ML20030A488

Semiannual Operating Rept,Jan-June 1975

ML20030A488
Person / Time
Site:	Big Rock Point File:Consumers Energy icon.png
Issue date:	06/30/1975
From:	CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.)
To:
References
NUDOCS 8101090734
Download: ML20030A488 (60)

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CONSUMERS POWER COMPEY BIG ROCK POINT PLANT SEMIANNUAL OPERATIONS REPORT NO 22 JANUARY 1,1975 - JUNE 30,1975 L'

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CONSOMERS POWER COMPANY j.

Docket 50-155 License DPR-6 22ND SEMIANNUAL REPORT OF OPERATIONS OF BIG ROCK POINT PIANT January 1,1975 - June 30,1975 I

-I.

INTRODUCTION - SEMIANNUAL OPERATING REPORT On January 16, 1975, approximate'y one week prior to our scheduled semi-2 annual outage, the plant was shut down when findings by the Suntac

' Corporation revealed that there were design and/or QA deficiencies in the instrumentation for the Post-Incident Cooling System.

T~.e shutdown t

1 marked the end of 173 consecutive days of power generation.

i A Task Force was appointed to review all of the equipment in the Post-Incident Cooling System as to its capability to operate in the postulated environment of the Loss of Coolant Accident (IOCA). Modifications to the system and other corrective actions were the result of the Task Force investigation and were completed in the first week of June. The unit returned to service on June 8, 1975 with an average power output at the i

end of this reporting period of approximately 62 MWe net.

Excellent fuel integrity <:ontinues to be maintained as the off-gas release rate is l

at its lowest rate in history when compared with previous fuel cycles (approximately 2500 pCi/s at the end of the report period).

Information concerning the outage and the subsequent modification is con-tained in letters to the NRC dated January 27, February 1h & 28, March 1h

& 27 and May 2 & 15, 1975 II.

OPERATIONS SUM'4ARY A.

Changes in Plant Design Facility changes are as follows:

1.

C-267

. This change consisted of installing " closed" position indicating

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lights for Bleeder Trip Valves BTV/hh50 and BTV/h451 in the turbine 1

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generator system. This change was made so that the operator can monitor bleeder trip valve operation in conjunction with turbine stop valve trips. Indicating lights were installed at the front end of the turbine.

2.

C-272 This change involved changing RMC Switch 5530 on motor-operated Valve 7073 and RMC Switch 5531 on motor-operated Valve 707h in the fire system header piping to main condenser to GE Type SB-10 switches.

The SB-10 type switch has a pull-to-stop feature making it compatible with other control switches on the panel' board.

3 C-273 This change consisted of installing 1-1/2" steel piping and two plug valves connecting the condensate demineralizer resin outlet header directly to the resin disposal tank inlet header. This change re-duces manpower requirements and effectively reduces personnel radia-tion exposure when changing condensate demineralizer resins.

h.

C-277

. This change consisted of replacing a 30-amr, 3-pole, 480 VAC ACB with I

a 50-amp, 2-pole, h80 VAC ACB in MCC#2B pcwer supply to lighting Trans-former LT-3.

Cable size was changed frca #8AWG to #6AWG feeding panel LT-3 from MCC#2B. This change was made to correct for a breaker trip-out problem when testing the emergency' diesel generator.

5 c-28h This change consisted of relocating the lifting beam for the diffuser 1

on the fuel pool sock tank. This change was made to minimize personnel radiation exposure and the spreading of contamination while working on the sock tank and radwaste cask.

6.

c-286 This change consisted of installing a hose from the plant service air supply to the stack gas isokinetic probe allowing moisture to be blown from the air line before purging the probe.

7 C-288 i

This facility change consisted of installing a walkway along the west I

side of the sphere heating and cooling A & B units to provide safety for operators when making valving changes.

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l 8.

C-289 This change consisted of-reducing the set point on the fire system accumulator relief valve (RV-50h0) from 110 psig to 95 psig to satisfy

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l the requirements of Section VIII of the B&PV Code (relief valve set j

points must be below tank design pressure).

To perform this change, it was also necessary to reduce the set point of the accumulator level control air cushion pressure switch (PS-609-2)

I from 95 psig to 90 psig to allow proper accumulator level control I

operation.

9 C-293 This change consisted of installing a barrier at the makeup de-mineralizer to prevent acid leaks from spraying on floor area adjacent to makeup demineralizer control par-1 and neutralize. tank.

10.

C-29h This change 3dded two electrical outle;s and one light fixture in the clean-up system demineralizer heat exchanger room to provide 4

I better lighting in this area and provite electrical outlet for power tools necessary for equipment repair and portable air sampling devices.

11.

C-30h This facility change consisted of changing the power supply for stack base lighting from Breaker 6L #11 to Breaker 6L #1. This change removed a lighting circuit that was connected to a circuit feeding 220 VAC piping heaters and will allow proper workman pro-tection while work is being conducted on the stack base lighting 1

system.

B.

Performance Chrracteristics At the start of the report period, reactor power output was being r

maintained at 200 W with a gross electrical generation of 63 We.

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On January 7,1975 power was reduced to 192 W due to encroachment g

of the 90% limit of the exposure dependent Technical Specifications MAPLHGR (Maximum Average Planar Linear Heat Generation Rate) limit

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on F-type fuel. The 90% administrative limit of the Technical 4

3

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Specifications thermal hydraulic limits (MCRFE, MAPLHGR) was imposed 2

due to a criterion based on availability of operational in-core detectors which at that time amounted to 10 out of a possible 24.

At 12h5 hours on January 16, 1975 the plant began a voluntary orderly shutdown because findings by the Suntac Corporation engaged in the Reactor Depressurization System design studies revealed a design deficiency in the presently installed instrumentation for the Post-Incident Cooling System.

1 During the control rod drive scram timing test on January 17, B h drive would not withdraw. This necessitated the removal of the reactor vessel head to allow the removal of adjacent fuel and chan-nels. A piece of 1/2" bolt shank approximately one inch long, with an attached nut, was retrieved from the B-4 " Dixie Cup."

Based on an investigation as discussed in the Unusual Event Report UE-1-75 dated February 11, 1975, the piece of bolt was suspected to have come from repairs to the reactor top guide in 1966 as all other accessible combination of bolts and nuts were accounted for.

1 On January 22, Channel'No 98, an old zire model, was found slightly damaged in three places on the lower edge of the support tube. The i

damaged section was reformed and the channel was returned to its core position. Early in the outage four new local power range mon-itors (LPRM) in-cores were installed in the reactor vessel in Positions 13, 16, 17 and 18.

On January 23, a 1/h" x 1-1/2" headless bolt with washer and nut and a 1/h" bolt head were found on the grid bar masking plate. The bolt and nut were from an obsolete lower grid bar locking bar beam clamp.

The in-use lower grid bar locking bar beam clamp fell off its position on the locking bar on this date also. The obsolete beam clamp lock was subsequently removed from the locking bar and retrieved from the

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. reactor vessel. Also retrieved were its second set of 1/h" bolt, nut h

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bolt assembly. The in-use beam clamp lock was repositioned and General Electric Co supplied assistance in performing the in-vessel underwater welds on the beam clamp lock bolts.

Replacement of the core internals was completed on February 20 and following this the shutdown margin check procedure was implemented.

On February 24, two fuel bun'les were removed from the core for a d

i cobalt rods exchange. Eight cobalt rods were replaced and the bundles were returned to the core in the same location and orientation. The removed cobalt rods, totaling 158,000 curies, were later shipped off

. site to Neutron Products, Inc.

The semiannual containment component leak rate test was conducted from March 18 through March 27, 1975. The supply ventilation butter-fly valve was determined to be leaking in excess of the limits of i

10 CFR 50, Appendix J.

Following adjustments to the valve seat and changing the rubber gaskets on the personnel and equipment locks, the total component leak rate was 65.7% of the 10 CFR 50, Appendix J, criteria.

Due to the problems associated with the supply ventilation butterfly valve, special monthly testing of the supply ventilation valves was initiated. On May 26, 1975 the test of the valves again showed ex-

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cessive leakage from the butterfly valve which (of the two supply vent valves that are in series) is nearest to the containment side.

4 A representative frcm Allis-Chalmers, the vendor of the valve, as-sisted the plant in completing repairs on the valve. Tests on the valve-then showed only minimal leakage. A retest in June again showed the leakage to be minimal.

(Also see Section II.D.l.e.)

The plant returned to power operation on June 8.

Power was escalated slowly with the escalation. rate based on GE fuel preconditioning 5

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criteria. Thermal catput reached 207 MW on June 22 where it was 4

restricted the remainder of the report period. The power level limit was based on the MAPLHGR limit for the LOCA (Loss of Coolant Accident).

The off-gas release rate after reaching 207 MW was approximately g

i 2500 pCi/s. The release rate prior to shutdown in January was ap-proximately 1600 pCi/s while at 200 MW.

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With the addition of the four new in-core strings during the outage, a total of 17 out of a possible 2h detectors is operational.

C.

