IR 05000245/1992025
| ML20127D909 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 12/01/1992 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20127D878 | List: |
| References | |
| 50-245-92-25, 50-336-92-27, 50-423-92-24, NUDOCS 9301190080 | |
| Download: ML20127D909 (39) | |
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U.S. NUCLICAR ltEGULATORY COMMISSION
REGION I
Docket / Report Nos.: 50-245/92-25; 50-336/92-27; 50-423/92-24 1.icense Nos.: DPib21; DPR 65; NPF-49 1.icensee: Northeast Nuclear Energy Company P. O. Ilox 270 llartford, CT 06141-0270 1:acility: Millstone Nuclear Power Station, Units 1, 2, and 3 inspection at: Waterford, CT Dates: September 8,1992 - October 27,1992 Inspectors: P. D. Swetland, Senior Resident inspector A. A. Asars, Resident inspector
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K. S. Kolaczyk, Resident inspector, Unit 1 D. A. Dempsey, Resident inspector, Unit 2 R. J. Arrighi, Resident inspector, Unit 3 E. T. llaker, Project Manage , NRR J. Anderson, Pmject Manag< r, NRR pd ,s Approved Sy: ' M O s m .- # c l 2 / A ) w_ t t/3R
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Lawrence T. Doerflein,' Chief l Date Reactor Projects Section 4 A l Scope: NRC resident inspection of core activities in the areas of plant operations, radiological controls, maintenance, surveillance, security, outage activities, licensee self-assessment, and periodic reports. The inspectors performed special reviews in the following areas: operation of the Unit I reactor vessel level reference leg backfill system, maintenance errors on the Unit 1 emergency service water strainer, retest of the Unit 2 enclosure building filtration syr. tem, operability of motor-operated valves at Unit 2, operability determinations for the Unit 3 auxiliary building filter system, and effectiveness of the site material receipt inspection progra The inspectors reviewed plant operations during periods of backshifts (evening shifts) and deep backshifts (weekends, holidays, and midnight shifts). Coverage was provided for 77 hours8.912037e-4 days <br />0.0214 hours <br />1.273148e-4 weeks <br />2.92985e-5 months <br /> during evening backshifts and 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> during deep backshift Results: See Executive Summary 7 9301190000 93011I2 PDR ADOCK 05000245 G PDR
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EX ECUTIVE SUMM AlW Millstone Nuclear Power Station Combined Inspection 245/92-25; 336/92-27; 423/92-24 Plant Operatiom Unit I operated safely throughout this inspection period. However, the Unit I opcii. tar requalification program was declared unsatisfactory for the second consecutive year when 5 of 15 operators failed an NRC-administered requalitication examinanon. Unit 2 was shutdown and defueled as the steam generator replacement outage continued. The transfer of new reactor fuel into the spent fuel pool was conducted safely Unit 3 operated at full power until September 29 when the licensee identified that both trains of the supplementary leak collection and release system (SLCRS) were inoperable due to system degradation, and design and operating deficiencies involving the auxiliary building filter system (ABFS). Unit 3 was shut down and remained in the cold shutdown condition through the end of this inspectio The inspectors were concerned that operation of the needle valves which regulate flow to certain (Mit I reactor vessel level instrumentation reference legs to compensate for flow reductions could adversely affect the instrumentation if the material which caused the bhickage was dislodged, in response, the licensee developed operating limits for the needle valves which are bounded by the design safety analysi Prior to and during the Unit 3 maintenance outage, several tests were performed to defme more accurately the operating parameters and design basis of the ABFS and SLCRS. The licensee clarified the dependency between SLCRS and ABFS; ABFS operation is necessary to support SLCRS in meeting the design requirement for a vacuum in the enclosure and auxiliary _ buildings. The licensee also identified that adequate surveillance tests of SLCRS have not been performed since initial plant startup. The issues of SLCRS and ABFS operability and the adequacy of surveillance testing of these systems are the subject of NRC-inspection report 50-423/92-2 Maintenance / Surveillance l While performing preventive maintenance during this inspection period, the licensee identified I that lubricating oil had not been added to the Unit i emergency service water strainer gearbox during its installation in August 1992. This omission rendered the strainer inoperable and raised concerns with the adequacy of the licensee's control over spare parts maintained by the maintenance department and proper system verification prior to its return to service. The issue was unresolved nending licensee implementation of corrective actions.
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Following discovery of a pinhole leak in the service water header in the engineered .
safeguards building, Unit 3 personnel performed a comprehensive inspection'of susceptible areas of piping. Pipe replacements were made as necessary with a high regard for preserving service water system integrity. To maintain system integrity, the licensee is developing a service water system monitoring program; the inspectors concluded that this was a good initiativ Engineering and Technical Support The licensee completed a review of the auxiliary building filter system design, equipment, and testing problems when the plant was shut down for this issue. Several design and equipment issues which necessitated system modifications were found. Once the full scope of the problems was identified, the licensee initiated a comprehensive effort to resolve the problems, inspector concerns were identified with the implementation of motor-operated valve upgrades in Unit 2. These concerns included the quality of the technical basis for operability of certain valves and the timeliness of completion of operability /reportability evaluations. These hsues
were unresolved pending further review by NR Safety Assessment /Qunlity Verification The inspectors reviewed the licensee's report of the discovery that the Unit I service water (SW) and emergency service water (ESW) systems would not be able to meet design loads occurring during a safe shutdown earthquake. The degraded areas of SW and ESW had-experienced corrosion when the piping exterior protective coating wore off. The pipe walls -
were further thinned during restoration of the rusty areas without evaluation of the effect of the thinning on system stress analyses. This condition was identified during the July / August 1992 maintenance outage and repaired by the inetallation of reinforcing saddles around the tie-in points of the SW and ESW piping. The identification and repair of these weak areas resulted from an individual inspector's initiative rather than a defined erosion / corrosion program. Unit I has committed to the development of a comprehensive SW and ESW maintenance and inspection pla A failure to report degraded Unit 1 fire barriers was of minor significance and the licensee committed to submit the required reports. Accordingly, enforcement discretion was exercise . Following licensee identification of dimensional nonconformances on Unit _3 reactor head stud replacements, the licensee adequately addressed the nonconforming cor,ditions. In addition, the licensee caused the vendor to make changes to its program for controlling subcontractors and revised their program for_ auditing vendor controls on subcontractors. However, the inspectors concluded that the licensee may have resolved the matter sooner had their review of three prior NRC information notices not been so narrowly focuse ii
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U n . P in following corrective actions for previous violations at Units I and 2, the inspector noted discrepancies in the licensee's implementation of committed corrective actions. In one case, the licensee committed to review a matter with operators at the Millstone and Haddam Neck sites, These actions were completed satisfactorily at Millstone, but Haddam Neck had not been informed of this commitrnent, in the second case, efforts to improve the timeliness of !
processing plant information reports have not been implemented effectivelv by plant management. In particular, NRC noted that licensee performance in this area was 1 inconsistent with recent management emphasis on procedural adherence,
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TABlJi OF CONTENTS Page P R I NCI PA LS CONTACTED . , , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 SUMM ARY OF FACILITY ACTIVITIES . . . . . , . . . . . . . . . . . . . . . . . . 1 PLANT OPERATIONS (IP 71707, 71710, 93702) . . . . . . . . . . . . . . . . . . . 2 Operational Safety _ Verification (All Units) ................... 2 Operation of the Reactor Vessel Level Reference Leg Backfill Modification - Unit 1 .......................,, ..... 3 New Fuel Storage in the Spent Fuel Pool - Unit 2 . . . . . . . . . . . . . . 3- Spent Fuel Pool Cooling and Purification System Walkdown - Unit 2' . . . 4 Safeguards Building Ventilation System Walkdown - Unit _3 . . . . . . . . . 5 Supplementary Leak Collection and Release System Inoperability - Unit 3 ............................................ 6 4,0 MAINTENANCE (IP 62703) .........................,, . 7 Emergency Service Water Strainer Declared inoperable - Unit 1 ...... 8 Enclosure Building Filtration System Retest - Unit ' 10 Service Water Piping Degradation - Unit 3 . . . . . . . . . . . . . . . . . . . I 1 -- SURVEILLANCE (IP 61726) .....,.....,................... 12 Area Radiation Monitor Calibration - Unit 2 . . . . . . . . . . . . . . . . . . 13 6,0 ENGINEERING / TECHNICAL SUPPORT (IP 37700, 37828) . . . . . . . - . . . . . 13- Motor-Operated Valve Operability - Unit 2 . . . . . . . . . . . . . . . . . . . - 13 Auxiliary Building Filter Operability Determination - Unit 3 ..... ,. 17
> SAFETY ASSESSMENT / QUALITY VERIFICATION (IP 40500,90712, 92700) . . ............. ..............,............19 - Review of Written Reports ' . . . . . . . . . . . . . . . . . . , . . . . . . . . . 19
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7.1. l' Reporting of Fire Barrier Deficiencies . . . . . . . . . . . . . . , , _
. 20-7. Report of Degraded Service Water and Emergency Service Water Systems - UnitI-......................... 20' Plant Operations Review Committec/ Nuclear Review Board - Unit 2 . . . . 23 Combustion Engineering Reactor Head Studs . . . . . . . . . . . . . . . . . . . 24 iv
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. Followup of Previous inspection items . . . . . . . . . . . . . . . . . . . . . . 25 7.4.1 Effectiveness of Licensee Receipt inspection Program ........ 25 7.4.2 Technical Specification Violations involving Containment integrity and Safety System Operabihty - U.1it 2 ........... 29 7.4.3 Fkxxling of Feedwater Heater - Unit 2 . ............... 30 7.4.4 Verification of Plant Records Accuracy (Tl 2515/115)... . .. 31 7.4.5 Control Rod Drive Hydraulic Control Unit Valve Out of Position - Unit 1. . . . . . ................. ...... 31 M ANAGEMENT MEETINGS .. . .. . ........... .. ... 33 The inspection procedures (IP) from NRC Manaal Chapter 2515, Light Water Reactor inspection Program, that were used as guidance are listed parenthetically for each report section.
