IR 05000336/1989011

Insp Rept 50-336/89-11 on 890505-0615.No Unsafe Conditions Noted.Major Areas Inspected:Plant Operations,Surveillance, Maint,Previously Identified Items,Allegations,Committee Activities,Licensee self-assessment & LERs

ML20247N306
Person / Time
Site:	Millstone
Issue date:	07/21/1989
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20247N298	List: IR 05000336/1989011 ML20247N295
References
50-336-89-11, NUDOCS 8908020356
Download: ML20247N306 (21)

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.f lL U.S. NUCLEAR REGULATORY. COMMISSION

REGION I

Report No; L50-336/89-11 Docket N ~ License N DPR-65 l

i Licensee: Northeast Nuclear Energy Company P.O.-Box 270

,~ Hartford, CT 06101-0270'

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<E Facility Name: Millstone Nuclear Power Station, Unit 2 Inspection At: .W aterford, Connecticut

' Dates: May 5 through-June 15, 1989

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Reporting _

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Inspector: P.--J. Habighorst, Resident Inspector, Millstone 2 L Inspectors: W. J. Raymond, Senior Resident Inspector

.T. A'. Rebelowski, Senior Reactor Engineer, DRS-G. Vissing, Licensing Project Manager, NRR P.J. Habighorst, Resident Inspector, Millstone 2 Approved by: 8.4. b b 7 bl fB E. C. McCabe,. Chief, Reactor Projects Section IB Date Inspection Summary: 5/5/89 - 6/15/89 (Report 50-336/89-11)

Areas Inspectedi Routine NRC resident and specialist inspection (160 regular

. hours, 19 backshift-hours, and 4 deep backshift hours), of plant' operations, surveillance, maintenance, previously identified items, allegations, committee activities,- evaluation of licensee self-assessment, and Licensee Event Reports-(LERs).

Results: No unsafe conditions were identifie PDR ADOCK 05000336 O PDC

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TABLE OF CONTENTS PAGE 1.0 Persons Contacted... ... ........................................... 1 2.0 Summary ot' Facility Activities....................................... 1

' Previously Identi fied Items (93702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 3.1 (Closed) Temporary Instruction (TI) 2515/91, " Inspection Follow-up to Generic Letter 83-28, Item 4.1".................. 1 4.0 Facility Tours (71707)............................................... 2 5.0 Plant Operational Status Reviews (71707/73753/37700)................. 2 5.1 Steam Generator (SG) Tube P1ugs................................. 2 5.2 .10 CFR 50.59 Reviews.......................................... . 5 5.3 Reactor Coolant System (RCS) Hot Leg Temperature (Th)

Oscillations and Divergence... ..... ......................... 6 6.0 Licensee Event Repor : ( LER) Revi ew ( 92700) . . . . . . . . . . . . . . . . . . . . . . . . . . 8 7.0 Committee Activities (40500)......................................... 9 8.0 Evaluation of Licensee Self-Assessment Capability (40500). . . . . . . . . . . . '10 9.0 Observation of Maintenance (62703)........ .......................... 11 10.0 Observation of Surveillance Testing (61726).......................... 13 11.0 Fol low-up of Empl oyee Concerns (93702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 11.1-RI-88-A-0040: Problems with the In-core Analysis Program to Measure Core Performance...................................... 13 11.2 RI-89-A-0071: Concerns About Containment Work at Millstone 3.... 17 11.3 Question on Ccmpliance with 10 CFR Parts 19 and 20.............. 18 12.0 Management Meetings (30703)................................... ...... 19 i,

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DETAILS 1.0 Persons Contacted Inspection findings were discussed periodically with the supervisory and

) management personnel identified belo S. Scace, Millstone Station Superintendent J. Keenan, Unit 2 Superintendent J.'Riley, Unit 2 Maintenance Supervisor F. Dacimo, Unit 2 Engineering Supervisor J. Becker, Acting Unit 2 Instrument and Controls Supervisor J. Smith, Unit 2 Operations Supervisor The' inspector also contacted other members of the Operations, Radiation Protection, Chemistry, Instrument and Control, Maintenance, Reactor Engi-neering, and Security Department .0 Summary of Facility Activities The unit began the inspection period at 55% power, performing power ascen-sion testing. On May 11, the unit escalated to 100% power operation after completion of the tenth refueling outage, which began on February 4,198 Between May 19-20, the unit downpowered to 90% to replace the 'A' Heater Drain Pump Seal, after which the unit remained at full power. Good opera-tor response was noted to prevent plant transients during a loss of two circulating water pumps (May 7), ' A' heater drain pump seal failure, (May 16), and failure of the 'A' reactor building component cooling water (RBCCW) pump (May 22).

3.0 Previously Identified Items (92701)

3.1 (Closed) Temporary Instruction (TI) 2515/91, " Inspection Follow-Up to Generic Letter 83-28, Item The purpose of TI 2515/91 was to review the licensee's response to Generic Letter (GL) 83-28, " Required Actions Based on Generic Imple-mentation of Salem ATWS Events." This Temporary Instruction (TI)

addressed the satisfactory completion of the action required in Item 4.1 of GL 83-28, vendor-related modifications for reactor trip breakers in response to Multiplant Action (MPA) B-8 The objective of this inspection was to verify licensee actions re-quired in Item 4.1 of GL 83-28, reactor trip system reliability (ven-dor-related modifications), have been implemented.