Changes in Procedures Manual Which Were Necessitated by Preceding A and B or Which Otherwise Were Required To Improve the Safety of Facility Operations The following proc 6 dural changes were made with respect to plant i

operations:

Change No Section and System Change i

1-75 Dl.3 Annunciator Tabulation - Annunciator Humbers 10, 16, 17 -

Clarifles Recirculation Pump Operation 2-75 Dl.2 Annunciator Tabulation - Annunciator Numbers Ih, 15 - Clarifies Steam Drum Water Level Conditions 3-75 D1.h Annunciator Tabulation - Annunciator Number 8 - Clarifies Con-denser Hot Well Water Level Conditions i

h-75 Bh.3.h.1 Procedures Section - Logging of Squib Valve Temperature 5-75 Dl.6 Annunciator Tabulation - Annunciator Number 10 - Changed Set Point on Fire Water Accumulator Tank Water Level 6-75 B27.4 Procedures Section - Checking of Operating Time on Air Compressors 7-75 A7 2 Procedures Section - Handling of Facility Changes 9-75 A2.8 Procedures Section - Establishing a Systems Status Board 10-75 C6.h.3 Change on Air Purge for Stack Gas Probe 11-75 B3.0 Rewrite Entire Clean-Up System 12-75 A7 1 5 Need for Radiation Protection in Facility Design Changes and Maintenance Orders 13-75 Bl.1.10 Change on Limiting Conditions, Reactor Operations lk E5.5 Change on " Release of Materia'3 or Equipment Off Site" 15-75 B24.h.5 Testing of Service Air Compressor - Change Wording 6

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Change No Section and System Change 16-75 Ek.h Addition of Exposure Limits 17-75 D1.2 Annunciator Tabulation Number 10 - Clarifies Core Spray System Operation on Low Reactor Water Level Trip.

18-75 B3.3 7 Resin Transfer to Clean-Up Demineralizer - Change Wording 19-75 B28.3 Operation of Station Battery Charger 20-75 B8.3-B8.4 Add " Starting cf Electric Fire Pump Manually o Post-Incident System Procedure 21-75 D2.26 Add " Manual Start of Fire Pump" to Emergency Procedures 22-75 D1.2 Tabulation Annunciator Number 22 - Enclosure Hi Pressure Scram Set Point D1.4 Tabulation Annunciators 3A & 4A - Change of Set Point.

D1.h Tabulation Annunciator 63 - Enclosure Hi Pressure Timer Start, 1

Clarify Set Point D.

Results of Surveillance Tests and Inspections Required by Technical Specifications The following listings show the system tested, the required test frequency, the dates tested during this report period, and the 1

4 results of the test.

1.

Containment Isolation a.

System - Containment isolation valve controls and instrumentation.

Reauired Frequency - Quarterly (conducted monthly).

Test Dates - T30-01 was performed on January 14, 1975; the plant vas removed from service on January 16, 1975 Prestart-up check sheet C-3 (similar to T30-01 in content) was run on June 3,1975; the plant was returned to service en June 8,1975 and test T30-01 was again performed on July 1,1975 Performance of this test is not required when the plant is shut down.

Results - The automatic contiols and instrumentation for eight of nine isolation valves were checked and found to function properly.

One valve (main steam drain valve M0/7065) is maintained in the closed position, de-energized and not used; therefore, testing the automatic controls of this valve is not required.

b.

System - Isolation valve leak and operability test.

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Required Frequency - Twelve months (or less).

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' Test Dates - Test T365-04 was partially performed on January 21 and 22, 1975 and completed on May 30, 1975 Results - Fuel pool and reactor drain outside isolation valve CV/hllh failed to pass the acceptance criteria. Maintenance was performed on this valve and the applicable section of T365-04 was rerun. Results of second test on May 30, 1975 vera satisfactory.

System - Containment sphere penetration inspection (visual).

c.

Required Frequency - Twelve months (or less).

Test Dates - April 22 and 23, i975 Results - On penetrations H-12, H-13, H-3h, H-67 and H-68, surface rust was noted on the outside of containment. The rust was removed, penetrations reinspected and subsequently repainted.

l d.

System - Containment sphere integrated leak rate test.

Required Frequency - Every two years, i

Test Date - This test was not required during this report period.

i e.

System - Containment component leak rate test.

Required Frequency - Six months (or less).

Test Dates - Test T180-01 was performed'on March 18 through March 27, 1975 J

Results - The results of the testing following maintenance showed a leakage of 65% of the allowable leak rate. Problems were en-countered with the containment supply butterfly valve seat adjust-1 ment which resulted in performing a special monthly leak rate test on the supply vent valves.

(See Section II.B Performance Characteristics.)

i 2.

Control Rod Drive Syst em and Associated Tests System - Reactor safety system scram circuits (not requiring plant a.

shutdown to test).

Required Frequency - One month (or less).

Test Dates - T30-01 was performed on January 14, 1975 Plant was shut down on January 16, 1975 Prestart-up Check Sheet C-3 was performed on June 3,1975 (similar in content to T30-01). The plsnt was returned to a

service on June v and T30-01 was again performed on July 1,1975 Per-formance of this test is not required when the plant is shut down.

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i Results - Satisfactory, no problems encodntered.

b.

System - Control rod performance - run.

-Required Frequency - Each major refueling and at least once every six months during power operation.

Test Dates - January 17-18, 1975 and June h-5,1975 Results - The "as found" withdrawal time for four CRDs (D-3, f

D-6, E-3 and 'F-3) was found to be less than the 23-second minimum withdrawal. time as specified in the current Technical Specifica-tions. A request for a Technical Specifications change has been submitted to the NRC for consideration to remove this minimum withdrawal time requirement. The control rod drive continuous withdrawal and insertion test, including withdrawal timing, was performed for each CRD during each test. Both tests were per-I formed for each CRD during each test.

Both tests were performed during the January 16 - June 8,1975 outage following completion of other CRD performance tests and adjustments and represents the results of the final timing of each CRD under cold conditions.

The results of the June h-5 test showed all CRDs to be operating satisfactorily with all withdrawal times between 36 and 38 seconds.

c.

System - Control rod performance - jog.

Required Frequency - Each major refueling and at least every six months during power operation.

Test Dates - February 15 and June h-5, 1975 Results - Satisfactory latching and unlatching of all CRDs.

d.

System - Control rod performance - scram.

Required Frequency - Each major refueling and at least once every six months during power operation.

Test Dates - January 18 and June h,1975 Results - The CRD scram test was performed for each CRD. The test included time from system trip to 100% of insertion. The results of the tests were all within the Technical Specifications of <2.5 seconds for 90% of travel. The longest time recorded was 1.k2 i-seconds.

I System - Reactor safety systems scram circuits (requiring plant e.

shutdown.

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4 Required Frequency - During each ' major refueling outage but not

-less frequently than once every twelve months.

Test Dates - February 19,1975 (refuel) and June 3,1975 Results - PS/RE15B (high condenser pressure scram bypass switch)

-set point wan found-to be 12 psi above set point. The switch was reset to < 350 psi. Other than this item, the test was satisfactory

_(A0 11-75). A Technical Specificaticns change has been submitted requesting the set point change to < 500 pai.

4 f.

System - Reactor-safety system response time (requiring plant-shutdown).

Required Frequency - During each major refueling shutdown, but not less frequently than once every twelve months.

Test Date - June 3, 1975 l

Results Satisfactory.

g.

System - Control rod withdrawal permissive interlocks function'.

Required Frequency - Twelve months or less. The refueling inter-locks will be tested prior to each major refueling.

Test Dates - Test TR-02 was performed on January 17 and 21 and February 15, 1975 Results - Satisfactory for each test.

h.

System - Control rod drive friction test.

Required Frequency - During each major refuelinn, but not less

'than once each year.

Test Date - February 16, 1975 Results - The test was run following core internal reconstitution.

Test v.s satisfactory.

3.

Euergency Cooling a.

System - Core spray system check valves.

Required Frequency - Twelve months or less.

Test Date - February 5, 1975 Results - Satisfactory.

b.

System - Post-Incident spray system automatic control operation.

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Required Frequency - Twelve months or less.

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Test Dates - Test T365-10 was performed on February 18 and I

June 2,1975 10 1

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i Results - Reactor containment building sprays electrical circuits were tested satisfactorily, c.

System - Reactor emergency core cooling system trip circuit.

Required Frequency - Twelve months or less.

Test Dates - Test T365-10 was performed on February 18 and June 2, 1975 R_esults - Satisfactory.

d.

System - Containment sphere isolation trip circuits.

Required Frequency - During each major refueling shutdown, but not less frequently than once every twelve months.

Test Dates - Test T365-15 was performed on February 19 and June 3, 1975 Results - Satisfactory.

e.

Systejg - Emergency condenser outlet valves test.

Required Frequency - Twelve months or less.

Test Date - Test T365-17 was performed on June 3, 1975 Results - Satisfactory.

f.

System - High energy piping leakage inspection.

Required Frequency - Monthly when turbine generator is in service.

Test Dates - January 7,1975 and June 17, 1975 (Turbine generator out of a2rvice from January 16 to June 8, 1975.)

Results - Satisfactory, no leakage detected.

g.

System - Primary system leakage test.

Required Frequency - Daily.

Test Dates - The.calculatica ans made daily from January 1 through January 17, 1975 Plant was removed from service on January 16 and remained so until June 8, 1975 calculations were resumed on June 7,1975 and continued daily through June 30, the end of the report period.

Results - Satisfactory, <1 gpm unidentified.

h.

Miscellaneous Systems a.

System - Reactor shutdown margin test.

Required Frequency - After each refueling, after certain core i

component changes if the system is cooled to atmosphere conditions and after 35,000 MWdt.

11

l Test Dates - Test RE-08 was performed on February 21 after four bundles were loaded. Shutdown margin checks were again performed on February 25 per Procedure RE-7 (two bundles reloaded). An optional two-rods-out shutdown margin test was conducted on June 5, 1975 per Procedure RE-08.

Test Results - The shutdown margin of 0.3% jf with the strongest rod fully withdrawn from the core was experimentally verified by means of the "go - no go" test. An additional two-rods-out shut-down margin check was performed as an administrative option. The core was rendered supercritical by approximately.05% Ak[k, with control rods A h to 23, A-5 to 16, and B-5 to 06. The test was halted since the acceptance criterion to continue (suberiticality) was not satisfied. This result indicated that operation with a rod, incapable of scramming, would not be allowable per Section 5.2.2(f) of the Technical Specifications.

b.

