IR 05000266/1990014

Insp Repts 50-266/90-14 & 50-301/90-14 on 900616-0731.No Violations or Deviations Noted.Major Areas Inspected:Maint & Surveillance,Emergency Preparedness,Security,Engineering & Technical Support

ML20058Q246
Person / Time
Site:	Point Beach
Issue date:	08/10/1990
From:	Jackiw I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20058Q245	List: IR 05000266/1990014 ML20058Q241
References
50-266-90-14, 50-301-90-14, NUDOCS 9008210192
Download: ML20058Q246 (20)

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REGION III-Y-Report No. 50-266/90014(DRP);50-301/90014(DRP)

Docket No. 50-266; 50-301 License No'. DPR-24; DPR-27

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Licensee: ' Wisconsin Electric Company m

231' West Michigan Milwaukee, WI 53201 Facility Name: Point Beach Units 1 and 2 Inspection At: Two Rivers, Wiscensin

't Cates:- ' June 16 through July 31, 1990 I_nspectors:

C. L. Vanderniet J. Gadzala-P. Castlema

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Re9ttor P ojects Section 3A Date

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Inspection Summary ilnspection from June 16 through Julyy,1990 (Reports No. 50-266/90014(DRP);

'No. 50-301/90014(DRP)

Areas Inspected: ; Routine',' unannounced inspection by resident inspectors of outstanding items; operational safety; radiological controls; maintenance and surveillance; emergency preparedness; security; engineering and technical support;~ and-safety assessment / quality-verification.

'Results: During this inspection period, Unit 1 experienced a turbine runback due to -a spurious signal in a nuclear instrument and developed two leaks j

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in the reactor' coolant system requiring the unit to be shut-down for repairs..

Unit 2 operated at: full power with only requested load following-power. '

reductions.

Issues addressed'in this inspection report include: Unit 1 Lautomatic turbine runback'(3.e),(Unit 1-reactor coolant system leak (3.f),

gas. turbine reliability project 3.h), zebra mussel monitoring (3.j), LiOH.

chemistry control-(4.a), plant management changes (9.c), temporar

' 2515/103 : loss of decay heat removal program enhancements review (y instruction-10.a),and i

reduction of F(q)gs (11). New issues which remain unresolved include:

management meetin limit in technical specifications (3.9), Appendix R fire zone checks while certain equipment is out of service (5.a), and lack of

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redundant instrumentation for reactor vessel level while shutdown (10.a).

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WThe utility ha'ndled aldifficult unplanned: outage, to repair.a reactoricoolant t ag Wsystem leakr in4a,welliorganized manner. - Although several: setbacks werei

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' encountered while: repairing the 1cak, the outage schedule:only, slipped three-

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days, : Plant-operation 1 continues' to be a perfonnance strong point..

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J The plant's;retentic:: of senior-personnel has the potential to ca'use concerna

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l iTuolsuperintendents.left the company this period and the ' regulatory i :gineer.

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tieft earlier this' year.

Tnis is aggravated by-.the' fact that the licensee;is -

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in:the;midst ofia major staff expansion effort.

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' DETAILS-

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-Persons' Contacted (30703) [(30702)]:

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• J. 'J.~ Zach, Senior Manager - Nuclear Engineering

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• G. J. Maxfield, Plant Manager

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T. J. Koehler General, Superintendent - Maintenance

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J.- C. Reisenbuechler, Superintendent - Operations

' W. J. Herrman, Superintendent - Maintenance

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'N. L. Hoefert, Superintendent - Instrument & Controls

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y p. J. Bruno - Superintendent - Technical Services i. L. Fredriens, Superintendent - Chemistry J.?J. Bevelacqua, Superintendent - Health Physics

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M.- L._ Mervine, Guperintendent'- Training u

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• R. D. Seizert, Superintendent, Regulatory & Support Services j

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D.;R. Stevens, Nuclear-Specialist

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F. An Flentje, Administrative Specialist

Other licensee employees were-also contacted including members of the tecnnical' and engineering.staf fs, and reactor and auxiliary l operators, h

• Denotes'the personnel attending the management exit interview for_

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summation of preliminary findings.

-2.

Licensee Action on Previous Inspection Findings ('92701)

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a.

-(Closed)LUnresolved' Item (266/90004-01; 301/90004-01): > Ir. properly

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Stored Quality Assurance-(QA) Circuit Breakers.

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On February 2,1990, the inspector noted a box of QA circuit'

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' breakers stored in the Turbine Building contrary to station'

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procedures. :The preliminary investigationi results indicated that M.

the breakers were not new but instead were 'old circuit breakers -

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.that were changed out of an electrical bus during previous main

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tenance work. The licensee has since completed'their investigatica and verified that these were in fact old breakers which:had been-W put-into the boxes that the new replacement' breakers came in.

The site QA group gathered all the breakers for storage 11n an

approved location pending final disposition.

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. briefed workers on this incident and restated sections of the.

procedure for storage and disposal of QA material.. The inspector

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discussed these corrective actions with the licensee and was satisfied. This item is closed.

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-(Closed)~ Unresolved item (266/89020-01; 301/89019-01 Q Station-

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Battery DOS Inconsistent With FSAR.

