IR 05000245/1985019
| ML20133N199 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 07/31/1985 |
| From: | Lipinski D, Mccabe E, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20133N144 | List: |
| References | |
| 50-245-85-19, 50-336-85-25, IEB-80-25, NUDOCS 8508130406 | |
| Download: ML20133N199 (13) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report: 50-245/85-19; 50-336/85-25 Docket Nos: 50-245/ 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: . June 30, 1985 through July 22, 1985 Inspectors: &., (% . b 7 /isfr5 John T. Shedlosky,' Senior Resident Inspector Date b bOJL. .h rhsIer David R. Lipinski, Resident Inspector Date Approved: Urt b% aliller E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary: Routine NRC resident (85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br />) inspection of plant operations, equipment alignment and readiness, radiation protection, physical security, fire protection, design changes and modifications, surveillance, and close-out of Inspection & En-forcement Bulletin 80-25. No violations or unacceptable conditions were identifie i PDR ADOCK 05000245 G PDR
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DETAILS 1. Plant Status Unit 1-The reactor. operated at full power except for planned power reductions for surveillance testing and preventative maintenance. On July 16, Unit 1 set a record for consecutive days of service for a domestic Boiling Water Reactor (BWR) of 345 days. As of the end of the inspection period, Unit 1 has been in service for 351 days. The previous record, held by Big Rock Point in Charlevoix, Michigan, was 344 day Unit 2 The reactor was taken critical at 2115 on June 30 ending a 135 day refueling and maintenance outage. A period of startup and power ascension testing fol-lowed and the unit reached full (100%) power at 2210 on July 11. The unit remained at full power until 1533 on July 15, 1985 when pressurizer spray valve problems led to a decrease in plant pressure and a Thermal Margin / Low Pressure scram. Investigation of spray valve problems revealed an error in a recently implemented design change to the pressurizer spray valve control circuits. Following maintenance on the pressurizer spray valves, repairs to secondary (steam) plant equipment, and a review of all design changes imple-mented during the recently completed refueling outage, Unit 2 was taken cri-tical at 0310 on July 19, synchronized to the grid at 0945 on July 20 and brought to full power on July 22. The license briefed NRC Region 1 management on the results of the design change review prior to startu . Loss of Pressure and Scram of July 15 - Unit 2 Overview On July 15, 1985 at 1533, Millstone Unit 2 scrammed from full power as pressure dropped through the Thermal Margin / Low Pressure (TM/LP) setpoint (approximately 2130 psia at the time of the scram). No Emergency Core Cooling System (ECCS) challenge occurred. All safety systems functioned properly. The minimum pressure reached was 1725 psia. The pressure drop was attributed to failures in both pressurizer spray valves. Following a containment entry, both spray valves were found stuck partially ope The valves were isolated, and normal pressure was restored. The licensee could not definitively determine the cause of the spray valves binding; however, stem / packing interference is suspected. Prior to startup, the valves were satisfactorily tested. A controls deficiency was identified during the investigation. However, this problem did not cause the transient. This matter will be more thoroughly reviewed following the licensee's report of the even ..
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3 Event Chronology The plant was initially at 100% power with 4 Reactor Coolant Pumps (RCPs)
operating, Presurizer (PZR) pressure 2275 psia, Cold Leg Temperature (Tc)
548 degrees F, and Hot Leg Temperature (Th) 596' degrees F. Data collec-tion at 100% power was in progress to complete post refueling startup and power ascension testing. To ensure that boron concentration remained equalized between the PZR and the Reactor Coolant System (RCS) loops, essentially continuous pressurizer sprays were being " forced." This latter evolution assures that plant temperature changes only (not tem-perature induced boron concentration changes during PZR outsurges) cause plant power changes during testing conducted at several power plateau A brief event chronology follows. Times are approximate and are recon-structed from installed recorders, the logs, and inspector note TIME ACTION / EVENT /0BSERVATION 1430 Minor difficulty controlling pressure using proportional heaters is experienced. Intermittent operation of backup heaters is necessary. Shift Supervisor (SS) requests main-tenance to check pressurizer heater Reactor Protective System (RPS) TM/LP Pre-Trip Alarms received intermittentl RPS TM/LP Pre-Trips continue intermittently. Control Operators call SS to control boards because of PZR pressure declin All PZR backup heaters are on. SS directs a gradual load re-duction on the Main Turbine. RPS TM/LP pre-trips received steadily. Both spray valve controllers indicate valve shut order PZR pressure drops past 2200 psi SS diagnoses problem as a stuck open spray valv Both spray valve controllers taken to " manual" and moved from full shut to full open and back to full shut in an effort to free the stuck spray valv PZR pressure continues to drop through 2180 psi RPS trips on TM/L All scram breakers o' pen. Main Turbine trips on reactor scram. Plant loads shift to off-site powe Normal scram transient behavior is observed (and reconstructed).