System - Nil Ductility Transition Temperature (NDTT) calculation.

Bequired Frequency - At least cace per year.

i Test Dates - The calculation was performed (Procedure RE-2),

reviewed and issued to Operations on February 25, 1975 Test Results - The veld metal NDTT of 97 F is the most limiting component, thus yielding an RT 0 F of 157 F.

NDT c.

System - Moderator temperature coefficient test.

Required Frequency - Following each major refueling outage.

Test Date - Test was not performed during this report period.

d.

System - Suberiticality checks.

Required Frequency - During core alterations which increase core 4

reactivity.

Test Dates - These checks were performed as incorporated in the core loading Procedure (RE-7) performed on February 20, 1975 (four bundles reloaded) and on February 25, 1975 (two bundles reloaded).

Test Results - The procedure's acceptance criterion of maintaining suberiticality was satisfied.

I e.

System - In-service primary system inspection.

12

I Required Frequency - A continuing program is being conducted during some major refueling outages.

Test Dates - January through March 1975 Results - One indication was noted during the inspection which required weld repair. This indication, on the main steam system, was ground out and rewelded. See Special Report No 22.

f.

System - Refueling operation controls.

Required Frequency - Each major refueling.

Test Dates - January 17 and 21 and February 15, 1975 (Test TR-02).

Results - Satisfactory.

g.

System - Reactor refueling safety system sensors and trip devices.

Required Frequency - Each major refueling.

Test Date - Test T365-13 was performed on February 19, 1975 Results - Satisfactory.

l h.

System - Recirculation pump valve interlock test.

Required Frequency - Twelve months.

Test Date - May 29, 1975 (T365-22).

Results - Satisfactory.

5 Poison System a.

System - Liquid poison system firing circuit test.

Required Frequency - Two months or less (T60-01).

Test Dates - February 28, April 28 and June 27, 1975 Results - Satisfactory.

b.

System - Explosive valve from equalizing line.

Required Frequency - Twelve months or less.

Test Date - Test T365-ll was performed on March 6,1975 Results - Satisfactory, c.

System - Explosive valve from nonequalizing lines.

Required Frequency - Twelve months or less.

Test Date - Test T365-12 was performed on March 6,1975 Results - Satisfactory.

6.

Radiation Monitoring a.

System - Air ejector and off-gas monitoring systec, I

Required Frequency - One month or less.

l 13

s Test Dates - January 24, February 2h, March 25, April 23, May 20 and June 25, 1975 Results - Checks showed the calibration to be satisfactory. The automatic closure function of the isolation valve timer was checked and showed the timer calibration to be satisfactory (within 3% of the maximum timer setting) and the isolation valve closed as specified.

b.

System - Calibration and functional test of the stack gas monitoring system.

Required Frequency - One month or less.

Test Dates - January 24, February 24, March 25, April 23, May 20 and June 26, 1975 Results - The stack gas monitoring system was checked using the built-in Cs-137 calibration source. The instrument check showed the calibration to be satisfactory, resulting in the alarm oc-curring within the specified 0.1 curie per second release rate.

An additional calibration of stack gas monitoring system is a enmparative calibration used to demonstrate operations of the monAtor and to detect gross calibration changes and/or instrument drift. All calibrations were within the acceptance criteria of

+ 30% since recalibration of the monitor with standard liquid 4

sources.

c.

System - Analyses of stack gas particulate and iodine filters.

Required Frequency - Weekly.

Test Dates - The analyses were conducted weekly.

Results - The results of analyses of the stack gas particulate filter and iodine filter are reported in terms of curies released I

in Appendix A of this report.

d.

System - Calibration of emergency condenser vent monitor.

Required Frequency - One month or less.

Test Dates - January 24, F.bruary 2h, March 26, April 24, May 21 and June 27, '.975

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Results - The emergency condenser vent monitors are checked by comparing with a calibrated portable instrument. The checxs lh

'i showed the vent monitor calibrations to be satisfactory with all monitor checks within j; 10% of full scale. Alann points were found to be less than 10 mR/h plus background.

e.

System - Calibration of canal liquid process monitor.

Required Frequency - One month or less.

J Test Dates - January 24, February 24, March 25, April 25, May 20 and June 26.

Results - The calibration of the canal liquid process monitor is a comparative calibration used to demonstrate operations of the monitor and to detect gross calibration change and/or instrument drift. All calibrations were within the acceptance criteria of f; 30%.since recalibration of the monitor with standard j

liquid sources.

f.

System - Canal liquid collection sample.

Required Frequency - Daily.

Test Dates - The analyses was conducted daily.

Results - Satisfactory.

g.

System - Calibration of area monitors.

-Required Frequency - One month or less.

Test Dates - January 24, February 2h, March 26, April 24, May 21 and June 27, 1975 Results - The area monitor calibrations are checked by comparing readings with a calibrated portable instrument. The checks showed the area monitor calibration to be satisfactory with most monitors within f; 10% and all ranitor calibrations within 2;20%.

h.

System - Calibration of all liquid process monitors (except the canal monitor which is reported separately) is a comparative calibration used to demonstrate operation of the monitor ar.9 t) detect gross calibration changes and/or instrument drift. All calibrations were within the acceptance criteria of f; 30%.

Repairs were required on the condensate monitor to obtain ac-i l

l ceptable results.

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E.

The Result of Any Periodic Containment Leak Rate Test Perfonned During the Report Period The biannual containment integrated leak rate test was not' required during this report period.

F.

Technical Specifications Changes During this report period, no Technical Specifications changes or tests were authorized by the Commission.

~G.

Changes in Plant Operating Organization Involving Key Supervisory Personnel 1.

Mr Hudson M. Phelps, Senior Plant Technician, was promoted to the position of Assistant Instrument and Control Supervisor on March 1, 1975 III. POWER GENERATION Report Period Total to Date A.

Thermal Power Generated (MWh )

168,302 13,h87,888 t

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B.

Gross Electric Power Generated (MWhe) 53,094 4,29h,796 C.

Net Electric Power Generated (MWhe) 50,198.2 h,067,810 D.

Hours Critical 945.8 75,810.6 E.

Hours Generator On Line 922.6 76,964.5 F.

Maximum Dependable Capacity (MWe Net) 71 71

.G.

Reserve Shutdown Hours 0

0 IV.

SHUTDOWNS A.

Forced f-c.

sff Line: January 16, 1975 - 20hh hours.

Unit On Line: June 8, 1975 - 1418 hours0.0164 days <br />0.394 hours <br />0.00234 weeks <br />5.39549e-4 months <br />.

Length of Outage: 3425 hours0.0396 days <br />0.951 hours <br />0.00566 weeks <br />0.0013 months <br />, 3h minutes.

i Dis:ussion: The plant was removed from Fervice on Thursday, Jant ary 16. Power decent was controlled nad deliberate to a cold shutdown mode.

Design studies associated with the planned installation of the rerctor depressurization system revealed a possible deficiency in the presently installed instrumentation associated with the Post-4 Ircident cooling system. Since it could not be assured that the i

Post-Incident cooling system would function automatically in the I

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event of_a Loss of Coolant Accident, Consumers Power Company Management decided to remove the plant from service.

The shutdown occurred eight days in advance of a scheduled shutdown originally set for January 24, 1975 Work planned for this outage was performed while the Post-Incident system investigation was in progress.

During the control rod drive timing test, B h drive was found to be stuck in the fully inserted position. This necessitated removal of the reactor vessel head to allow the removing of adjacent fuel and hardware. A piece of 1/2" bolt shank, approximately 1" long with a nut on it, was retrieved from the B-b " dixie cup."

A special Task Force committee was appointed to investigate the Fost-Incident cooling system and containment isolation system to ascertain

(

its capability of operation in the postulated environment of the Loss of Coolant Accident. Investigations, tests and Post-Incident system deficiency-related maintenance was completed and the plant returned to 22rvice June 8.

V.

SAFETY-RELATED MAINTENANCE NOTE: Dates contained in this section generally refer to the weekly period when the maintenance was performed.

A.

Reactor Protection and Control System Instrumentation 1.

Neutron Monitoring Channel No 1 2/6/75 - The picoammeter range switch for this channel was re-a.

placed with the spare switch for preventive maintenance cleaning 3

and inspection. Replacement was performed in accordance with Procedure INM-ll. The reactor was in the shutdown condition at the time of replacement.

b.

h/10/75 - The picoammeter in this channel was replaced with a spare unit because of a marginal high flux trip unit relay.

During previous testing of this picoammeter, it was noted that

(

the annunciator and trip were not in coincidence (the annunciator relay would operate 2% lower than the actual high trip point).

18

I Bench tersing resulted in minor adjustment to the trip unit hystere,is potentiometer. The reactor was in the shutdown ji condition at the time of replacement.

l-2.

Neutron Monitoring Channel No 2 1

1/23/75 - The picoammeter in this channel was replaced with a l.

a.

spare unit following erratic operation of the unit in service.

This did not correct the problem and the erratic operation was traced to faulty operation of the g. *n trim potentiometer in the auxiliary gain module.

This problem occurred following reactor shutdown at which time absolute calibration of the picoammeters is not required. The auxiliary gain module'was disconnected causing a slightly higher reading and allowing the internal range switch gain control to have full effect The gain module was inspected during range switch inspection at a later date (see below).

b.

2/13/75 - The picosmmeter range switch for this channel was re-placed with the spare unit for preventive maintenance cleaning and inspection. A noisy potentiometer was replaced in the i

auxiliary gain module. Replacement was performed in accordance with Procedure INM-11.

The reactor was in the shutdown condition at the time of replacement.

4 c.

h/10/75 - The high-voltage power supply in this unit was replaced with a spare following periods of erratic operation with the range switch in the most sensitive positions. A slight variation in the output voltage of the supply was discovered during subsequent bench testing. Repa.'rs consisted of replacement of a marginal voltage regulator tube, 1

Failures of this nature are considered to be within the design limitations of the equipment. The reactor was in the shutdown condition at the time of replacement.