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DETAILS PRINCIPALS CONTACTED Within this report period, interviews and discussions were conducted with members of the licensee's management and staff as necessary to support the inspectio .0 SUMMAltY OF FACILITY ACTIVITIFS During this report period, with the exception of small power reductions to conduct turbine stop valve, and main steam isolation valve testing,, Millstone Unit I remained at 100% of rated thermal power. On October 2,1992, the licensee reported to the NRC that, because of excessive wall thinning caused by exterior corrosion, the service water and emergency service .
water systems had been inoperable prior to their repair during the July-August 1992 maintenance outage. NRC review and followup to this issue is discussed further in this report. During the week of September 21-251992, the NRC administered requalification examinations to fifteen operators Five operators failed the examination and the Unit I requalification program was declared unsatisfactory. On October 7,1992, the licensee met with NRC management to discuss the operator examination failures and the basis for continued plant operation; and to outline a corrective action plan to restore the operator requalification program to a satisfactory status. On October 9,1992, the NRC issued Confirmatory Action Letter 1-92-014 to the licensee which outlined the licensee's commitments for corrective actions, and indicated that additional inspection of the training program would be conducte Millstone Unit 2 remained shutdown and defueled throughout the inspection period. Major outage activities included installation, welding, and nondestructive testing of the new steam generators; replacement of vital 120 volt ac. inverters; diagnostic testing of motor-operated valves; overhaul and series conversion of the 'A' emergency diesel generator; and modification of the engineered safety features actuation syste Millstone Unit 3 entered the report period at 100% power. On September 29 the licensee declared an unusual event and commenced a plant shut down after identification that both trains of the supplementary leak collection and release system (SLCRS) were inoperable. The unusual event was terminated on October 1 after the plant reached cold shutdown, a. condition >
in which the SLCRS is not required to be operable. The plant remained in cold shutdown through the end of this inspection to modify the auxiliary building filter system, which is required to support SLCRS operatio ._
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2 PLANT OPER ATIONS (IP 71707, 71710, 93702) Operational Safety Verification (All Units)
The inspectors performed selective examinations of control room activities, operability of engineered safety features systems, plant equipment conditions, and problem identiGcation systems. These reviews included attendance at periodic plant meetings and plant tour The inspectors made frequent tours of the control room to verify sufficient stafGng, operator procedural adherence, operator cognizance of control room alarms and equipment status, conformance with technical specifications, and maintenance of control room logs. The inspectors observed control room operators response to alarms and off-normal conditions. No noteworthy deficiencies or safety concerns in this area were identified during this inspectio The inspectors verified safety system operability through independent reviews of the following: system configuration, outstanding trouble reports and event reports, and surveillance test results. The selection of safety systems for review was made using risk-based inspection guidance developed by NRC. During system walkdowns, the inspectors made note of equipment condition and tagging. The inspectors performed detailed walkdowns of the Unit I core spray system 'B' train, the Unit 2 spent fuel pool purification system, and the Unit 3 safeguards building ventilation system. The system configuration'for the Unit I cote spray system was correct. The results of the Unit 2 and Unit 3 walkdowns are discussed in sections 3.4 and 3.5 of this report, respectivel During plant tours and system walkdowns, the inspectors verified the use of installed jumpers, bypasses, and lifted leads in accordance with ACP-QA-2.06B " Jumper Lifted Lead and Bypass Control (NEO 8.05)," Revision 12. The inspector reviewed jumpers at Millstone 2 involving the installation of a temporary spent fuel pool filter, recirculation of the 'A' boric acid storage tank, temporary service water system seismic restraints. Safety evaluations for these temporary modifications were well-written and promptly reviewed by the plant operations review committee. The modifications were reflected properly in the applicable __
r control room drawing The accessible portions of plant areas were toured on a regular basis. - The inspectors observed plant housekeeping conditions, general equipment conditions, and fire prevention practices. The inspectors also veriGed proper posting of contaminated, airborne, and radiation areas with respect to boundary identification and locking requirements. Selected 4 aspects of security plan implementation were observed including site access controls,-
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implementation of compensatory measures, and guard force response to alarms and degraded
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3 Oper4 tion of the Reactor Vessel level Reference leg Backfill Modification -
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Unit 1 in August of 1992, the licensee installed a system in Unit I which provided a source of water from the control rod drive system to the bottom of the reference legs of the cold condensate pot reactor vessel level indicating system. The licensee believes that the addition of water ,
into the reference legs of the cold condensate pot system will prevent the buildup of noncondensable gases which could cause large level fluctuations during rapid reactor coolant system depressurizations. Some level fluxuations were noted during the July 4,1992, plant shut down. The now of water into the reference legs is controlled by needle valves which maintain the Dow at .008 gallons per minute (gpm). Adjustment of the valves is conducted and controlled in the presence of a reactor engineer through use of Instrumentation and Controls Procedure 428C, " Reference Leg Flow Metering Valve Adjustment." NRC inspection of the modification installation and startup testing is documented in NRC-inspection report 50-245/92-2 During the months of August and September 1992, the setting of the 'A' side reference leg needle valve was adjusted twice while the setting of the 'B' needle valve had to be adjusted
- four times. All six adjustments were in the open direction to conipensate for a reduction in Gow across the needle valve. On September 10, 1992, the needle valve on the 'B' reference
leg backfill system was replaced after three consecutive adjustments, Examination of the 'B'
needle valve revealed that a brown film on the needle valve stem caused the gradual reduction in Dow. At the close of the report period, the licensee had not determined the material composition of the film or why the 'B' needle valve requirca more adjustment than the 'A'
valve. However, foreign material in the tubing to the 'B' needle valve that was not remove by flushing during installation, is suspected as the cause. The 'B' valve would be more susceptible to this type of failure mechanism since its has a longer run of tubin While reviewing the operation of the modification, the inspector noted that the safety assessment that was performed for installation of the modification was based upon a maximum flow rate through the needle valve of .0085 gpm. The inspector was concerned that if the licensee continued to adjust the needle valve as the flow rate decreased due to Glm buildup, and the blockage suddenly dislodged, the flow rate into the reference leg would b greater than the .0085 gpm analyzed amount. To address the inspector's concern, the Unit i engineering manager issued a memorandum to the supervisor of the Unit I reactor engineers which instructed him to limit operation of the valve to values which would be bounded by the safety analyses. This memorandum limiting operation of the valve provides interim guidance until additional analysis can be completed to allow for a potentially higher flow rate. The inspector considered this action to be an acceptable resolution of this concent New Fuel Stnrage in the Spent Fuel Pool- Unit 2 The inspector witt.essed transfer of several new fuel assemblies from the new fuel storage racks to the spent fuel pool. -Through review of documents the inspector verified that the -
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new fuel elevator, cables, slings, and cranes had been tested in accordance with applicable requirements. Movement of the fuel assemblics into Region B of the spent fuel pool was controlled properly using station material transfer form SF-1422. Appropriate cleanliness controls were implemented during the evolutio The inspector veri 6ed through system walkdowns and review of completed surveillances that applicable technical specification (TS) requirements were satisfied. These included:
- Spent fuel pool bulk temperature was less than 140*F (TS 3.9.3.2).
- A minimum of 23 feet of water was maintained over the top of fuel assemblies seated in pool storage racks (TS 3.9.12).
- At least two spent fuel pool area radiation monitors were operable and one train of enclosure building filtration system was in operation in the auxiliary exhaust mode (TS 3.9.13 and 3.9.15).
- The storage pattern of Region B of the spent fuel pool was controlled by properly-positioned blocking devices to maintain Keff less than or equal to 0.95 (TS 3.9.12.2).
The inspector noted that since the new fuel inspection machine was not operable, certain inspection steps of procedure EN-21028, "New Fuel Assembly and Control Element Assembly Receipt and inspection," had not been performed for some of the fuel assemblie The liccesee dispositioned these items as acceptable in nonconformance report 292-66 Since detailed fuel inspections were conducted prior to shipment of the new fuel and there was no evidence of shipment damage, the licensee considered the particular waived inspection steps to be redundant and the fuel assemblies acceptable for use as is. The inspector
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reviewed the report and had no concerns regarding the disposition of the items. - The
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inspector concluded that the evolution had been conducted safely and in accordance with applicable technical specifications and procedure .4 Spent Fuel Pool Cooling and Purification System Walkdown - Unit 2 The inspector performed a detailed walkdown of the Millstone 2 spent fuel pool cooling and
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purification system using as guides the system operating procedure OP-2305, " Spent Fuel-l- Pool Cooling and Purification System," and associated valve lineup check sheets, the fmal safety analysis report, and the control room system drawings. Material conditions were acceptable. A caution tag dated 1991 on the local power switch for the 'A' cooling pump indicated a long-standing oil leak, and some oil was present in the drip tray. The inspector did not consider the amount of oil present sufficient to constitute a fire hazard. An automated work order to overhaul the pump is scheduled for completion during the present refueling outage. The inspector also noted a small body-to-bonnet leak on discharge header
- check valve 2-RW-8. This discrepancy was corrected promptly. The inspector verified that system flow, pressure, temperature, and differential pressure instruments were calibrated properly and that all operating parameters were within the limits speci6ed by the operating procedure. The inspector found that while the valve lineup check sheets were consistent with -
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the procedure for placing the system into operation, they were not consistent with the control room " operations critical" drawing. For example, system makeup valve 2-PMM-167 is closed by the procedurc, but is shown open on the drawing. The licensee stated that system operation is controlled by the procedure rather than the drawing. Finally, the inspetor found
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that the system drawing in the updated final safety analysis report (FSAR) had ben superseded by three subsegent revisions. The licensee committed to correct the di?crepancy in the next scheduled (FSAR) updat .5 Safeguards Building Ventilation System Walkdown - Unit 3 The inspector performed a review of the Unit 3 engineered safeguards features (ESF) building emergency ventilation system on September 18 to verify system operability, The inspection included a review of system alignment, equipment condition, associated surveillances, and a comparison of the p' ant system drawings to the as-built configuratio The ESF building ventilation system is composed of five safety-related subsystems designed to maintain the residual heat removal, safety injection, quench spray, containment recirculation, and the auxiliary feedwater pump area temperatures suitable for equipment operation and personnel access. Each subsystem is designed to automatically start and limit the temperature in the applicable area to the maximum allowed by design whenever any of the safety-related pumps within their respective area start The inspector noted that the systems were properly aligned and appeared to be in good physical condition. However, four minor de6cient items were identified: the condenser discharge piping appeared to be rusty and sitting in standing water; there were a number of valves with label plates missing or inconsistencies between piping and instrument diagram (P&lD) labels versus plant labels; the P&lD did not show the hot gas bypass valve or the correct arrangement of the condenser vent line; and the P&lD indicated that the compressor inlet and outlet valves were to be locked open while the system lineup specified in operating procedure OP 3314D, " Engineered Safeguards Feature Building Ventilation and Air Conditioning," indicated the required position as open. _ The inspector informed the operations supervisor of these issues; he indicated that they would be addresse At the end of this inspection, the licensee informed the inspector that the P&ID would be changed to incorporate the inspector's Ondings and that the engineering department will address the maintenance issue of the rusty pipe. The licensee also indicated that the missing valve label plates had been replaced, and that the inconsistent valve labeling issue would be reviewed to determine the correct valve identification and ensure accurate plant equipment labeling. The operations department has turned these issues over to the engineering ,