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l A review of the licensee's preventive maintenance program on reactor trip circuit breakers verified the licensee has successfully imple-

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mented the criteria indicated by vendor instructions. Results ob-tained per procedure 2701J-1 indicates breakers are satisfactorily maintained and tested. This closes TI 2515/91.

l l' 4.0 Facility Tours (71707)

l The inspector observed plant operations during regular and backshift tours of the following areas:

Control Room Containment Vital Switchgear Room Diesel Generator Room Turbine Building Intake Structure Enclosure Building; ESF Cubicles Control- room instruments were observed for correlation between channels, proper functioning, and conformance with Technical Specifications. Alarm conditions in effect and alarms received in the control room were dis-cussed with operators. The inspector periodically reviewed the night order log, tagout log, Plant Incident Report (PIR) log, key log, and by-pass jumper log. Each of the respective logs was discussed with operation department staff. No inadequacies were note During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication and equipment status. No inadequacies were note .0 Plant Operational Status Reviews (71707/73753/37700)

5.1 Steam Generator (SG) Tube Plugs On May 2, the licensee was notified by the steam generator (SG) me-chanical tube plug vendor (Westinghouse) of an additional plug heat lot susceptible to primary water stress corrosion cracking (PWSCC).

The NRC previously reviewed SG mechanical tube plugs in inspection reports 50-336/89-05 and 50-336/89-08 dated May 4 and June 20, 198 Mechanical tube plug heat log NX-4523 initially passed the vendor's accelerated corrosion test; however, testing of a tube plug removed at other nuclear power plants showed indications of PWSCC. PWSCC is a function of the material's microstructure, the primary coolant en-vironment (particularly the operating temperature), and the residual and applied stresse !

On May 2, the vendor supplied the licensee a data sheet of installed NX-4523 mechanical plugs installed in the steam generators, with cal-culations in effective fuel power days (EFPDs) of when the plugs are 1

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estimated t'o reach minimal ligament (potential circumferential crack-ing). The vendor also provided temperature scaling factors based on a reference of 622.5 F for the Reactor Coolant system hot leg tem-peratur The licensee confirmed the vendor's information on the population of i

' installed NX-4523 mechanical tube plugs. The number, year installed, location, and characteristics of the mechanical plugs are listed be-low:

Total' Year Number Installed Location Characteristic 35 January 1988 No. 2 SG cold leg Mechanical Plug 17 February 1987 No. 1 SG cold leg Mechanical Plug 1 February 1987 No. 2 SG cold leg Mechanical Plug 2 October 1986 No. 1 SG cold leg Mechanical Plug 121 January 1988 No. 1 SG cold leg Mechanical Plug 23 January 1988 No. 1 SG hot leg Mechanical Stabilizer Plug 3 January 1988 No. 2 SG hot le Mechanical Plug in a Sleeved Tube 21 January 1988 No. 1 SG hot leg Mechanical Plug in a Sleeved Tube 1 October 1986 No. 1 SG hot leg Mechanical Plug in a Sleeved Tube 2 February 1987 No. 1 SG hot leg Mechar,ical Plug in a Sleeved Tube The 176 mechanical tube plugs in both the No. I and No. 2 SG cold legs are predicted to fail, based on the Arrenhius algorithm, between 2626 to 2941 EFPDs. The time to failure equates to at least four cycles of operation based on the current operating cycle length. In preparation of the justification for continued operation (JCO), the licensee did not consider the cold leg plugs installed based on pre-dicted time to failure not falling within the present cycl The remaining fifty mechanical plugs are installed in both SG hot legs. The population is divided into twenty-seven (27) mechanical plugs installed in SG tubes which contain Westinghouse sleeves, and twenty-three (23) mechanical plugs integrally attached to stabili-zer On May 16, the licensee completed a JC0 to address the fifty hot leg mechanical plugs. The duration of the JC0 is until the next refuel-ing outage, predicted to commence in October 199 The design of the SG tube sleeves prevents a partial tube rupture from occurring due to the unexpanded portion of the tube sleeve re-straining the mechanical plug top. This conclusion is based on an-alysis and testing performed by Westinghouse and documented to the NRC in April 198 __-_ _- -_ - - _ _

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The deferral of actions until the.next refuel outage based on un-expanded tube sleeves is consistent with NRC Bulletin 89-01, Failure of Westinghouse. Steam Generators, dated May 15, 1989. A dimensional review was conducted by the inspector to verify the interference and the linear. tube distance based on sleeve. geometry installed at Mill-stone 2. The inspector had no further questions in regards to the licensee's JC0 as it relates to sleeved tube The second group of hot leg NX-4523 mechanical plugs are those with

, plug stabilizers. The mechanical plugs are integrally attached-(swaged) to a stabilizer. The Westinghouse stabilizer used in Mill-stone 2.SGs vary from about 28-46 inches long and consist of a stain-less steel cable'with attached collars. The stabilizer plugs are used for the'following reasons: to stabilize tubes that contain cir-