19 i

^

A 3.

Neutron Monitoring Channel No 3 2/20/75 - The picoammeter range switch for this channel was re-a.

placed with the spare unit is, treventive maintenance cleaning and inspection. Replacement was performed in accordance with Procedure IN};-11. The reactor was in shutdown condition at the

' time of replacement.

b.

$/Ch/75-Failureofthestaticinverter,thenormalsupplyfor this neutron monitoring channel, occurred during the reporting period.

The failure mode consisted of an internal short in the input.trans-former, resulting in a groundinc. condition to the station battery.

Due to the unavailability of repair parts, a replacement inverter (and spare) was procured and installed. This replacement is dis-cussed in Section VI (Facility Change C-308) of this report.

i The reactor was in the shutdown condition during the failure period.

Power for this neutron monitoring channel was provided by the alternate power source, Instrument and Control Bus lY.

h.

Neutron Monitoring Channel No k 6/5/75 - The ion chamber and coaxial cables between the chamber a.

and chamber drive head were replaced in this channel due to in-creased readings on the Log-N/ Period amplifier. High humidity conditions were suspect as the cause of failure, i

This failure occurred near the end of an extended tutage, at which time the plant was in the shutdown condition, l.

5 Neutron Mon?toring Channel No 5 2/6/71 - The Log-N/ Period amplifier in this channel was replaced a.

with the spare unit following erratic operation of the calibration potentiometers of the unit in service. Bench repair of the failed unit retalted in replacement of both the "Hi" and "Lo" calibration k

potentiometers.

i I

20

?

The reactor was in the shutdown condition when this failure occurred. The potentiometers are used only during testing of the unit and the eafety-related function var not compromised.

Failures of this type are within the design limitations of the equipment.

b.

2/27/75 - The Log-N/ Period amplifier in this channel was re-placed due to spurious short period trips received while testing the reactor protection system. Bench testing resulted in re-placement of a defective voltage regulating diode in the internal

+150 V d-c power supply.

Failures of this type are within the design limitations of the equipment. The reactor was in shutdown conditien at the time failure occurred.

6/5/75 - The dual hi h-voltage power supply was replaced in this c.

E intermediate channel due to the negative supply failure. Bench repair consisted of the input power transformer replacement.

Failures of this type are within the design limitations of the equipment. The reactor was in the shutdown condition at the time of failure.

6.

Neutron Monitoring Channel No 6 1/23/75 - The log count rate meter in this channel vas replaced 4.

with the spare unit following no response from the unit in service.

This did not correct the problem and subsequent testing of cam-ponents revealed a defective power fuse (1/10 ampere) in the cur-rent pul a amplifier.

Repairs to the current pulse amplifier consisted only of fuse replacement as no abaormalities were observed. The unit continued to operate satisfactorily.

4 This failure occurred during power operation at which time the I

start-up channels are not required. Test operation of both start-I up channels was being performed in preparation for unit shutdown.

21

i.

b.

2/27/75 - The log count rate meter in this channel was replaced 4

with a spare unit following low readings at the calibration test points. Bench repair consisted of electron tube replacement and alignment. The reactor was in shutdown condition at the time of failure. Failures of this type are within the design limitations of the equipment.

c.

5/15/75 - The log count rate meter in this channel was replaced with the spare unit following receipt of several spurious short period glarms. Bench repair of the failed unit resulted in re-placement of a marginal electron tube in the period amplifier circuitry.

Failures of this type are within the design limitations of the equipment. The reactor was in shutdown condition at the time of i

this failure.

7 Neutron Monitoring Channel No 7 a.

2/27/T5 - The chamber drive motor for this channel was repaired following failure of same. Repairs consisted of gear replacement in the gearbox. Manual chamber positioning was available during repairs to the motor.

This failure occurred during cesting and checkout of the neutron monitoring system components. The reactor was in shutdown condi-tion during the failure period, b.

4/10/75 - The log count rate meter in this start-up channel was replaced following down scale failure. Bench repair of the failed unit consisted of electron tube replacement in the internal -150 V d-c supply.

Failure of this type is within the design limitations of the equip-ment.

The reactor was in shutdown condition at the time of failure.

c.

,/29/75 - The B-10 proportional counter in this channel was replaced with a new unit following low response to the neutron source during I

operational checks (Test TR-19). Chamber replacement restored the count rate to normal.

22 l

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4 d

-During the testing and chamber replacement, the reactor remaine$

~in shutdown condition.

8.

Reactor Protection System 5/15/75 - Isolation valve control relays 1KhA and 1K4B (Channel

-a.

1), 2KhA and 2K4B (Channel 2) and ventilation trip relays 2K5A and 2K5B (Channel 2) were replaced as per the recommendation of the vendor. Qualified relays had previously been obtained for this planned replacement.

Shortly before the replacement was made, relay 2K5A had exhibited signs of overheating and the relay was de-energized (placing it in the trip condition) to prevent excessive heat and subsequent fire hazard.

4

-The reactor was in shutdown condition for the above-mentioned maintenance.

b.

6/19/75 - The reret switch for Channel 1, Group 2 solenoids was replaced following intermittent operation. Failure of this switch prevents reset of the system only and does not inhibit the :

tor protection system from performing its intended safety function.

B.

Radioactive Effluent Monitoring Systems 1.

Air Ejector Off-Gas System 1/9/75 - A plugged drain piping from the off-gas line and gland a.

seal exhaust line between radiation elements RE-125 and RE-126 4

was disassembled, cleaned and reassembled.

b.

1/23/75 - Repair maintenance was performed on the No 1 and No 2 gland seal exhausters. The No 1 exhauster pump and motor was dis-assembled, inspected and cleaned of scale as much as possible without damaging the exhauster. The No 2 motor bearings were re-placed and both pumps motors were aligned and returned for service.

i The repair was performed while the plant was shut down.

c.

2/27/75 - The off-gas filter was changed and the filter cavity was i

cleaned. The demister was inspected and returned to service.

(

23

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d.

6/19/75 - RL27 solenoid valve was replaced and an integrity test of the system including the off-gas system monitor was performed per Procedure MWGS-2.

2.

Stack Gas Monitoring System 1/9/75 - Repairs were made to the stack gas radiation monitor a.

calibration source assembly following indications of erratic counting rates.

Inspection of the source motor revealed that the braking resistor had failed. The resistor was replaced and the source motor operated properly.

This failure was first detected by an increased count rate during normal operation. The source motor would drift, adding to the actual stack gas radiation measurement. Repair of the source motor assembly returned all count rates to normal.

b.

1/9/75 - The particulate inlet valve in the stack gas sample system was replaced due to uncorrectable leakage through the valve packing gland.

1/16/75 - The two Calrod heaters on the upper end of the stack c.

gas probe piping were inspected. The inspection showed the heater units were in sr.tisfactory condition but the connection wires were overheated. The viring was rep 3 aced with a high temperature insulated wire and returned to service.

i d.

1/16/75 - The flexible stainless steel hose in the stack gas filter piping was inspected for leaks and the vacuum gauge l

checked for damage. A leak check proved acceptable after the i

bottom seam on the particulate filter canister was velded.

4 3.- Liquid Process Monitoring System 3/6/75 - Excessive vibration in the canal sample pump and motor a.

was corrected when the motov and coupling were replaced and the pump and motor were realigned.

l b.

3/13/75 - The spare canal sample pump motor shaft was realigned and new bearings were installed.

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1 This system may be removed from service per the Technical Specifi-cations proviaed the repairs are made promptly and the system is returned to service.

C.

Containment Sphere Isolation System 1.

-Containment Sphere Vacuum Relief Sensors 2/13/75 - The differential pressure sensors (dPS-9051.and dPS-9052) were replaced with the original sensors (which had been previously removed in 1973).

The previous replacement occurred when reliable operation of the original switches was questioned due to drifting set points and and abnormt.lly wide reset values. The replacement sensors were discovered to be temperature sensitive and additional replacement sensors were obtained.

However, during bench testing of the original sensors, a small amount of residue was discovered in the pressure connection of both switches. Following cleaning, the switches were calibrated to within set point requirements.

1 Reinstallation of the switches was performed with particular atten-tion to proper sloping of the sensing lines to a drip leg to pre-vent further accumulation of foreign material in the switch pressure connections.

2.

Supply Vent Valves CV/h096 and CV/h097 3/27/75 - Supply vent valves CV/h096 and CV/4097 - valve discs were a.

discovered not to be seating properly during semiannual component leak rate test. Leakage from the supply vent valves exceeded that allowed by the plant Technical Specifications and 10 CFR 50, Appendix J.

j Corrective action included cleaning of the seating surface el CV/4096 and cleaning and adjusting the seat of CV/h097

(.

25

t Precautions required to provide for reactor safety during the maintenance repair were performed according to Procedure MCIS-7 b.

6/5/75 - Containment ventilation valve CV/4097 failed to meet

'the acceptance criteria for the leak rate specified in the plant Technical Specifications.

Corrective action included the adjusting of the valve seat and operator alignment under the direction of an Allis-Chalmers service engineer. The valve was leak tested satisfactorily following completion of repairs.

This work was performed under Maintenance Procedure MCIS-7 with the reactor in the cold shutdown condition.

3 Miscellaneous Containment Sphere Isolation System Components h/17/75 - Installed a regulated air rupply for testing of the a.

I supply and exhaust vent valves. Also repaired a leak in the regulator following installation.

b.

5/22/75 - Filed the locking pin and tightened setscrew on drive gear to correct difficulty in moving the mechanical interlock on the containment personnel lock. Adjusted pressure switch and metering valve on personnel lock interior door, 6/5/75 - Leakage from reactor and fuel pit drain isolation valve c.

