ML20125B896

Special Rept on Operation of Northern States Power Co, Monticello Reactor Facility, Conducted on 720804

ML20125B896
Person / Time
Site:	Monticello
Issue date:	08/04/1972
From:	US ATOMIC ENERGY COMMISSION (AEC)
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ML20125B887	List: ML20125B886 ML20125B896
References
NUDOCS 9212100206
Download: ML20125B896 (37)

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i SPECIAL REPORT ON THE OPERATION OF THE NORTHERN STATES POWER COMPANY MONTICELLO REACTOR FACILITY

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\ Prepared By The

• DIRECTORATE OF REGULATORY OPERATIONS NORTHERN STATES POWER COMPANY (HONTICELLO - DOCKET No. 50-263)

IN CONNECTION WITH FULL TERM OPERATING LICENSE APPLICATION i

j AUGUST 4.'1972 1

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9212100206.720824 PDR ADOCK 05000263 P. PDR-

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, e TABLE OF CONTENTS i

4 INTRODUCTION 1

SUMMARY

1 CONCLUSIONS 3 DISCUSSION 4

1. OPERATING HISTORY 4

11. UNUSUAL OCCURRENCES 5 A. Reactor and Auxiliary Systems 5

1. liigh Reactor Coolant System Safety / Relief Valve Setpoings (4/71) 5

2. Slow Closure of Main Steam Isolation Valve (MSIV) (5/71) 6

3. Indicated Low Flow Through Main Steam Line Flow Nozzles (5/71) 7

4. Inoperable liigh Steam Flow Sensor Pressure Switchee (11/71) 7

5. Scram caused by Instrument Air Failure (9/71) 8-

6. MSIV Closure Time and Leakage (11/71) 9 B. Radiological Controls 10 Unplanned Caseous Release (7/71)

C. Containment 11 Detachment of Torus Baffles (11/71)

III. RADIOACTIVE WASTE DISPOSAL 13 A. Caseous Ef fluents 13 B. Liquid Effluents 13 1

i C. Independent Measurements of Plant 14 Releases by REGULATORY ' OPERATIONS I

IV. ENGINEERED SAFEGUARDS 15 A. Containment 15 B. Emergency Electrical Power System 16 C. Emergency Core Cowijng Systems 16

1. High Pressure Coolant Injection System 16

2. Im Pressure Coolant Injection and Core Spray System 17 V. SAFETY SYSTEM PERFORMANCE 18 A. Reactor Safety System 18 B. Reactivity Control 19 C. Reactor Pressure Relief System 20 VI. PRIMARY SYSTEM INTEGRITY 21 VII. NONCOMPLIANCE ITEMS 22 Vill. OPERATING ORGANIZATION 26 Attachments:

3 Table I - Summary of Regulatory Inspections Table II - Chronology of Operation Table III - Reactor Scrans Figure 1 - Plant Operating Organization i

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REPO3T l

BY THE -!.

DIRECTORATE OF REGULATORY OPERATIONS OPERATION OF THE MONTICELLO NUCLEAR GENERATING PLANT UNDER PP9 VISIONAL OPERATING LICENSE DPR-22 l J

INTRODUCTION - 1 The staff of the Directorate of Regulatory Operations has prepared this report on the operation of the donticello Nuclear Generating T'lant for consideration by the Directorate of Licensing in connection with Northern States Power Company's request. for a full-term operating j license. The report, covering plant operation through May 1972, is based on the results of our inspection program for the Monticello ,

Nuclear Generating Plant; our evaluation of the operating experience of the plant including review of abnorinal occurrence reports to the AEC -

by the licensee; the performance of reactor systems important to safety;.

and the competence of the licensee's organisation in operating'the plant.

StPMARY The Monticello Nuclear Generating Plant has_ completed 11 months of' comunercial power operation since completion of its 100-hour warranty run, and has generated a total of 2,545,750 Mw-hrs of electrical energy. Since initial criticality on December 10,~1970, the total energy output of the reactor is equivalent' to 4860 hours0.0563 days <br />1.35 hours <br />0.00804 weeks <br />0.00185 months <br /> of full  :

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power operation.

l" The principle operating problems encountered since initial operation s ,

l. have involved the following: Icakage through the main steam isolation i- ,

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2 valves; the detachment of the torus baffles; and indicated low steam flow rate through the main steam lines; and several individual failures of components, 1

The leakage through four of the eight main steam isolation valves was measured to be in excess of Technical Specification-requirements in November 1971. The leakage was reduced to acceptable values by rework-ing the valve internals before the plant resucied operation.

During an inspection of the containment suppression chamber in November, 1971, several baf fles were found to have broken f ree f rom their mountings.

This was attributed to pressure pulses generated from operation of the primary system relief valves which were transmitted through the suppression chamber water. Based on analysis by the General Electric Company and the licensee, baffles were removed from the suppression chamber ar.d the relief valve discharge lines were f astened more securely and extended to discharge at a lower level in the suppression chamber.