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cumferentially. oriented defects; to stabilize . tubes if SG eddy cur-rent testing cannot occur due to interference from tube denting; and to. stabilize a tube that potentially exhibits wear due to fretting from adjacent, tubes. The conclusion of the licensee's May 16 JC0 as it relates to mechanical plug stabilizers was based on the Westing-house. conclusion that_ the plug top with the stabilizer contains in-sufficient energy to pierce. adjacent active tube On June 7, the NRC was notified by the licensee of a Westinghouse error in modeling the calculations to support the mechanical stabili-zer plug conclusion for the May 16 JCO. .The vendor error consisted of an energy balance calculation not identifying the plug top and stabilizer as an integral unit. The revised conclusion indicates the mechanical plug failure has the potential to affect adjacent tube The revision partially invalidated the May 16 JCO. Based on the ven-dor's Arrenhius calculation, the stabilizer plugs are now predicted to fail in 293 EFPD starting at the beginning of this operating cycle. The licensee provided this additional information to the NRC via a conference call on June At the end of the-inspection period the licensee was preparing a re-vised JCO, revising the modeling of the unit specific plug / stabilizer arrangement for testing, and giving consideration to lowering reactor coolant system operating temperature to extend the predicted lifetime of NX-4523 mechanical SG plug The inspector considers the licensee's JC0 evaluation, conclusions, and resolution to SG NX4523 tube plugs still open under a previous NRC open item UNR 89-08-01. Inspector review of the licensee's re-sponse to NRC Bulletin 89-01, and of the licensee's response to the June 5 NRC letter addressing a .need for Millstone 2 mid-cycle steam generator inspection, will be completed in future inspection _- ___ - _ _ - _ ___ - _-__ _ ___-___ - - _ _____._____ __ __ ___-________ ___ _ _ .. _

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a e j 5.2. 10 CFR 50.59 Reviews i Licensee administrative procedures require a safety' evaluation or an integrated safety evaluation for each facility modification, test or ;

experiment. Each safety evaluation is to be conducted in accordance -

to Administrative Control Procedure (ACP.) QA-3.08 and Nuclear Engi-neering and Operations Procedure (NEO) 3.12, Safety Evaluations. The safety evaluation documentation accompanies each Plant Design Change Report (PDCR). The purpose of NEO 3.12 is to define the process of preparation of a safety evaluation'to determine if a plant change is safe and satisfies 10 CFR 50.59 requirements. Each safety evaluation includes an Unreviewed Safety Question determination that specific-ally addresses the three 10 CFR 50.59 factors as follows: Considers whether there has been an increase in the probability or consequences of accidents previously evaluate . Considers whether there has been possibi' ity of an accident or malfunction of a different type than any evaluated previousl . Considers whether there has been a reduction in safety margir ys defined in the bases of the Technical Specification The licensee's procedure is thorough and, when applied strictly in the format provided in the procedure, a detailed and explicit 10 CFR-50.59 determination will most likely follow. The procedure allows the format of the safety evaluation to differ, with the proper ap-proval, from that which is provided. As an example, the Engineering 6.Tartment has developed its own instruction for use of a narrative report stylc format for safety evaluation The narrative report provides a well developed description of the change, followed by a logical analysis of the effects on safety. However, there is less assurance of explicit addressal of the three 10 CFR 50.59 factor The licensee schedules an initial four-hour training session on the safety evaluation procedure, with quarterly upgrade training, for each engineer at the site. The engineers at the corporate offices do not necessarily.take the training, but are evaluated by their super-visor on the procedur The following PDC,Rs were reviewed by the specto ~; PDCR No. P.-008-89, Installation of New Service Water Pipe N

4/30/87 PDCR 2-21-87, Anticipated Transient Without Scram (ATWS),

11'30/87 PDCR 2-40-87, Steam Generator Tube Removal PDCR 2-84-86, RCP Motor Oil Strainer Replacement, 10/3/86 PDCR 2-028-87, DC Switchgear Room Halon System, 10/22/87

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, _ v .. u-6' Procedure, IC 2417UA, 9/20/87 7; Test 88-43, RCP Seal Instrumentation Control Bleed Off Pipe Leak

,@. -Test PDCR MPC-89-032, Charging Pump Valve Material Specification Safety evaluations of PDCRs 1, 3, 4, 5, 6, 7, and 8 above did not follow the specific format of the guidance of NE0 3.12 but were in a narrative style format'. All but PDCR 2-f1-87 clearly addressed the three factors of 10 CFR 50.59. PDCR 2-21-87 had two other safety evaluations by other engineering disciplines that adequately ad-dressed the three factors of 10 CFR 50.59. Safety evaluations of PDCRs 2, 3, and 5 above did follow the format of the procedure and made explicit 10 CFR 50.59 determinations. Safety evaluations of PDCRs 7 and 8 above were in the format of the Engineering Department instruction and made explicit 10 CFR 50.59 determinations. No inade-quacies were identifie Plant incident reports are reports that range from very minor inci-dents to major transients. The inspector considered reviewing a major incident to determine if the documentation and background in-formation was available to track the event. The inspector chose the-dropped rod event of April 8, 1988 and the loss of normal power event of.0ctober.25, 1988. The file that the licensee had on these events consisted of only the initial shift operator's reports and the LER There was no other background material with the file such as a com-puter print out of the sequence of events, copies of strip charts of the plant response instrumentation, copies of the plant log at the times of the event or other information gathered for investigation of the event. However, both events were reported as Licensee Event Re-ports (LERs) and no unacceptable conditions were identifie Based on the review cf the process and a sample of PDCRs, there is reasonable assurance that changes meet the criteria in 10 CFR 50.5 .3 Reactor Coolant System (RCS) Hot Leg Temperature (Th)

Oscillations and Divergence Millstone 2 experienced unexpected Th oscillations and channel dif-ference in both hot legs throughout the inspection period. The unit has four resistant temperature detectors (RTDs) insertad into wells which protrude into the RCS flow stream for each loop. The detectors all located in four equally separated quadrants (90 degrees apart) in the RCS hot le Afte ompletion of the cycle 10 refueling outage and return to full powet operation, the licensee noted variations for indicated Th measurements and deviations between channel measurements. The os-cillations in specific channel readings ranged between 1 - 2.5 F over 10-15 seconds. The loop Th readings differed up to 7F. The average Th of all four safety channels between loops varied 1-2 F.

