Concerning outage safety, your Unit I shutdown safety requirements appeared to have been well developed and implemented. Operations and outage management appeared to have maintained a
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very high level of safety system availability and configuration control during the outag You are encouraged to maintain this high level of safety.
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200501 In accordance with 10 CFR 2.790(a), a copy of this letter ar.d the enclosures will placed in the NRC Public Document Roo Should you have any questions concerning this inspection, we will be pleased to discuss them with yo
Sincerely, Se ,~ -O S. A. Richards, Acting Chief Reactor Projects Branch
Enclosures:
Notice of Violation Inspection Report Nos. 50-275/92-31 and 50-323/92-31
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REGION V==
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Report Hos: 50-275/92-31 and 50-323/92-31 Docket Nos: 50-275 and 50-323 License Nos: DPR-80 and DPR-82 Licensee: Pacific Gas and Electric Company Nuclear Power Generation, B14A 77 Beale Street, Room 1451 P. O. Box 770000 San Francisco, California 94177 Facility Name: Diablo Canyon Units 1 and 2 Inspection at: Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted: September 29 through November 9, 1992
Inspectors: M. Miller, Acting Senior Resident Inspector B. Olson, Resident Inspector D. Corporandy, Project Inspector J. Melfi, Resident Inspector, Trojan C. Myers, Reactor Inspector (Paragraph 15)
Approved by: Jw # Dh '/ P. Jphpson, Chief Date Signed Reactic Projects Section 1 Summary: ,
InSp_ection from September 29 through November 9.1992 (Report Nos. 50-275/92-
_31 and 50-323/92-311 areas Inspected: The inspection included routine inspections of plant opera- l tions; maintenance and surveillance activities; followup of onsite events, open items, and licensee event reports (LERs); and selected independent !
inspection activitie Inspection Procedures TI 2515/20, 37700, 41701,~61726, !
62703, 71500, 71707, 71710, 90712, 92700, 92701, and 93702 were used as '
guidance during this inspectio Safety issues Manaaement System (SIMS) Items: TI 2515/20, inspection of l Anticipated Transient Without Scram (ATWS) system, was closed for Unit Results General Conclusions on Strenaths and Weaknesses Strengths:
Operations and outage management maintained a high level of awareness and control of safety system availability during the Unit 1 outag l
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Weaknesses were identified in:
- Containment cleanliness at the close of the Unit 1 outage, as well as failure to fully correct the weakness identified .a the earlier Unit 2 outage (Paragraph 6).
- Lack of a drainage path from relief valve tailpipes which could collect condensation (Paragraph 12).
- Lack of attention to detail in periodic walkdown and review of plant temporary jumper logs (Paragraph 13).
Sionificant Safety Matters:
None Summary of Violations:
- A violation was identified involving inadequate corrective actions to ensure containment cleanliness while in Mode 4 after an outage (Paragraph 6).
A non-cited violation was identified, involving failure to follow procedures concerning periodic walkdowns and reviews of jumpers (Paragraph 13).
Open Items Summary:
One item was opened and 15 items were close i l
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' 2005C1 DETAILS i Persons Contacted I i
Pacific Gas and Electric Company G. M. Rueler, Senior Vice President and General Manager, ,
Nuc: car Power Generation Business Unit l
- J. D. Townsend, Vice President and Plant Manager, Diablo Canyon Operations W. H. Fujimoto, Vice President, Nuclear Technical Services
- D B. Miklush, Manager, Operations Services
- B. W. Giffin, Manager, Maintci.ance Services W. G. Crockett, Manager, Technical Services J. E. Holden, Instrumentation and Controls Director W. D. Barkhuff, Quality Control Director
- R. P. Powers, Manager, Support Services T. L. Grebel, Regulatory Compliance Supervisor
- J. S. Bard, Mechanical Maintenance Director H. J. Phillips, Electrical Maintenance Director J. A. Shoulders, Onsite Project Engineer
- D. A. Taggart, Director, Quality Performance and Administration
- S. R. Fridley, Operations Director T. A. Moulia, Assistant to Vice President, Diablo Canyon Operations M. R. Tresler, Project Engineer
- D. A. Moon, Regulatory Compliance Engineer
- R. L. Thierry, Regulatory Compliance Senior Engineer
- L. R. Collins, Senior Quality Assurance Supervisor
- D. R. lampert, Outage Management Coordinator
- * P. McLane, Outage Director
- O. Sommerville, Senior Health Physics Engineer
- J. Griffin, Onsite Engineering Group Leader
- R. Groff, Technical Services Assistant Manager
- T. Rapp, Onsite Safety Review Group Chairman
- Burgess, System Engineering Director
- Denotes those attending the exit intervie The inspectors interviewed other licensee employees including shift supervisors, shift foremen, reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, and quality assurance personne . Doerational Status of Diablo Canyon Units 1 and 2 During this inspection period, Unit 1 completed its fifth refueling outage and achieved criticality on the last day of the inspection perio Unit 2 operated at 100% power for the entire report period.