In May,1971, during the initial rise to power, the measured pressure dif ferential across the 4 main steam line flow nozzles was observed to be substantially less than predicted indicating an abnormally low steam flow rate. This was subsequently attributed to a leakage path internal to the flow nozzles between the differential pressure instrument sensing lines. This condition was corrected by modifying the low pressure tap in the flow nozzle.

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The nature and frequency of the individual component failures l

experienced are comparabic with that experienced at other power  ;

reactor facilities during the early operating life of the plant.

l The overall performance of the control and safety systems has been essentially as designed. Periodic surveillance tests of engineered safeguards have demonstrated the availability of the safeguard systems to meet the performance required by the Technical Specifications.

The management, operating, and engineering support organizations have remained essentially stable since plant startup. Sevstat matters involving a lack of effective administrative controls were detected by Regulatory Operations during the fir 4t year of operations. The licensee has been responsive in correct!.ig identified deficiencies in a timely manner and initiating appropriate action to pttevent their recurrence. This action included a major reorganization of NSP in March 1972, both at the Monticello site and at the corporate enginect-Ing offices. Regulatory Operations is currently conducting an inspection of the controls being impicmented by management to assure the safety of operations and to assure compliance with their operating license and other applicable regulations.

! CONCLUSION t The results of our overall inspection program to date show that the Monticello Nuclear Generating Plant has been operated safely since initial startup in 1970, and that the performance characteristics of the reactor and other systems important to safety have been in accordance with design objectives with the exception of the excessive leakage

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$ Based on our review and evaluation, as presented herein, we have concluded that the Provisional Operating License can be converted Y

to a full-term Operating License uithout undue risk to the health p and safety of the public.

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DISCUSSION _

The operatir.n of the Monticello Nucicar Generating Plant of thf Northern States Power Company (NSP) has been reviewed on a con -

ing basis by the Directorate of Regulatory Operations since the j initial plant utartup in December 1970. This review was accomplished through a total of 23 inspectionu '~volving the expenditure of app s i stely 128 man-days at ti. giant site. A listing of inspection I

dates ar.d gent tal areas inspected is given in Table I.

In addition to these inspections, we have had frequent informal contact uret the operating o 301 ation and have reviewed the operating reports and other subaissions to se AEC made by NSP. The significant results of the inspection. program are discussed and evaluated below

1. Operatink History The provisional operating license for the plant was issued on September 8, 1970. Initta'. criticality was achieved on December 10, i

t 1970. Commercial power operation was started on July 4, 1971. The plant has operated with only brief interruptions since that time i

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F 5-with the exception of a two and one-half month period (November 1971 through January 1972) when removal of the torus _ baf fles was accomplished.

A chronology of significant events given in Table 11 includes each-outage since the start of commercini operation. The number of scrams l

which have occurred and other pertinent operating statistics are summarized below:

No. of Times No. of Equivalent Cross Brought Reactor Full Power Electrical Year Critical Scrams

• Hours Hw-hours 1971 (beginning 7/4) 11 7 2131 1,241,080 1972 (Jan. thru May) 14 6 2289 1,304,670 TOTAL 25 13 _4420 2,545,750

• The dates and associated causes of reactor scrams are given in Table III. The average fuel burnup through the end of w ay.1972, was 3285 Hwd/NTU.

II. Unusual Occurrences This section saatarires the more significant occurrences associated with the safety of the reactor since initial startup of f the plant.

A. Reactor and Auxiliary Systems

1. Analysis of reactor pressure data recorded during the ,

planned " loss-of-of fsite-povar" test performed on April 22, 1971, indicated a possibility that the initiation setpoints of the four reactor coolant system safety / relief valves.were i

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~6-above the Technical Specification limit of 1080 psig.

Calibration checks indicated that three of the valves were set incorrectly, with the settings ranging from

.[ 1095 to 1110 psig. All four safety / relief valves were i inspected under the direction of the manufacturer's

\ representative. A leaking pilot valve was repaired, a dowel pin was shortened to proper length, and all four valves were adjusted to actuate at less than 1080 psig. A report on this problem was submitted to the AEC by NSP on April 30, 1971,

2. On April 26, 1971, while performing a planned test at 25 percent power involving the simultaneous closure of all main steam isolation valves (MSIV's) one MSIV closed in approximately six seconds. The Technical Sptcifications require a closure time of three to five seconds. The closure time for this MSIV was readjusted -

and tested satisfactorily. Test results for the redun-dant valve showed the closure time to be within the range required by the Techr-ical Specifications and thus the isolation capability was not compromised. A report on this prob 1cm was submitted tc the AEC by NSP on May 19, 1371.

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On May 3, 1971, during the; initial rise to power, the measured pressure dif ferential across the four main steam flow nozzles was observed to-be substantially less than predicted by design calculations. A review of the nozzle design and testing of a similar nozzle showed the cause to be a small leakage path which permitted pressure equalization between the high and low pressure sensing taps. The flow nozzle instrumentation was readjusted to compensate for the reduction in measured dif ferential and surveillance of this -

instrumentation was increased. Following a modification made in December 1971, to the throat tap of the flow nozzle,-

the measured differential pressure has compared favorably with the calculated value. _ A report on this problem was submitted to the AEC by NSP on July 21, 1971.

