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Insp Repts 50-245/85-14 & 50-336/85-21 on 850513-0629.No Violation or Unacceptable Conditions Noted.Major Areas Inspected:Plant Operations,Equipment Readiness,Radiation Protection,Physical Security & Fire Protection
	ML20133G694
Person / Time
Site:	Millstone
Issue date:	07/19/1985
From:	Lipinski D, Mccabe E, Robertson J, Shedlosky J, Swetland P; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20133G683	List: IR 05000245/1985014; ML20133G680;
References
	50-245-85-14, 50-336-85-21, NUDOCS 8508090039
	Download: ML20133G694 (12)
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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report: 50-245/85-14; 50-336/85-21 Docket No ; 50-336 License Nos. DPR-21; DPR-65 Licensee: Northeast Nuclear Energy Company Facility: Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: Millstone Units 1 & 2 Dates: May 13, 1985 through June 29, 1985 Inspectors: $ kO, b ill4/P5 J. T. Shedlosky, Senior Residant Inspector Date Cle L%. k D. R. Lipinski, Resident Inspector

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P. D. Swetland, Senior Resident Inspector, ylts (tr Date Haddam Neck Plant

& 0 N, -d/1(Er J. A. Robertson, Reactor Engineer Date Approved: O b ~/hdfJ E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary: Routine NRC resident (193 hours0.00223 days 0.0536 hours 3.191138e-4 weeks 7.34365e-5 months ) and region-based (32 hours3.703704e-4 days 0.00889 hours 5.291005e-5 weeks 1.2176e-5 months ) inspection of plant operations, equipment alignment and readiness, radiation protection, i physical security, fire protection, plant operating records, maintenance, modifi-cations, surveillance, calibration and reporting to the NRC. This inspection also included the review of plant systems and procedures which may influence the poten-I tial for a loss of coolant accident between interfacing high and low pressure sys-tem Also addressed were the circumstances concerning the mechanical degradation of Unit 1 safety-related motor operated valve No violations or unacceptable conditions were identifie :

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h50809003985079 G ADOCK 05000245 PDR

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DETAILS Plant Status Unit 1 The reactor operated at full power except for planned power reductions for

surveillance testing and preventive maintenanc The Commission issued Amendment No. 102 to the Provisional Operating License on June 5, 1985. The amendment changed the Technical Specifications to allow reactor operation with a deinerted reactor primary containment drywell for up to 45 hours5.208333e-4 days 0.0125 hours 7.440476e-5 weeks 1.71225e-5 months . This change was made to allow safe personnel entry into the drywell for inspection and maintenanc A containment entry was made on June 8 to replace belts on drywell cooler air handling units. A failed bearing on one unit was also replaced. The licensee commenced deinerting the containment at 1600 June Drywell oxygen concen-tration was greater than four (4) percent at 162 The initial personnel entry into the containment was made at 0625, June 8; work was completed at 1600. Reactor power was maintained at thirty (30) percent during this tim Containment atmosphere was reinerted and oxygen concentration was three and one-half (3.5) percent at 1020, June 9; and less than one (1) percent at 110 The reactor was returned to full power at 180 These repairs improved bulk drywell temperature by about six (6) degrees Unit 2 The reactor has been shutdown for a refueling / maintenance outage since Febru-ary 16. The significant maintenance activities included steam generator tube inspections and repairs. The reactor core was reloaded May 27 through June 1, 198 A primary containment integrated leak rate test was done on June 1 Details

, of that test are contained in inspection report 50-336/85-2 Reactor coolant system heatups were terminated on two occasions. The "D" Reactor Coolant Pump shaft seal failed on June 23 and a steam leak was found

at the No.1 MSIV seal ring on June 2 Following repairs, a reactor heatup l to operating temperature and pressure was made on June 2 . Failure of Bevel Gear Housing, Crane-Teledyne Valve Motor Operator - Unit 1 The bevel gear housing of a valve motor operator failed at 1310, May 21. The motor operator had been installed on drywell spray isolation valve 1-LP-16A; the failure was observed by a health physics technician who was in the are The valve was not being operated at the time. The bevel gear housing, a l

casting, failed where four (4) one (1) inch long cap screws attach the motor operator to the gear housing. The housing is attached to the valve yoke, and its gearing engages the valve stem extension.