1537 PZR pressure reaches 1790 psia then begins to recover (Th is 525 degrees F).
1540 PZR pressure reaches 1853 psia then begins to declin r; 1
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-4 1600 Preparations to enter containment to investigate problems with the spray valv PZR pressure is at 1740 psia with Th at 530 degrees The pressure decline is continuin SS directs RCPs "B" and "D" secured (one per steam Generator)
to reduce spray flo Containment is opene Both spray valves are isolated by shutting their manual outlet isolation valves (2-RC-252 and 2-RC-253). As spray valve 2-RC-100E was isolated, the operator reported a decrease in flow noise through the valve. The pressure drop is stopped. The minimum pressure reached was 1725 psia. At that time Th was 535 degrees F. Pressure begins to ris The outlet isolation valve for spray valve 2.-RC-100F is opene RCP "D" is started; pressure begins to dro Spray valve 2-RC-100F is isolate Observation of spray valve movements during troubleshooting leads to the discovery that valve 2-RC-100E responds to the controller for 2-RC-100F and vice vers RCP "B" is started. Plant pressure is being controlled at 2250 plus/minus 25 psia using the PZR heaters. RCS temperature is 530 degrees F. All four RCPs are running, c. Assessment of Core Conditions The thermal hydraulic conditions in the core were closely monitored dur-ing the pressure transient by both the inspector and the license Forced convection through the core and both steam generators was main-tained was maintained throughout the event. Therefore, RCS Th closely reflected core exit temperature. The inspector plotted actual Tc, Th, and PZR pressure as well as the saturation temperature corresponding to PZR pressure for the period from 1525 to 1545. At the time of the scram, the subcooling margin was approximately 98 degrees F. At its minimum, just after the scram, subcooling margin was approximately 74 degrebs ,
At the time the lowest pressure (1725 psia) was reached, subcooling mar-gin was at least 75 degrees F. Based on this behavior, it is concluded that the core heat transfer regime did not depart from nucleate boiling during the transient, thus core damage is unl.ikel .
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Following the scram, dose equivalent Iodine activity in the reactor coolant was monitored as an indicator of core damag Peak Iodine acti-vity measured was 0.02 micro-Curies per milli-litre. This peak is low when compared to post-scram peaks observed during the preceding cycl From this indicator, no core damage is inferre The Safety Limits on temperature, pressure, and power of Technical Specification 2.1 were not exceeded. At the existing conditions of temperature and power at the time of the scram, the safety limit on pressure was approximately 1750 psi d. Pressurizer Spray Valve Summary Two spray valves are provided. The valves are Fisher Controls 3-inch angled valves. The valves are air operated and move in proportion to the demand. Ordered position is displayed in the control room. No valve stem position indication is provided. The control system was changed during the preceding refueling outage from a General Electric
"GE/MAC" current loop to a Foxboro " Spec.200" current loop (PDCR 2-8-85).