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3. Operational Safety Verification (71707) General During the' inspection period, the inspectors observed and examined activities to verify the operational safety of the licensee's facilit The observations and examinations of those activities were conducted on a daily, weekly or monthly basi On a daily basis, the inspectors observed control room activities to verify compliance with selected Limiting Conditions for Operation (LCOs) as prescribed in the facility Technical Specifications (TS).
Logs, instrumentation, recoroci traces, and other operational records were examined to obtain information on plant conditions and to evaluate trends. This operational information was then evaluated to determine whether regulatory requirements were satisfied. Shift turnovers were observed on a sampling basis to verify that all pertinent information on plant status was relayed to the oncoming crew. During each week, the inspectors toured accessible areas of the facility to observe the following:
(1) General plant and equipment conditions (2) Fire hazards and fire fighting equipment (3) Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures (4) Interiors of electrical and control panels (5) Plant housekeeping and cleanliness (6) Engineered safety features equipment alignment and conditions (7) Storage of pressurized gas bottles The inspectors talked with control room operators and other plant {
personnel. The discussions centered on pertinent topics of general l
plant conditions, procedures, security, training, and other aspects of the work activitie Radioloaical Protection The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being ;
implemented in conformance with facility policies and procedures and 1 in compliance with regulatory requirements. The inspectors verified l that health physics supervisors and professionals conducted frequent '
plant tours to observe activities in progress and were aware of significant plant activities, particularly those related to radio-logical conditions and/or challenges. ALARA considerations were found to be an integral part of each RWP (Radiation Work Permit).
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< 2005C1 Physical Security Security activities were observed for conformance with regulatory requirements, implementation of the site security plan, and administrative procedures, including vehicle and personnel access screening, personnel badging, site security force manning, compensatory measures, and protected and vital area integrit Exterior lighting was checked during backshift inspection Safety System Availability Durina Unit 1 Outaae During the Unit I refueling outage, the inspectors observed that the licensee's program to control the availability of safety systems appeared to be highly effective. The availability of safety systems such as emergency diesel generators, the auxiliary saltwater system, and other safety significant systems was well coordinated and controlled. This control appeared to have assured that the maximum number of redundant systems were available while work was done on the remaining systems. Also, a high level of plant staff awareness and system availability were maintained during higher risk operations, such as mid-loop operations. An NRC team inspection of outage safety control was also conducted, as discussed in pending NRC Special Inspection Branch Inspection Report No. 50-275/92-20 No violations or deviations were identifie . Onsite Event follow-un (93702) Crackina of Containment Fan Cooler Unit (CFCU) Backdraft Damper Dld Summary:
During the Unit 1 outage, the licensee identified that cracking had occurred in some of the blades of the Unit 1 CFCU backdraft damper The licensee assessed the safety significan of the cracking, developed an operability assessment for Unit 2, and performed visual inspections of the Unit 2 backdraft damper blades (Unit 2 was operating). The licensee identified two cracked blades in Unit The cracked blades which had been identified were removed from Unit 2 on November 10, 199 Time line:
9/25/92 Three cracked blades were identified in Unit 1 CFCU dampers during outage wor /10/92 An additional crack was identified by use of magnetic particle examinatio /13/92 Analysis and testing concluded that the cracks could lead to blade failure during a design basis 1.0C _- . - __ - _ __ - - - - - --
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10/14/92 Prompt operability assessment (P0A) concluded that the Unit 2 CFCUs were operable. This was partially based on expected confirmation that the Unit 2 blades were in a condition similar to or better than Unit /15/92 Licensee implemented Event Response Plan ERP 92-9 to address the CFCU blade issu /18/92 Unit 2 CFCUs were inspecte Two blades were identified to have crack /26/92 Operability Evaluation (0E) 92-20R0 was issue .