CV/4027 exceeded that allowed by plant Technical Specifications.

Corrective action included the adjusting of the microswitch at CV/h097 The valve was tested satisfactorily and returned to service. This work was done with the plant in the shutdown condition.

d.

6/5/75'- On solenoid valves SV/4891, SV/h869, SV/h892 and SV/h879 the manufacturer recommended that they be rebuilt using the ap-propriate spare parts kit.

i The manufacturer stated that valves would probably operate satis-t factorily in their present condition.

However, the valves were rebuilt using ASCO spare parts kit.

26

.q-This work was controlled by Maintenance Procedure MGP-5 with the plant in the cold shutdown condition.

D.

Emergency Power System 1.

Emergency Diesel Generator 5/22/75 - The following inspection and test procedures were a.

completed on the emergency diesel generator with no abnormalities noted:

T365 Emergency Diesel Generator Protective Device Testing T365 Emergency Diesel Generator Resistance Measurement Testing.

E.

Emergency Condenser System 1.

Emergency Condenser a.

2/20/75 - A section of pipe on-the emergency condenser, north tube bundle outlet line was removed and prepared for shipment to the 1

metallurgical lab for analysis of defects found during an NIYT inspection.

Metallurgical examination o# the four-inch emergency condenser outlet line revealed the defect to be fabrication-related. There was no evidence of deterioration of the pipe during operation.

The section of the pipe containing the defect was removed and a new section of pipe installed prior to plant start-up. The new velds were radiographed, liquid penetrant inspected and ultra-sonically inspected with no defects noted. The velds were hydrostatically tested successfully at 1600 psig. This work was performeo ith the reactor in cold shutdown cendition.

b.

6/5/75 - Emer6.. icy condenser outlet valve M0/7053 limit switches i

vere found to be out of adjustment. This resulted in an inaccurate indication of valve opening and closing.

Corrective action included adjusting the limit setting on the valve per Procedure MGP-2.

The valve was then test operated

{

satisfrctorily. The plant was in the celd shutdown condition for the p trformance of this work.

27

6/12/75 - Emergency condenser inlet valves M0/7062 and M0/7052 c.

leaked excessively through the packing glands during the system hydro.

Corrective action included repacking M0/7062 with four rings of paching and tightening of the packing on M0/7052.

Packing adjustments can be made on these valves so long as the valves are subsequently test operated. Test operation presented no operational difficulty and thus did not affect plant safety.

F.

Primary Coolant System a.

1/30/75 - The fittings on the one-inch and three-quarter-inch reactor cooling water heat exchangers were inspected and repacked.

b.

2/27/75 - Recirculation pump discharge valve M0-N001 was found to be leaking from the valve bonnet to body flange joint.

Corrective action included the seal velding of both discharge a

valves bonnet to body joints followed by an NDT inspection and hydrostatic testing of the velds to insure acceptability.

I Work was performed with the plant in the cold shutdown condition t

and the valve bodies drained. The work was controlled under Procedure MPCS-7.

G.

Shutdown Cooling System No work in the shutdown cooling system was performed during this I

report period.

H.

Control Rod Drive System 1.

CRD Filters a.

1/9/75 - The No 1 control rod drive filter was replaced due to high differential pressure.

b.

2/27/75 - The No 1 rod drive filter was changed due to high.

differential pressure and the lover 0-ring was replaced. The

(..

plant was shut down during the filter change.

28

i The No 2 rod drive filter was changed due to high differential pressure. The plant was shut down during the filter change, 6/12/75 - Changed out filters No 1 and No 2 due to a high dir-c.

ferential pressure. The lower 0-ring was also changed on filter No 2.

The filter changes were made per established procedural controls with the plant at power operation.

2.

CRD Accumulators 1/30/75 - F-2 accumulator bladder was changed.

a.

b.

3/6/75 - Leakage from the B-4 accumulator between the gas and water chambers was repaired by replacing 0-rings and Teflon rings on the nitrogen side.

h/2h/75 - Removed D-6 accumulator and replaced bladdcr and 0-rings c.

in both cylinders, d.

6/12/75 - CRD accumulator bladders Bh, Dh and F4 developed leaks due to the long shutdown and not being in the full charged condi-tion.

Corrective action included replacing bladders and Teflon 0-rings in the upper and lower accumulators for the Bh, Dh and Fh ac-cumlators.

With the exception of the B4 accumulator repair of 3/6/75 and the F2 repair, all work was performed while the reactor was at power.

In each case, only one accumulator was removed from service and only for the time required to perform the corrective maintenance.

3 CRD Pumps 6/12/75 - No 1 CRD pump was removed from service because of exces-a.

sive leaking at the cylinder packing.

Corrective action-included the fabrication of new gland throat bushings and repacking of the three cylinders.

(

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29

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This repair was performed with the reactor at power and the No 2 pump in_ service. Therefore, plant operation was not affected.

h.

Control Rod Drive System Instrumentation a.

1/23/75 - The following repairs were made to the CRD position probes:

E-3 Aligned "00" Switch Position E-6 Aligned "00" Switch Position B-1 Repaired Thermocouple Connections in CRD Probe Connector.

b.

1/23/75 - The jog bypass feature was reinstalled on this syste2.

j following reactor shutdown for the purposes of control rod drive testing (Procedure CRD hS5).

1/30/75 - Sticky contacts on the scram dump tank vent valve c.

indicating lamps were repaired.

d.

2/20/75 - Repairs were performed on the manual reactor control system following erratic operation of the control rod drives on an insert signal.

Testing of the system revealed that the insert' signal time delay relay (hK3) was intermittently failing to operate, allowing a continuous insert signal on the drives instead of the 1.6-second insert timing.

The relay was replaced with a spare unit, the control system tested for proper timing (Procedure ICR-1) and returned to service.

The job bypass feature was eliminated following CRD testing e.

(Procedure CRD hS5(1)). All work on the CRD instrumentation was performed with the reactor in the shutdown condition.

5 CRD Valves No major maintenance was performed on this system during the report period.

I.

Reactor Vessel

(

l.

Reactor Vessel Internals 30

(

/

4 a.

1/30/75 - The lower end of the fuel channel support tube, which was damaged during refueling operations, was repaired.

2.

In-Core Assemblies a.

1/30/75 - Four new in-cores were replaced per Procedure MRVI-1.

3 Reactor Bleed-Off Valves None.

J.

Post-Incident System 5/29/75 - The following instrumentation was replaced or rebuilt to meet qualifications for resolving the ECCS instrumentation deficiencies (AO-1-75):

PS-636 and PS-637 - Reactor Enclosure High-Pressure Sensors PS-1GllA Thru PS-lGllH - Reactor Pressure Sensors LS-RE09A Thru LS-RE09H - Reactor Water Level Sensors PT-186 and PI 412 - Reactor Core Spray Line Pressure Indication.

These items are described in greater detail in Section VI of this report.

K.

Fuel Handling Systems 1.

Cranes and Cables a.

1/23/75 - Fuel handling systems - prior to fuel handling, the following cranes and cables were inspected:

Reactor building bridge crane - acceptable for service.

Fuel pool shuffling vinch - acceptable for rervice.

Reactor jib crane - acceptable for service.

Fuel transfer cask and cables - acceptable for service.

Fuel handling cables - cable No 5 was rejected and replaced; the remainder was acceptable for service.

2.

Fuel Handling Systems Equipment a.

3/13/75 - Broken flexible steel conduit (Greenfield) and wiring was replaced on the fuel shuffling vinch.

5 b.

3/13/75 - Prepared a spare high-pressure pump for use at the fuel

)

pool cleaning station.

l 31 l

l

c.

h/17/75 - Removed NPI detector from calibration assembly located on reactor deck and shipped detector and cable to NPI.

d.

6/26/75 - Removed Dillon dynamometer S/N ANC948 from the cask.

It was disassembled, decontaminated, reassembled and shipped to the Consumers Power Company lab for calibrstion.

L.

Main Steam Supply 1.

Main Steam Supply Components and Equipment 2/13/75 - Microswitch viring was replaced in HS-7036 after a.

indication of CV/bl0h showed both open and close indication lights on with HS-7036 in the closed position.

b.

3/13/75 - The isolation valve for the radiolytic gas sampling cooler was removed and replaced because of leakage.

3/13/75 - Sample cooler at the radiolytic gas sampling station c.

was replaced with the high-pressure Calgon cooler that was formerly used for moisture separator steam samples.

d.

h/2h/75 - An oil leak in the turbine bypass valve Rucker system was repaired.

e.

6/5/75 - The inservice inspection revealed a cold lap piping defect on main steam piping veld #37 The defect was ground out and weld repairs made to ASME Section XI and Section III Boiler Codes. A post-veld heat treatment, radi-ography, dye penetrant and ultrasonic examinations and a successful hydrostatic test at 1500 psig were performed on the repaired weld.

M.

Feed-Water System t-l.

Feed-Water System Components and Equipment None.

N.

Post-Incident System 1.

Post-Incident System Components and Equipment h/2h/75 - An enclosure spray cross-tie valve (Mo/7069) inspection a.

revealed broken strands of lug wire in the Y-phase contactor. A new lug was installed and the valve was satisfactorily test operated upon completion.

~f b.

6/19/75 - Leakage from valve M0/7068 was corrected by limit switch adjustment to ensure proper stem travel for tighter valve closing.

32

/

c.

6/19/75 - Leakage from a telltale downstream from valve M0/706h resulted in a leak rate test being performed. Leakage, however, was measured at only 0.317 gal /h and no corrective action was taken.

d.

6/5/75 - Motor operators on valves M0/7068, M0/7069, M0/7070, M0/7071 and M0/7072 were removed and sent to Franklin Institute, Philadelphia, Pennsylvania for environmental testing to meet the postulated LOCA conditions.