During a surveillance test on November 11 and 12, -1971, four of the sixteen main steam line high flow switches -(which cause icolation of the steam line in the event of excessive-steam flow) failed to trip at the required setpoint. System redundancy would have assured proper isolation if required.

All sixteen switches were replaced with switches of-a design more suited to this application and no further problems have

d been encountered. Reports on this problem were submitted to the AEC by NSP on November 23, 1971 and February 21, 1972.

5. On September 5, 1971, the operating feedwater-pumps tripped:

and a reactor scram was initiated by a " low" reactor water icvel trip signal. Water level continued to decrease to just -below the " Low Low" Icvel trip point, the Emergency Core Cooling system was actuated automatically, and a reactor isolation occurred as designed. Reactor water level was returned to normal by operation of the High Pressure Coolant Injection and Reactor Core Isolation Cooling systems and by manual operation of a feedwater pump. Tripout of the operat-ing feedwater pumps was attributed to a low pressure condition in the plant air system which was caused by the f ailure .of an air compressor combined with operator error.

The reactor was restarted after review by the licensee; however, it was later recognized that the main steam isolation valves (HSIV's) had reopened during the early stages of the-transient following the reactor isolation. After this abnormal condition was recognized, ets' reactor was shut down for further investigation. The Monticello Operations Committee concluded, after testing of the MSIV's had been-l

.- .. 9 completed, that an operator had-inadvertently reset the isolation condition after the isolation initiating _ signal hed cleared. Dual reset switches were installed to prevent A future inadvertent resets, and additional instructions' vere issued to plant operators cautioning then against resetting a reactor isolation condition until appropriate conditions had been satisfied. A report on this occurrence was submitted..

to the AEC by NSP on October 5,1971.

6. Operating dif ficulties were encountered in November 1971, with the main steam isolation valves (MSIV's), . ni that -

(1) two of the eight MSIV's failed to close in the required three to five ser.onds (causes not related to the occurrence '

on Apeil 26, 1971) and, (2) four main steam isolation valves were discovered to be leaking in excess of the Technical Specification limit of 11.5 SCFH. The abnormal closure rate of the MSIV's was corrected by (1) repairing a dashpot cylinder oil' leak which had allowed dashpot oil level to decrease below its normal value;-and, (2) by replacing a spool valve in the pilot operator. Correction of excessive 1cckage through the MSIV's was accomplished by reworking the valve intervals. Reports on these protlems were submitted

., to the AEC by NSP on November 26, 1971 and February 18, 1972.

l B. Radiological Controls .

On July 14, 1971, an unplanned gaseous release occurred from the f acility as a result of the following sequence of events.

t During surveillance testing of the main steam line high flow dif ferential pressure switches with the reactor at 90 percent power, the main steam isolation valves (MSIV's) automatically closed which resulted in a reactor scram. Following the scram, the bypass valves around the MSIV's were reopened manually to supply steam to the steam jet air ejectors. Erratic operation of the steam pressure regulator for the steam jet air ejectors allowed sufficient steam to pass into the of f-gas line to expel the t'at er f rom the of f-gas line loop seal. The loss of the loop seal allowed gaseous activity to be released to the turbine and reactor buildings. During the incident, the release rates from the turbine and reactor buildings to the environs remained well within license and 10 CFR 20 limits. The gaseous activity released was directed towards the main cooling towers by the existing wind conditions where some of the activity was scrubbed f rom the air by the water in the cooling towers and, subsequently, released to the discharge canal. The measured liquid activity

-6 in the discharge canal was approximately 2.5 x 10 uCi/cc (short lived daughters of noble gases) for a short duration. Analysis l

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MANAGER  !

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ORGANIZATION 1 3-1-72 Chief Clerk Plant Clerks E i Superintendent Superintender.t j en DPis ts .

Operation and Plant Engineeriq Maintenance ,g pg(% i t

Quality Engineer 3 ,

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Supervisor

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• 12 that the cause for the baf fle sections breaking free was a pressure impulse resulting from the initial rapid expulsion of water and air when steam is released to the torus through the submerged portion of the relief valve discharge lines.

The safety analysis for BWR f acilities subsequent to Monticello had shown that the baffles were not required. Therefore, based upon a recommendation from the General Electric Company, the licensee removed all baf fics f rom the torus except some sections required for support of the relief valve discharge lines. This modification required the draining of approximately 500,000 gallons of water in the torus, of which 43,000 gallons were discharged via the discharge canal. The balance was stored in the plant for return to the torus-after completion of repairs.

The relief valve lischarge lines were modified to terminate in a tee which is oriented to discharge along the internal center-line of the torus. All areas exhibiting distress caused by the movement of the baf flee and all suspected high stress areas (connecting welds, bracing, etc.) within the torus were nondestructively examined using magnetic particle techniques.

Three areas requiring repair were identified and corrected.

Reports on this problem were submitted to the AEC by NSP on December 15, 1971 and February 15, 1972.