10/30/92 On Site Safety Review Group (0SRG) and Plant Safety Review Committee (PSRC) identified several concerns with OE 92-20R The licensee planned to revise the O /10/92 The 2 cracked damper blades in Unit 2 CFCUs were remove Operability Evaluation On October 14, 1992, the licensee prepared a prompt operability assessment (P0A) which preliminarily concluded that CFCUs were operable although damper blades could break during a post-LOCA pressure wave and be blown up into the fan volute. This conclusion of operability was based on the low fraction of damper blades expected to enter the path of the fan blades, and the low probability of significant damage to the fan if a damper blade did come in contact with a fan blad On October 26, 1992, the licensee issue OE 92-20R0 which concluded that Unit 2 CFCUs were operable with cracked damper blades at least i until November 26, at which time all of the blades would be removed from the dampers. Unit 2 would then be run until the scheduled 1 March 5, 1993 outage, at which time all CFCU blades would be l replaced with less brittle materia This conclusion of interim operability with cracked blades was based on:
the low number of (2) cracked blades observed in Unit *
the reliance on leak before break, which would significantly reduce the peak LOCA pressure wave design basis differential pressure for the damper blades of 7 ps *
the low likelihood of damper blade travel up in the direction of the fan volut *
the low likelihood of fan damage if a damper blade were to strike a fan blad The interim basis for operability, to operate with all damper blades removed, extended from November 26 to the scheduled March 5, 1993, outage. Operability was based on earlier design calculations which concluded that reverse rotation of the fan, if initially running,
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- 5- 200501 would not result in CFCU motor breaker trip upon ECCS actuatio The calculation considered the post-LOCA pressure wave, as well as length of time for the CFCUs to sequence on the bus after the SI ;
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signal, The inspector observed that, although licensee internal discussions appeared to have appropriately considered the relevant issues, OE-92-20R0 lacked documentation of many of these specific bases for operability; e.g., the quantitative basis for low likelihood of damage to the fan if a damper blade were to be blown up into the fan, and other concern ;
Inappropriate Information included in Operability Evaluation:
l In OE 92-20RO, the licensee included discussion of the low probability of a LOCA occurring during the interim period before the l blades were removed or repaired. Also, the licensee included discussion of the need to consider leak before break, since a >
licensee topical report on this area has been submitted to the NR The results of the NRC safety evaluation have not been issued at this dat The inspector considered these topics to be inappropriate for an operability evaluation, since plant components must be able to perform the design basis safety function stated in the NRC license, '
regardless of LOCA probabilities and a leak before break analysis pending NRC revie Onsite Review Group (0SRG) and Plant Safety Review Group (PSRC)
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The OSRG and PSRC reviewed OE 92-20RO. The OSRG issued an action request documenting several concerns regarding the content of the operability evaluation. The PSRC returned the OE to Regulatory Compliance for clarification of the basis for operability. The specifics of these concerns were consistent with many of the i inspcctor's concern The licensee planned to revise the operability evaluation. On November 10, after the end of the inspection period, the licensee removed the two cracked blades from Unit 2, and was considering operation of Unit 2 with all damper blades installed except for those removed due to blade crackin Resolution of this issue will be followed by open item 50-323/92-31-0 Inadvertent Bypass of Unit 1 Containment Ventilation Isolation (CVI)
Canability
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On November 7, 1992, while venting containment, the licensee inad- i vertently bypassed the radiation monitor which initiates the CVI function. Normal containment isolation functions were not affecte A modification to the containment atmosphere high radiation monitor ;
had been performed during the recent outage, and an operations l l
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procedure valve lineup checklist had not been revised to refied the new configuration. However, the plant vent monitor was in the flow path, and the licensee determined that the release had been well below limits, and had been monitored by the plant vent monitor. The licensee plans to report this occurrence. Corrective actions will addressed during review of the associated LE No violations or deviations were identifie . Maintenance (62703. 715001 The inspectors observed portions of, and reviewed records on, selected
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maintenance activities to assure co...,;11ance with approved procedures, Technical Specifications, and appropriate industry codes and standard Furthermore, the inspectors verified that maintenance activities were performed by qualified personnel, in accordance with fire protection and housekeeping controls, and that replacement parts were appropriately certified. These activities included:
- Work Order CO 105825, Implement DCN 1-SE-47705, Rod Control Power Supply Replacemen * Work Order C0 104365, Fire Proofing of Block Wall Structural Steel Support *
Post Modification Test 10.06, RHR Flow Control Valves HCV-637, 638, and 670 Flow Tes ;
No violations or deviations were identifie !
6. Identification of Items in Containment Which May Prevent Containment Sumo Operability <
On March 5, 1992, the licensee issued Licensee Event Report (LER) 50-323/
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' 91-12 which indicated that loose materials were found inside the Unit 2 containment in October 1991, during Mode 4 with containment int v ity established, and that Technical Specification (TS) surveillance requirement 4.5.2.c had not been met. The surveillance requirement indicates that after establishing containment integrity, a visual inspection of affected containment areas -shall be performed to verify
, that no loose debris are present which could be transported to the sump and cause restriction of pump suctions. The licensee concluded that the i loose materials (small plastic bag, wipealls, tool bag, water jug, and tool bin) would not have rendered the containment sump inoperabl The root cause of this event was determined to be the lack of a compre-hensive program for control of material after containment integrity has been established. In response, Surveillance Test Procedure (STP) M-45C and Inter-Departmental Administrative Procedure AD4.ID9 were developed to establish a program for controlling material after containment integrity
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i is established. STP H-45C specified requirements for documenting and ,
inspecting containment work activities, and AD4.lD9 specified containment '
housekeeping and material control requirements. Step 5.2.2 of AD4.ID9 indicated that all floatable material would either be in use and attended j l