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} y The Th RTD indications provide signals to the Thermal Margin Low

- Pressure (TMLP) variable reactor trip signal, and to the reactor regulating system to provide'an average RCS temperature signal to centrol systems. The TMLP reactor trip functions to shutdown the reactor'should conditions approach departure from nucleate boiling (DNB) during normal operations. During the course of normal opera-tion, the cor. trol room operators experienced numerous TMLP pre-trip conditions. A TMLP pre-trip provides an alarm function to operator The licensee's preliminary investigation concluded the pre-trip sig-nals were a result of the Th variation The inspector reviewed the impact of the anomalies in Th with the accident safety analysis initial condition li., 'verage loop Th is maintained within the extrapolated value of 603.6 F based on core

. inlet temperature nf 549 F and average coolant temperature of 57 The average loop Th values range between 599-601 The uncer-tainties in the accident analysis are +/- 2 F for primary coolant temperature, +/-2% for power, +/ .06 for Axial Shaping Index (ASI),

-3.0% for decalibration, and +/-8.5% for power peaking. All of the above inputs are processed for the TMLP variable setpoint reactor tri Inspector review concluded the variation / deviations in Th temperature indications remain bounded by initial conditions assumed in the accident analysi Applicable requirements related to core parameters were reviewed by the inspector. The technical specification (TS) requirements re-viewed were: Linear Heat Rate (LHR), Axial Shape Index (ASI), Total Integral Radial Peaking Factor (Frt), Azmuthal Power Tilt, RCS flow calculations, and DNB parameters. The review included in-core an-

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alysis reports for May 19, May 29, and June 2, routine control room observations of parameters, and discussions with unit and corporate reactor engineers. All conditions reviewed were acceptable and within requirement The inspector attended the Plant Operations Review Committee (PORC)

meeting 2-89-111 on June 6. A discussion topic for the committee was the Th variations and plant impact. The specific items discussed were: comparison of cycle 9 to cycle 10 Th response during power as-cension and steady-state full power; bulk temperature changes; other previous utility experience; and performance of the RTDs. In early 1980, another facility had experienced similar Th response during power ascension testing. A vendor nemo described vortexing and stratification in the RCS hot legs as contributors to this conditio On June 8, the NRC requested a conference call with the licensee to discuss the variations and impact of Th indications. The licensee discussed the following: in-core exit thermocouple have little or no change, Th variations were observed on previous cycles but were less pronounced, previous other utility experience, and future licensee

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h actions. The licensee actions include a Combustion Engineering re-

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view and analysis, determination of the root cause, and fuel vendor l

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review. The licensee plans to continue to update the NRC as evalu-ations are completed. The inspector had no further question .0 Licensee Event Report (LER) Review (92700)

Licensee event reports submitted during the period were reviewed to assess LER accuracy, the adequacy of corrective actions and compliance with 10 CFR 73 reporting requirements, and to determine if there were any generic implications or if further information was require LER 88-008-01, Unrecoverable Dropped Control Element Assembly (CEA).

The inspector previously reviewed and documented review in inspection report 50-336/88-0 LER 89-005-00, Inadvertent Engineered Safeguard Actuation System (ESAS) Channel 2 Safety Injection Actuation Signal (SIAS). The in-spector previously reviewed and documented the SIAS actuation event in routine inspection report 50-336/89-08 Section LER 89-006-00, Incomplete Surveillance Requirements for a Containment Isolation Valve. On May 16, with the unit at 100's power, the unit operated outside the requirement of Technical Specification Action Statement 3.6.3.1. The event started on May 4, when surveillance procedure SP 2605G-1 was performed to determine operability of con-tainment isolation valve 2-EB-91. Valve 2-EB-91 is a six-inch, but-terfly, inboard containment isolation valve for the hydrogen purge syste *

The valve failed its TS surveillance requirement to stroke in less than 5 seconds. The valve stroked in 9.6 seconds. During the same required sur-veillance, 2-EB-92 (outboard containment isolation valve) met the accept-ance criteria. The operators identified the condition to the maintenance department via a trouble report (TR); however, failure to enter the re-quired action statement (3.6.3.1) violates the licensee's requirement On May 10, a control room operator on another shift questioned the TR for 2-EB-91. The operation department reperformed the required operability surveillance. The surveillance (SP 2605G-1) was completed satisfactoril Valve 2-EB-91 is a normally closed valve, and is maintained closed except during routine containment depressurization evolution. The valve receives a Containment Isolation Actuation Signal (CIAS) to close during a contain-ment accident pressurization event. The inspector reviewed the contain-ment depressurization evolutions between May 4-10. On May 7, the valve was open for approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> for containment depressurization, i

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9 The safety significance of this event is minimal in that_the valve is nor-mally closed, the outboard containment isolation valve was operable during the entire event time, and the valve was cycled successfully on May 1 The TS action statement requires the isolation of the affected penetration by deactivating the automatic valve within four hours. This licensee-identified item was evaluated as having low safety significance, accept-ably reported and corrected, and not due to a previous corrective action inadequacy (LII 89-11-01). Therefore, no violation citation was issue In review of tle LER, the inspector questioned the licensee's root cause determination as it related to operation of valve 2-EB-91. The develop-ment of a root cause determination is unresolved pending further NRC re-view (UNR 89-11-02).