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department for resolution. The engineering department has issued an assignment tracking sheet for these issues, however no action to resolve them had been taken by the end of this inspectio __ _ _ _ _ _ _ _ - _ _ _ _ _ _ . _ _ _
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The impectcr concluded that the inconsistency betwcen the P&lD and the plant labels was of minor safety significance since the valve lineup and label plate ideritifications were identical and proper positioning of the system was achieved. A!though some valves were not identified on the P&lD, the valves were listed in the system valve lineup and were in the correct position for proper system operation. The inspector considered the dispositioning of these items to be appropriate. The inspector also noted that system surveillance and operating procedures for the safety-related equipment in the ESF building did not require verification of its respective ventilation unit operation. Without verification of satisfactory ventilation system operation, the basis for operability of this necessary support system to various ESF components could not be determined. The inspector discussed this concern with the operations supervisor and indicated that this issue remained unresobed pending clarification of the basis for operability of support systems (UNR 50-423/92-24-01), Supplementary leak Collection and Release System inoperability - Unit 3 On September 29, 1992, the licensee determined that both trains of the supplementary leak collection and release system (SLCRS) were inoperable and initiated a technical specification (TS) required shutdown. The licensee declared an unusual event and made all the required offsite notification The SLCRS is designed to ensure that during a loss of coolant accident any containment leakage imo the enclosure building and contiguous buildings will be filtered prior to discharge to the atmosphere. The auxiliary building filter system (ABFS) is designed to control the release of radioactive material from the area of the charging pump and reactor plant component cooling water pumps and heat exchangers in the auxiliary building by directing releases through a filtered path and assisting SLCRS in maintaining a negative pressure within the secondary enclosure around containment. The two systems work together to draw and
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maintain a 0.25 inch water gage vacuum within one minute inside the enclosure and auxiliary buildin As part of ongoing investigations regarding the ABFS design basis and its interaction with the St.CRS (see NRC inspection report 50-423/92-23) and in response to inspector concerns regarding failure to perform surveillance tests in a contiguration which demonstrates the ability to perform as designed following an accident, the licensee performed numerous inservice tests. Inservice Test (IST) 3-92-019, " Auxiliary Building Filter Test," was performed to determine ABFS instrument behavior and to identify parameters which contribute to unreliable fan performance with the fan variable inlet vanes in automatic. Test data identified that the 'IP train ABF filter fan takes approximately 75 seconds to come on line due to time delay settings in the system logic. Due to the SLCRS dependency on the ABFS to assist in drawing the 0.25 inch vacuum, the licensee concluded that the 'IP train of SLCRS would be unable to draw the required vacuum within one minute and that it was questionable whether the ' A' train of SLCRS/ABFS would be able to meet this design requirement. Previous testing had demonstrated that the SLCRS was unable to draw the required 0.25 inch vacuum without the assistance of the ABFS fans. Based on this
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information, the licensee concluded that the 'B' train of SLCRS would not perform its design function and was therefore inoperable. Additionally, the licensee determined that an adequate surveillance of the 'A' train SLCRS capability to draw a vacuum had not been performed as required by TS 4.6.6. l.d(3). Accordingly, on September 29 at 12:45 p.m., the licensee entered two TS action statements; TS 3.6.6.1 for one train (B) of SLCRS inoperable and TS 3.0.3/4.0.3 for failure to perform a surveillance on the ' A' train within the required interva On September 29 the licensee performed IST 3-92-020, "' A' Train Drawdown From Sequencer Panel," to verify satisfactory arr.wdown capability of the ' A' train of the SLCRS and ABFS when sequenced onto the emergency desel generator as they would be in the event of a safety injection signal with a concurrent loss of power, l'est results indicated that the _
' A' train of SLCRS and ABFS could not meet the TS requirement of 0.25 in, wg vacuum within the required time. The system was able to draw the required vacuum after approximately 80 seconds of operation. The ' A' train of SLCRS was also declared inoperable at !1:47 p.m. following the unacceptable drawdown test. The licensee initiated a plant shutdown in accordance with TS 3.0.3. The licensee declared an unusual event and made all the required offsite notifications. The unusual event was terminated on October I at 8:14 a.m. after the plant reached cold shutdown, a condition in which SLCRS operability is not require This issue regarding ABFS and SLCRS operability and the adequacy of surveillance testing performed on these systems is the subject of NRC inspection report 50-423/92-2 .0 NIAINTENANCE (IP 62703)
The inspectors observed and reviewed selected portions of preventive and corrective maintenance to verify compliance with regulations, use of administrative control procedures
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and appropriate maintenance procedures, compliance with codes and standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retest. The inspectors reviewed portions of the following work activities:
- AWO M3 92-18903, inspect and verify damper position of 3HVR*AOD 40B (SLCRS Boundary)
- AWO M3-92-16073, MEQ, 3 year required maintenance - neoprene seal inspection and verify damper position of 3HVR*AOD 33B (SLCRS Boundary)
- AWO M1-92-10152, Restore oil in 'A' ESW strainer
- AWO M2-90-15619, inspect and calibrate instruments (spent fuel pool temperature)
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- AWO M2-92-10849, Retest engineered safeguards actuation system modules
- AWO M2-92-07260, Overhaul 'B' enclosure building Gltration system fan motor Maintenance activities were observed to be good; the following observations were mad .1 Emergency Service Water Stiainer Declared Inoperable - Unit 1 Millstone Unit I has two redundant Emergency Service Water (ESW) system trains which supply cooling water to the low pressure coolant injection (LPCI) system heat exchanger Each ESW system has a rotating self cleaning strainer which keeps debris out of th individual LPCI heat exchangers. On September 16, 1992, while performing preventative maintenance checks on the 'A' train ESW system strainer at Millstone Unit 1, maintenance personnel noted that the strainer gearbox assembly did not contain lubricating oi Maintenance restored the level in the gear box by adding six quarts of oil and tested the strainer for galling by veriGcation of proper motor amperage. The abnonnally low oil level was documented by plant incident report (PIR) 1-92-13 On September 18, 1992, the licensee inspected the gearbox assembly of the 'A' ESW strainer. During the inspection, small metal fines were noticed in the gearbox oil; however, no significant wear was identified on the worm or drive gear assemblies. The gearbox assembly was subsequently removed and replaced with a spare assembl The gearbox assembly of concern was installed on August 26,1992, when the previously installed ESW system strainer tripped on thermal overload during a surveillance test, The strainer motor trip and other issues concerning strainer procurement / installation were discussed in NRC inspection report 50-245/92-22. During installation of the strainer assembly, the lube oil level in the gearbox was not checked prior to declaring the strainer operable. According to the strainer manufacturer, without adequate lubricating oil in the gearbox assembly, sustained operation of the strainer during an accident event could not be assured. Therefore, the 'A' train of the ESW system was potentially moperable from the time of the gearbox installation on August 26,1992, until replenishment of the oil on September 16. Since this time period exceeded the seven day out-of-service time allowed in Unit i Technical Specification (TS) 3.5, " Containment Core Cooling Subsystems," the
- licensee reported the TS violation in Licensee Event Report (LER) 92-24, dated October 16, 199 The strainer assembly of concern was ordered from the manufacturer during the Summer 1991 refuel outage to replace an old strainer body which foiled a hydrostatic test. According to the licensee engineers, the strainer gearbox assembly was shipped from the manufacturer .
with oil. However, prior to installing the strainer body, the licensee elected to utilize the old strainer gearbox assembly. Accordingly, maintenance personnel drained the oil from the new gearbox assembly, removed the gearbox from the strainer element and installed the old drive assembly. This modified strainer body was then installed in the ESW system in August
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1991. The unused gearbox assembly was left in the maintenance shop until August 1992 when it was placed on a spare strainer element and installed in the ESW syste To prevent recurrence of the event, the licensee revised the procedures governing the repair and installation of the ESW strainers, to require verification of proper lubricating oil prior to declaring the component operational. All procedures governing the repair of rotating equipment will be reviewed to ensure lubrication is verified prior to work completio Additionally, because of the numerous component operability issues which arose during the strainer replacement activity, the licensee will conduct an overall review of the plant design change process and how it was followed during the strainer replacement activities. This review will be accomplished to determine if any generic deficiencies exist in the design _
change proces NitC lleview Several program weaknesses and personnel performance issues, which were not documented in LER 92-24, became evident as a result of this event. The first error occurred when Unit I maintenance personnel who drained the oil out of the assembly in 1991, failed to document this action under the description of work section of automated work order AWO M1-91-09985 which installed the original strainer drive assembly on the new strainer elemen Therefore, maintenance personnel who may have referred to that AWO in August 1992, when installing the new gearbox assembly on the strainer body would not be alerted to the fact that oil had been drained from the gearbo When the strainer gearbox was removed from the strainer element, the Unit l maintenance department left the gearbox assembly in the maintenance shop for an extended period of tim Based upon this event the inspector was concerned that licensee personnel were not
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adequately-controlling QA category -1 material once it was issued from the store room and -
that material issued for previous work was being used for new work orders without proper re-certification of the applicability and material condition of the locally stored componen Additionally, the Millstone work control processes do not require specifically that personnel verify that the applicable preventative maintenance actions have been performed on components prior to installation. If preventative maintenance checks were performed on the strainer gearbox prior to declaring the system operable, the low lube oil level would have been detecte At the close of the report period, the licensee had not completed its investigation of the event, closed the PIR, or developed a final corrective action plan. Therefore, the inspector could not determine if adequate corrective action will be taken to warrant the use of enforcement discretion for this issue. Accordingly, unresolved item 50-245/92-25-02 will be opened until the inspector has reviewed the licensee's final corrective actions and determined if enforcement discretion is warranted for the violation of TS 3.5.
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10 Enclosure Building Filtration System Retest - Unit 2 During a routine walkdown of the auxiliary building on October 14, 1992, the inspector identified air leakage at the discharge of the 'B' train enclosure building filtration system (EBFS) fan. Technical specifications require the EBFS to be operable during fuel movement or crane operation ever the spent fuel pool. Also, the system must be able to draw a negative pressure in the area when the irradiated fuel in the pool has decayed for sixty days
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or less, Whenever irradiated fuel is in the fuel pool and the EBFS automatic initiation function is inoperable, the system must be operating in the auxiliary exhaust mode. At the time of this walkdown, new fuel was being moced into the spent fuel pool, all of the irradiated fuel had decayed for more than 60 day, and the EDFS was lined up to ventilate that area, operating continuously in the auxiliary uhaust mode because an out-osservice radiation detector rendered the automatic initiation Ometion inoperable.