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< 20050 or placed in an approved container, and Step 5.3.3 indicated that all unattended tools and containers should have a " tool reserve tag" attached to prevent inadvertent removal from containmen On November 5,1992, the inspector and two licensee QC inspectors walked down portions of the Unit I containment while the unit was in Mode 4 with containment integrity established. The inspectors observed unattended loose materials adjacent to the containment sump, including procedures, a pen, two water jugs, mechanical fittings, and a graduated cylinder used to support a hydrostatic test. Adjacent to the containment fan coolers and inside one fan cooler, the inspectors observed unattended tools, testing equipment, a nylon bag, and safety harnesses that were not in an approved container and did not have a " tool reserve tag" attached. The inspectors' observations were brought to the attention of the containment coordinator, and the QC inspectors initiated action requests (ARs) to document the findings. A QC inspector observed more unattended floatable material, consisting of several yellow rags, at the containment sump level on November 7,1992, and initiated an additional A On November 6,1992, with Unit 1 in Mode 3, the inspector walked down containment and observed that the materials adjacent to the sump a..d near the containment fan coolers had been removed. The inspector questioned the presence of open drums near the personnel hatch which were used to collect protective clothing and trash, and was provided a February 1, 1991 document issued by the project engineering group that provided guidelines for radiation protection activities inside containment during Modes 3 and 4. The guidelines indicated that scissor stands were acceptable for collecting clothing and trash, but the stands were to be covered to ensure that the materials would not become dislodged if con-tainment spray actuated. When contacted regarding the actual practice used, the Manager of Radiation Protection indicated that the drums had holes drilled in them to prevent filling with water, and an AR to evalu-ate the use of the drums had been initiated after the inspector ques-tioned the practic The inspector later noted that the drums contained bags, and drilling holes in the drums would not prevent the bags from filiing with water and the materials in the bags "om becoming dislodge l
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During the conversation, the inspector expressed a concern that the radiation protection guidelines did not appear to have been implemented by procedures that were developed to control material inside containmen The safety significance of the loose materials appeared low due to the small amount of material present. However, the inspector's observations I indicated that the licensee's program to control material inside contain-ment was not comprehensive, and that the corrective actions indicated in l the LER were not sufficient to prevent recurrenc In the exit meeting on November 17, 1992, the licensee indicated that l
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lessons learned from the Unit 1 outage would be incorporated into the procedures for controlling materials in containment prior to the next ]
outage. The licensee also indicated that radiation protection practices ,
would be reviewed and incorporated, as necessary, into procedure The
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failure to provide adequate corrective actions to prevent loose material adjacent to the sump when containment integrity was established appeared to violate 10 CFR 50 Appendix B, Criterien XVI (50-275/92-31-02). In l
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view of the licensee's immediate and proposed corrective actions to include additional training of personnel performing work in containment during operating modes 1 through 4, and to provide additional control of health physics equipment and protective clothing in containment, no response to this violation it required. LER 50-323/91-12 is closed and followup actions will be tracked by the enforcement ite One violation of NRC requirements was identified. Modification to Residual Heat Removal (RHR) System (377001 Because of the safety importance of the RHR system, the inspectors reviewed modification design change package (DCP) N-45952, which changed RHR valves HCV-637, 638, and 670 from butterfly to ball valves. The modification was performed primarily to prevent RHR pump runout should HCV-637 and/or HCV-638 fail open during refueling mid-loop operation, and to reduce flow-induced vibration and associated problems due to the flow characteristics of the original butterfly valves. The licensee determined that the new ball valves have a higher flow coefficient than the old butterfly valves. Consequently, the licensee recognized the importance of limiting the open position of the ball valves and appropriately included post-modification tests to determine the maximum open position for the ball valve The inspectors reviewed the post-modification testing and modification analyses to verify the capability of the RHR system to perform its intended function for each of the required operating modes. The inspectors found that the post-modification testing for DCP N-45952 appeared adequate. The inspectors noted the following:
The Emergency Operating Procedures (E0Ps) indicated a potential for one RHR pump to provide flow to the reactor primary coolant hot legs, two safety injection pumps, and two centrifugal charging pumps at the same time. The licensee stated that the maximum single pump flow rate under these conditions could approach 5250 gallons per minute (GPM) in the case of a common mode instrument air failure causing air operated valves HCV 637, 638, and 670 to fail to their open positions. Based on the certified pump curve, the net positive suction head calculation, and the maximum motor amps, the licensee determined the maximum allowable flow for the RHR pumps to be 5500 GPM at runou *
Results from licensee tests performed to simulate the shutdown cooling mode demonstrated the potential for RHR pump runout for the case of a common mode instrument air failure causing valves HCV-637, 638, and 670 to fail to their open positions. According to the licensee, procedures to preclude RHR pump runout have been implemented during the shutdown cooling mod In addition to replacing three butterfly valves with ball valves, DCP N-45952 relocated two of the valves, HCV-637 and 638, to a different area. This required rerouting of associated piping and modifications to pipe supports. The inspectors noted that the licensee's Quality Assurance organization appeared to have recognized the safety importance
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of this significant change in piping configuration. The inspectors reviewed Quality Performance and Assessment (QP&A) Report Number 92.-0023 ,
on this subjec In general, the surveillance appeared to have covered most of the critical parameters, one exception being evaluation of pipe displacements for potential interferences. In discussions with the licensee's pipe stress engineers, the inspectors determined that the licensee appeared to have adequately addressed this issu '
In reviewing QP&A Report Number 92-0023, the inspectors observed that some points made in the surveillance report were either unclear or inaccurate. For example:
- In the section on seismic spectra the report referred to "zero period acceleration" as "zero point acceleration" and in that context indicated " system acceleration - 0." Zero period acceleration should refer to the acceleration in the rigid range of the response spectr * The report section which discussed seismic and dilation (containment expansion under pressure) displacements used " extrapolation" instead of " interpolation" to discuss determination of seismic anchor motion displacements. The licensee's stress group actually used linear interpolation method ;
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The inspectors interviewed the auditor who prepared the subject surveil-lance report in order to clarify report statements and to review the auditor's qualification The auditor appeared knowledgeable of stress analysis methods. During the exit meeting, the inspectors emphasized the ;
importance of clear, accurate reports in implementing an effective .