Following successful testing at Franklin Institute, the operators were reinstalled. Terminal connections and conduit runs were modified to match the test conditions.

The installation of the motor operators was controlled under Maintenance Procedure MPIS h.

All the Post-Incident system repairs above were performed while the plant was in the cold shutdown condition.

O.

Station Power System 1.

Station Battery Charger h/2h/75 - During investigation of the static inverter failure, a a.

check of the station battery output revealed a 1.0 volt peak-to-peak ripple at 180 Hz.

The Consumers Power Company Laboratory Services Department repaired the unit by replacing two 12-ampere fuses in the filter circuit of the charger. The output ripple was reduced to 0.1 volt peak-to-peak or s 0.035 volt RMS.

VI.

CHANGES, TESTS, EXPERIMENTS A.

Facility Changes Performed Pursuant to 10 CFR 50.59 I

1.

Facility Change C-262 This change consisted of adding a subpanel to Instrument and Control Power Panel 2Y (located in the containment sphere) to allow for future expansion since no spare circuit breakers were available.

k 33

Review of this. facility change indicated that the supply to Power Panel 2Y had more than ample capacity for this addition. Installa-tion methods were in accordance with required practices. It was concluded that the change did not compromise or change the system as described in the Technical Specifications, FHSR or plant operating requirements and, therefore, does not represent an unrevieJed safety question as described in 10 CFR 50.59 2.

Facility Change C-285 A moisture trap was installed ahead of the stack sample filters in the i

stack gas sampling system. This was installed to prevent moisture from collecting on the filters and improving the measurement of stack gar.

The safety evaluation for this change concluded that the margin of safety wear? not be reduced and that operation of the system would be improved. The change does not compromise or change the system as described in the Technical Specifications, FHSR or plant operating requirements. This facility change, therefore, does not represent an unreviewed safety question as described in 10 CFR 50.59 3

Facility Change C-287 This change consisted of removing an obsolete beam clamp lock for the lower grid bar assembly in the reactor vessel and remounting the ex-isting Honeycut lock which had loosened.

The safety evaluation concluded that removal of the obsolete beam clamp lock did not compromise or change the reactor vessel as pre-viously described in the Technical Specifications, FHSR or plant operating requirements. Instead, the removal of the obsolete material improves the system by elimination of unnecessary components within the vessel. This facility change, therefore, does not repre-sent an unreviewed safety question as described in 10 CFR 50.59 h.

Facility Change C-290 This change consisted of replacing a solenoid valve (SV/RL-27) in the off-gas sample demister drain line with a solenoid valve of improved

(

design and reverse action. This change was made to improve the integrity of the off-gas isolation system (Ref: A0-6-75).

34

4 The safety evaluation concluded that the overall operation and integrity or the off-gas system would be improved and that the change would not compromise or change the characteristics of the system as described in the Technical Specifications, FHSR or plant operating requirements. This change, therefore, does not represent an un-reviewed safety question as described in 10 CFR 50 59 5

The following facility changes were completed as a result of design d

reviews of engineered safeguards equipment associated with a postu-lated Loss of Coolant Accident. These items are discussed in greater detail in Special Report No 21 of May 2, 1975, entitled " Investigation of and Correction of Deficiencies Associated With Equipment Required To Operate During a Postulated Loss of Coolant Accident."

Safety evaluations performed on the following facility changes con-cluded that the characteristics of the various systems would not be compromised or changed (as described in the Technical Gpecifications, 1

FHSR or plant operating requirements), and that the facility changes would place the associated equipment within design requirements. The changes listed below, therefore, do not represent any unreviewed safety questions as described in 10 CFR 50.59 a.

Facility Change C-295 This change consisted of the addition of a new 120 VAC instrument and control distribution panel (3Y) located external to the con-tainment sphere. This panel was added to provide power for instrumentation relocated outside of containment. The original 120 VAC instrument and control panel (1Y) had no space available for additional systems.

b.

Facility Change C-296 This change consisted of adding an isolation breaker (decoupling device) in the power source to the 120 VAC instrument and control distribution panel'(2Y) located within containment. The addition was made to prevent loss of total instrument and control power because of flooding or shorting of 2Y panel during a postulated LOCA. The 2Y panel is not qualified to meet LOCA conditions and will not be considered a Class lE bus.

35 1

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('

c.

Facility Change C-297 This change consisted of relocating the flow and level instru-mentation power supplies associated with a LOCA to a more suit-able environment outside of containment. This change was performed because the power supplies were not environmentally qualified to meet LOCA conditions. The instrumentation power source was changed from 2Y panel (within containment) to 3Y panel (outside containment).

d.

Facility Change C-298 This change consisted of relocating the local control station for the reactor enclosure backup spray valve (M0/7068) to outside of reactor containment. The power source was changed from 2P power panel (inside containment, not qualified) to IP power panel (outside containment). This change was performed to place the contactor in a suitable environment and provide power from a re-liable source (not susceptible to LOCA conditions).

e.

Facility Change C-299 This change consisted of replacing the care spray line pressure l

transmitter indicator system (PT-186 - PI h12) with qualified i

equipment. This change was performed because the equipment in use would not meet LOCA conditions.

f.

Facility Change C-300 This change consisted of modifying the reactor water level switches (LS/RE09 E through-H) used for redundant core spray actuation to meet LOCA conditions. The modifications consisted of switching element and case cover replacement.

g.

Facility Change C-301 This change consisted of the same modifications as in Facility Change C-300, except that this change applied to the reactor water level switches used for primary core spray actuation (LS/RE09 A through D).

h.

Facility Change C-302 This change consisted of replacing the reactor pressure switches

(

(PS/IGll E through H) for the redundant core spray switches with 36

1 qualified units. The original switches were not qualified for LOCA conditions.

i. Facility Change C-303 This change consisted of replacing the reactor pressure switches (PS/IGll A through D) for the primary core spray system with qualified units. The original switches were not qualified for LOCA conditions.

J.

Facility Change C-306 This change consisted of changing the piping in the reactor core spray line to raise valves M0/7051 and M0/7061 approximately eight feet higher in the containment sphere The piping change con-sisted of shortening a vertical section of piping on each-side of the two valves.

This change will permit the core spray valves to operate properly above the sphere water level should a postulated LOCA occur.

k.

Facility Change C-307 This change consisted of replacing the reactor containment building pressure sensors (PS/636, PS/637) with new units, as the original i

units were not seismically qualified.

6.

Facility Change C-308 This change consisted of replacing the static inverter used for i

neutron monitoring Channel No 3 with a new unit. The original in-verter had failed and repair parts were not available. Two qualified replacement units were obtained so that an operational spare would be available.

Based on a review of the specifications of the replacement inverter, the suitability thereof and application qualification by the vendor (who supplied the original unit), it was concluded that the inverter was adequate for our particular application. Replacement, therefore, does not represent an unreviewed safety question as described in 10 CRF 50.59 37 i

8

VII. RADI0 ACTIVE EFFLUENT REEASES This section was submitted August 29, 1975

(

38

i _-

f l.

VIII. ENVIRONMENTAL MONITORING A.

Environmental Survey Environmental levels of radioactivity as found in the vicinity of the plant were composed almost entirely of naturally occurring radio-active materials. In the vicinity of the circulating water discharge i

. canal, radioactive material of plant origin has been found. These materials occurred primarily in aquatic organisms. The levels of radioactive materials, however, were extremely low and are of no l

significance to the health and safety of the organisms or the public.

Further, the levels of radioactive material found in the resident I

biological community are consistent with levels found in previous years and show no upward trend.

i 1

I The environmental surveillance program includes continuous sampling of air for particulate and halogen activity at seven locations in-l cluding background sample locations at Traverse City and Boyne City, 4

l Michigan, about 50 miles south-soutevest and 20 miles southeast of I

the plant, respectively, to determine increased concentrations, if 1

any, of radioactivity of plant origin.

i Thermoluminescent dosimeters (TLD), placed at each of these locations plus six additional locations on the site property boundary, measure direct dose in the environment.

In addition to the exposure received in the field, dosimeters also receive an exposure in transit. To account i

for this exposure, two control dosireters accompany the field dosimeters l

during shipment to and from the environmental contractor and are stored i

in a lead shield while the other dosimeters are in the fiela. The average dose received by the control dosimeters is then subtracted

]

from each field dosimeter to obtain a net exposure.

i i'

)

The average net doses.at the site, inner ring and background stations i

are compared monthly and any difference, at the 95% confidence level, is determined using standard "F" and "t" tests. The results of these dosimeter analyses are given in Appendix D.

While all the dosimeters i

]

s s

39

record doses from natural occurring sources, the dosimeters on site can also be expected to receive doses from not only the plume but direct radiation from the plant. A difference between the site and background stations was observed on only one occasion. A difference of 4.5 f,1.0 mR was noted for March. The site TLDs averaged 1.5 f, 0 7 mR while the background TLDs averaged 6.0 f,0.3 mR.

No difference was noted between the inner ring and background TLDs.

As noted in the last semiannual, the January TLDs were not placed in the environment due to their late arrival from the contractor. The i

TLDs were returned to the contractor unexposed to assure the progran would be on the proper replacement schedule starting in February.

Air samples gathered cone.inuously and analyzed weekly at the stations shown in Appendix D showed no difference, at the 95% confidence level, in the level of radioactivity acasured at those stations close to the site and those remote from the site.