In concert with the follow-up of the above reportable events, the inspec-tor reviewed licensee adherence to technical specification requirements during the previous 1.5 years. Overall, from this programmatic review, management and operations department adherence to requirements was good; however, instances of noncompliance were noted and dispositioned as either licensee-identified or as a violatio Examples included changing modes with the emergency diesel inoperable (LER 88-07), penetration fire seal operability (LER 89-01), control room ventilation system operation, radi-ation monitor operability (LER 88-10), power operated relief valve opera-tion, and an incomplete surveil' lance for a containment isolation valve (LER 89-06). Collectively, improvement is needed to address operator at-tention to detail for minor safety significant operational requirements, such as the necessity to enter the appropriate TS action statement based on emergency power source availability for the control room ventilation syste The results of the inspectors programmatic review were discussed with licensee management on June 30. The licensee acknowledged the inspector's conclusions. This aspect will be considered for Millstone 2 SALP Sys-tematic Assessment of Licensee Performance (SALP).

l 7.0 Committee Activities (40500)

The inspector attended meetings 2-89-102, 2-89-103, 2-89-105, 2-89-107, 2-89-108, 2-89-109, 2-89-110, and 2-89-111 of the Plant Operations Review Committee (PORC) meetings on May 8, May 10, May 17, May 18, May 25, June 1 June 2, and June 3.. The inspector noted that committee administrative requirements were met, hand that the committees discharged their functions in accordance with regulatory requirements. The inspector observed a

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thorough discussion of matters before the PORC and a good regard for safety in the issues under consideratio Selected items approved by PORC are: I/62430F Procedure for ATI installation and removal; SP-2862 Instru-l ment Air Quality check in response to NRC Generic Letter 88-14; LER 89-005; JC0 approval of Westinghouse mechanical tube plugs; and, LER 89-00 No inadequacies were identifie ______ -_ _ _- ____ -

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8.0 EvaluationofLicenseeSelf-AssessmentCapability(405001 The objective of this inspection was to evaluate the effectiveness of the licensee's self-assessment programs. The inspection focus determined whether the licensee's self-assessment programs contribute to the pre-vention of problems by monitoring and evaluating plant performance, pro-viding assessments and findings, and communicating and following up on corrective action recommendation The inspection included a review of ' CRs, enforcement history, routine resident inspection reports, licene implementation of oversight act:

vities, and licensee self-assessment organizations between January 1, 1988 through June 15, 1989, During this period the licensee submitted a total of seventeen (17) LERs, excluding security event reports. The LERs omerally identified root cause and corrective action steps taken in sufficient detail, however; inspection report 50-336/89-01 identified two LERs in which the root cause was not clearly identified. The licensee's corrective actions in response to the inspection report was to issue supplemental LERs, and notify PORC members of the inspector's concerns of root causa determination and de-tai In comparison to the previous SALP period, the total number of reportable events as required per 10 CFR 50.73 declined (35 to 18), the number of plant trips declined (9 to 1), and engineering safety feature actuations declined (9 to 5). A significant reduction in reportable events attri-buted to equipment failure from the previous SALP assessment period (17 to 4) was evident. This indicates that licensee management focus on equip-ment reliability has improve The enforcement history during the assessment period included six non-compliances. Three of the violations were a result of failure to provide qualification reports of electrical equipment important to safety, and maintenance of equipment environmental qualification (EEQ) document file Two violations were a result of nonadherence to the calibration procedure for ventilation radiation monitors, and the final violation was for inade-quate containment airborne samples and an unplanned intake by worker The enforcement actions are described in detail in the following inspec-tion reports: 50-336/88-07, 50-336/88-09, 50-336/88-10, 50-336/88-20, and 50-336/88-22. Licensee corrective actions for each noncompliance were adequate. Improvement is needed to ensure procedural adherence to cali-bration procedures for radiation monitor The inspector reviewed, in part, the licensee's self-assessment program By letter dated December 15, 1988 the NRC requested the licensee to pro-vide information on the self-assessment programs and a schedule for future self-assessment activities. In March 1989, the licensee responded to the NRC's request. The self-assessment program for the unit includes the Nuclear Review Board (NRB), Plant Operations Review Committee (PORC),

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Human Performance Evaluation System (HPES), Site Nuclear Review Board, Quality Services Department and, specifically for 1988, a Safety System Functional Inspection (SSFI).

The inspector has attended and reviewed numerous PORC meetings and minutes. The inspector observed thorough discussions of matters before PORC with a good regard for safety in the issues under consideration by the committe A review of the program descript:on and performance of the HPES for Mill-stone 2 was undertaken. The program is controlled and implemented by two procedures: Millstone Administrative Procedure (MAP) 1.07, Human Perform-ance Evaluation System; and Nuclear Safety Engineering Procedure (NSE)

4.21, Human Performance Evaluation System. The department responsible for implementation of the evaluation system is the Nuclear Safety Engineering department. The. purpose of HPES is understanding and aiding in resolution of human performance ' conditions in order to increase plant safety and reliabilit The inspector reviewed the evaluation system utilizing the HPES periodic report for 1988, discussions with the HPES coordinator and review of the program guidelines. The periodic report notes four (4) events reviewed at Millstone 2 during 1988. These events were concluded to be a result of personnel factors. Personnel factors were characterized as examples of:

failure to follow procedures, inattention to detail, or a transposition of actions. The inspector concluded that the HPES program is adequate to present human factor root cause determinations to licensee management for consideration of corrective action The inspector observed NRB meeting 2-89-6, on June 20, 198 The meeting was well coordinated, met the requirements of composition, meeting fre-quency, and topics before the board. There were probing questions on issues presented at the board. The inspector will continue to review the board activities in future inspection In conclusion, the licensee maintains an effective self-assessment organi-zatio .0 Observation of Maintenance (62703)