quality review progra No violations or deviations were identifie Surveillance (61726)
By direct cbservation and record review of selected surveillance testing, the inspectors checked compliance with TS requirements and plant procedure The inspectors verified that test equipment was calibrated,
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and that test results met acceptance criteria or were appropriately dispositioned. These tests included:
- STP M-45A, Containment Inspection Prior to Establishing Containment 4 Integrit * STP M-45C, Outage Management Containment Inspectio * STP I-1A, Modes 1, 2, and 3 Shift Checklis * STP I-16A2B, Actuation Logic Test of Protection System Logic, Inclu-ding Master Relays and Reactor Trip Breakers (Mode 1, 2, 3, and 4).
= STP P-6B, Routine Surveillance Test of Steam Driven Auxiliary Feedwater Pump.
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- STP M-9A, Diesel Engine Generator Routine Surveillance Tes No violations or deviations were identifie . Enaineered Safety Feature Verification (717101
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During the inspection period, selected portions of the solid state protection system (SSPS) for Units I and 2 were inspected to verify that system configuration, equipment condition, and electrical lineups, and local breaker positions were in accordance with plant drawings and Technical Specification No violations or deviations were id. tifie . Observation of licensed Ooerator Trainina (41701)
On November 4, 1992, the inspectors observed licensed operator training in the simulator (Course LR92, lesson LR923S5). The training addressed
systematic problem solving skills required during plant transients and event Skills exercised and discussed included individual diagnostics skills, team communications, and team diagnostic skills. The lesson consisted of several short exercises which isolated and emphasized elements of problem solving and teamwork skills involved in arriving at a group consensus of plant condition No violations or deviations were identifie . Ismoorary Instruction (TI) 2500/20. (Closed - Unit 1) "Insnection to Determine Comnliance with the ATWS Rule. 10 CFR 50.62."
The inspector walked down the licensee's system to meet the Anticipated Transient Without Scram (ATWS) rule,10 CFR 50.62. The licensee installed the ATWS Mitigation System Actuation Circuitry (AMSAC) to meet this requirement for both units. The design of the Unit 2 AMSAC was verified in Inspection Report 50-275/323/89-01. The design of the Unit 1 AMSAC system is similar to Unit 2, but had not been walked down s the NRC to verify installatio The results of the talkdown were satisfactory. Based on discussions with the licensee, the system has been available for use most (greater than 95%) of the time. Based on the similar design to Unit 2 and the walkdown, TI 2500/20 is close No violations or deviations were identifie . Control of Relief Valves (71707)
During tours of the plant, the inspector observed two items involving the licensee's relief valves that did not appear to be according to the American Society of Mechanical Engineers (ASME) Code. The first was the inconsistent use of seals to assure required relief valve settings. The second involved discharge pipes from several relief valves which were pointed up but did not allow drainage from the low point. These items are discussed belo _ _ _ _ __ - ___ _ _ _ . _ - . _ . _ _ _
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200 2 Lockwire Rals The inspector found that one main steam safety valve (2-MS-RV-4) and ,
some diesel air start receiver relief valves (e.g. DEG-2-RV-269) did not have a seal around the setscrews for the guide / nozzle ring setting This seal provides a positive verification that the settings have not been changed from design value ASME Section III Articles NB-7515, NC-7515 and ND-7515 state for Class 1, 2, and 3 relief valves, respectively, that the certificate holder shall install seals at the time of setting a relief valve. Following maintenance on these valves, seals should be installed since the valve has been reset. The main steam safety valve is a Code Class 2 relief valve. The diesel air receiver valve is an ASME Section VIII relief valve, and this code requires the vendor of the relief to install a sea The licensee wrote AR A0281812 to document that 2-MS-RV-4 did not have a lockwire seal on it. The licensee concluded that the setscrews had not been repositioned since there was undisturbed rust around the setscrew The licensee believed that the seals had been installed on this relief valve, but had come off since the last maintenance on the valve (If o/).