- Immediately upon being informed of the inspector's Ondmg, the licensee investigated, found more leakage around the fan housing, and initiated a plant incident report to track resolution of the problem. A test was performed which verified that the technical specification flow requirement of 9000 +/- 10% cfm was satisfied. Also, temporary repairs were made to the ductwork until the fan could be taken out of service for permanent repairs. The inspector found these short term corrective actions to be acceptabl The inspector reviewed the maintenance retest requirements of administrative procedures ACP-QA-2.02B, " Retest," and ACP-QA-2.02C, " Work Orders," and the automated work order packages (AWO M2-92-07259 and h12-92-07260) associated with the overhaul of the
'B' EBFS fan and motor in late July 1992. Regarding post-maintenance retests, the ACPs require that tests be proposed by the appropriate department head, documented on the AWO, and reviewed and et .icurred with by the operations shift supervisor or supervisory control
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operator, If the retest is performed as part of an approved surveillance procedure, the-appropriate data sheets are to be appended to the AWO package and forwarded to the document control facility. This provides an auditable trail of the successful completion of the maintenance activity. At Millstone 2, the procedure MP-270lX, " Maintenance Retest Guidelines," implements the requirements of the ACPs. Form 270lX-3, " Miscellaneous Equipment Retest Matrix," for fans requires the performance of operational checks to verify
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component operability, vibration moni toring, and a check of motor running current. -These items were documented on the AWO. The inspector noted that item two of the matrix,
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which requires a check of mechanical joints for leakage, is not applicable to fans. The licensee indicated to the inspector that the adequacy of the retest matrix for fans would be reviewe The inspector found that surveillance procedure SP-2609D-1, " Enclosure Building Filtration System," had been performed satisfactorily on August 6 prior to placing the system-into-service. The surveillance tests system Dow and differential pressure across the combined high efficiency filters and charcoal absorber. In this case, previous testing of the EBFS
. system in the auxiliary exhaust mode had demonstrated the importance of eliminating leaks t
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I1 from system ductwork and across dampers, and that the existence of required system flow alone did not demonstrate operability of the system. No verification of fan boundary ir.tegrity had been specified or performed. Additionally, the completed surveillance forms were not appended to the work package, nor was the work order annotated to indicate that the surveillance had been performe Through review of other work packages during the outage and discussions with Unit 2 operations and maintenance personnel, the inspector considered this occurrence to have been an isolated case. Nonetheless, failure to perform an adequate post-maintenance retest of the
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fan and establish an auditable trail tying the retest to the maintenance activity is c violation of Millstone procedures and 10 CFR 50, Appendix B, Criteria XI, " Test Control,"_ and XVII, -
" Quality Assurance Records," Similar problems have been noted recently on the Unit 3 hydrogen recombiner system (NRC Inspection 50-423/92-23). As this issue had minor safety significance, enforcement discretion was exercised in accordance with section Vll.B of the NRC Enforcement Policy. However, licensee review and upgrade of the work control process including retest and record keeping remains unresolved under the formerly issued identincation number (50-423/92-23-002). Service Water Piping Degradation - Unit 3 On October 5,1992, while performing a leak test of the 'A' train safety injection pump cooling water (CCl) system the licensee identified a pinhole leak on the service water (SW)
header in the engineered safeguards feature (ESP) building. The SW system supplies cooling water for heat removal for various components / systems. The SW to the ESF building supplies cooli. water to the air. conditioning (AC) units in the ESF building and the CCI system heat ex . angers. The ESF building AC units start whenever any safety related pump within their respective area starts to provide a suitable environment for equipment operatio >
The CCI system provides cooling for the safety injection pump lube oil coolers. The licensee determined that the leak was caused by erosion / corrosio As part of the investigation, the licensee removed the lagging from all the SW header fittings -
in the ESF building and visually inspected them for indication of system degradation. Of the fittings inspected the licensee identined one leak and four areas which had indication of salt deposits. The licensee repaired the leaking joint and performed ultrasonic testing (UT) of the other potential problem areas as well as ten additional areas to determine if there was any indication of wall thinning and to evaluate overall system condition. Of the-fourteen areas inspected the licensee found four indications of system degradation. All but one of the piping areas measured were signincantly above the minimum required wall thickness. The licensee repaired one of the degraded areas and processed non-conformance reports (NCRs) to document the deficiencies for the other three areas. One problem was determined to be the result of piping outside diameter defects. The other two NCRs documented piping degradation. In addition to inspecting the ESF building SW header, the licensee visually inspected the lagged and exposed areas of the small bore piping in the ESF building, the SW-l
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header to the control building AC water chillers, and the atailiary building SW supply header to the charging pump coolers, and the motor control center and rod control area ventilation unit The licensee determined that the mechanism causing the wall thinning was erosion / corrosion impingement attack. This is a highly localized form of corrosion caused by high local turbulence downstream cf cibows, tees, and valves. This corrosion typically affects only a few inches of pipe length. Since 1987, the SW system has experienced chronic minor leak The licensee has determined that many of the leaks have occurred in the small/ medium bore copper / nickel pipe. The leaks appear near pipe tees, elbows, or reducers. Where possible, the licensee has replaced elbows with wide radius sweeps to decrease crosion. The licensee also replaced some copper / nickel piping with monel which has a higher corrosion resistanc The licensee informed the inspector that they are in the process of developing a monitoring program for inspecting the SW syste The inspector visually inspected portions of the SW header in the ESF building and reviewed the discrepancies identified by the licensee. The inspector concluded that the scope of inspection performed by the licensee was comprehensive and demonstrated a high regard for preserving service water system integrit .0 SUltVEll l.ANCE (IP 61726)
The inspectors observed and reviewed selected portions of surveillance tests, and reviewed test data, to verify compliance with: procedures; technical specification limiting conditions for operation; removal and restoration of equipment; and, review and resolution of test deficiencies. The inspector reviewed portions of the following tests:
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- SP 3026.5, Service Water Pump 3SWP*PIB Operational Readiness Test
- SP 3440A01, Plant Startup Surveillance, Operational Test of Source Range Neutron Flux Reactor Trip
- IC 412G, lireat Detection Valve Permissive Functional and Calibration Test
- SP 611.1, hiain Steam isolation Valve Closure functional Test
- SP 66S.2, Gas Turbine limergency Fast Start Test
- IC 2435A, llalance of Plant Instrument Calibration - Operating (Spent Fuel Pool Temperature)
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- SP 2402AO, Spent Fuel Pool Area Radiation Monitors Calibraticn
- SP 2404AN, Spent Fuel Pool Area Radiation Monitors Functional Test Surveillance activities were observed to be good; the following observation was mad .1 Area Radiation Monitor Calibration - Unit 2 The inspector witnessed a spent fuel pool area radiation monitor logic function test conducted in accordance with portions of the system calibration procedures SP 2404A0 and SP 2404A The calibration constituted a retest of work performed on associated engineered safety features actuation system (ESFAS) modules. The monitors provide indication of radiation levels around the spent fuel pool; any two of the four monitors will initiate emergency ventilation of the area in the event of a fuel handling accident. Since the ESFAS actuation cabinets were deenergized for maintenance, the ventilation system was operated continuously in the emergency mode. The inspector verified that the calibration had been authorized properly by the operations shift supervisor; that the procedures in use contained the most recent revisions and changes; and that the test equipment was in calibration. While walking down the system, the inspector found that the detector for the spent fuel pool southwest area radiation monitor (RM 8139) was partially blocked by a portable steel cabinet. The licensee promptly moved the cabinet. None of the remaining three monitors were obstructe Though the instrument indicated approximately the same as the other area monitors, the inspector was concerned that the cabinet could attenuate area radiation levels at the monitor and result in nonconservative readings. Upon further review by the NRC Region I staff, it was concluded that the presence of a cabinet in front of the radiation monitor would be unlikely to cause a problem with the monitor readings. However, it is a good practice to keep radiation monitors unobstructed. The inspector had no further questions regarding this surveillance activit .0 ENGINEERING /TECIINICAL SUPPORT (IP 37700, 37828) Motor-Operated Valve Operability - Unit 2 in July 1992 a partial loss of normal power (LNP) event occurred at Millstone 2. The event -
is documented in inspection report 50-336/92-22. In response to the event, the licensee reviewed the design of the engineered safety features actuation system and found certain failure modes which could result in inadvertent opening of the pressurizer power-operated relief valves (PORVs). This would require isolation of the PORVs by closing the motor--
operated PORV bkick valve The PORVs provide overpressure protection for the reactor coolant system by opening on receipt of a pressurizer high pressure reactor trip signal. The valves are sized to pass the maximum steam surge resulting from'a control element assembly withdrawal accident -
initiated at low power, and to prevent lifting of pressurizer code safety valves on a loss of
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load accident from full power operation. Each PORV is provided with a motor-operated block valve to permit isolation in the event of valve leakage. In operating modes 1,2, and 3, technical specifications require both PORVs and block valves to be operable. Operation with one PORV inoperable is permitted provided that its associated block valve is shut with its power removed within eight hours. Otherwise the plant must be placed in the cold shutdown condition within the following 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> No credit is taken for PORV operation in the overpressuri7.ation accident analysis contained in the Millstone 2 Final Safety Analysis Report. Failure of both PORVs in the open position is an analyzed loss of reactor coolant inventory event with acceptable consequences provided that the charging and/or safety injection systems are operable. However, failure of a PORV to close was a significant contributor to the Three Mile Island (TMI) Unit 2 accident item II.D.1 of the NRC TMI Task Action Plan (NUREG-0660) required, in part, that licensees determine expected PORV and block valve operating conditions through use of accident analyses and apply the single failures of those analyses such that the dynamic forces on tne valves are maximized. The licensee participated in a PWR owners group program which tested typical block valves and correlated the results to tne valves actually installed in Unit The NRC reviewed and approved the licensee's approach to assuring block valve operability in a safety evaluation report and subsequent correspondence issued in 1988. Due to the ,
recent licensee discovery, in response to the LNP event, of risk-significant failure modes involving inadvertent PORV actuation with safety injection systems unavailable, the inspector initiated a detailed review of PORV block valve operability, in May 1992, the licensee initiated a reportability/ operability determination (REF) based on new motor-operated valve (MOV) target thrust calculations which suggested that the block valves would not have been capable of isolating a stuck open PORV under worst case design basis conditions. A preliminary fmding in July 1992, supplemented by updates in August and September, concluded that the valves were operable. The inspector reviewed the information relied upon by the licensee to support this conclusio NRC Generic Letter (GL) 89-10, " Safety Related Motor-Operated Valve Testing and Surveillance," requires licensees to develop and implement a program to assure that valve motor-operator switch settings for valves in specified systems are selected, set, and maintained so that MOVs will operate under design basis conditions. Millstone 2 has included the PORV block valves in this progra The licensee contracted Babcock & Wilcox Nuclear Services (BWNS) to perform MOV evaluations using Babcock & Wilcox's (B&W) PC-based motor-operated valve evaluation (MOVE) program. The program determines the thrust required to operate an MOV under design conditions and evaluates the thrust producing capability of the valves. The MOVE -
program utilizes a standard valve operator sizing formula to determine design thrust requirements and compares it to operator thrust and torque limits, spring pack capability,
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motor undervoltage capability, and valve load limits. Design inputs, including valve factor, stem coefficient of friction, and system line and differential pressure, are provided to BWNS by the license The inspector reviewed the input assumptions for the PORV block valves and the MOVE program results for calculations performed on April 24, July 2, and July 23,1992, and had the following observations:
- Valve seat diameter was changed from port size to actual seat diameter. This results in a higher thrust requirement and is conservativ * Use of a stem coef0cient of 0.2 results in a higher thrust requirement and is probably conservativ * Valve diagnostic data (VOTES) indicates that a stem packing load assumption of 1500 pounds is conservativ * For worst case scenarios, an assumed differential and line pressure of 2485 psig may be conservativ * A valve factor of 0.3 is assumed. This is the value speciDed by Limitorque, and was standard industry practice, for solid wedge gate valve The MOVE calculations indicated that the PORV block valves would not have developed the required closing thrust without exceeding the thrust and torque limits of the actuator, and that in undervoltage conditions at the motor, the salve would have stalled before torque switch trip. In order to relate the theoretical conclusions to conditions in the field, the inspector compared the licensee's cold, static VOTES data taken in June 1990 for block valve 2-RC-403 and in May 1992 for block valve 2-RC-405 and compared them with design thrust -
requirements assuming a valve factor of 0.3, a stem coef0cient of friction of 0.15, and normal operating pressure of 2250 psig. The inspector found that the switch settings for valve 2-RC-403 provided a margin less than that accounted for by VOTES instrument accuracy and torque switch repeatability. Sufficient thrust was available for valve 2-RC-405, but the valve was over thrusting by approximately 200 pounds. The inspector also noted that, since the calculations use nominal bus voltage, the valves may have stalled under design bas:s undervoltage conditions. Finally, the inspector noted that the licensee was modifying the vac actuator gear ratio and changing spring packs to provide more thrust capability, ,
The plata des lgn change records state that the modifications are necessary since initial calculation results could not provide reasonable assurance that the valves were capable of performing their design functions. This conclusion was consistent with the inspector's findings and appeared to conflict with the preliminary operability determination in the RE Due to the uncertainties associated with operability of the PORV block valves, the inspector reviewed BWNS calculations for the remaining valves evaluatec by the licensee during the i
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I 16 current refueling outage. Fifteen other valves in the main steam, auxiliary feedwater, safety injection, and component cooling systems were identified by the MOVE program as being inoperable, and all are being modified to increase thrust capability. Noting that REFs were initiated for only some of these valves, the inspector questioned the basis for this decisio The licensee responded that the other valves were considered operable based on the engineering judgement that input differer,ttal and line pressures were overly conservativ The valves selected for evaluation under the REF process represented those where more serious problems were felt to exist. The licensee also stated that for NRC reporting purposes, GL 89-10 analysis results were not applicable to past operating cycles before which time the generic letter was not part of the plant licensing basis. Where operability problems were not found in the past, the licensee found no requirement to evaluate historical operability using the new methodology. The inspector stated that this position appeared to conflict with the NRC position expressed in Supplement i to the generic letter, which states that licensees must meet the reporting requirements of 10 CFR 50.72 and 50.73 with regard to identification of deficiencie The inspector observed that the BWNS design thrust calculations upon which the licensee's valve modifications were based assumed a valve factor of 0.3. Previous NRC information notices Generic Letter 89-10, industry experience, and the results of licensee valve testing pursuant to NRC llulletin 85-03 conflicted with this assumption. In a memorandum dated December 1989, the licensee compared its test results with those of NRC and industry sponsored test programs and concluded that for solid wedge gate valves, a valve factor of probably was reasonable. While agreeing that the assumed valve factor is irrelevant for valves which are demonstrated to be operable when tested under design basis conditions, the inspector was concerned that the licensee's current program did not take adequate account of industry experience. For those valves which will not be tested under design basis conditions, the inspector considered that the licensee had not justified adequately the use of a potentially nonconservative valve facto The inspector concluded that the PORV block valves may have been inoperable under certain design basis conditions, and questioned the licensee's failure to identify and report this condition to the NRC. The inspector also questioned why the design basis of the block valves remained undetermined in light of a long-standing TMI Action Plan requiremen With regard to the other valves in the generic letter program, the inspector questioned the validity of assuming potentially nonconservative valve factors despite industry experience to the contrary, and was concerned that design basis inputs to the MOVE program appeared not to have been well thought out by the licensee. Finally, the inspector was not satisfied that the licensee had understood and applied NRC ieporting requirements to the generic letter program finding _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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This item is unresolved (50-336/92-27-03) pending the following licensee actions:
- Justification of using a valve factor of * Reconciliation of the apparent con 0ict between the preliminary operability determination and the implementation of valve modification * Explanation of why the valve design basis, supposedly settled under the TMI Action item between 1982 and 1988, was still undetermined in 199 *
Resolution of the reportability of valves found inoperable by GL 89-10 standard .2 Auxili"y llullding Filter Operability Determination - Unit 3 Since initial startup the licensee has not fully understood the auxiliary building filter system (ABFS) design basis and operating parameters, in addition, the licensee did not test the ABFS and the supplementary leak collection and release system (SLCRS) in a manner so as to verify the system capability to perform its design function following an accident. This issue is the subject of NRC inspection report 50-423/92-23. At the conclusion of that inspection in mid-September 1992, the licensee's evaluation of the design, operation, and testing of the SLCRS and ABFS was continuin The SLCRS is designed to ensure that any containment leakage into the enclosure building and contiguous buildings during a loss of coolant accident will be filtered prior to discharge to the atmosphere. The AI3FS is designed to control the release of radioactive material from the area of the charging pump and reactor plant component cooling water pumps and heat exchangers in the auxiliary building by directing these releases through a filtered path and to maintain these areas above 65"F. The ABFS also assists SLCRS in maintaining a negative pressure within the secondary enclosure around the containment building. The two systems work together to draw and maintain a vacuum (0.25 inch water gage) inside the secondary enclosure buildings within 50 seconds of a design basis acciden As part of the ongoing investigation regarding the ABFS design basis and its interaction with the SLCRS, the licensee conducted system inspections and performed extensive system testing to obtain information regarding SLCRS and ABFS performance. As a result of their investigation, the licensee determined that the ABFS would not perform its designed accident function and that the SLCRS performance has degraded since initial plant startup such that the ABFS must function with SLCRS to meet the accident analysis assumptions for SLCRS performance. Through tests and further evaluation, the licensee determined that the SLCRS/ABFS function was inoperable due to the system degradation and design problem Both trains of SLCRS were declared inoperable and the plant was shut down on September 29 (see section 3.6 of this report).
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As a result of timing delays in the ABF fan circuitry, the required vacuum in the secondary enclosure buildings could not be achieved within the 50 second time requirement. During testing the SLCRS was able to draw approximately 0.20 in vacuum without the assistance of the ABFS. About 80 seconds passed before the 0.25 inch vacuum was achieved with SLCRS and ABFS running. The licensee also duplicated the test conditions during initial startup testing in which filter fan cycling and instability with the ABFS in the automatic mode occurred. The licensee determined that the filter fan instability was caused by low flow to the filter fans and that the filter fans cycled due to problems associated with the automatic starting feature of the differential pressure switch. The licensee concluded that the Olter fans ,
cannot operate reliably at Dows less than approximately 15,000 cfm. Other problems
, identified included the need for a fan interlock between the supply and exhaust fan to ensure that two supply fans will not operate with only one exhaust fan running. This condition would prevent SLCRS/ABFS from providing a negative pressure in the auxiliary building in the event of an accident. The licensee also identi6ed that the ABFS is vulnerable to single failure. A single failure of various components in the ABFS could render both trains inoperable by effecting the capability of the system to maintain greater than 0.25 inch vacuum or exceeding the design basis hich/ low temperature limits in the affected area At the end of this inspection the licensee was in the process nideveloping a plant design change record (PDCR) to modify the ABF control circuitry, sequence timing, and control dampers such that the system will be operated in conjunction with SLCRS to dtaw the '
required vacuum following an accident signal and maintain the charging and reactor plant component cooling water areas above 65*F. The plant will remain shut down until the modifications are complete and testing is performed to verify system operabilit Safety Significance As a result of the SLCRS performance degradation and the misoperation of the ABFS, the licensee concluded that in the event of an LOCA, the exposure to _the low population zone
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and the exclusion area boundary would be affected but doses would still remain below the part 100 limit. Assuming a delay in drawdown to a time of up to two minutes, the licensee calculated a total exclusion area boundary dose increase from 150 Rem to approximately 280
- Rem (thyroid dose) using ICRP 2 methodology (current licensing basis). If the same L conditions are assumed but ICRP 30 were used to determine the increased dose the result i I
would be an increase to about 180 Rem. The calculations using both methodologies assume that an untiltered radiological release occurs until the 0.25 inch vacuum is achieved. The failure of the ABFS to automatically actuate would have been annunciated on the main control board. Plant operating and emergency procedures specify operator actions to restore system operation, but not within the time frame assumed in the accident analysis. In addition, the licensee has now determined that operator action to start the Olter fans may not have been successful due to system instability and flow balancing problem . - ,, ..- -
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Summary and Conclusions .
The licenwe did not have a full understanding of the system design, equipment, and testing problems until the plant was shut down in September 1992. Once the probleins were .
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identi0ed and the plant shut down, the licensee initiated a comprehensive investigation to resolve the concerns. The licensee did identify several necessary design and equipment modifications which are being reviewed as part of the PDCR. The inspectors will continue to follow the licensee's closure of these issues. Resolution of this issue will be followed under items opened in NRC inspection report 50-423/92-2 .0 SAFETY ASSESSMENT / QUALITY VERIFICATION (IP 40500,90712,92700) Review of Written Reports Periodic Reports and Licensee Event Reports (LERs) were reviewed for root cause and safety significance determinations and the adequacy of corrective action. The inspectors determined whether further information was required and verified that the reporting requirements of 10 CFR 50.73, station administrative and operating procedures, and technical specifications and 6.9 had beca met. The following reports and LERs were reviewed:
LER 245/92-24 Emergency Service Water Train Rendered inoperable LER 423/92-16 Both Trains of the Auxiliary Building Filter System Inoperable LER 423/92-19 Both Trains of the Hydrogen Recombiner System inoperable LER 423/92-20 Both Trains of the Auxiliary Building Filter System inoperable Unit 1 Monthly Operating Report covering operation for September 1992, dated October 14, 1992 Unit 2 Nonthly Operating Report covering aperation for August 1992, dated September 8, 1992 Unit 2 Monthly Operating Report covering operation for September 1992, dated October 8, 1992
- Unit 3 Monthly Operating Report covering operation for August 1992, dated September 8, 1992 Unit 3 Monthly Operating Report covering operation for September 1992, dated October 14, 1992 The reports reviewed were accurate; the following observations were made.
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7.1.1 Reporting of Fire liarrier Deficiencies While reviewing Plant Incident Reports (PIRS) which were written during the 1989-1991 time period, the inspector noted that PIR l-91-25 which reported an unsealed fire barrier l penetration in the turbine building was not reported to the NRC via a Licensec Event Report (LER). The unsealed penetration of concern was a longstanding condition that was not scaled during the implementation of the Appendix R program at Unit 1. A review of PIRS written during the 1990 time period identified five other instances where Grc barriers required by technical specifications (TS) were found unsealed but not reported to the NRC.