Manual inlet and outlet isolation valves are provided. No remotely operated isolation or blocking valves are provided. Two 3/4-inch bypass throttle valves are installed. These provide a small flow of water to warm the piping oetween the spray valves and the PZR and to cool the PZR spray head. This action limits the thermal stresses experienced when spray is initiate Routine preventative maintenance on the spray valves consists of valve re packing. This was accomplished during the preceding refueling outag Troubleshooting spray valve 2-RC-100E showed normal valve motion through its range of trave However, the valve was approximately 1/4 inch (stem movement) from full closure at the end of the air operator's strok The stroke was adjusted to fully shut the valve. Valve 2-RC-100E had no prior history of mechanical problem Troubleshooting spray valve 2-RC-100F showed erratic valve motion; the valve bound in intermediate positions. The valve was disassembled to attempt to identify and correct the cause of the mechanical bindin No obvious valve damage was observed; however, some scratches were found on the globe and stem and a packing ring was displaced (" cocked"). The valve was rebuilt and tested satisfactoril Valve 2-RC-100F had no re-cent history of mechanical problems since 1978, when the globe separated from the ste The throttled position of the spray valve bypass valves was also adjuste Both spray valves are presently in service. A small amount of spray flow through the valves continues and is compensated by maintaining one group of PZR backup heaters (approximately 300 kilo-Watts) energized. The
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licensee has deemed this to be acceptable until the next extended outag The inspector confirmed that plant pressure is being maintained as pre-scribed by Technical Specifications, e. Related Systems Effects At Millstone Unit 2, pressure is normally maintained by two groups of proportional heaters (150 kil-Watts per group). At set pressure (nomi-nally 2250 psia) half power is supplied to the proportional heater At 2275 psia, proportional heaters are off and at 2225 psia proportional heaters are at full power. At 2200 psia, decreasing, four groups of backup heaters (300 kilo-Watts each) are energized; these are de-ener-gized at 2225 psia, increasin The spray valves normally do not, cycle. Both spray valves begin to open at 2300 psia and both valves are fully open at 2350 psia. To " force" sprays in order to equalize PZR and RCS loop boron concentrations, the spray valve controller setpoints are reduced to initiate spray flow at normal presure and backup heaters are manually energized to maintain pressure. Operation with known spray valve leakage and partial backup heaters is equivalent to the routine evolution of " forcing" spray Emergency Core Cooling System (ECCS) injection sources at Millstone Unit 2 include the normally running positive displacement charging pumps, High Pressure Safety Injection (HPSI) pumps, Low Pressure Safety Injection (LPSI) pumps, and Safety Injection (SI) accumulators. The low pressure Safety Injection Actuation System (SIAS) initiation occurs at PZR pres-sure of 1600 psia. Charging pumps inject via their normal flow pat Charging pump flow does not change as these positive displacement pumps are driven at constant speed. The HPSI pumps nominal shutoff head is 1600 psia. Both LPSI and SI accumulators inject only at further reduced pressures. Since the minimum pressure reached, 1725 psia, was well above the SIAS setpoint of 1600 psia. ECCS was not initiated. Had the initi-ation occurred due to an early initiation of SIAS, an RCS thermal transi-ent would not have resulted as the only injection source (charging pumps)
would have injected via their normal path Some time following the scram, main condenser vacuum was los Trouble-shooting revealed that a steam deflector plate had carried away tearing the low pressure turbine exhaust flexible coupling (" exhaust boot") to the main condenser. Resulting repairs dominated the duration of the forced outage resulting from this even f. Deficiencies in Design Change Control In the course of troubleshooting the problems with the spray valves, it was discovered that the controller for valve 2-RC-100E actually con-trolled valve 2-RC-100F and vice versa. The previously installed General Electric "GE/MAC" controllers had been replaced by Foxboro " Spec.200" controllers as part of Plant Design Change Request (PDCR) 2-8-85 which
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was implemented during the preceding refueling outag Although the spray valves and their controls are not themselves safety-related, other changes implemented via that PDCR involved safety-related pressure in-strumentation, power supplies, and safety / control isolation. Thus PDCR 2-8-85 was handled by the licensee as a safety-related design chang The error which resulted in the cross-operation of the controllers was not due to an installation error. Rather, the wiring drawings for the spray valve controllers were drawn in erro Three sheets, vice one long sheet, were used and the error occurred in the sheet transition labelin The post-design change testing included individual calibration of the safety-related PZR pressure instrument channels and was accomplished with actual test pressures applied to the pressure transmitter Testing of the non-safety-related PZR spray valve controllers did not include ob-servation of spray valve stem movement in response to position orders from the new controllers. Instead, controller output currents were measured. During the loop current checks, a discrepancy was identified between the control room and hot shutdown panel indications. Resolution included reversing the valve identifier tags at the hot shutdown pane This appears to indicate a lack of thorough investigation to resolve the discrepancy, since the actual cause was the error in design as previously discussed. Following repairs and correction of the design change error, adequate operational testing of the entire PZR spray valve control system was conducte Prior to restart of Unit 2, the licensee reviewed all 65 plant design changes implemented during the preceding refueling outage in order to identify changes of potentially operational significanc Seventeen such changes were identified for further followup to ensure that adequate operational verification of affected system performance had been con-ducted. The inspector independently screened the PDCR list and found the licensee's selection to be acceptable. On July 18, 1985, represen-tatives of the Northeast Nuclear Energy Company met with NRC Region 1 management to discuss the results of the design change review and other matters relating to change and testing deficiencies. Meeting report 50-336/85-26 discusses design change issues in detai . Monthly Surveillance Observation In order to ascertain that surveillance of safety-related systems and compo-nents is being conducted in accordance with license requirements, various testing evolutions were observed at both units 1 and 2 as described below: Unit 1
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" Reactor Low Water Level Scram and Low Low Level Isolation Func-tional and Calibration Test" per SP408C Revision 3 and " Reactor Low Low Water Level Functional and Calibration Test" per SP412C Revision '
9 (with change 1).