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111. Radioactive Waste Disposal A. . Caseous Effluents Radioactive waste gases are released through the plant of f-gas stack which provides dilution before dispersion of the radio-active material to the atmosphere. During normal operation, the gaseous radwaste system operates on a continuous basis, with monitoring and control, allowing a holdup time of approx-imately 30 minutes to permit radioactive decay. Our inspection findings are that the gaseous activity releases during the period of the plant's operation have been substantially below the applicable AEC license limits as shown by the following data i

Type 1971 1972*

Discharge Curies  % of Limit Curies  % of Limit Noble Cases 75,800 0.89 136,449 3.9 0.22 Halogens 0.048 ]

Particulate 0.0037 0.0026 a

• January through May i B. Liquid Effluents Radioactive liquid wastes are processed through the radwaste-

! system on a batch basis, and either returned to the condensate system for plant reuse or disposed off-site by dispersal to the river via the discharge canal. The release of torus water i

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totaling 215 micrccuries in November, 1971 (see Section II.C.),

received considerable public interest; however, a special inspection at the site by Regulatory Operations confirmed that no violation of license requirements had occurred.

Recent improvements made by plant personnel in administrative controls and procedures have placed increased emphasis on vaste-recycling to the extent that essentially no radioactive liquids 1 have been discharged from the Monticello plant since January 4, 1972. Our inspection findings are that the liquid activities released to the environment since the plant commenced operation -

have been substantially below applicable AEC license limits as shown by the following data:

Type 1971 1972**

Discharge Curies  % of Limit Curies  % of Limit

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Gross activity

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~4 Tritium 5.9 x 10' 7.7 x 10 1.2 x-10 ***

• Excluding Tritium

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'*f Monthly average for January C. Independent Hessurement of Radioactive Effluents by Regulatory Operations Regulatory Operations periodically performs independent measure-ments of liquid and gaseous radioactive effluents released from the Monticello facility. Results to date show that NSP's analysis -

are adequate to identify and measure radionuclides in liquid l

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effluents. Results to date have also shown NSP's measurements are consistent with RO's results.

4 IV. Engineered Safeguards A. Containment Our inspection findings are that the integrity of the' primary containment was demonstrated successfully during the performance of an integrated primary cont _inment leak rate test in July 1970, before the plant became operational. Abnormal leakage through i

4 4 of the 8 main steam isolation valves was detected on one occasion during a reactor shutdown period in November 1971 (see Section II. A.5) . Two of the Icaking valves were located in the same steam line and resulted in a measured leakage through this individual containment penetration of approximately eignt times the allowable leakage. The leakage was corrected by reworking the valve internals and the leakage rate of all eight MSIV's was measured to be within allowable limits _before resuming plant operations.

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B. Emergency Electrical Power System Our inspection findings are that the plant's diesel generators have been functionally tested on a weekly basis to verify Although diesel proper operation of the emergency power system.

generator No.12 f ailed to start on two occasicas as a result of unrelates' problems, which were promptly corrected, an emer-gene; 3 wer supply has been available at all times.

C. Emergency Core Cooling Systems (ECCS)

Our inspection findings are that there have been isolated problems experienced with the subsystems of the ECCS since initial plant operation. The redundancy of subsystems, however, has proven to be adequate as the ECCS has always bem available to meet Technical Spec.ification requirements since plant startup. The principal problems that have been experienced are discussed below:

1. The High Pressure Coolant Injection (HPCI) sub-system has -

been tested at monthly intervals since plant operation com-On menced to demonstrate the operability of the system.

three occasions in September 1971, the HPCI system was reported inoperable as a result of an an m ly associated linc. T.t was with the flow sensor in the 11PCI steam su:-

subsequently determined that the steam flow sensor was affected by steam flow in the B main steam line (the HPCI g turbine steam supply comes froa the B main steau line 1

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upstream of the MSIV's), sad that no difficulty was encountered in testing the HPCI system after the B main steam line flow was reduced, as would be the case in an actual condition calling for HPCI operation. The licensee has initiated procurement of materials to install a venturi flow meter in the HPCI steam line during the first refueling outage (Spring 1973) to eliminate this condition.

A special procedure has been developed to permit perform-ance of HPCI surveillance tests in the interim.

2. Monthly tests of the Low Pressure Coolant Injection (LPCI) and Core Spray sub-systems have been performed to verify their operability. One reactor low low water level initiating switch was found to be out cl calibration in  :

April 1971; however, red.ndant switches would have provided proper system initiation. In September 1971, the trip settings of the pump start permissive switches for the core spray and LPCI sub-systems were found to be set approximately 15 - 25 psi below the required trip setting of 450 psig.

This resulted from an improper calibration technique. The l switches were promptly recalibrated and surveillance pro-

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cedures were reviewed and revised to prevent recurrence.

Two occurrences in November 1971 of improper valve opening permissive switch setpoints resulted from the use of AC-rated pressure switches in a DC appifcation. Proper a

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' . pressure switches were subsequently installed. Redundancy-of pressure switches would have resulted in' proper system 1 operation :if required.: A- core spray _ injection valve failed to open during a system. filling operation in- >

January 1972, as a result of the. loosening of the valve, operator gear train. This problem was promptly corrected, and proper operation of a second core spray pump NJ !ts related injection valves would have permitted system operation, if required.