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Millstene Unit i TS 3.12, " Penetration Fire Barriers," requires all Gre barriers which protect safety related components to be operable. If a penetration is not operable, the TS requires a temporary fire barrier to be established of equal effectiveness or a continuous fire watch he established on at least one side of the fire barrier. When the degraded fire barriers were discovered, a continuous fire watch was posted until the discrepant condition was correcte Ilowever, the violations of TS 3.12 were not reported to the NRC as required by 10 CFR 50.73(a)(2)(i)(B) as any operation or condition prohibited by the plant TS. The NRC position that the discovery of a longstanding degraded Grc seal was reportable as a violation of TS, was discussed with the Unit I engineering manager. The inspector noted that Unit 3 routinely reports longstanding degraded fire barriers when discovered, the most recent example being the issuance of LER 50-423/91-29 dated December 23,199 To prevent recurrence of the event, Unit I engineering agreed to disseminate guidance to the engineering and operations departments that longstanding degradations of TS-required fire barriers should be reported to the NRC via an LER. The licensee has commi tted to review previously unreported Gre barrier degradations which were documented in PIRs and to make the necessary reports by November 30,199 The aforementioned reporting inconsistency between Units 1 and 3 is another example of a -
failure of personnel to share information and communicate issues between individual unit This weakr.ess was identified in the most recent Systematic Assessment of Licensee Performance Report. The inspector noted that the failure to report the degraded fire barriers to the NRC via an LER is of minor signi6cance since a fire watch was posted when the degraded barriers were identified and the barriers were eventually rescaled. The inspector determinea that the corrective actions taken by the licensee to prevent recurrence of the failure to report were adequate. Therefore, enforcement discretion was exercised in accordance with section VH.B of the NRC Enforcement Polic .1.2 Report of Degrnded Service Water and Emergency Service Water Systems -
Unit i L On October 2,1992,. the licensee reported to the NRC that an engineering evaluation
- concluded that areas of thinned Service Water (SW) and Emergency Service Water (ESW)
l piping discovered during the July-August outage would not have been able to meet design I
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loads imposed by a Safe Shutdown Earthquake (SSE).' The licensee reported this finding in accordance with 10 CFR 50.72(b)(1)(ii)(ll) as a condition that was outside the design basis of the plan The SW system at Millstone Unit I consists of one common 34 inch header that can be supplied by four pumps. Major cooling loads for the SW system consist of the diesel generator, reactor building component cooling heat exchangers, shutdown cooling heat
- exchangers, turbine building secondary component cooling heat exchangers, and the turbine building component cooling heat exchanger The ESW system at Unit I consists of two 100% capacity systems which are each supplied by two ESW pumps, Each train supplies cooling water to its respective low pressure coolant injection heat exchange The areas of degraded ESW and SW piping are located underneath the floor of the intake structure. In this structure, one 34 inch SW header and two 20 inch ESW headers cross the individual intake bays. The degraded SW piping concerns the area where the ' A', 'B', 'C',
and 'IP SW pump discharge piping ties into the main 34 inch SW-header. Each 'T' joint section of piping had thinned from a nominal wall thickness of .375 inches to .260, .254,
,194, and .209 in:hes. respectively. The degraded sections of ESW piping, consisted of the area where th ' A', 'C', and 'D' ESW pumps discharge into the their respective 20 inch headers. i hose areas of piping had degraded from .365 inches to .236,.250, and .300 inches, respectivel As documented in NRC inspection report 50 245/92-16, the pipe thinning was the result of corrosion which occurred when the protective coating wore off the exterior of the main SW and ESW headers and their associated piping tie-in from the SW and ESW pumps. The coadng degradation exposed the carbon steel piping to the saltwater environment in the intake bays allowing general corrosion to occur. In the 1985-1991 time period, the licensee commenced a program of restoring the piping in the intake bays by removing the corrosion from the piping and painting the exposed areas. However, the effect of the wall thinning-caused by corrosion and grinding and how that thinning affected pipe integrity was not fully assessed on the limiting SW and ESW tie-in points. Specifically, following the restoration effort, licensee engineers measured and evaluated the piping thickness of some discrete areas of the affected piping, but not the T-joints where the minimum wall thickness requirements were most critical. A representative sample of the entire restored area would have been more i appropriate. Further, site engineering evaluated the measured wall thinning against thickness l criteria derived from the pipe pressure criterion and did not consider the more limiting i stresses including joint configuration and seismic stresses. Therefore, the significance of the thinning at the T-joints was not evaluated at that time. In response to another SW pipe integrity concern which caused Unit I to shutdown for repairs in July -1992, the licensee L
L conducted augmented inspections designed to assess the current status of previously identified
! degraded areas. While setting up to monitor a degraded pipe area above the T- joint, the
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Unit 1 inservice Test (IST) technician decided to measure the wall thickness of one T-joint
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for data gathering purposes. Engineering evaluation of the T-joint data determined that repairs were necessary because of the small margin designed into this high stress joint. The licensee subsequently measured and repaired all of the T-joint connection To restore the degraded areas to an operable condition, the licensee installed reinforcing saddles around the tie-in points of the SW and ESW piping; thus redistributing the system stresses and reducing the minimum pipe wall thickness needed to withstand design transient As a long-term corrective action item, the licensee is investigatmg the possibility of moving the SW and ESW piping away from the sah environment by installing it at the ground level in the intake structure. The licensee also has committed to develop and implement by February 1993, a comprehensive SW and ESW maintenance and inspection strategy. This ~
strategy would be used to target areas in the SW and ESW systems for additional inspection, maintenance and monitoring based upon past performance, system configuration and industry es penenc To evaluate the signiticance of the thinning, the licensee contracted with Stone and Webster (S&W) engineering company to analyze the ultrasonic test (UT) data taken on only the SW pipe 'T' joints. Based upon the data supplied, S&W concluded that with the exception of the
'Ir SW "1" joint, all tie-in points would remain operable during normal operating pressure stresses and the stresses of an Operating Ilasis Earthquake (OilE) and Safe Shutdown Earthquake (SSE). However, the ('IT) joint was found to have insufficient wall strength (0.209 vs 0.335 inches) to remain operable during a SSE event. Loss of this joint affects the operability of the entire SW system which would prevent normal safe shutdown of the uni Based upon the conclusions reached by S&W, the licensee conservatively postulated that the ESW systems would also have been rendered inoperable during an SSE even NRC ltesieu During inspection 50-245!92-16, inspector review of this event concluded that there was weak engineering oversight of past maintenance activities which could affect the pipe strength of the SW and ESW systems. Specifically, when maintenance removed the external corrosion from the ESW and SW systems during previous refueling outages, the licensee did not ensure that all areas of the SW and ESW piping still contained adequate wall strength to meet all design requirements. During that inspection, the inspector further concluded that the lack of a systematie approach / program for maintaining the condition of these systems contributed to the degradation of the SW and ESW piping. Specifically, the licensee did not maintain and restore the protective paint on the exterior of the ESW and SW systems before significant wall loss occurred. During this inspection, the inspector determined that no previous instances of significant external corrosion have occurred at the site. The inspector also determined that there are no specific code requirements to establish programs to monitor or evaluate esterior corrosion on piping. Also, periodic volumetric examination of Class 3 systems is not a code requirement. In addition, the identification of the degraded T joint piping during the July 1992 outage was due to good initiative by one technician. The
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initiative resulted from the increasul licensee inspection and engineering review of service water systems initiated following the plant shutdown to repair another SW pipe degradatio Nonetheless, chapter 3.7, " Seismic Design," of the Millstone Unit i Final Safety Analyses Report states that the SW and ESW systems are designed to remain operable in the event of an OllE of .07g and an SSli of .17g This is to ensure the systems are available to shutdown of the plant and maintain it in a shutdown condition. Millstone Unit 1 Technical Specifications (l'S) 3.5.ll " Core and Containment Cooling Subsystems," and TS 3.5.F.,
" Minimum Core and Comainment Cooling System Availability," require the SW and ESW systems to be operable whenever irradiated fuel is in the reactor vessel. If these TS cannot k be met, the reactor is to be placed in cold shutdown wi:hin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee failed to maintain the SW and ESW systems in a systematic manner. Those systems eventually degraded due to exterior corrosion and were rendered inoperable. The inspector noted that the licensee identified and corrected the delicient condition. Further, the long term SW and ESW maintenance plans should prevent recurrence of the even The loss of the ESW and SW systems during a seismic event would significantly reduce the options available to an operator to place and maintain the plant in a safe shutdown conditio Continued reactor cooling using seismically-qualified equipment would be lost. Specifically, the isolation condenser would be available to remove reactor heat. However, the isolation condenser requires make-up water within 30 minutes of actuation and no qualified source of makeup exists. The licensee stated that a qualilled now path from the reactor vessel to the torus via the safety relief valves provides some additional cooling which would allow time for operators to find a makeup source for the isolation condense In accordance with Section Vll.Il of the Enforcement Policy, the NRC exercised enforcement discretion for the service water system degradation and inability to withstand the SSE because of the licensee's identification and correction of the problem; and the fact that no prior instances of significant external corrosion of this nature nor any required programmatic inspections were expected to identify and resolve this issue soone .2 Plant Operations lleview Conmiittee/ Nuclear llevien lloard - Unit 2 The inspector attended one plant operations review committee (PORC) meeting and a combined PORC/ Nuclear Review Board meeting during the inspection period. The PORC meeting agenda included discussion of a plant incident report concerning the failure of a local leak rate test of a containment penetration; approval of a control room ventilation system in-service test, and approval of a plant design change for the ' A' emergency diesel generato The combined meeting was held to discuss plant design changes proposed to mitigate the consequences of a main steam line break inside the containment and issues involving the July 1992 loss of normal power event. Both committees discharged their functions in accordance with relevant technical specification requirements and, through frank and thorough discussion, demonstrated an appropriate regard for nuclear safety, i
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24 Combustion Engineering Reactor llead Studs
- The inspector reviewed the licensee's disposition of discrepant conditions involving the reactor head studs purchased for Unit 3 from Combustion lingineering (Cli). Nonconforming conditions were identined at Millstone during receipt inspection in September 1990, but were not identified by Cli or their subcontractor, PCI linergy Services (PCI), prior to delivery to Niillstone. The hiillstone staff subsequently generated Ove NCRs (NCRs 290 566,290 575, 290 589,290-235, and 200-239) that documented these nonconforming conditions discovered during the receipt inspection and subsequem reinspection of the critical dimensions by the vendor.