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These tests verify the calibration and functional operability of Yarsay level switches used in the Reactor Protective System (SP408C),
the Primary Containment Isolation System (SP408C), and the Emergency Core Cooling System (SP412C). The tests use the " Cold Water Cal.-
Dry Method" as described in Yarway manual 21-101N " Instruction Manual for Yarway Liquid Level Indicator and Accesory Equipment for Millstone Point" section 5. A 3 point calibration check as well
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as a demonstration of control-logic relay actuation as a result of the physically imposed differential pressure were featured in the test Test results were satisfactory. The test gauges had been calibrated and were included in the licensee's periodic calibration progra Restoration involved two party checks and documentation of final instrument valve positions. The physical condition of the environmental enclosures (including the condition of door gaskets)
which mitigate the effects of postulated high energy pipe breaks upon these instruments was found to be satisfactory. The inspector concluded that both tests satisfied the requirements of Technical Specifications 3/4.1.A and 3/4.2.A&B both in terms of the extent of testing and of the periodicity of testin No unacceptable con-ditions or practices were observe " Manual Scram Functional Test" per SP609.1 Revision This test demonstrates, in turn, the ability of each reactor manual scram push button to initiate a scram (de-energize scram relays)
in its respective trip system. The inspector found the test to meet the requirements of Technical Specification 3/4.1.A. No unaccept-able conditions were observe "Drywell High Pressure Scram and Constant Isolation Functional and Calibration Check" per SP408H Revision This test verifies the calibration and functional operability of ,
Barton Model 288 pressure switches in the Reactor Protective System and Primary Containment Isolation System. The Barton Model 288 in-strument manual outlines a calibration method which exercises the instrument then measures instrument response at 3 points - at the low end of the scale, at mid-range, and at the high end of the scale. The licensee's test procedure, describes testing the instru-ments in the "as-found" condition by venting the instrument, ob-serving the 0 pound per square inch gauge value, then applying air pressure to the instrument to observe the contacts close at 1.8 psig (nominal) as measured by a precision gauge. The inspector discussed the discrepancy with Instrumentation & Controls Department senior technicians and foremen. The inspector determined that the instru-ments in question are used as an input to the Reactor Protective System rather than as an indicator, as is assumed by the manufac- '
turer's procedure. The inspector concurred in the adaptation of -
test points to check the instruments' zero response and to check l the response at the most significant point (the reactor trip set point). The requirements of Technical Specifications 3/4 were me No unacceptable conditions or practices were observe r'
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9 Unit 2
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" Calibration of Excore Nuclear Instruments to Incores" per SP2401E Revision 7 and " Power Range Safety Channel and Delta T Power Channel Calibration" per SP2601D Revision These tests are conducted to satisfy the channel calibration re-quirements for reactor power sensors as described in Technical Specifications 3/4.3. The amplifying notes 2, 3, and 4 of Table 4.3-1 are particularly germaine. SP2401E uses a desk top computer (Commodore PET Model 4032) to assist the operator in data collection and analysis. The program disc is controlled personally by the In-strumentation and Controls supervisor and provides its revision number to the operator to permit verification of its applicabilit The test also uses data from the plant process computer and a digi-tal volt meter (DVM) of suitable accuracy. SP2401E causes the in-dividual excore detector outputs to be adjusted to reflect the neu-tron flux shape measured by the fixed incore detector SP2601D uses installed test instruments only. It adjusts neutron channel outputs (2 detectors per channel) to reflect primary calorimetric power. No unacceptable conditions or practices were note " Facility I Containment Spray Alignment and Operability Test" per SP2606C Revision 3, " Facility I Containment Spray Pump Operability Test" per SP2606A Revision 3, and " Containment Spray Pump 'A'
Operational Readiness Test" per SP2111 These tests collectively demonstrate the operability of the "A" Containment Spray System as described in Technical Specification 3/4.6.2.1 (surveillance "a" items 1,2,3,4 and 6) SP2606C tests all remotely operated valves through a full stroke cycle and verifies the position of manual valves in the flow path. SP2606A tests the pump by remotely starting it, by verifying that the expected pres-sure head is developed with flow through the recirculation path, and by observing the pump complete a 15 minute sustained ru SP21116 measures pump vibration and hydraulic characteristics as required by ASME Boiler & Pressure Vessel Code Section XI Chapter IW The inspector verified the system flow path line-up following restoration. No unacceptable conditions or practices were observe "LPSI Pump 'A' Operational Readiness Test" per SP2111 This test is part of the licensee's pump and valve In Service Test (IST) program which assesses pump readiness according to ASME Boiler
& Pressure Vessel Code Section XI Chapter IWP standards. The tost-ing acceptance criteria were attained. No unacceptable practices were observe .