• V. Safety System Performance A. ' Reactor Safety System Our inspection findings are that performance of.the-sensors-and associated circuits in the. reactor safety system has'been demonstrated'in that the system has never failed to initiate 3 a reactor scram signal when a scram condition occurred. Then s

plant . instrumentation monitoring reactor power, system pressure,

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r coolant temperature, coolant flow, and related parameters have been tested and calibrated as required by'the Technical ,

Specifications. Surveillance testing of the intermediate-power range monitor, low condenser vacuum scram switch, and average I_

.l power range monitor trip setpoints sera..dtacavered to be inaccurate-on separate occasions; however,:these occurrences were unrelated and did.not inhibit the redundant. circuitry from y

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or problema have been encountered with the systems during operation.

B. Reactivity Control Our inspection findings are that the control rod system has performed satisfactorily since initial operation of the plant in that the rods have always responded to action-initisting.

signals. Two deficiencies relating to operation of tha control rod system have been encounterr.d. On one occasion in harch 1971, one group of rods was inadvertently left in a partially inserted position, out of its normal withdrawal sequence.

Revised administrative controls were established by the licensee to prevent recurrence. On another occasion in January 1972, a variation in predicted core reactivity was encountered when criticality was achieved with only 23 control rods with-drawn as opposed to a predicted withdrawal of 43 rods.

In-vestigation of the anomaly showed that: (1) the origical reactivity worth of the poison curtains (and the resultant depletion rate) had been originally underestimated in the design analysia, and (2) the actual individual control rod worths for the rod withdrawal sequence in use differed from those used ir.

the criticality predictions. New reactivity values for the control rods and poison curtains were generated and confirmed during the subsequent startup. -The "one stuck rod" core reactivity shutdown margin was demonstrated to have remained within the Technical Specification limit.

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C. Resctor Pressure Relief System Our inspectica findings are that the pressure relief syntes has demonstrated its ability to protect the reactor from overpressure.

Problems summarized below have been identified with the relief valves .rA safety valves during the _ operating history

. of the plant; however, the ability _to provide overpressure -

protection was not affected:

1. Fuses were discovered to be missing from a pressure relief-valve backup power supply in May._1971, and fuse removal-procedures were revised and subsequently reviewed with plant electricians to prevent recurrence.

2. The D relief valve failed to reset properly-af ter a plant scram in September 1971. This was cc.used by galling of the relief valve stem. The valve! stems in all four relief._

valves were subsequently replaced with stems having a-stellite coating to prevent abrasiont

3. New springs (designed for a higher temperatereLapplication) were installed in the relief valve pilot operators as a precautionary measure as a result-of a problem experienced, with premature actuation of' relief valves at another.

facility.

4. Following a' turbine.. trip-in February.1972, one safety valve lif ted approximately 100 psi- below the-desired setpoint for' e-an estimated 1.5 seconds._ This safety valve was subsequently _

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21 replaced with another valve and returned to the manufacturer for testing.

VI. Primary System Integrity Our inspection findings are that the leakage from the primary system has been limited to leakage through valves, valve packings and pump seals. These conditions have required outages for maintenance and repair during the operating history of the plant.-

Recirculation pump seals failed on two occasions in early 1971, and new seals were installed. Seal failure was attributed to the flow of hot primary water past the seal after the pumps were secured. To prevent further recurrence, isolation valves were installed in the seal leak-off lines, and a supplemental seal cooling feature (using water from the control rod drive hydraulic-system) was subsequently installed.

A reactor water cleanup system isolation valve failed to operate on separate occasions in July and August 1971, because of an improperly secured wire in the control circuit and again in September due to improper installation of a mechanical interlock.

A redundant valve in the same line provided isolation capability in each case and repsirs have prevented further recurrence.

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No significe6 probler- .!fecting the integrity of the primary system have been enco. :ered to date. Requirements for inservice inspection of sht priw r- system boundary are established in the Technical Specifications and the licensee is currently developing'

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• his inspection program. The inspection program is scheduled for implementation at the first refueling outage (Spring 1973).

Methods and criteria for determining primary system leakage and procedures for responding to detected and suspected leakage have-been implemented. The methods available to detect leakage include containment sump monitors and containment sump pump flow integrators.

In addition, drywell pressure, temperature and radioactivity measurements are also used as indicators of primary system leaks.

VII. Noncompliance Itera

1. In March,1971, the primary containment was vented to the stack for one minute via the standby gas treatment system without first obtaining a sample of containment atmosphere. This was not in accordance with the licensee's approved operating pro-cedure for venting the containment. Paragraph 6.2.A of the Technical Specifications requires all operations to be conducted ,

in accordance witt. the Operations Manual. Management issued new instructions to all operating personnel concerning the proper procedure for venting the primary containment and stressing the need to adhere to established procedures.