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The licensee agreed to install new seal In discussions with the inspector concerning the lockwire seal for the diesel air receiver relief, the licensee stated that the requirement for
' use of seals had changed over time. Originally, relief valves had seals installed by the manufacturer. After initial plant startup, the licensee's program did not require the use of seals. The licensee's program changed about two and one half years ago to require seals following maintenance. The licensee implemented procedures to require seals on May 29, 1991. The current program does require installation of seals on relief valves after setting a valve. The licensee stated that the valves without a seal were last maintained when there was no procedural requirement to install a sea Discnarne Lines With respect to the discharge lines pointing upward (vertically) without drainage, an inspector review of ASME Section VIII, Division I (1968)
identified that this practice is contrary to Articles UG-126(e) and UG-134(g). This practice is also contrary to ASME Section III, Division I, (1974) Articles NB-7154, NC-7154, and ND-7154. These articles stated that the discharge lines from relieving safety devices shall be designed to facilitate drainage or be fitted with drains to prevent liquid from lodging in the discharge side of the safety device. There was no
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drainage line observed on the relief valve discharge lines for the diesel air receiver tanks, or on two relief valves for backup air bottles in containmen .- . -, . . .-
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The licensee stated that the intent of the Code was to (1) prevent corro-sion of the valve internals, (2) prevent static head from affecting lift setpoint, and (3) avoid water hammer in the discharge line if contact with steam results. In subsequent discussions, the licensee stated that the safety concern was low, because the air in the diesel rooms was dry, the possibility of water condensation was low, corrosion had not been observed in relief valves, and that the design met the intent of ASME Section VIII. The licensee also said that a literal reading of the Code would require drains, but they considered their configuration to meet the intent of the Code. However, the licensee made a commitment to promptly request a Code interpretation for the full scope of Code controlled relief valves, and to inform the NRC of intended actions to comply with that interpretatio Resolution of this concern will be followed by Open Item 50-275/92-31-0 No violations or deviations were identifie . Temporary Modifications (92701. 37700)
The inspector assessed a licensee program which controls temporary modifications. Temporary modifications are temporary changes to the plant which include lifted electrical leads, electrical jumpers, and temporary bypass lines. Temporary modifications are required to be controlled by approved procedures, independently verified, and have a log
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maintained of the status of the temporary modifications. The inspector reviewed the licensee Administrative Procedure (AP) C-4S1, " Temporary Modification Control - Plant Jumpers."
, Temporary Jumners The licensee's procedure defined jumpers as electrical jumpers, lifted electrical leads, and mechanical bypasses. The procedure required a shift manager approval prior to jumper installation, identification tags on the jumper, an engineering review within fourteen days after installation, and field walkdowns every ninety day The inspector noted that the total number of jumpers between both units
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was about 30, with no installation older than 21/2 years and the majority less than one year old. The inspector also reviewed recent Quality Assurance (QA) observations of temporary modification No problems were identified with the placement of jumpers which the inspector examine The inspector reviewed data sheets on October 19, 1992, and found prob-lems with the administration and attention to detail of the quarterly (i.e., 90 day) review of plant jumpers. AP C-451, step 6.4.6 required the installing department to walk down the plant jumper every 90 days following installation, and document this activity on the jumper log for The problems identified with quarterly reviews ' included:
(1) some historic reviews had taken greater than the required 90 days, (2) one review (jumper in place about a year) had not been done, (3) two currently due reviews were late, and (4) incorrect review dates had been logged. When informed of the inspector's observations, the licensee issued Quality Evaluation (QE) Q0010166.
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,. . 200501 The inspector found that the historic reviews exceeding 90 days all occurred in the same period (September 1991 through January 1992). One 1 jumper (Unit 2,91-045) had not had a 90 day review, although it had been i installed since October 17, 1991. The inspector also found that two jumpers were late for their current 90 day review, not having been reviewed since July 13, 1992 (98 days), and that five jumpers had their quarterly review incorrectly logged as having been completed on October 21, 1992, two days after the date of the inspector's revie The unit, log numbers, and problems identified are summarized belo UNIT Log Historic Reviews > Review Current Review Date Number 90 days done Review Late Mislogged 1 90-009 140, 177, 121 days Yes No No 1 91-052 121 days Yes No No 1, 2 91-060 121 days Yes No No 1, 2 91-061 121 days Yes No Yes 2 90-028 169, 178, 121 days Yes No No 2 90-057 121 days Yes No No 2 90-086 122 days Yes No Yes 2 91-029 115 days Yes No No 2 91-045 None No No No 2 91-051 None Yes No Yes 2 91-052 None Yes No Yes 2 91-056 None Yes Yes No 2 91-061 None Yes No Yes92-015 None Yes Yes l No
[2 The licensee found that jumper 91-045 had not been walked down because the I&C department installed the jumper and believed that operations would verify the jumper, since it was in containment. The operations department was unaware of the need to verify the jumper. The jumper was ,
subsequently verified on October 28, 1992, as still installe The licensee verified the two jumpers that were late for their 90 day review on October 22, 1992. The licensee also stated that the logs had incorrect dates for five jumpers due to a transposition error from the previous log entry. All of the previous log entries were 7/21/92, and the log entries were copied as 10/21/92 for the five jumper The licensee's root cause evaluation determined these problems had been caused by personnel error. The errors were: (1) inattention to detail,
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(2) personnel not completely understanding the requirements of proc;_'.re AP C-4S1, and (3) departmental roles in the program not having been adequately stated. The licensee counseled individuals and initiated '
procedure changes to AP C-4S Although no safety concern regarding the placement or control of jumpers was identified, the licensee's weaknesses in administrative review of the jumper program, and failure to follow procedure AP C-451, is an apparent violation (Severity Level V) of TS Section 6.8.1, which requires that activities be implemented according to procedures (50-275/92-31-04).