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The inspector reviewed the five NCRs, incit. Jing the actions taken to resolve the
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nonconfmming conditions. The nonconforming conditions consisted of discrepancies in documemation and dimensions. All 60 of the reactor head studs were dispositioned use-as is in October 1990. The documentation problems were resolved by rewiving corrected documentation from the suppliers. The dimensional problems were dispositioned as use-as-is
, based on either chasing out internal threads to remove excessive coatings, load testing, running the reactor head nuts over the studs to assure proper fit, or discussions with the supplier about the safety significance of the particular dimensional nonconformance, llased on tl'is review, the inspector concluded that the licensee adequately addressed the
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reactor head stud nonconformances. ;
The inspector also reviewed the actions the licensee took with regard to the performance of Cl! The initial action was to change Cl!'s status on the approved suppliers list from l " approved" to " conditionally approsed." This required anyone who wanted to place an order with Cli to contact Procurement Quality Services to determine what the conditions for placing
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an order with Cli were, This included source inspection for a'l orders for items purchased to the requirements of the ASMF lloiler and Pressure Vessel Code (ASMli Code). The status of Cli has been returned to " approved"t however, the condition of source inspection for ASMli Code orders is still in place. The inspector questioned why the source inspection was only applied to ASMii Code orders. The licensee responc:cd that ASMll Code orders are the only ones for which problems were detected durir.g receipt inspection. The licensee i attributed this to the fact that CII was placing suppliers of ASME Code items on the their I approved supplier list solely on the basis of the suppliers' ASMli certificate. Combustion
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lingineering was not verifying that the suppliers had a quality assurance (QA) pcogram to control characteristics not covered by the ASMB Code, (e.g., dimensions, non-pressure -
boundary parts) or performing inspections to verify the items supplieJ met all requirement The company has since modified their QA program to include tests and inspections to cover characteristics not controlled by the ASMii Cod The inspector noted that the NRC has issued three information notices (IN) that addressed
,- issues similar to those surfaced with CE as above: IN 90-03, " Malfunction of Borg-Warner .
j llolted llonnet Check Valves Caused By Failure Of The Swing Arm," IN 88-95, " inadequate i-- - - - . -
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Procurement Requirements imposed Ily Licensees On Vendors," and IN 88-35, " Inadequate 1.icensee Performed Vendor Audits." The inspector reviewed the licensee's actions taken following receipt of the ins. Each IN was assigned to an individual for review and the need for a response was placed in a tracking syste The licensee concluded that no action was necessary in response to IN 90-03 because none of i the Millstone units had Ikirg Warner valves. The licensee did not recognize or address the !
j generic issue raised by the IN concerning the effectiveness of the qualification and oversight of vendors by licensees, in response to IN 88 95 the licensee concluded that revisions being prepared for two +
procedures would address the issues raised by the IN. The two procedures being revised addressed the preparation and review of purchase requisitions and the use of commercial grade items in safety related applications. The issue of the qualification and oversight of vendors, which was also raised by the IN, was not addressed by the license Actions taken in response to IN 88-35 were documented in a memorandum issued in September 1988 that gave a very positive assessment of the licensec's vendor audit proces There was no indication the licensee's review process determined if the problems identified by the IN had or could occur under the licensee's program, in August 1992, the licensee modified the checklist used to perform audits of vendors to include verification that vendors hssure that their sub-suppliers control important attributes for the items supplied. Combustion Engineering had been audited in 1987 and was not due to be audited again until 1990. The inspector observed that if the licensee had fully used the -
information supplied by the ins to assess their vendor audit programs at the time the ins were issued, that would not have affected this event because of the delay between the notifications and the next triennial audit. However, if the licensee factored the information from the ins into the annual assessment of vendors, the fact that CE's program for controlling sub-suppliers was not adequate may have been discovered prior to the receipt inspection of the reactor head stud Ilased on the changes the licensee recently made to their program for auditing vendors, the inspector had no further questions concerning the program for procuring material or monitoring vendor performanc .4 Followup of Previous inspection items 7.4.1 Effectiveness of 1,1censee Receipt inspection Program Unresobed item (245/92-12-01) involves three issues: commercial grade electrical connectors installed in nuclear instrumentation, nonconforming commercial grade fasteners accepted by Stone & Webster (SWEC) and transferred to Millstone stores, and a i
programmatic issue concerning the effectiveness of SWEC's and the licensee's receipt r
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, inspection programs. The inspector reviewed and ulxiated the status af all three issues during this inspection.
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Stone & Webster Fastener Materials - Unit 3 An update of the licensce's efforts to resolve the SWEC fastener issue was previously provided in NRC inspection report 50-423/9216. As noted in that report, the licensee had selected a total of 90 faswners for tensile testing; 30 from each of the three manufacturers l that supplied fasteners. The tample included fasteners with porosity, linear indications, :
oversired heads, and undercut, During this inspection, the inspector reviewed the test result !
With the exception of one cap screw, all of the fasteners tested had acceptable test results.
, One cap screw manufactured by Bethlehem Steel, identined by the manufacturer's mark BS, i only had a ten:ile strength of 121.3 ksi, compared to a speciDed minimum of 125 ks ,
However, the cap screw did have an acceptable y!cid strength and when pulled to failure; it l failed in the threaded portion, the portion of the fastener expected to fail, llased on these results, the licensee concluded that the nonconforming conditions have not adversely affected
, the ability of the fr.steners to perform their function. The licensee initially stated that the remaining fasteners that were transferred from SWEC to Millstone stores would be scrapped, llowever, due to ongoing maintenance, the licensee did install some of the fasteners in the units after performing additional inspections and dedicating the fasteners prior to installatio This portion of the unresolved item is considered close Nuclear lustrumentation Electrient Connectors ,
As noted in NRC inspection report 50-245/92-12, a procurement engineer preparing to order electrical connectors for nuckar instrumentation from General Electric (GE) noted that on the previous order GE had supplied commercial grade connectors when safety related connectors had been specified. Based on this discovery, the licensee initiated plant incident report (PIR)
1-92 052 to document the problem and initiate a review to determine the cause of this erro To characterire the extent of the problem, the licensee reviewed documentation for purchase orders issued for safety related items during the 1988 - 1989 time frame, including purchase orders issued to GE. For the GE purchase orders, the licensee limited the scope of the ' .
review based on changes in the licensee's program during 1989 and changes GE made in i 1989 to their program for handling discrepancies between the purchase order and the items being supplied. In addition, as reported in the inspection report referenced above, the inspector reviewed eight purchase orders from the 1988 - 1989 time frame and found an example of GE supplying commercial grade electrical connectors when safety-related connectors were ordered; this was not identiDed previously by the license The licensee's review of the documentation on purchase order 116668 showed that the ,
electrical connectors had been ordered from GE as safety-related for use in nuclear i
- instrumentation. General Electric ordered the connectors from Reuter-Stokes, a subsidiary of l Gil. The parts were received by the licensee with certificates of conformance that stated that the supplied products were supplied in conformance with the purchase order quality
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requirements. At receipt inspection, the licensee identified that the part numbers on the connectors did not match those ordered and issued a nonconformance report (NCR) on December 6,1988. In response to the NCR, on 1)ecember 14, 1988, GE sent a facsimile of a memorandum dated November 18,1988, (previously sent to the purchasing department supervisor at Millstone) that stated that the part numbers had been changed and that the parts provided had the same tit, form, and function as the original parts, liased on the information contained in the facsimile from Gli, the licensee accepted the part Ilowever, during the review of the facsimile the licensee failed to notice that the Nos ember 18, 1988, memo included a statement that Reuter-Stokes needed to know the system where the parts were to be used to assure that the parts were suitable for the _
application. In addition, the memo also stated that the quotation for the parts was for an unspecified nonsafety related applicatio When the problem was brought to GI!'s attention in March 1992, Gli performed a 10 Cl R Part 21 seportability evaluation for the connectors. This evaluation concluded that the problem was not icportable. Their conclusion was based on reviewing the failure modes and concluding that either the failure was in the safe direction or that the failure was very unlikely given the actual system condinons where the parts were installed, llased on the information provided by GE, the licensee concluded that the installed connectors were acceptable. General Electric did conclude that it was an error on their part to complete the order without resolving the discrepancy between the stated request for safety-related connectors and the listing of a nonsafety-related part number in the purchase order. As corrective action, Gliinstructed their employees to resolve all customer purchase order discrepancies prior to filling the order. In addition, Reuter-Stokes has since revised their certificates of conformance to more clearly note whether the material being supplied is safety-relate To date the licensee has not determined why engineering personnel were not initially aware of the November 18. 1988, memo informing Millstone that the parts ordered were nonsafety-related prior to the parts being receipt inspected on 1)ecember 6,1988. The licensee has also not determined why engineering did not recognize that the parts supplied were nonsafety-related when engineering used the memo as the basis to disposition the parts as use-as-is on December 14, 1488. The licensee's teview of this issue is ongoing and has been referred to the Project Services Division for an independent assessment of the root cause of the proble This portion of the unresolved item remains open pending NRC evaluation of the licensee's review and corrective actio Programmatic Receipt inspection issues As a result of the questions raised concerning the effectiveness of the licensee's and SWEC's receipt inspection programs discussed atiove, the licensee initiated a corrective action request (CAR) 02-04. The purpose of the CAR was to provide reasonable assurance that SWEC's
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quality assurance program for Category 1, non-engineered items identified nonconforming l items and prevented their installation in Unit To accomplish this, the licensee reviewed SWEC's program for establishing purchase order ,
and receipt inspection requirements. The licensee concluded that appropriate procedures existed it, assure the quality of Category 1, non-engineered items. To review the implementation of the procedures, the licensee reviewed approximately 4,500 receipt inspection reports (RIR) and selected about 1,000 of these that identified nonconforming conditions for detailed review. From this review, the licensee concluded that SWEC's program was effective in assuring the quality of Category 1, non engineered items and closed the CAR on August 24, 199 The inspector reviewed the licensee's analysis and a portion of the background information on which the analysis was based. The background information was segregated by the basic specification under which the item was procured. The inspector reviewed the background information associated with the speci0 cations for installation of electrical items (E350),
erection and installation of piping (M968), and instrumentation installation (1943), in addition to the information reviewed by the licensee, the inspector also reviewed the requirements for Category 1, non-engineered items in each of the basic speci0 cations mentioned abov The inspector reviewed 19 RlRs from the background information for items purchased under the electrical installation specification. Thirteen of the RIRs were for fasteners, one was for terminal bh>cks, and five were for support parts and materials. Several inconsistencies between RIRs for similar items and between the RIRs and the specification requirements were noted, The electrical installation speciGeation required that fasteners purchased as Category 1, non-engineered were inspected upon receipt for manufacturing imperfections. The inspector believed that the attribute from Quality Assurance Directive (QAD) 7.7, " Receiving inspection - General," that covers manufacturing imperfections is fabrication. Of the thirteen RIRs for fasteners, three included the fabrication inspection attribute and ten did no Specification E350 requires that the receipt inspection for terminal blocks include a random check to verify proper sizes, lengths, and compatibility. In addition, for terminal bhxks subject to radiation, the block insulation material is required to be polysulfone produced by a specific company. The RIR included the attributes of manufacturer's documentation, damage, marking, and cleanliness. The RIR did not include dimensions, fabrication, or material propertie The inspector reviewed eight RIRs from the background information for items purchased under the piping installation specification. Two of the RlRs were for Category 1, Engineered items rather than Category 1, non-engineered items. The remaining six RIRs were for items purchased to the quality requirements of Appendix B or Section 111 of the ASME Boiler and
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Pressure Vessel Code. No discrepancies were noted in these 1(lits, although it should be noted that the two l(lits for Category 1, lingineered should not have been included in the revie The inspector reviewed five Itllts from the background information for items purchased under the instrumentation installation speci0 cation. Three of the itilts were for fasteners, one was for tubing, and the other was for tube clamps. One of the Itllts for 7ine plated fasteners did not include the attribute for coating / preservatives, which should have been inspected according to QAl) 7.7. The other Itllts correctly reflected the sircification requirement With the exception of the discrepant bolts addressed above, their have been no other accepted i non-engineered items which have subsequently been found to be non-conforming. Therefore, l l it appeared that the SWi!C receipi inspections had been effective, llowever, the inspector l
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was concerned that the receipt inspections may not have inspected all the required attribute Addnionally, the inspector concluded that the licensee closed the CAlt without adequate justi0 cation that the SWiiC receipt inspections had been conducted in accordance with QA program requirements.