2. On two occasions in March 1971, small quantities of low activity liquid waste (50 gallons and 345 gallons) were inadvertently discharged before samples were obtained and analyzed. Subsequent analysis by the lice.nsee disclosed that the releases were well t

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-4 9 can be definitely determined that system isolat:.e 'Luot required, and (3) placed a plastic cover over tae MSIV reset switch to prevent further inadvertent operation. The~cir-cuitry was subsequently modified to provide two reset switches (one for inboard and one for outboard MSIV's) to minimize the possibility of a single failure causing the MSIV's to reopen.

4. No samples were taken from four radioactive liquid tanks during seven time intervals occurring during the period September - December 1971. Paragraph 4.8.D of the Technical Specifications requires sampling the tanks at least every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> unless no additions to the radioactive liquid tanks have been made since the last sample. Records showed that additions had been made to the tanks during the particular time intervals concerned. Additionally, no analyses of canal samples for tritium were made for the months of August and September 1971. Paragraph 4.8.C.2.d of the Technical Specifi-cations requires a grab sample from the discharge canal to be analyzed monthly for tritium and significant isote es._ To prevent recurrence, the licensee (1) discussed the procedural errors with the individuals involved, (2) established a master surveillance schedule to assure that each tank is sampled every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and that the discharge canal is sampled on a monthly basis, and (3) provided a preprinted surveillance form to be filled out by the technician completing the work, which

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25-is'then forwarded to the Plant Chemist and the Radiation

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Protection Engineer for review.

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-1 5. -The failure of diesel-generator No.-12 to start during a ~ ,

V surveillance test on January 15, 1972 was not reported to the Region III, Directorate of' Regulatoryf 0perations Of fice ;

within 24-hours as a result of insufficient communication-between management and operating ~ personnel. Paragraph 6.6.'A.1' of'the Technical Specifications requires reporting of abnormal ~

occurrences of this type within-24 hours. . Licensee management ,

issued a new procedure requiring the Shift Supervisor to notify ~the Operations -Supervisor and the Assistant Plant Superintendent as_soon as possible in the event.of anyfoccur-rence'which may require reporting to the AEC.

- 6. No formal review by the Operations Committee-was made of'the-relocation of the adjustment potentiometer in the steam line . -

radiation monitor instrument chassis on April:21, 1972.

Paragraph 6.1.E.2.d of the Technical Specifications requires _ a1 review by the. Operations Committee of proposed changesLor; modifications-to plant systems;or equipment. To prevent re : ,

currence,-the licensee is developing additional; administrative

! procedurea which will-control changes to safety system-instru-mentation and equipment.

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Vill. Operatina Organization The basic organization of the plant operating staff, as affected by a reorganization in early 1972, is shown in Figure 1. The reorganization of the plant staff, accompanied by reorganizatio of the NSP General Office Power Production Department, was imple-mented to obtain optimum benefit of technical personnel in support of plant operation. Although interrelations of plant personnel were changed somewhat by the reorganization, the plant staff has generally remained stable since operation commenced insofar as assigned personnel are concerned. Key management, operating, and engineering support functions have been fulfilled by the same individuale since plant startup.

The Safety Committees have generally functioned as required by the Technical Specifications; however, during the early months of operation, it appeared that several operating events had not received the full attention of management. As a result of AEC discussions with Utility Management and related formal correspondence, NSP initiated organizational changes on March' 9,1972, at both the -site and corporate levels. The major organizational changes have been completed and revised manegement programs are currently being developed and implemented.

The licensee's technical support organization, as restructured in early 1972 (see Figure 1), provides for (1) a Quality Assurance

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Engineer; (2) a group of five system-oriented plant engineers plus two consultants under a Plant' Engineer-Operations;i(3)1 nuclear, -

instrumentation and computer. engineers under a Plant Engineer-Technical; and (4) a chemist and two Health Physicists under a Radiation Protection Engineer. This organization is headed by.a Superintendent-Plant Engineering and Radiation Protection,'who is a principal assistant to the Plant Manager. : Technical support at the site is ' considered to satisfy the commitments contained:in the FSAR. Technical Support at the corporate level is considered minimal in the areas of Health Physics and Radiochemistry; however, _

HSP has been utilizing outside consultanta for these services.

The Monticello plant staff has generally demonstrated itself to be competent to operate the plant in a safe manner. ?The reorganiza-tion and revised management programs effected early this yea'r i

should, when fully implemented, provide stronger support in the '

areas of problem identification and timely resolution of problems.

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1 Tablo 1 - Summary ref Resuletory Insp etinas Dates of Inspection Activities Reviewed 9/9/70 Completion of facility construction and-testing.

9/23/70, Fuel loading and reactivityf control 10/1-2/70 and reactor' aystems performance.-

10/19-21/70~ Status of resolution of standby gas treatment and.feedwater system operating problems.

11/5/70 Standby gas treatment and feedwater system problem resolution plans N:s .(aceting with GE, NSP, and Bechtel).

11/30/70 -

Reactor operation and progress.of=

12/3/70 resolution of standby gas treatment and feedwater system problems.

12/10-11/70 Preparations for_ initial critical-test. initial criticality.