Both particulate filters and carbon cartridges are used to measure potential concentration of radioactive materials resulting from plant operations. From average meteorological dispersion conditions, the following maximum concen-trations can be calculated:

Particulates (January) = (1.2 pCi/s) x (8.56E-04) x (5.0E-lh s/ce)

= 5.1E-17 pCi/cc Halogens (December) = (1.2 pCi/s) x (2.06E-03) x (5.0E-lh s/cc)

= 1.2E-16 pCi/cc These compare to the minimum detectable activity values and normal background concentrations as follows:

Maximum Calculated Minimum Detectable Normal Background 3

Release Concentration pCi/cm Activity pCi/cm3 Activity pCi/cm3 Particulates 5.lE-17 1.0E-lh 7.0E-lh Halogens 1.2E-16 2.0E-lh

(.

Hence, the negative data obtained in the program was e2 ho 4

7..-------.

---

i w

,- g r,-

-.m

-g-+

During the period only two of 188 air samples showed detectable concentrations of I-131. The site air samples for the collection periods of April 17 through 24 and May 1 through 8 had I-131 con-3 centrations of 0.'02 1 0.01 and 0.03 + 0.01 pci/m, respectively.

Both samples had low airflow volumes and, therefore, the two values probably represent statistical variations not real ambient concentrations. It appears that the examination of spectra to 1

determine the presence of a true peak in the 0.36 MeV region has eliminated the previous false identification problem as identified

~

in the last semiannual report.

At the Big Rock Point Plant, daily composite condenser circulatin6 water inlet and canal water discharge samples are taken and analyzed for radioactive content.

In addition, a monthly composite of these samples is analyzed for radioactive content (gross beta and tritium).

l These results are shown in Appendix D.

Additional aquatic smnples are taken and analyzed during the spring and fall and these results are also tabulated in Appendix D.

Based upon the liquid release of 1.15 curies of radioactive material (less tritium and noble gases) which results in an average concentra-tion in the discharge canal of 2.38E-08 pCi/ml, the analysis of dis-4 charge canal water should indicate an increase of radioactive material in discharge canal water samples since the minimum detectable activity for gross beta measurements is about 2.0E-09 pCi/ml or about twelve times lower than the predicted discharge concentration. The results shown plotted in Appendix D indicate an average concentration of about 3.3 1 0.5E-09 pCi/ml above intake concentration and roughly seven times lower than the predicted concentration.

t Also contained in Appendix D are the results of the analysis of the j

site well water, aquatic biota, a sampling and analysis summary and the high, lov and average concentration for the highest average

(

sampling location.

41 a-r

--n-.

.w.

r

i.

4-IX.

OCCUPATIONAL PERSONNEL RADIATION EXPOSURE l-The following is a list of personnel radiation exposure by job breakdown during the forced outage (January 16, 1975 to June 9,1975). The radia-l I

tion exposure accumulated from January 1,1975 to January 16 and from June 9 to June 30 will appear at the end of this section.

t l

These exposures were tabulated from pocket dosimeter records, radiation j

protection logbooks, weekly radiation exposure record work sheets and high radiation area work sheets. The tabulation is considered to be 10%

high since the pocket dosimeters normally read 10% higher than the film dosimeters.

t Total Exposure No of

)

Operations mrem Personnel l

Routine' Plant Surveillance 8,6h7 19 I

Radwaste or Puel Pool Filter Change h59 8

Reactor Level - Vessel Shield Wall Scrubbed 27 2

Recirculation Pump Room Tagging and Valving 3,246 16 Main Condenser Area Inspection 92 1

i Clean-Up Pump Room 17 1

_ Reactor Level - Work With Reactor I

Internals 1,178 15

)

Reactor Level - Routine Refueling and Co-60 Work 1,135 12 i

Vacuum Puel Pool 225 3

Reactor Deck Cleanup 73 2

Interlock Test Reactor Deck 20 1

Steam Drum Area Tagging and Valving 118 3

i Reactor Deck - Head Cleaning 9

2 Total 15,246 T

Pocket Dosimeter Acewnulation h2 a

..,_,..,,,e-.-.#

m

..- r -.

, _......, +

_-m_.

OCCUPATIONAI. EXPOSURE 7 2.2.1.0.a(1)(h)

Number of Persons Within Exposure Rance mrem Dose 1/1/75 - 1/31/75 2/1/75 - 2/28/75 3/1/75 - 3/31/75 0-100

• Maint 3

oper 5 Maint 5

oper 9 Maint 7

Oper 1h Supv 18 Tech 3 Supv 20 Tech 5 Supy 22 Tech 8 Others 35 Others 33 others 23 101-500

• Maint h

Oper lh Maint 8

Oper 10 Maint h

Oper 5 Supy h

Tech 5 Supv 3

Tech h Supv 1

Tech 2 Others 9 others 3 Others 0 501-1250

• Maint 6

Oper 0 Maint 3

oper o Maint 2

Oper 0 Supv 0

Tech 2 Supv 0

Tech 1 Supy 0

Tech 0 Others 0 Others 2 Others 0 1251-2500 Maint 2

Oper 0 Maint 1

Oper 0 Maint 0

Oper 0 Supy 0

Tech 0 Supy 0

Tech 0 Supy 0

Tech 0 Others 0 Others 1 Others 0

>2500 Maint 0

Oper 0 Maint 0

Oper 0 Maint 0

Oper 0 Supy 0

Tech 0 Supy 0

Tech 0 Supy 0

Tech 0 Others 0 Others 0 Others 0 Total Number of People Badged 110 107 88 mrem Dose h/1/75 h/30/75 5/1/75 - 5/31/75 6/1/75 - 6/30/75 0-100 Maint 15 Oper 19 Maint 1

Oper 13 Maint 7

Oper 11 Supv 23 Tech 7 Supv 18 Tech 0 Supy 20 Tech 5 Others 23 Others h9 Others 36 101-500 Maint 4

Oper 0 Maint 3

oper 6 Maint 6

Oper 8 Supy 0

Tech 3 Supv 3

Tech 11 Supv 3

Tech 5 Others 0 Others 2 Others 4 501-1250 Maint 0

Oper o Maint 9

Oper o Maint 0

oper o Supy 0

Tech 0 Supy 1

Tech 2 Supy 0

Tech 0 Others 0 Others 1 Others 1 1251-2500 Maint 0

Oper 0 Maint 4

Oper 0 Maint 0

Oper 0 Supy 0

Tech 0 Supy 1

Tech 0 Supy 0

Tech 0 Others 0 Others 17 Others 0

>2500 bhint 0

Oper o Maint 0

Oper o Maint 0

oper o Supy 0

Tech 0 Supy 0

Tech 0 Supy 0

Tech 0 Others 0 Others 2 Others 0 Total Number of People Badged 92 1h1 65 Others include office secretaries, General office personnel, contract personnel, vendors, plant guards, Region repairmen (other than from Traverse City) and visitors.

(

• Maint includes Region repairmen from Traverse City.

h3 I

~

b i

EXPOSURE - JOB BREAKDOWN (January 1 - June 1975)

Total Exposure No of mrem Men Shift Supervisors Routine Plant Surveillance 1,941 6

i Main Condenser Area - Inspection 128 1

Plant Grand Tour

_ Inspection 40 1

~

Stean ) rum Area - Inspection 439 2

Recire Pump Room - Inspection 101 2

Reactor Level - Refueling & Inspection 112 3

Total 2,761 Administration and Supervision Routine Plant Surveillance 3,844 17 j

Recire Pump Room - Change Recire Pump Seal 261 2

Reactor Level - Reactor Internals 90 2

1 Recire Pump Room - Inspection 1,229 8

{

Honeycut Lock Reactor Deck 352 1

Recire Pump Discharge Valve 370 1

Insulation Removal - Recire Pump Room 82 1

Control Rod Drive Room Cable Penetration 5

1 Steam Drum Area - Inspection 130 2

Recire Pump Room Core Spray Valves 813 3

Recire Pump Room for Calibration 107 1

Total 7,283 i

Maintenance - Big Rock Plant Routine Plant Surveillance 8,000 13 Recire Pump Seal, Insulation Inspection 763 5

i Solid Radwaste Disposal 557 6

Main Condenser Area - Work' 235 7

Reactor Level - Work 990 6

Honeycut Clamp Reactor Deck 510 3

Reactor Deck - Cleaning 165 3

Recire Pump Discharge Valves 1,99h 5

Steam Drum Area - Work on Valve 1,160 7

Control Rod Drive Room Insulation Removal 22k 5

i-Recire Pump Room Insulation Removal & Grinding 1,542 6

i-

.Ste'an Drum Insulation Removal & Cleaned Manhole i-Cover Bolts 110 2

Control Rod Drive Pump Room 120 3

I Loaded Co-60 Cask h97 6

i

i Total Exposure No of mrem Men Maintenance - Big Rock Plant (Contd)

Cleanup 31 2

Accumulator Room 20 2

Emergency Condenser - Inlet Line Repair 17 2

Shutdoan Heat Exchanger Room - Valve Packing 30 1

Repair Fuel Pit Filter Cover 15 1

Moved Radiolytic Gas Cooler 30 2

Recire Pump Room Insulating 1,061 2

Clean-Up Heat Exchanger Room Install Wiring 230 1

Control Rod Drive Cleanup 20 1

Recire Pump Room - Inspection 2h0 2

Reactor Deck Head Installation 2,089 10 Steam Drum Enclosure 752 2

Recire Pump Room Preparation for Spray Line 262 2

Recire Pump Room Core Spray Line 6,499 7

Recire Pump Room & Steam Drum Enclosure Check Motor Operations 93 1

Shutdown Heat Exchanger Room To Check Valves 70 2

Recire Pump Room - 6/8/75 288 h

Steam Drum Enclosure - 6/8/75 16 1

Clean-Up Demin Pit - 6/8/75 h0 1

Total 28,670 Radiation Protection and Chemistry Routine Plant Surveillance h,228 7