The inspector observed,and reviewed selected portions of preventive and corrective maintenanceito verify compliance with regulations, use of ad-

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ministrative and maintenance procedures, compliance with codes and stand-ards, proper QA/QC iny'olvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retes On May 22, at approximately 10:40 a.m., the licensee entered 48-hour TS action statement 3.7.3.1 due to an inoperable 'A' reactor building com-ponent cooling water (RBCCW) pump, coupled with the 'C' RBCCW heat ex-changer out of service. The heat exchanger was unavailable because of a mm___:____ _ _ _ . - _ _ _ . - _ - . - - . - _ . - - - . - - - - - -

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licensee initiative to apply preventive coating to the heat exchanger end I covers. At 5:10 p.m. on May 22, the licensee restored the 'C' RBCCW heat exchanger to service to comply with the.TS requirement for two independent RBCCW operable loops.

l The licensee documented failure of the 'A' RBCCW pump in Plant Incident l Report (PIR) 89-50. The identification of a problem with the RBCCW pump was a result of auxiliary operator (AO) rounds. The A0 identified an un-

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usual noise coming from the horizontal pump / motor combination. Shortly thereafter, the licensee's engineering group performed in-service testing (IST) surveillance SP-21108, RBCCW IST Pump Operability. The pump vibra-tion signatures exceeded the required action range per 'SME Section XI paragraph IWP-3230, and the licensee declared the pump incperable. No inadequacies were identifie A discussion was held with licensee maintenance personnel on the over-haul / repair effort on the ' A' RBCCW pump. The licensee eplaced the out-board and inboard pump radial bearings, the motor / pump coupling, the pump impeller and wear ring, and the inboard motor radial bearing. The motor was steam cleaned, and oven-baked. The apparent cause of failure was the motor / pump coupling which had locked-up and did not prevent axial move-men The inspector noted this was the same type of coupling which resulted in a hot outboard bearing temperature on the 'A' auxiliary feedwater pump in October, 1988. The details of this event are referenced in inspection report 50-336/88-24. The licensee had committed to inspect all similar couplings for lateral movement to verify no hydraulic locked conditio Those inspections are still in progress. The 'A' RBCCW pump / motor coup-ling had not been inspected before its failure on May 22, 198 The inspector reviewed the previous three months of IST surveillance (SP-21108) and OP-2611A " Facility I RBCCW Pump Operability Test" for the

'A' RBCCW pump. The IST vibration signatures had increased over the pre-vious months; however, the magnitude was still well below the ASME XI

" alert" levels. On May 2, licensee internal memo EN2-89-112 from the en-gineering department to the maintenance department documented the recent IST trends and inboard pump seal condition, and recommended maintenance overhaul of the pump. According to discussions with the maintenance de-partment, the overhaul was planned pending purchase of spare parts and '

dedication of mechanics in response to the internal correspondence in early May, 1989. Licensee management's decision to delay overhaul of the pump was predicated on the RBCCW heat exchanger coating project. The RBCCW pump overhaul was tentatively scheouled in the late June,1989. The RBCCW pump was overhauled and successfully restored to service on May 2 The inspector discussed with the licensee what his assurance was that a precipitous failure of other pumps due to coupling failures would not oc-cur. The licensee's response was continuation of coupling inspections, completion of a revised preventive maintenance procedure for couplings,

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and on going in-service inspections, and the continued acceptable opera-l tion of the motor / pump couplings inspected between October 1988 and May 1989 are factors in preventing coupling failures. The inspector had no further question The inspector reviewed previous ISI data, internal memos and overhauls on safety-related pumps prior to a potential failure. The licensee success-fully repaired a containment spray pump, a service water pump, and an eux111ary feedwater pump prior to inoperability as-described in ASME Sec-tion XI for in-service testing of safety-related pumps. The inspector  ;

will review the predictive maintenance program as it related to engineer-ing, maintenance, and IST functions at the facility for safety-related component .0 Observation of Surveillance Testing (61726)

The inspector observed portions of and reviewed completed surveillance tests to assess performance in accordance with approved procedures and Limiting Conditions of Operation, removal and restoration of equipment, and deficiency review and resolution. The following tests were reviewed:

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OP 2401U " Reactor Protection System Matrix Testing"

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OP 2420E " Control Element Drive Motion Logic Testing"

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SP 89-2-2 " Arco Coating to the RBCCW Heat Exchangers" No inadequacies were note .0 Follow-up on Employee Concerns 11.1 RI-88-A-0040: Problems with In-Core Analysis Prograri, to Measure f.o_p Performance A licensee employee telephoned the resident inspector at 2:00 p..m. on May 5 to inform the NRC about problems with the INCA program used to measure core performance, the operability of the excore nuclear in-struments, and to express concerns about the safety of operating the plant under these conditions. Specific concerns included:

(1) Whether the plant should be operating at 96% power due to the problems with the INCA program. Plant procedures limit reactor power to 80% when INCA is unavail sle and the calculation of core thermal limits using INCA was not operatin (2) The 'A' RPS channel NI input bypassed in the high power averag-ing circuit and has been disconnected for two cycles of opera-tion because of inadequate isolation on a component, resulting in a noise problem. Since channel 'A' always reads higher than the other 3 channels, the lack of this input results in a non-conservative calculation of the LHGR limit from the excore !1 I