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w 10 Engineered Safety Features (ESF) System Walk-Down - Unit 2 In addition to cursory inspection of safety-related systems and components during routine daily facility tours, the inspector conducted a detailed walk-down of the "A" containment spray system. This walk-down included the condi- l tion of piping and valves in the suction lines from the containment sump and the Refueling Water Storage Tank; the condition of pumps, valves, piping and heat exchangers in the Facility I Safeguards Equipment Room (Auxiliary Build-ing -45 foot elevation); the condition of flood control docrs, sump pump suc-tions, and ventilation in the Facility I Safeguards Equipment Room; the con-dition of valves and piping in the Enclosure Building west penetration area; and the condition of accessible mechanical and hydraulic pipe snubbers. The inspection verified the position of all manual valves in the injection flow pat Additionally, the inspector witnessed tests of pump operability and motor operated injection valve operability. No unacceptable conditions were observe . Extended Observation of the Control Room Environment - Unit 1
, Observation of Unit 1 control room practices was conducted over an extended 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period on July 9. The shift included 2 Senior Reactor Operators and 2 Reactor Operators as well as several non-licensed equipment operators. Logs were up-to-date and sufficiently detailed to permit reconstruction of plant conditions and event The control room was clean and free of debris. The inspector viewed the interiors of the control boards and found only a light layer of dust with no excessive buildup on circuit components, cables, and housing Routine control room transactions were conducted smoothly and with due pru-denc Procedures were observed to be in use. Emergency procedures were found to be conveniently available to operators. No personnel were observed to loiter in the control room. No extraneous reading material was in evidenc The recent re-arrangement of furniture has improved the Control Operators'
view of the panels and their responsiveness to changing condition No unacceptable practices were observe . Plant Startup and Power Ascension Testing - Unit 2 Millstone Unit 2 was taken critical at 2115 on June 3 Power ascension tests were conducted per special test T19-8 The inspector observed segments of testing involving determination of incore neutron detector operability, moder-ator temperature coefficient, isothermal temperature coefficient, reactivity anomalies, peaking factors, and shutdown margin. The inspector noted that the results of testing conducted indicated that shutdown margin, moderator temperature coefficient, total planar radial peaking factor, and total inte-grated radial peaking factor were within the limits of Technical Specifica-tions. No independent calculation of results and no assessment of computer analytical methods or sof tware was attempted. The results of the startup and power ascension test program may be reviewed in greater detail in a future inspection (50-336/85-19-01).