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The licensee's preliminary analysis indicated that the failure may have been caused by impact side loads on the four (4) attachment cap screws. The motor operator is not keyed to the gear housing. Therefore, if the attachment bolts are not tight, the design allows some movement of the motor operator within the clearance of the bolt holes. The licensee's corrective actions included replacement of the bolts with a one-half inch longer cap screws (1.5" v .0"). Both new and old bolts have nylon locking inserts and lock washer A thread locking compound was also used before and after this problem. The motor operator was returned to service at 1400, May 2 The licensee conducted a special surveillance on all other accessible motor operator That consisted of an inspection to attempt to manually move the motor operator, to inspect for any lubrication leaks which may indicate an attachment problem and to observe the motor operator assembly for motion dur-ing remote valve operation. The inspection was made of all Crane-Teledyne T4, T10 and T40 motor operators. From this inspection, nine (9) other valve motor operators were repaired to ensure bolt tightness. They are:

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1-CS-2A,-5A,-5B

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1-LP-7A,-13A,-13B,-14A,-14B and -15A These motor operators were found to perform their intended function before and after maintenance. The licensee has agreed to include this inspection into future surveillance testing of this type of T4, T10 and T40 motor opera-tor This is an open item (50-245/85-14-01) pending procedure revision The resident inspector obtained the following information from the Unit 1 Acting Superintendent of Operations on the PORC (Plant Operations Review Com-mittee) determination that continued plant operation is justified in this cas Only 2 MOVs with Crane-Teledyne operators are inaccessible (in drywell)

during operation. These valves are IC-4 (Isolation Condenser Return Line Stop) and 50-1 (Shutdown Cooling System Inlet).

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Valve 50-1 is normally shut. The valve is interlocked shut while recir-culation loop temperature is greater than 350 F. Outside containment, the line splits; each leg has an isolation valve (Valves SD-2A and SD-28).

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Valve IC-4 is normally open. Its companion stop valve, IC-3, is normally shut and is located outside the drywell. Quarterly valve operability testing (stroke time test) surveillance provides assurance that both IC-3 and IC-4 remain operabl Failure history for the MOVs with this style operator include LP-16 (the valve that failed in the incident described) and Valve IC-1. IC-1 is located in a hostile (hot) environment very high in the dyrwell. The Crane-Teledyne operator on IC-1 was replaced by a Limitorque operator, making LP-16 the only Crane-Teledyne operator MOV with a history of pre-vious failur .

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In addition, the resident inspector verified that the MOVs involved fail as-is with no loss of pressure boundary integrity as a result of a casualty of this i- nature.

i These motor operators are scheduled for replacement because of other commit-

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ments involving equipment qualifications. Replacements are scheduled to begin

during the October 1985 refueling outag . Error in Seismic Analysis of Pressurizer Vent Piping (Unit 2)

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. On May 30, 1985, the licensee reported the discovery of an error in the seis-

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mic analysis of pressurizer head vent piping. The section of piping is manu-l ally isoiable in containmen A snubber supporting a section of the piping was identified as " questionable" durin~g the ongoing s7ubber inspection and reconstruction program. Analyses to determine the effects of replacement of

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the snubber with a rigid support lead to the discovery that a section of 3/4 inch piping (3/4-BCA-3) could have been overstressed during an Operating Basis

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Earthquake. The initial analysis had been conducted during 1980 using the 1 ADLPIPE computer code version 18. The ADLPIPE code yields motion amplitude and stresses at various locations in the modelled piping system in response

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to vibration / acceleration spectra in three (3) dimensions. Due to a format

! error in the input data for the analysis for this piping segment, data for '

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the spectrum in the "y-direction" were used in calculating the response in both the "x-direction" and the "y-direction." As the "x-direction" input spectrum was more severe than the "y-direction" input, the erroneously calcu-

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lated responses were less than they would have been had the correct input been use The supports for the pipe segment in question (3/4-BCA-3) have been redesigned to incorporate two fixed supports instead of the formerly installed snubbe The inspector reviewed the Plant Design Change Request (PDCR 2-48-85) and as-