l 1.icensee review of these concerns identiDed that SWi!C receipt inspections for non-engineered items relied heavily on the experience of the inspector and did not strictly follow QAl) 7.7 Specifically, the receipt inspector would decide what needed to be inspected by ,
review of pnwurement documents. lie conducted the inspections and documented the results )
on a generie checklist. Therefore, any required attribute could have been iaspected and l documented m another attribute of the inspector's choic The SWiiC program was not consistent in documenting inspection attributes reviewed and !
may not always have assured that all inspection requirements delineated in the basic-specincations were included in the receipt inspections. Ilowever, the licensee's current receipt inspection program is deliberate and controlled, and consistent in the choice of required attributes and the documentation of the result. Since there have been no unacceptable SWi!C parts identiGed in use in the field, the inspector had no further questions in this area. This portion of the unresolved item is close .4.2 Technical Specification Violations involving Containment integrity and Safety System Opernbility - Unit 2 The Orst violatinn (336/90 22-01) involved two failures to maintain containment integrity during fuel movement. The Orst incident occurred when a supervisory control operator opened a steam generator atmospheric dump valve while a steam drum manway was open, thus creating a direct path from the containment to the atmosphere. The valve was opened in spite of a procedure cautionary note and valve tagging instructions. The second incident occurred when containment purge system valves were opened without automatic isolation
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30 capability. Another combined violation (336/92 04-01 nnd 336/92-04-02) involved entry into and operation in mode 4 (flot Standby) with the required high pressure safety injection system train inoperabl The licensee attributed both violations to a combination of inadequate administrative controls, personnel error, and lack of attention to detail. Corrective actions included procedure revisions, operator shift turnover process enhancements, control room status board improvements, and operator training. The inspector reviewed these actions and noted in particular that operating procedure OP-2201, " Plant l{catup," and operations department instruction 2-OPS-l.14 " Conduct of Operations," had been strengthened by the addition of independent reviews of system status prior to changing operating modes and following shift turnover. During the present refueling outage, an assessment of plant status in terms of shutdown risk is performed daily. Plant operators have received formal training on leamwork, and human performance, and have attended bric0ngs on lessons learned from previous operational event Through attendance at shift turnovers and discussions with plant staff, the inspector observed that operators at Millstone 2 typically perform shorough and professional shift chnnges and are knowledgeable of plant conditions and system configurations. Since the inspector considered that the licensee's corrective actions addressed the causes of the violations acceptably, these items are closed, llowever, a recent loss of normal power / loss of spent fuel pool level event, attributed to personnel error in the performance of an electrical system tagout, indicated a continuing need for aggressive licensee response to human performance issues. The effectiveness of the licensee's corrective actions will be assessed further by the Millstone resident inspector staff during fuel reload and startup from the present refueling outag .4.3 Flooding of Feedwater IIcater - Unit 2 This violation (336/9214-02) involved inadvertent Gooding of a feedwater heater while personnel were working inside the heater shell. The inspector attributed the incident to the licensee's failure to follow administrative work controls properly prior to releasing the heater for maintenance. The licensee's corrective actions included changes to the operations department instruction regarding system venting and draining; operator briefings on the violation, its causes, and corrective actions; and a commitment to review the incident with operators at the other Millstone units and at the lladdam Neck phnt. The inspector considered the licensee's corrective actions to be acceptable and verified that they had been implemented at the Millstone units. Ilowever, the inspector found that lladdam Neck was not aware of the issue. The inspector discussed with the licensee the NRC expectation that corrective actions to which the licensee commits will be implemented in a timely fashio While this item is closed, implementation of corrective actions for enforcement issues at the licensee's other nuclear units is unresobed (336/92-27-04) pending NRC review of future licensee performance.
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7. Verification of Plant Records Accuracy (Tl 2515/115)
This temporary instruction (TI) provided guidance to the inspectors for evaluating the licensce's ability to obtain accurate and complete log readings from both licensed and non-iicensed operators. The need for this type of inspection became apparent following the identification by several licensee't that plant records (operator logs) may have been falsified, in April 1992, in response to industry findings that plant equipment operators (Pl!Os) were falsifying their rounds log sheets information, the licensee conducted an internal review of Pl!O performance at the three Millstone units. A management team from the line organization was assembled for this task. The team compared rounds log sheets and security information for ucry individual performing PEO rounds over a six month period (October 1991 to March 1992) at a preferred frequency of about one shift per month per PE Several PEOs were identified with discrepant logs. Details regarding the management team investigation, results, and licensee response are contained in NRC inspection reports 50-245/92-12, 50-336/92-12, 50-423/92-11; and 50 245/92-14, 50-336/92-15, and 50-423/92-1 An independent revicw team (IRT) was chartered to determine the root cause and generic implications of this problem and recommend corrective actions. The team was comprised of personnel trom each unit and the corporate office with experience in the areas of training, licensing, engineering, operations, and human factors disciplines. The IRT final report was submitted to NRC by a letter dated May 21,1992. In addition to personnel accountability, the team identified a number of causal factors which in0uenced PEO performance including:
rounds procedures, management ewectations, commtmications, PEO oversight, and trainin The IRT made a number of recommendations in the areas of procedures, management egeetations, communications, and training to correct this situation. Closure of this matter is pending completion of NRC review of the results of the IRT investigation (see NRC inspection report 50-245/92-14, 50-336/92-15, 50-423/92-14).
At the close of this inspection, the licensee was preparing its response to NRC describing the long term corrective actions planned to prevent future problems with the accuracy of plant record .4.5 Control kod Drive llydraulle Control Unit Yalve Out of Position - Unit 1 Violation 245/91-16-01 concerned the failure of operators to restore a charging header isolation valve for a control rod drive hydraulic control unit (HCU) accumulator to the condition required by the plant operating procedure following charging of the accumulato This incident was similar to an event which occurred six months earlier involving the same valve. 1 ollowing the first event, a plant incident report (PIR) was generated and the corrective action to prevent reoccurrence was developed to provide procedural enhancement and independent valve verification. However, this corrective action was not implemented prior to the occurrence of the second event. The inspector reviewed the licensee's response
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to the Notice of Violation, and commitments to change procedures as described in the licensee's letter dated December 24, 199 i
In response to the initial finding, the licensee took immediate corrective actions to restore the system to its normal configuration, in addition, the Operations Manager issued a memorandum concerning the charging of accumulators which stressed the importance of verifying that the charging isolation header valves are fully opened efter charging operations, and instituted requirements for dual verification of the hydraulic control unit valves upon accumulator charging restoration, l.ong term corrective action to prevent recurrence of the violation included a change in both the plant equipment operators (Pl!O) logs and the accumulator charging procedure. The change to the charging procedure will ensure that the charging header isolation valves are fully open upon restoration of a charging evolution by requiring dual verification. To address the failure of corrective action for the first event to prevent the second, the licensee also revised Administrative Control Procedure (ACP) 10.01, " Plant incident Report," to emphasize the importance of evaluating and closing PIRs in a timely fashion. Specifically, the revised ACP reqmres a PIR to be investigated in two phases. The first phase, which would be used to detect adverse trends in performance, is to be completed typically within a few days of the event. The second phase, which would develop the corrective action to prevent recurrence of the event, should be completed within 90 days unless an extension was granted by the unit director. Administrative Control Procedure 10.1 also requires a quarterly trend report providing statistics of the number of PIRs initiated and closed during the last quarter and the current backlog. No guidance or restrictions regarding the timeliness of implementation of corrective actions was included in ACP 1 The inspector teviewed the Pl!O logs, accumulator charging procedure, and ACP 10.1 and verified that the changes had been made. However, while reviewing the PIR backlog, the inspector noted that the intent of ACP 10.01 was not followed. Specifically Units 1 and 2 each had 28 PIRs which had not received a Phase 1 investigation within a few days of the event, in Unit 3,47 PIRs had not received Phase 1 investigations and 35 PIRs which were greater than 90-days old had not received the required extensions from the unit director, The inspector noted that the licensee revised the PIR investigation process in late 1991 to quicken the investigative phase of the PIR proecss, but personnel do not appear to be able to meet the new requirements. Personnel who are performing the Phase 1 and 2 investigations indicated that they are not able to meet these requirements due to the pressure of higher priority tasks. Additionally, department supervision did not emphasize the importance of PIR investigation and closcout in their respective department The timeliness of investigation and closcout of Millstone issues has been an NRC concern particularly at Unit 3. Specific issues include the Millstone Unit 3 investigation of the fouling of the *1P train of the service water system (NRC inspection report 50-423/91-15),
and the failure of fire dampers on the supplementary leak collection and release system
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33 (reference NRC inspection report 50-423/91-26). The licensee recognized this weakness and subsequently developed a corrective action plan for both deficiencies as outlined in letters to the NRC dated October 30,1991 and March l'7,1992, respectively. These letters also informed the NRC that the PIR investigative praess would be revised to require a timely Phase 1 evaluation of an even liased upon the inspectors' review, it appeared that the corrective action for the two problems originally uted was not implemented appropriately. Also, the untimely response to PIRs contributed to the second itCU event. In addition, the backlog in the PIR investigative pmcess at all three units as described in ACP 10.01 may be contributing to the procedural adherence issues at Millstone. Specifically, licensee management has emphasized that employees follow procedures as written or change the procedure, yet licensee management allows the PIR backlog to occur without addressing the conflict with ACP 10.01. This process could send conflicting signals to licensee personnel regarding procedural adherenc The corrective actions to violation 245/91-16-01 have not yet been implemented effectively, this violation remains ope The backlog of PIRs was also identified by the Nuclear Safety lingineering Group (NSli)
while conducting an internal evaluation of the PIR pmcess. This was documented in an NSli report issued on September 9,1992. At the close of the inspection report period, the licensee had not responded to these findings. Therefore, the effectiveness of the corrective actions taken for NSli findings cannot be assessed, In response to the inspectors observations, the Unit i engineering manager issued guidelines which stated that Phase 1 investigations should be completed within five working days of the event. Phase 2 investigations should be completed within 60 days of the event. At the end of this inspection, the corrective action plans for Units 2 and 3 had not been dev. lope .0 M ANAGEMENT MEETINGS Periodic meetings were held with station management to discuss inspection findings during the inspection period. Following the inspection, an exit meeting was held on November 24, 1992, to discuss the inspection findings and observations. No proprietary information was covered within the scope of the inspection. No written material regarding the findings of this inspection was given to the licensee during the inspection perio __ _ - - . ._ _ __ _ ___ -__ _ __