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7. Followup of Inspection & Enforcement Bulletin 80-25, Target Rock Safety Relief Valves" This Bulletin discusses failures in Target Rock safety-relief valves at Boil-ing Water Reactors (BWRs). The Bulletin requires 3 actions of BWR licensee Two of these are surveys with results to be reported to the Office of Inspec-tion and Enforcement. The information has subsequently been incorporated into NUREG/CR 3794 "Close-Out of I&E Bulletin 80-25/ Operating Problems with Target Rock Safety-Relief Valves at BWRs". The third action requires the inclusion of valve test requirements in plant procedures for safety-relief trouble-shooting and maintenance. The licensee's submittal included a commitment to make the required procedural changes. The inspector reviewed the licensee's procedure index and found that one procedure, MP717.1, addresses trouble-shooting and repairs for these valves. The inspector confirmed that MP71 " Maintenance of Target Rock Relief Valves" Revision 7 includes the testing guidance of the Bulletin in section 4, " Precautions." The procedure speci-fically references the Bulletin to help assure that future revisions will not inadvertently delete the guidanc This Bulletin is close . Review of Licensee Policies Regarding Control Rod Manipulations As a result of several events at other operating reators which involved mis-positioned control valves, the inspector reviewed licensee policies regarding the positioning of control rods and operation with mispositioned control rods, Unit 1
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Plant procedure OP204 " Power Operation" requires a Reactor Engineer to be present for all but the most minor power changes. Examples of conditions in which a Reactor Engineer is required include con-trol rod pattern adjustment, power ascension following turbine synchronization, and fuel preconditioning. A " Reactor Engineering Information Sheet" is prepared to address times when a Reactor En-gineer is not stationed. The sheet includes the name and number of the "on-call" Reactor Engineer, reactivity trends expected, trends in thermal limits, a flow reduction / rod insertion sequence for unplanned power reductions, and a log for all rod motion. The sheet is approved both by the Station Reactor Engineer and the Operations Supervisor. The resident inspector has often observed this system in us A scroll-type list of the rod sequence for startup/ rod withdrawal and, conversely, for shutdown / rod insertion (" blue box") is mounted at the rod control station. Procedures direct all rod motion be conducted in accordance with the " blue box" (OP204).
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Individual rod scram capability exists as part of the installed scram timing equipmen Use of this equipment is limited to scram testing and emergencies involving an Anticipated Transient Without a Scra Millstone Unit 1 does not incorporate a Rod Sequence Control System (RSCS). The RSCS at other plants has complicated unscheduled shut-downs at several plants. Use of the " emergency in" and " notch over-ride" features of the Reactor Manual Control System at Millstone Unit 1 together with the " blue box" does not lead to difficulties in shutting dow Training in proper control rod movements, consequences of improper rod patterns, RWM, and reactivity addition accidents is conducted as part of license training and requalification trainin No unacceptable policies or procedures were note Unit 2
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Recovery from a dropped or mispositioned Control Element Assembly (CEA) is addressed in detail in Technical Specification 3.1. Plant procedure AOP 2556 " Dropped CEA Recovery" implements Technical Specification requirement CEA position indicator operability is addressed in detail in Tech-nical Specifiation 3/4.1. Sections 4.2 and 4.3 of plant Pro-cedure OP23498 " Process Computer" addresses operation allowable under the Action Statement in the event of pulse counter position indicator inoperabilit Training in proper CEA manipulation, rod position limits, and reac-tivity addition accidents is included in the requalification train-ing and license training program No unacceptable policies or procedures were identifie . Facility Tours The inspectors toured Units 1 and 2 as well as associated outbuildings and related yard areas throughout the inspection period. Improvement in general housekeeping was particularly noted in Unit 2 areas due to post-outage cleanup effort Continued decontamination efforts in the Unit 2 auxiliary building-45.5 foot elevation and in the west penetration room of the enclosure build-ing appear warranted. Unit I areas remain relatively free of surface contami-nation areas. The inspectors observed the material condition and monthly checks of fire extinguishers required by Technical Specifications as well as the integrity of a sample of fire barrier No deficiencies were observe .-
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The inspector noted that improvements in temporary solid waste storage to the east of Unit 1 were in progress. Personnel access to the Condensate Storage Tank and associated valves and to the nitrogen evaporator were not impaire A walk-down of the protected area boundary revealed no deficiencies in the protective barrier Personnel and package access procedures were observed at both the Condensate Polishing Facility (CPF) and Personnel Access Point (PAP). No unacceptable conditions were observe . Steam Generator Repair Summary - Unit 2 The inspector reviewed the licensee's summary of steam generator repairs sub-mitted in accordance with Technical Specification 4.4.5.1.5a in a letter dated June 18, 1985. Some adjustment to the extent of repairs forecast in Inspec-tion Report 50-336/85-13 is necessary. A total of 63 tubes were plugged and 2918 tubes were repaired by sleaving. The licensee's report contains greater detai . Exit Interview At periodic intervals during the inspection, meetings were held between lic-ensee site management concerning the inspection scope and findings. One item, a detailed technical review of Unit 2 startup test results (50-336/85-19-01),
remains ope At no time during the inspection was written material concerning inspection findings provided to the licensee.
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