12/31/70 - Completion of outstanding inspection 1/2/71 items -(facility procedures, surveillance

' testing of safety systems, CRDN testing, ,

preoperational and hot functional' test-ing).

1/25-27/71 Operation of- feedwater system. '

i 2/15-18/71 Operation of feedwater system.

2/25-27/71 Startup testing results and Quality Assurance efforts associated with-

_ piping andfother. components.

, 3/15-17/71 Repairs to feedwater minimum flow piping and operation of feedwater system._

{ 3/25-26/71 Startup testing program results.

4/26-29/71 Control rod drive performance.

6/1-4/71- Operational unusual occurrences.

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7/4-7/71 Turbine trip test from full power.

7/20/71 Circumstances associated with the 8/3/71- unplanned gaseous release of July 19 -

1972.

9/1b/71 Reactor scram events.

,,,_._ 11/11-12/71 Reactor operations, s

11/21-24/71 Circumstances associated with torus water discharges.

12/1r 15/71 Reactor shutdown activities which included torus baf fle removal progress, radweste systems review.

2/2-4/72 Records of torus repairs, corrective action for other reactor system components, completion of radwaste systems, review.

4/21/72 Operating records relative to TLD readings.

5/8-9/72 Reactor operations, radwaste facility construction.

5/23-26/72 Inspection of site management systems, i

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Trble 11 - Chrenology of Opnrn o on o'. ,

9/8/70 Provisional Operating License DPR-22 vaa issued, fuel loading commenced.

12/10/70 Initial criticality was achieved.

3/6/71 First synchronized turbine generator to NSP system.

4/18/71 HPCI operability.was demonstrated with the controller in manual and set to deliver the required flow and pressure.

4/19/71 Startup testing at 15% power was completed.

4/26/71 Startup testing at 25% power was completed.

S/8/71 Startup testing at 50% power was completed.

5/20/71 Startup testing at 75% power was completed.

6/27/71 startup testing at 100% power was completed.

7/4/71 Completed 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> warranty run.

7/5/71 Performed turbine trip test from 100% power. This completed all startup tests.

7/6/71 Completed initial drywell inerting.

7/14/71 While establishing steam flow to the main condenser following a reactor isolation, *he water loop seal at the air ejectors- discharge was L.)st, resulting in j

' off-gas being discharged to the turbine building sump.

This resulted in the diacharge of a small amount of gaseous activity (2000 uci/sec) from the reactor building ventilation stack over a half-hour period. Modifications

, were made to procedures, the air ejector steam supply and the loop seal isolation controls to prevent recurrence.

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7/15/71 Outage to remove tirbine stop valve and intercept valve

, to startup screens. Replaced filter elements in condensate /

7/25/71 demineralizer "B" and chemically cleaned condensate / '

demineralizer "C". Resumed power operation 7/26/71.

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8/7/71 Reactor scram f rom condenser low vacuum due to cooling tower return line screens plugging while going to closed circulating water system operation Resumed power operation 8/8/71.

8/9/71 Reactor scram caused by improper opening of sensing line while calibrating condenser vacuum switches. Resumed power operation 8/10/71.

8/20/ 71 Reactor scram from APRM lii-Hi trip caused by sudden increase in No. 11 recirculation pump speed. Replaced faulty control amplifier. Resumed power operation, 8/22/71 Reduced power to hot standby to repair flange leak on 12-A LP drain cooler. Resumed power operation.

8/26/71 Shutdown plant to repair leak on 12-A feedwater heater, to While shutdown discovered and repaired leak in generator 9/1/71 hydrogen seal. Also replaced filter elements in condensate /

demineralizer vessels "A", "D", and "E". Resumed power operation 9/2/71.

9/5/71 Low air pressure caused closure of condensate demin outlet valves which in turn caused a low suction pressure trip of the reactor feed pumps. Reactor scram was initiated by low water level sensors. Air compressor loading valve repairs were completed and additional operator training was .

instituted to prevent a recurrence. Resumed power operation 9/6/71.

9/9/71 Shutdown plant to test MSIV closure reset circuit. Circuit found satisf actory. Resumed power operation 9/11/71.

9/22/71 Reduced power to 50% to close "B" steam line isolation. valve, and test RPCI system. Test verified that the differential pressure developed by the HPCI steam line flow elbow-is affected by flow in "B" steam line. The HPCI system was demonstrated to operate successfully in both AUTO and MANUAL control with "B" steam line MSIV shut. RHR service water pump No. 12 tripped as a result of a short in the motor.

Motor extensively damaged.

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3 9/24/71 Plant shutdown while investigating RHR Service Water System flow anomaly. Investigation revealed that the vendor supplied flow orifice calibration-data was in error. Returned to power operation 9/26/71.

9/27/71 Reactor power was reduced to 60% when No.11 recirculation pump field breaker tripped. Cause could not be determined.

9/28/71 Restarted No. 11 recirculation pump.- Reactor scrammed due to APRM Hi-Hi trip when No.11 recirculation pump speed suddenly increased.