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(3) The LHGR check using the curve for axial shape index (ASI) is inadequate because'the excores have not been calibrated against the.incores at equilibrium xenon conditions. As xenon builds ~

in and pushes power around in the core, the excores (with the ,

missing channel A input) may not accurately reflect the power '

conditions and thus result in a nonconservative ASI setpoint determination for verifying LHGR limit The inspector reviewed plant parameters including core performance relative to safety limits, reviewed the status of inputs to the power ratio calculator (PRC), and interviewed the Reactor Engineer (RE) to discuss LHGR determinations relative to the above mentioned concern The inspector also independently reviewed the adequacy of the reactor and protection system operating conditions. This review concluded

.that the plant was operating safely with adequate margins to core thermal limits, and that safe operation was assured by fully operable reactor safety instruments, as confirmed by reactor control instru-mentation channel NRC inspection (Inspection Report 50-336/89-08) previously reviewed the licensce's identification and resolution of a problem with the INCA program. The power shaping'coeff1cients used in INCA for nodal power determinations were found inaccurate in the top and bottom re-gions of-the core. which affected INCA calcui n.e of LHGR and radial peaking factors (FrT). The program problem caused a 2% error in the-INCA correction factors for nodal power determinations. The error affected the accuracy of the INCA LHGR determinations, principally in the upper and lower regions of the core. Licensee actions were found acceptable to identify the cause and significance of the software error, and to use temporary penalty factors in the manual calculation of radial peaking and thermal limit evaluations. The excores were used for verification of acceptable linear heat generation rate Power ascension continued using manual verification of thermal limits as correct INCA factors were developed with the fuel vendor. The INCA software problem did not affect the ability to measure quadrant tilt or axial offset (ASI) using the incores, and it did not affect use of INCA data to calibrate excore ASI versus incore ASI. The INCA values were relatively accurate in the core central regions where margins to thermal limits are lower. The licensee did not rely on INCA when the coefficients were in error. A:surance that LHGR limits met was provided(using the excore detectort supplemented by INCA data in core hot regions, showing adequate margins to limits. Corrections were subsequently 2made (on May 6) to the INCA program to address the calculational error The inspector noted that INCA showed a maximum core LHGR of 1 kw/ft at 92% Fp, which was weil below the 15.1 kw/ft technical speci-fication limit, and far below the fuel design limit of 21 kw/f The core axial shape index ihtermined from the excores was -0.03 ASI

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units, which was within.the ASI limits of -0.14 to +0.17 ASI unit Based on the above, the inspector concluded on May 5 that there was assurance that core thermal limits and technical specification re-quirements were being met and no safety issues were identifie The inspector verified after correction of the INCA power shaping coeffi-cients on May 6 that adequate margins remained to linear heat rate limit The RE stated the excore ASI was calibrated to the incores at 55%

power under "near" e.qilibrium xenon conditions, as allowed by a PORC approved procedure T89-12: Power Ascenzion Test - Cycle 10. The RE stated xenon was close to (within 96% of) full equilibrium at the test plateau, and since the measurement was done with the core un-rodded and with ASI very stable at the top and bottom peaks in the xenon oscillation, the desired accuracy in the excore/incore correla-tion was assured. The next incore/excore correlation is to be done at 96% full power under full equilibrium conditinn Inspector re-view concluded that the incore/excore measurements had been taken when the slope of the xenon (Xe) concentration was very near zero, i.e., when the effect of Xe burnout due to the higher neutron flux at higher power had decreased to the point where it essentially matched the Xe buildup due to greater Xe production due to higher powe The inspector determined on May 5 that all NI inputs to the Reactor Protection System were normal. The bypassed input referred to by the employee concerned an isolated input from RPS channel 'A' to the power ratio calculator (PRC). The inspector confirmed that the A RPS input was bypassed from tt e PRC per Jumper and Lifted Lead 2-88-55 on March 28, 1988 in accordance with the controls established by NOD-3.04. The jumper bypass request was properly reviewed and approved prior to implementation, and periodically therefore, to verify con-tinued need to maintain the bypass in effect. The jumper request was reviewed and accepted by the Plant Operations Review Committee on March 30, 198 The configuration created by the bypass jumper affected only the RPS channel 'A' input to the PRC. The jumper was necessitated by the oc-currence of electronic noise in the circuit downstream of the isola-tion amplifier. There was no affect on the NI input to the RPS safety channel. The effect of the jumper was to eliminate needless alarm Inspector discussions with the RE noted that multiple inputs to the y PRC are provided for power generation reliability. As long as any '

single input is available from the NI channels (X or Y and A through D), core axial offset measurement and limit calculation will be ac-ceptable.

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.The RE stated that the PRC calculated ASI limits are conservative with respect to the TS limits by 0.003 ASI units, and the TS is fur-ther conservative with respect to the accident analysis limits due to having more RCS flow than assumed by the analysi Thus, even with an uncertainty in whether the most conservative NI input is being used (since all channels are calibrated in the same manner to within prescribed tolerances of 2%), compliance with the safety analysis assumptions is assured. The RE stated he was further assured that LHGR limits were being adequately maintained by using the incore The inspector conducted an independent evaluation of the power ratio calculator including its design and inputs by reviewing the FSAR, Technical Specification 3.2, Drawings E-18767-411-071, -072 and -085, and by reviewing system descriptions and training lesson plans for the PRC, the core protection calculators and the reactor regulating system. The PRC is not described in the FSAR sections on core pro-tection systems or the reactor regulating syste The PRC uses a control grade input to develop axial shape index (ASI)