Main Condenser Area - Inspection 20 1

Steam Drum - Inspection & Monitoring 808 3

Solid Radwacte Disposal - Monitoring 57 3

Grand Tour (Steam Leak Inspection) 65 2

Recire Pump Room Monitoring & Inspection 1,889 5

Recire Pump Room Survey 115 h

Recire Pump Room Monitoring Core Spray Job 2,508 6

i-Reactor Deck Monitoring & Surveys h65 3

Transfer Cask Rigging Monitoring 10 1

Control Rod Drive Room Monitoring 121 2

Honeycut Lock Reactor Deck 220 1

iff-Site Cask C3 1

Shutdown Heat Exchanger Room - Monitoring 32 2

Transfer of Cs-137 and Co-60 Source 60 2

Clean-Up Heat Exchanger Room - Monitoring 27 2

Total 10,708 i-

~

h5 i

l l

r Total Exposure No of' mrem Men l

Plant Technician - Instrument and Control l

Ro'itine Plant Surveillance 1,634 5

Control Rod Drive Room Worked on Probe 51 2

Recire Pump Room 30 1

Control Rod Drive Room In-Core Instrumentation

& Flux Wires 322 h

Control Rod Drive Room In-Core Connectors 230 1

Steam Drum Enclosure - String Wire 30 1

Recire Pump Room Check CV Valves 20 1

CV Heat Exchanger Room - Information From Valve Plates 110 1

Eeactor Deck Start-Up Instr 60 1

Puel Pool Heat Exchanger Room IG-ll 31 1

Recire Pump Room - Calibration h03 3

Total 2,921 Maintenance Consumers Power Company Off-Site Personnel Recire Pump Seal Change 1,510 2

Pipe Tunnel 99 2

Reactor Level 1,011 5

Steam Drum Area 98 1

Control Rod Drive Room 108 2

Solid Radwaste Disposal 10 1

Recire Pump Room Insulating 2,384 5

Recire Pump Room & Clean-Up Pump Rocn Valve Stroking & Packing 86 2

Emergency' Condenser 89 2

Turbine Inspettion 17 1

Recire Pump Room 405 2

Recire Pump Dischcrge Valve 4,511 5

Recire Pump Room Core Spray Line 44,325 20 Recire Pump Room Install 1/2" Line & Insulate 1,376 3

Routine Plant Surveillance 219 6

Total 56,248 Plant Technicians (I&C) Off-Site Personnel Control Rod Drive Room - In-Cores 353 2

Total 353

(

h6

m

=

1' Total Exposure No of mrem Men Maintenance Supervision Off-Site Personnel Routine Plant Surveillance h2 1

Recire Pump Room Inspection 75 1

Recire Pump Room Core Spray Line h,023 3

Total h,1ho NDT Technicians Off-Site Personnel X-Ray, Die Penetrant, Ultrasonic & Visual Inspection 6,319 h

Total 6,319 QC Off-Site Personnel Inspection 1,272 1

Total 1,272 Summary of All Non-07nsumers Power Company Personnel (January 16 to June 9, 1975)

SWRT Reactor Level 225 h

UTEC UT Expert With NDT People 721

_1 Hartford Insuracce_

Inspection 216 2

NRC Inspection 109 h

NE Co Resin Removal 68h 3

Newkirk Security System Installation 120 h

Catalytic and Suntac Survey for ECCS Project 268 8

Oakridge Government Project 125 3

Grand Total for Cunsumers Power Company Personnel'-

1/16/75 - 6/9/75 135,921 Grand Total for Non-Consumers Power Company Personnel -

1/16/75 - 6/9/75 2,h68 hT

1 i

Total Exposure Ho of 4

t mrem Men Summary for All Consumers Power Company Personnel Operations 15,2h6 19 Shift Supervisors 2,761 6

Administration and Supervision 7,283 17 Maintenance - Big Rock Plant 28,670 13' i

j Radiation Protection and Chemistry 10,708 7

Plant Technicians (I&C) 2,921 5

Maintenance' Consumers Power Company Off-Site Personnel 56,248 20 Maintenance Supervision Off-Site Personnel 4,140 5

Plant Technicians (I&C) Off-Site Personnel 353.

2 HDT Technicians Off-Site Personnel 6,319 h-i QC Off-Site Personnel 1,272 1

Total for Consumers Power Company Employees 135,921 Exposure for Periods of Plant Operations Only a

January 1, 1975 to January 16, 1975 and June 9,1975 to June 30, 1975 l:

l Operations Routine Plant Surveillance 1,674 19 i

Main Condenser Area - Inspection 124 2

Clean-Up Demin Pit - Inspection 10 1

1 Total 1,808 Shift Supervisors Routine Plant Surveillance 333 6

j Main Condenser Area - Inspection 231 h

Clean-Up Demin Pit - Inspection 90 1

j Recire Pump Room - Inspection 20 1

Total 674-Administration and Supervision

(

Routine Plant Surveillance 551 17 Main Condenser Area Inspection 98 1

\\

Total 649 h8 a

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tw--gp e-+ Mea-a t'e=-

Total Exposure No of mrem Men Maintenance - Big Rock Plant Routine Plant Surveillance 1,215 13 Repair Fuel Pool Filter Pump 20 2

Repair Off-Gas Drain Line 10 2

Clean-Up Demin Pit - Inspection h0 1

Main Condenser Area Repair Pipe Leak and Take-Up on Packing 206 2

Solid Radvaste Disposal 3h h

Total 1,525 Radiation Protection and Chemistry Routine Plant Surveillance 79h 7

Main Condenser Area - Inspection 12h 3

Main Condenser Area - Monitoring 119 3

Shipping Spent Resins - Monitoring 230 h

Recire Pump Room - Inspection 20 1

Solid Radwaste Disposal - Monitoring 32 2

Total 1,319 Plant Technicians (I&C)

Routine Plant Surveillance lh8 5

Total 148 Total for Consumers Power Company Employees -

1/1-16 and 6/9-30/75 6,123 Newkirk Work on Security System 129 5

Total 129 NE Co Loading Spent Resins for Shipment 2,691 6

Total 2,691 Total for Outside Personnel 2,820 h9

i Total Exposure No of mrem Men Summary for All Consumers Power Company Personnel Operations 1,808 19 Shift Supervisors 67h 6

Administration and Supervision 6h9 17 Maintenance - Big Rock Plant 1,525 13 Radiation Protection and Chemistry 1,319 7

Plant Technicians (I&C) 1h8 5

Total 6,123 Final Summary January 1 to June 30, 1975 January 1 - January 16 - June 9 - June 30,1975 Consumers Power Company Employees 6,123 Nonemployees 2,820 January 16 - June 9, 1975 4

Consumers Power Company Employees 135,921 Nonemployees 2,h68 i.

Total 147,352 X.

RADIOACTIVE LEVELS IN PRINCIPAL FLUID SYSTEIG Minim'i_m__

Average Maximum A.

Primary Coolant Reactop W)ater Filtrate

-5

-3

-1 UCi/mita 8.9 x 10 9 2 x 10 1 5 x 10 Reactor Water Crud

-5

-2

-1 pCi/ml/ Turbidity Unit 2.9 x 10 2.0 x 10 5.8 x 10

-9

-3

-2 Iodine Activity - pCi/ml 1.0 x 10 2.6 x 10 3.0 x 10 B.

Reactor Cooling Water System i

Beacto ooling Water pCi/ml{a

-3

-3

-2 2.0 x 10 3.2 x 10 2 9 x 10 C.

Spent Puel Pool

-9 Fuel Storage Pool "

1.0 x 10 9 0 x 10-8.5 x 10 Fuel Storage Pool Iodine 1.5 x 10-1.0 x 10-2.9 x 10" l

("}A crunte:* efficiency based on a decay scheme consisting of one gamma photon per disintegration at 0,662 MeV used to convert count rate to

(

microcuries. All count rater were taken two hours after sampling.

(b) Based on efficiency of Iodine-131 two hours after sampling.

Based on APHA turbidity units and 500 ml of filter sample.

NOTE: Plant shut down January 16 to June 9, 1975.

I 50

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APPENDIX D (Contd)

Sampling and Analysis Summary January 1, 1975 to June 30, 1975 l'

No of Samples

. Frequency of Medium Description Location Collected Type of Analysis

' Analysis Air Continuous at All 188 Gross Beta, I-131 Weekly Approximately 1 cfm Lake Water 1 Gal ST, CH 18 Gross Beta, Gross Gamma

, Monthly Well Water 1 Gal Grab ST 6

Gross Beta Monthly y

Gamma Dose Continuous All 60 TLD Dose Monthly Aquatic Biota Grab ST, NM, 16 Gross Beta, Isotopic Semiannual Mt McSauba 1

i.

s e

e t'

i a

APPENDIX D (Contd)

High, Low and Average Concentrations For Highest Average Sampling Location

' January 1, 1975 to June 30, 1975 1:

Type Type of Analysis Units Location High Low Average 3

Air Gross Beta-Gamma pCi/m TR O.25 0.07.

0.12 3

I-131 pCi/m ST 0.03

<0.2

<0.2 i

Lake Water Cioss Beta pCi/1 BR ST LWO 17.h h.3 9.0' i

H-3 pCi/1 BR ST LWo 740 300 512 6w Well Water Gross Beta BR ST WW 6.1 0.3 1.8

• TLD Dose mR/mo 3

12.1 3.0 5.2 4

i.

"In excess of control dosimeters.

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P00R ORIGINAL

i ls APPENDIX D (Contd)

Difference in Average TLD Readings mR/ Month Site Versus Background Inner Ring Versus Background Month Stations Stations January (

ND(

ND February March 4.5 i 1.0 ND April ND ND May ND ND June ND ND Average TLD not received from contractor in time for placement in the field.

(2)ND - No difference at the 95% confidence level.

(3) Background TLD average reading = 6.0 1 0.3 Site TLD average readirs = 1.510 7 60

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