This violation is not being cited because the criteria specified in Section Vll.B.1 of the Enforcement Policy were satisfie .
One non-cited violation was identifie . Licensee Event Report (LER) Followuo (927001 The following LERs were reviewed and closed based on the licensee's root cause determination and corrective actions:
Unit 1: 92-10 Revision 0, 92-20 Revision 0, 92-05 Revisions 0 and Unit 2: 92-01 Revision 2, 92-04 Revision LER 50-275/92-04 Revision 1 and 2 (closed)
These LERs described a loss of offsite power that occurred on March 7, 1991, while Unit 2 was in a refueling outage. An NRC Augmented -
Inspection Team investigated the event and documented their findings in NRC Inspection Report 50-275/91-09. These LERs are closed
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because followup actions for the event were tracked by open items associated with the inspection repor LER 50-275/91-18 Revisions 0 and 1 (closed)
These LERs described certain plant conditions and system configurations that could result in component cooling water ;
temperatures exceeding design basis limits. The licensee identified ;
this problem during an investigation to determine the viability of a i potential change to plant Technical Specifications. The licensee subsequently revised emergency operating procedures (E0Ps) to ensure the undesirable system configurations would not be used. This item is closed based on the revisions made to the E0Ps. Followup item 50-275/92-16-04 will be used to track the licensee's engineering .
evaluation of their design basi .
' LER 50-275/92-19 Revisions 0 and 1 (closed)
These LERs described improper maintenance of containment fan cooler '
units. This issue was the subject of a special NRC inspection and '
an enforcement conference documented by NRC Inspection Reports 50-275/323/92-17 and 50-275/323/92-19. The LERs are closed because the followup actions are being tracked by enforcement items 50-275/92-17-01 and 02, along with enforcement item 50-323/92-17-0 '
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,. LER 50-275/92-22 Revision 0. Unit 1 Indications in Main Feedwater Pipina Near Steam Generator Nozzles Due to Thermal Fatique (closed) ,
The licensee identified linear indications of cracks in a weld near the steam generator nozzles in all four Unit I steam generator Based on the estimated depth of the indications, and past occurrences of thermal fatigue in 1985, the licensee replaced the piping segment in all four feedwater lines. Later destructive analysis of the welds showed that the crack size had been overestimated by about a factor of te A management meeting was held on October 16, 1992, with the licensee in the Region V office to discuss the crack indications on the feedwater pipe adjacent to the steam generator feedwater nozzle According to the licensee, the cracks had likely occurred as a result of thermal fatigue from thermal stratification during low feedwater flow conditions. The licensee had removed the affected sections of feedwater piping. The licensee presented documentation that showed actual crack depths were an order of magnitude smaller than the crcck depth measurements initially indicated by conservative UT examination. According to the licensee, the a tual maximum crack depth was significantly less than that allowed by the ASME Section XI code guidance for maximum allowable flaw dept ,
followup and corrective actions performed by the licensee included:
' stronger ASME A-508 material (the same material as the adjacent steam generator feedwater nozzles).
- Analyses which estimated the effect of thermal stratification on the feedwater piping based on assumed temperature ,
distribution * Instrumentation of the affected feedwater piping to determine actual temperature distribution Region V and NRR staff reviewed the licensee's approach, including preliminary analysis results, and concluded that they appeared appropriate. Further review of results and validation of calculation assumptions will be performed when data become :
available. A copy of the licensee's presentation on the feedwater ,
piping cracking issue is included as an attachment to this repor . Eddy Curren,t Testina of Steam Generator Tubes (73755, 73052)
The inspector reviewed the licensee's program and procedures and the preliminary results of eddy current testing (ECT) of steam generator tubes conducted during the IR5 outage. Persons contacted during this ;
inspection activity are listed in the appendix to this repor The inspector reviewed the following licensee documents and procedure l
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Nuclear Plant Administrative Procedure (NPAP) C-804, " Inservice Inspection and Testing Program," Revision *
Field Service Procedure MRS 2.4.2 PGE-35, " Eddy Current Inspection of Inservice Steam Generator Nonferromagnetic Tubing for Diablo Canyon Units 1 & 2," Revision *
Technical and Ecological Services " Steam Generator Eddy Current Data Analysis Guidelines," Revision a. ECT Prooram and Procedures The inspector found that the licensee's ECT program incorporated state of the art technology for the detection of tube degradation including bobbin coil probes, rotating pancake coil (RPC) probes, multi-frequency analysis, and optical disk data storage. The licensee's in 'n nion sample size and data analysis had been conservatively aveloped consistent with technical specification requirements and the recommendations of the Electrical Power Research Institute (EPRI).