l: value and alarm functions fcr display on the main control board and L the control room annunciator. The PRC is developed within the reac-tor regulating system and uses inputs from reactor control nuclear instruments Channels X (NI channel 9) and Y (NI channel 10) to mea-sure core axial offset. The system design has provision for calcu-lating axial offset by averaging inputs from the X and Y channels, but it also contains provisions to bypass either the X or Y channels, if inoperable, and determine axial offset on the basis of a single NI inpu The PRC does interface with the Reactor Protection System and uses an isolated signal from the four safety grade NI channels (A, B, C, D)

to calculate and display the offset limit. The offset limit calcula-tion is obtained by using an auctioneered high value from the four RPS safety channels, and not the average value. The limit calcula-tion based on the high NI input would be the most conservative limi However, the circuit is designed to calculate an acceptable ASI limit with any one operable RPS channel for inpu The inspector noted this design provision is consistent with the operability requirements of TS 3.2, which specifies the minimum num-ber of linear power range safety channels that must be operable for

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i continued reactorf operation at power. The technical specifications allows indefinitejreactor operation with one RPS NI safety channel in

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bypass. This configuration would also make the RPS input unavailable to the PRC. Adequate core protection from large axial offsets is i therefore assured in this conditio The PRC is not relied upon to assure reactor operation within the fuel safety limits. Core protection is provided by the RPS local power density trip and by the thermal margin low pressure trip, which

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has an ASI input. Both trips are developed entirely from the highest

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of either NI power o;- the calculated delta-T power derived from the hot and cold leg RTDs. The local power density trip settings in TS 2.2.1 provide for reactor shutdown if ASI reaches the relatively large' values of plus or minus 20% (or 0.2 ASI units) at full. powe The limiting safety system setting will provide for reactor safety so that the fuel linear heat rate design limit of 21 kw/ft is not ex-ceeded. The txcores can be used to satisfy the surveillance require-ments for TS 3.2.1. The PRC can perform this function acceptably with an.NI, input bypasse In summary, no safety inadequacy was found in the operations per-formed while an INCA program problem existed, in the 'A' RPS channel input being bypassed to the high power averaging circuitry, or in the incore/excore treasurements taken before equilibrium xenon was renche During follow-up of these allegations, the inspector noted aspects that meet requirements but may merit evaluation in regard to licensee performance. Therefore, the inspector asked the licensee for further information on the design specifications for the PRC, on why the underlying condition for the ' A' channel bypass had not been cor-rected for an extended period, and on why the incore/excore measure-ment procedure specified an equilibrium xenon concentration without specifically authorizing the near zero rate of xenon change condition utilize These matters will be further evaluated incident to rou-tine inspectio .2 RI-89-A-0071: Concerns About Containment Work at Millstone 3 On May 31, a contractor employee called the resident office about ingress / egress from the Millstone 3 containment personnel air-lock hatch. The alleger stated that on May 29, the licensee was working on the personnel air lock inboard hatch and noted a sign saying no entrance /no exit. The alleger further stated containment access was secured between 1:30 p.m. - 2:30 p.m. on May 2 According to the alleger, he was told by his supervisor to work in-side containment during the 1:30 - 2:30 p.m. time frame on May 2 The a11eger subsequently did not work in containment during this time fram The inspector discussed work activities surrounding the containment personnel air lock with the licensee's maintenance supervisor. The supervisor stated prior to work activities on the containment access door, all supervisors in Instrument and Controls (I&C) shift super-visors, and contractor supervisors were notified. The inspector also noted work on the access door was inside containment and appropriate  ;

licensee controls existed to remove individuals from containment on a i need basis. The alleger was notified of the licensee controls and i

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had no further questions. Licensee controls were appropriate, and

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the allegation is unsubstantiated, however review of ifcensee/ con-tractor communications during outages will be further reviewe '11.3 Question on Compliance with 10CFR Parts 19 and 70 A contractor supervisor contacted the inspector on May 11 regarding a question of compliance with 10 CFR Part 19. This supervisor did not

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wish to.make an allegation but did have questions stout a letter to him from a former employe The contractor hired a worker in February 1989 to work during the Unit .2 outage on the steam generator (SG) tube inspections. After being on site for about one week of training, and apparently after learning about the radiation exposure involved in the SG work, the worker left the job because of concerns over the exposure. The con-tractor issued a termination letter to the worker indicating he had left the job voluntaril In a letter dated May 2, 1989, the worker asked the contractor to correct the termination letter before the New York State Department of Labor Unemployment Inservice Division to show his departure from the job was " justifiable" since the conditions of employment and radiation levels were hazardous to his health, as were his rights as providec for under 10 CFR Parts 19 and 2 The inspector reviewed the worker's radiation exposure while at the Millstone site. The worker's May 2 letter indicated he was on site from January 31 - February 5. Licensee dosimetry records showed. the i worker was assigned TLDs from February 2 - 10 (the TLDs were returned '

to dosimetry 5 days after the worker was last on site). Dosimetry records showed the worker did not do any work under a radiation work permit and no exposure was recorded on the TLDs for the time at Mill-stone statio The inspector reviewed this matter relative to 10 CFR Parts 19 and 20 regarding Instructions to Workers and Protection Against Radiatio It is the licensee's responsibility to assure worker exposures are controlled within the limits of the regulations and that the require-ments of 10 CFR Parts 19 and 20 are met. No licensee or licensee contractor inadequacies were noted in inspector review of this mat-ter. NRC inspections have found the licensee to have an acceptable radiation control program. No further inspector follow-up is planned on this matter.

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12.0 Management Meetings (30703)

Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findings was also discussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspection. No written material was given to the licensee during the inspection perio i-L_________.______________._____.