9/29/71 Operated at 60% power with one recirculation pump in to operation while investigation and repair of No.11 9/30/71 recirculation pump speed and excitation controls were in progress, 10/1/71 Completed repairs to No. Il recirculation pump controls, placed it in operation and brought reactor power to 90 percent.

11/12/71 Scheduled plant shutdown to install new design rotating to assembly in No. 12 feedwater pump and perform general 1/24/72 maintenance. Testing and inspections performed during the outage revealed that several FGIV's were Icaking and several torus baffles had become detached from their-supports. The outage was extended to repair the'MS1V's and to remove all torus baffles. Other work completed during the. outage included modification of the main steam flow restrictors, extension of the main steam relief valves dischargo lines, insta11ntion of an off-gas loop seal low 1cvel isolation sensor, replacement of the seat pressure adjustment springs for the main steam relief valves, and balancing of No. 11 Recite MG set.

1/25/72 Performed core physics tests to determine reasons for to apparent core reactivity-anomaly encountered during reactor 1/31/72 startup on 1/24/72 (discussed in Section V.B of report).

Resumed power operation 1/31/72.

2/6/72 Shutdown to repair Icaks in turbine inner hood manhole covers. Resumed power operation 2/10/72.

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4 2/11/72 Reactor scram from 80% power caused by high neutron flux trip as a reault of a recirculation pump control malfunction. ,

Corrected recirculation pump controls, including installation of a scoop tube locking feature to hold pump at existing flow on receipt of a rapidly changing signal. Returned to power operation 2/13/72.

2/26/72 Scram from 100% power caused by turbine stop valves tripping shut as a result of a surge in the hydraulic system expe-rienced during routine exercising of the stop valves. Made adjustment to stop valve control, returned to power operation 2/28/72.

3/3/72 Scram f rom 96% power caused by high reactor pressure which resulted from #2 turbine control valve closure. . Investiga-tion revealed that the servo feedback linkage had disconnected.

It was reconnected and the bolt was staked. Resumed power operation 3/4/72.

3/11/72 Decreased power to 55% to repair jacking hole plug leak on

1. 12 feedwater pump. Resumed normal operation.

3/18/72 Shutdown plant to repair shaf t end-cap gasket leak on feed-water check valve. Reswned power operation 3/19/72.

3/24/72 Reduced power because of erratic pressure control, followed by closure of f2 turbine control valve. Power reduction on initial detection avoided scram. Shutdown reactor, found servo feedback linkage disconnected. It was reconnected and all connecting bolts were velded to prevent further loosening. Resumed power operation 3/25/72.

3/27/72 Reduced power to investigate recirculation pump controls  ;

following unexpected speed decrease. Problem was found 1 to be associated with the scoop tube positioning. control.

Resumed nonnal operation with scoop tube locked in position, operated manually when necessary, pending further evaluation j during planned outage.

4/8/72 Reactor scram from 58% power caused by turbine stop valve trip resulting from loose operating spool valve linkage.

Corrected linkage to prevent further loosening, resumed power operation.

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4/21/72 Scram occurred during removal of steam line radiation monitors for maintenance. Cable dropped to monitor chasois below, causing short and subsequent scram.

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Resumed power operation af ter investigation revealed 9 no damage.

5/12/72 Shutdown for operator licensing examinations. Also performed miscellaneous maintenance. Resumed power operation 5/14/72.

5/23/72 Scram resulted from generator trip caused by voltage regulator malfunction. Resumed power operation with _

voltage regulator control in manual while repairs were affected. Power operation continued through end of May.

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O" - f Table III - Reactor Scrams 7/5/72 Planned scram from turbine trip test at 100% power.

7/14/71 Pressure surge occurred in the instrument sensing line when pressure transmitter was valved in service follow-ing routine calibration. Pressure surge tripped the main steam line high flow switches connected to the same line

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causing a group I isolation. Main Steam Isolation Valve closure caused the scrsm.

8/7/71 Low condenser vacuum cause ' the scram while changing to closed circulating water syseem operation. Circulating water pumps tripped due to low basin water level caused by plugged cooling tower return line screen.

8/9/71 Reactor scram from improper ere ting of sensing line while calibrating condenser vacuum St.am switch.

8/20/71 Reactor recirculation pump No.11 suddenly increased in speed causing an Average Power Range Monitor (APRM) high flux scram.

9/5/71 Both reactor feedwater pumps tripped on low suction pressure when the condensate /demLncralizer control valves closed due to low air pressure. Low water level scrammed the reactor.

9/28/71 Sudden increase in No.11 recirculation pump speed caused an APRM high flux scram.

2/11/72 APRM high flux trip resulted from a sudden increase in No.11 recirculation pump speed.

2/26/72 Turbine stop valves tripped shut during routine exercising of turbine stop valves.

3/3/72 closing of No. 2 turbine control valve (as a result of a dioconnected linkage) cause high pressure trip.

4/8/72 Turbine stop valves tripped shut during routine exercising of turbine stop valves.

4/21/72 During removal of steam line radiation moniter for main-tenance, cable dropped and made contact with chassis below, causing short.

j 5/23/72 Generator tripped because of voltage regulator malfunction.