The following weaknesses were identified during the inspector's review of the licensee's progra (1) loose Parts Monitorino The inspector noted that the licensee's program was based on Electric Power Research Institute (EPRI) guidelines for steam generator examinations. The EPRI guidelines recommended followup of eddy current indications suggesting the presence of a foreign objec The inspector noted that the licensee's ECT data ar.alysis guidelines did consider loose parts in the secondary side of the steam generator tube bundle as a possible cause for individual tube wear indications. However, the ECT prcgram did not include followup provisions for specifically locating and characterizing the loose parts or examining additional tubes surrounding a suspected foreign objec According to the licensee, eddy current inspection was used to supplement their program of visual inspection for loose parts in the secondary side of the steam generator tube bundle. If a i foreign object was visually located, then adjacent tubing would l be identified for ECT to assess any resulting tube wea Industry events related to steam generator tube defects have been attributcd to loose parts. The inspector noted that examinatica for loose parts did not appear to be a priority in the licensee's ECT progra The licensee stated that they had not experienced a significant problem with loose parts causing tubing wear. However, the licensee acknowledged the inspector's concern and committed to
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review their data analysis guidelines to enhance their use of ECT data for monitoring for loose parts in the steam generator tube bundle. The inspector found the licensee's proposed actions to be adequat (2) Data Analysis Guidelit3s Not Issued as a Plant Procedure The inspector found that the licensee utilized written guidelines for the analysis of eddy current data. However, these guidelines were not issued as a formal plant procedur ,
The guidelines had been developed by the licensee's Technical and Ecological Services (TES) division for use by contractor inspection personnel at the plant. Contract analysts receiveo training at the plant in the use of the guidelines and con- '
ducted their evaluations of the eddy current inspection data in accordance with the guidelines. The inspector noted that the lack of formal procedural control of the inspection guidelines could result in inadequate docunentation of the data evaluation criteria used in each outag The licensee acknowledged the need to formally control the data analysis guidelines and committed to issue the guidelines as formal plant procedures by the 2R5 outage. The inspector found the licensee's proposed actions adequat (3) Defect Acceptance Criteria Not Identified in Plant Procedure The inspector found that the licensee determined the need for tube plugging based primarily on the results of their evalua-tion of the eddy current inspection data. As a minimum, the licensee utilized the plugging limit acceptance criteria contained in Technical Specification 4.4.5.4. In addition, preventive plugging cased on an administrative decision was used in some cases. However, the inspector found that the defect acceptance criteria were not specifically identified in the licensee's procedures. The inspector noted that defect acceptance criteria were included in the data analysis guide-lines which the licensee used to characterize eddy current indications.
f The license acknowledged the need to formally define and
control the tube defect acceptance criteria used for eddy L current inspection. The licensee committed to incorporate specific defect acceptance criteria within plant procedures by the 2R5 outage. The inspector found the licensee's proposed actions to be adequat Review of 1R5 Eddy Current inspection Results The inspector reviewed the preliminary results of the licensee's s
eddy current inspection of steam generator tubes during the ongoing 1R5 outage. The inspector noted that the initial sample size had been expanded as required due to defect indications in all stean generators. A total of 29 tubes were plugged during the IR5 outage r
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t due to continuing tube wear at anti-vibration bar (AVB) locat' ..s and crack indications in the short radius U-bend tube areas. The licensee's IR5 inspection activities appeared consistent with their committed program and technical specification requirement No concerns were identified during this revie No violations or deviations were identified.
16. Exit Meetina An exit meeting was conducted on November 17, 1992, with the licensee representatives identified in Paragraph 1. The inspectors summarized the scope and findings of the inspect... as described in this repor The licensee did not identify as proprietary any of the materials reviewed by or discussed with the inspectors during this inspectio i
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200501 APPENDIX Persons Contacted durina Eddy Current Testina inspection (Paraaraoh 15)
- S. Banton, Director, Plant Engineering
- Barkhuff, Director, Quality Control
- Crockett, Manager, Technical Services
- R. Exner, Project Manager, Maintenance
- C. Groff, Technical Services D. Gonzales, Inservice Inspection Coordinator, Technical Services D. Hampshire, Technical Coordinator, Nuclear Operations Services (N05)
J. Kang, Analyst, Technical and Ecological Services (TES)
H. Karnar, Auditor, Quality Assurance
- D. Miklush, Manager, Operatier.2 Services
- D. Moon, Regulatory Compliance
- D. Taggart, Director, Quality Assurance
- J. Townsend, Vice President
- R. Thierry, Regulatory Compliance A. Young, Manager, Quality Assurance
- Attended the exit interview on October 9. 199 . . _ - . - _ , _ _