. sociated drawings (25203-20125 Sheet 61 and 25203-22200 sheets 60246A and 60245A) and observed that design reviews had been completed and documente Installation of the new supports has been completed. No independent design

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analysis was attempted by the inspecto i The extent to which the use of ADLPIPE version 1B could have led to other

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similar errors was investigated. Although version IB of the ADLPIPE code de-i faults to previously used values and continues to run when unexpected input

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is encountered, the current version,10, rejects unexpected inputs and prints l j a description of the error when unexpected input is encountered. ADLPIPE

! version IB is no longer in use. Analyses which had been conducted using ver-l sion 1B have been reviewed using version 1D. No additional errors in input

were foun The licensee is preparing a 30-day report of this matter. Review of the is-sues involved will remain open pending review of that report and close-out of the PDCR implementing corrective measures (50/336/85-21-01).

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5 Review of Interfacing Systems Loss of Coolant Accidents (LOCAs)

Recently, events have occurred at several reactor facilities in which low pressure piping connected to the reactor coolant system has been overpressur-ized. The potential for loss of coolant accidents in these " interfacing" low pressure systems has been previously reviewed by NRC. Generic licensing ac-tion was implemented to reduce the risk of this event for pressurized water reactors during the period 1980-1981 because of a dominance of this accident sequence for PWRs in the Reactor Safety Study (WASH 1400). These recent overpressurization events have occurred at boiling water reactors and have resulted, in part, because of multiple component / personnel failures. During this inspection, the arrangement, maintenance and testing of such interfacing systems were reviewed to verify data used in previous evaluations of the in-terfacing LOCA concern and to assess the potential for bypassing of system components or interlocks designed to protect against this accident sequenc The inspector also interviewed selected operations and maintenance personnel to evaluate their understanding of the interfacing LOCA event and the effect of certain maintenance or test activities on the potential occurrence of this even NRC has compiled summary descriptions of interfacing systems at many reactor facilitie This computer data base is used for NRC evaluations of certain accident sequences, and was published in NRC NUREG/CR 2069, Summary Report on a Survey of Light Water Reactor Safety System As part of this inspec-tion, the accuracy of this data base was verified by review of plant drawings and walk down of accessible systems. Inspection findings were as follows: Unit 1

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The descriptions of piping arrangements in NUREG/CR 2069 for the low pressure coolant injection (l,PCI) and core spray (CRS) systems were correc The shutdown cooling system does not have any low pressure piping and should not have been identified as an interfac-ing system. No other interfacing systems were identified.

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The LPCI system arrangement provides protection against overpres-i surization of low pressure piping by a normally closed motor-oper-l ated valve (MOV) and a stop-check valve. The motor-operated stop

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check valve is closed prior to opening the upstream MOV for sur-veillance. Another check valve inside the drywell provides redun-j

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dint isolation; however, the licensee has identified a 1 inch bypass path around this check valve which compromises the pressure isola-tion capability of this valve. This check valve was formerly a

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testable check valve design, however, the licensee had previously disconnected and disabled this air-operated test feature. The by-

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pass path is in a common drain header which connects valve body

! drain connections on both sides of the valve seat. Since two other

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boundary valves provide overpressure protection for downstream piping, the existence of this bypass path is not an immediate con-

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cer The licensee plans to modify the check valve body drains to eliminate this bypass path during the next refueling outage, which is scheduled for October 198 The CRS system arrangement provides overpressure protection for low pressure piping using a swing check valve inside the drywell and

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a normally closed MOV outside the drywell. A third normally open MOV is installed on the injection pump side of the closed MOV, in-side the high pressure pipe boundary. This valve can be closed when the upstream M0't is opened for surveillance. A pressure switch which is located between the two MOVs alarms on the main control board if pressure rises above 350 psig. Since this alarm does not actuate when the MOVs are cycled for surveillance, the integrity of the check valve in containment is verified. Therefore, two boundary valves protect against an interfacing system LOC The normally closed MOVs in both the LPCI and CRS systems open automatically upon receipt of a LPCI/CRS actuation signal. Low low reactor vessel level coincident with low reactor vessel pressure, or high drywell pressure automatically starts the LPCI/CRS pumps, however, the closed MOVs are interlocked to an additional reactor coolant low pressure signal to delay opening the MOVs until reactor coolant pressure drops below tne low pressure injection system de-sign pressure. The inspector reviewed surveillance activities re-lated to the LPCI/CRS actuation sensors, logic and interlocks to determine the potential for inadvertent overpressurization of low pressure piping. It was noted that the integrity of the LPCI system stop check valve and the CRS system swing check valve remains unaf-fected by surveillance / personnel errors. Surveillance procedures for reactor vessel level and pressure, and drywell pressure verify sensor calibration and alarm setpoints on a monthly or quarterly cycle during plant operation. These functional checks are conducted

, one sensor at a time providing only partial trip signals to the ac-tuation logi Full system actuation functional tests are conducted at refueling intervals while the plant is in cold shutdow Routine surveillance at power does not involve bypass or jumping of MOV ac-tuation signal During routine sensor functional checks, a spurious failure in a redundant channel could cause inadvertent system actu-ation, however, the separate low pressure valve interlock would prevent opening of the motor operated boundary valve. Therefore, in order to overpressurize low pressure piping during system testing, one must postulate an actuation channel failure, a low pressure interlock failure and a check valve component failur The risk of this accident sequence is low. The licensee has estimated the contribution to core melt frequency of this type of occurrence to be less than one in 10 million reactor years (1 X 10 E-7/Rxyr).

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As stated above, the licensee does cycle the closed motor operated boundary valves open for quarterly inservice testing. These test procedures specifically call for closing the downstream boundary

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valve prior to opening the upstream valve. The tests are conducted from the control room with personnel at the valves in direct com-munication with the control room operators. Both LPCI and CRS have low pressure pipe overpressure alarms which would promptly alert operators to an error in the conduct of this procedure. Again, in order to postulate an overpressurization in this case, one must assume mechanical failure of the system boundary check valv Ma'intenance of " interfacing" systems is conducted in accordance with the licensee's routine quality assurance program, including appro-priate documentation, administrative and quality control, and post maintenance testing. No special requirements are established for

" interfacing" systems, however, major repairs to system bnundary valves are necessarily conducted in a cold shutdown condition. Post maintenance and startup testing would re-establish the f.itegrity and operability of the " interfacing" system boundary valves, b. Unit 2

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The descriptions of piping arrangements for high and low pressure safety injection piping of NUREG/CR 2069 was correct except that the safety injection tanks, which provide a high volume core re-flood capability, were not included. There are four (4) safety in-jection tank Each injects into a HPSI/LPSI header. All related components are located in the containment. The following can be added to the NUREG/CR 2069 data tables:

Interfacing System SIT Piping Location IN Number of Penetrations None Component Line-up:

RCS - CK - MOV - CK - H/L - SIT NO Low Pressure (PSIG) 250 High Pressure (PSIG) 2485 Monitoring PIND

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All overpressure protection is provided by two (2) or three (3)

check valves in series. Valve seat leakage is monitored through presure indicators on the control room main control boards with associated high pressure annunciator The isolation cteck valves are included in the inservice test pro-gram which requ:res disassembly for inspectio The valves are cycled during i.jection testin All inspection and testing is performed during refueling outage The safety injection tanks (SIT) may also be overpressurized through a one-inch pipe used for nitrogen supply to the pressurizer steam space and the safety injection tanks. This occurred on January 17,

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! 8 1981 when two manual isolation valves were inadvertently left ope In that event No. 1 SIT was pressurized and a safety valve lifte As a result, check valves were installed in nitrogen supply piping I

at interfaces to RCS piping, valves were re-worked to insure leak tightness and administrative procedures were upgraded (Reference Inspection 50-336/81-01). The following additional component lineup should be added to that above:

RCS - MV - MV - CV - H/C - CV - MV - A0V - SIT C C (flow)LO C

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Maintenance of " interfacing" systems is conducted in accordance with the licensee's routine quality assurance program, including appro-

! priate documentation, administrative and quality control, and post 1' maintenance testing. No special requirements are established for

" interfacing" systems, however, major repairs to system boundary valves are necessarily conducted in a cold shutdown condition.

Post-Maintenance and startup testing would re establish the integ-j rity and operability of the " interfacing" system boundary valves.

! The inspector also reviewed the licensee's evaluation of IE Information Notice 84-74, Isolation of the Reactor Coolant System from Low-Pressure Systems Out-side Containment, which reevaluated the interfacing LOCA event and found no

further potential interfacing sytem pathways and no surveillance or preventive 1 maintenance activities which compromise protective measures for this even The inspector had no further questions in this are . Refueling Activities (Unit 2)

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This inspection was conducted in order to ascertain whether refueling was conducted in accordance with Technical Specifications and licensee i procedure Reference:

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OP2209A, " Refueling Operations," Revision 9 i

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OP2303, " Fuel Handling System," Revision 12

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EN21064, " Refueling Machine Load Test," Revision 1 1 --

EN21001, "Special Nuclear Material Inventory and Control, Revision

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OP2614A, " Refueling Periodic Checks," Revision 3

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OP2614B, " Penetration Isolation Verification-Refueling," Revision 0, CH-1

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Licensee procedures EN21064 and OP2303 implement the requirements i of Technical Specification 3.9.6 and 3.9.7. regarding verification 1 of load capacities and interlocks associated with the refueling l

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machine and related hoists and cranes. The inspector reviewed the completed records of the refueling machine load test (ENG Form 21064-1) completed on 5-27-85 and of the overall fuel transfer sys-tem preoperational checks (OPS Forms 2303-4, 2303-2 & 2303-8) con-ducted on 3-8-85 and 5-27-85. No deficiencies were note The reactivity control and monitoring requirements of Technical Specifications 3.9.1, 3.9.2, and 3.9.3 were found to be implemented by OP2209A. The inspector observed that reactor coolant was being sampled for boron concentration in a timely manner and that results were posted both to reactor engineering and the licensed operator The inspector verified source range char.nel operability and that source counts were clearly audible both in the Control Room and from the refueling machine. Additionally, shift reactor engineers were maintaining plots of inverse count rate (1/m) during fuel movement to help monitor core reactivit No unacceptable conditions were observe The containment integrity and area ventilation requirements of Technical Specifications 3.9.4, 3.9.9, 3.9.10, 3.9.13, 3.9.14, and 3.9.15 are implemented by licensee procedures OP2209A and OP2614A

& B with associated checklists. The inspector reviewed the com-pleted checklist Selected requirements were verified by direct inspection including containment closures, spent fuel pool exhaust ventilation, and radiation monitor statu No unacceptable condi-tions were observe Cooling and water inventory requirements of Technical Specifications 3.9.8, 3.9.10, 3.9.11 are implemented by licensee Procedure OP2209 The inspector verified shutdown cooling operation and water levels in the reactor cavity and spent fuel pool by direct inspectio No unacceptable conditions were observe The inspector observed fuel loading operations during portions of 4 shifts including 2 backshifts. Fuel handling was conducted deli-berately and in accordance with detailed procedures (0P2209A and OP2303). Watchstanders, in accordance with Technical Specification 6.2.2, were clearly in charge of operations in the fuel machine area, j the control room, and the spent fuel pool area. Communications by

dedicated telephone line were judged to be adequate (Technical Specification 3.9.5 refers). No unacceptable conditions or prac-tices were observed. The detail and thoroughness of plant proce-dures is notabl Fuel accountability was observed to be maintained in accordance with licensee procedure EN21001. Both handwritten logs and a graphical 1 status board were in use. Core verification was conducted and videotaped by the Quality Assurance group. The inspector witnessed the verification effort.

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Cleanliness and foreign material exclusion in the vicinity of the reactor cavity and spent fuel pool was actively maintained. Re-fueling water was quite clear and free of debri Conclusion Refueling activities were conducted in a controlled and deliberate manner and in accordance with both technical specifications and licensee re-quirements. The detail and thoroughness of procedures and checklists is a noteworthy strengt . Reactor Coolant System Resistance Temperature Detectors (RTD) - (Unit 2)

All of the RCS RTDs were replaced during the 1985 refueling / maintenance outage and the wells were cleaned and vacuumed to remove the nickel Never-Seez lubricant. The Never-Seez had been used in six wells previously to improve thermal transfer on RTDs and provide faster response times. Some licensees have experienced a degradation of response times due to a breakdown in the thermal characteristics of the Never-Seez at normal RCS operating temperatur The previous RTDs (Weed Model 612) installed during the 1983 refueling / main-tenance outage were' replaced with Weed Model 612-1 RTDs. The new RTDs were installed without Never-See The inspector observed the RTD response time testing (SP 2401Q) performed June 27, 1985 by NNECO and contractor (AMS) personnel. The loop current step re-sponse method was utilized. Three of the sixteen RTDs failed to respond within 8 seconds and required rework to provide better contact between the RTDs and the walls of the wells in which they were mounted. This was accept-ably done following a June 28 RCS cooldow No unacceptable conditions were identifie . Potential Generic Problems Identified at other Facilities (Units 1 and 2)

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Another licensee experienced the failure of interpole connecting straps in Fairbanks-Morse Type TGZDJ emergency diesel generator rotors.

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The inspector found that the Unit 1 generator was supplied with an interpole connecting ring which is a different design than the hoop-like interpole con-necting straps that faile At Millstone, a single piece ring is bolted to l the end of the rotor pole The ring is attached to each pole with four bolts

! and is located under fan shaped prices. These four bolts are secured by two locking plates at each pole. This design is duplicated at each end of the

! roto There have been no past problems concerning these ring There are no interpole connecting rings or straps in the Unit 2 emergency diesel generator There were no unacceptable conditions identified.

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11 Status of TMI Action Plan Item NUREG-0737 Item 1.B.1.2: This action plan item specifies the establishment of an Independent Safety Engineering Group to review plant operations and transients. On May 29, 1985, the licensee formally approved Procedures NE0 2.19 " Independent Safety Engineering Group Organization and Functions," NSE 6.01 " Plant Observation Program," and NSE 6.02 " Plant Evaluation Program,"

which collectively implement the requirement. The Independent Safety Engi-neering Group (ISEG) includes a total of 16 engineers who will serve both the Connecticut Yankee and Millstone Units. The ISEG supervisor and the indivi-dual unit ISEG coordinators are degreed engineers with extensive plant oper-ating experience. Two types of routine evaluations are planned: 1) 2 to 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months observations of plant activities by a single engineer and 2) 2 tn 4 week detailed evaluations by a team of engineers. The same program has been re-viewed and accepted by the Office of Nuclear Reactor Regulation (NRR) (see Millstone 3 FSAR 13.44 and SER 13.44). The inspectors will observe the acti-vities and effects of the ISEG program in the course of the normal Manual Chapter 2515 inspection progra . Observation of Surveillance The inspector observed parts of surveillance tests to determine for conduct in accordance with requirements. These tests included:

Unit 1

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Emergency Gas Turbine Generator Surveillance on May 28, 1985 per SP68 Main Steam Line High Radiation Functional Test on May 28, 1985 per SP406 Unit 2

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Engineered Safety Features Functional Test on June 7, 1985 per SP2613 Response Time Testing of RCS RTDs on June 27 per SP 2401 CEA Drop Time Measurements on June 27 per T85-2 . Unit 1 Checks Routine checks of Unit 1 operations identified no unacceptable condition . Exit Interview At periodic intervals during the inspection, meetings were held with senior licensee site management to discuss the inspection scope and findings. There were two new open items identified. The first relates to the incorporation of additional inspections for loose mechanical connections of Unit 1 Crane-Teledyne valve motor operators. That item (50-245/85-14-01) is addressed in Report Paragraph .

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12-The second item is open pending submission and review of an LER concerning an error in the seismic design analysis frr the Unit 2 pressurizer vent pipin This item (50-336/85-21-01) is addressed in Paragraph At no timo during this inspection was written material concerning inspection findings provided to the licensee by the inspector. Information which may have been proprietary and which was addresed during this inspection period was discussed with licensee representatives. No information identified as proprietary was included in this report.

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IR 05000245/1985014

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REGION I

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