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.The spare cell (No. 60) of station battery DOS was connected to its

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own battery charger,' inconsistent with Figure 8.2-10 (Revision 3) of

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the FSAR. The' licensee has since updated this figure in a Junes1990

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FSAR revision to correspond with the as built condition of 59 celle,

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Since the spare cell'is-no longer considered part of the safety-related DC system, neither it'nor its charger are listed -in the FSAR. A review of the licensee's documents show that~ this charger, was installed in 1975 in response to the vendor's recommendation to keep the cell on a floating charge _of 2.25 VDC to prevent degradation. No safety evaluation was done at the time because the

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spare cell was not considered safety related. A modification is

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pending to provide the spare cell of station battery 006 with its own battery charger.

The licensee will perform a safety analysis of this conficuration which will include an evaluation of having a.

common housing enclosing both cell 59 of the station battery and the spare cell.

This analysis will apply to both batteries (D05 & D06).-

No concerns were noted and this item is closed.

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c.

(Closed) Unresolved Item (266/89024-02; 301/89023-02):

Incorrect FSAR Loss of Coolant Accident (LOCA) Analysis Calculations.

During preparation of an instrument line modification package, plant engineers noted that Final Safety Analysis Report (FSAR) LOCA -

analysis calculations were incorrect. The erroneous calculation, which was in a nonconservative direction, was used as a basis to exempt 3/8.ich and smaller tubing attached to the Reector Coolant System (RCS) pressure boundary from being controlled as Quality

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Assurance (QA) scope material.

AsdiscussedinInspectionReport(266/90005;301/90005),the licensee reanalyzed the 3/8 inch line break and revised their QA Policy Manual to include this diameter piping.

Since then, an evaluation was performed to determine what, if any, procedural changes or additional training would be needed to prepare operators to respond tc this type event. The inspector discussed this evaluation with the iicensee and concurred with'their determination

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that existing abnormal operating ' procedures adequately' cover this

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event. No other concerns were noted and this item is closed.

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Plant Operations (71707) (93702)

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Control Room Observation (71707)

The inspector observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the inspection period. During these discussions and observations, the inspectors ascertcined that the operators were alert, cognizant of current plant conditions, attentive to changes in those conditions and took prompt action when appropriate. The inspectors y"

noted that a high degree of professionalism attended all facets of control room operation and that both unit control boards were generally in a ' black board' condition (no non-testing annunciators in alarm condition). Several shift turnovers were also observed and appeared to be handled in a thorough manner, d

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i-The inspectors performed walkdowns of the control boards to verify

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the operability of selected emergency systems, reviewed tagout-records and verified proper return to-service of affected components.

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Facility Tours (71707)

Tours of the Unit 1 Containment, Turbine Building, Service Water Building and Auxiliary Building were conducted to observe plant equipment conditions, including plant housekeeping / cleanliness conditions, status of fire protection equipment, fluid leaks and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance.

During facility tours, inspectors noticed some occasional signs of leakage. All equipment appears to be in good operating condition.

Plant cleanliness has not impreved and appears only marginally

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adequate since the last Unit I refueling outage.

c.

Unit 1 Operational Status (93702)

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The unit operated at full power for the first part of this period.

A turbine runback of_14% power was experienced on June 19, as discussed _ in paragraph 3.e.

The unit developed a reactor coolant-

-system leak on July 4 which resulted in a shutdown on July 20 to

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repair the leak' located on the vessel head. During the shutdown a

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second leak was discovered of the "B" steam generator channel head drain valve.

Both~ leaks were corrected and the unit restartad on

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July 28, this event is further discussed in paragraph 3.f.

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Unit 2 Operational Status-(93702)-

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The' unit continued to operate at full power during this. period with j

only' requested. load following power reductions and power reductions i

for turbine stop valve testing.

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e.

. Unit 1 Automatic Turbine Runback (93702)

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On June 19, while operating at full power, Unit 1 experienced an i

automatic-turbine runback'of 14%. The runback was generated by the

negative rate, rod drop bistable on channel N43 of the power range

nuclear instrumentation. The activation of this bistable is

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believed to have resulted from a power fluctuation in the power i

supply to the N43 channel.

It is believed that the inadvertent and

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unexpectei power fluctuation was generated during the performance of d

ICP 2.3 (Revision 20), "I&C Surveillance Test Reactor Protection System Logic (Long)". The licensee notified the NRC of this event

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via the emergency notification system.

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As part of the licensee's immediate corrective action, control rJd po.;itions were verified. -The licensee determined that there were

no control rods inserted either fully or partially into the reactor i

core. The licensee also suspended ICP 2.3 and performed ICP 2.7, Revision 17, " Periodic Test; Nuclear Instrumentation Power Range-Channels N41, N42, N43, N44".

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After erification of control rod positions, suspension of ICP 2.3, and successful completion of ICP 2.7, the licensee commenced a power

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ascension back to full power. This ascension was suspended at approximately 90% power when Individual Rod Position Indication

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(IRPI) for control. rods C4 and C7 indicated that the rods were not level with the bank. Evaluation of this problem found that the i

g IRPIs were defective and that the rods were still in proper alignment within the bank. MaintenanceWorkRequests(MWRs)were-

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issued for each IRPI and the unit was returned to full power.

The licensee issued a MWR to troubleshoot cheel N43 in an attempt to duplicate the power fluctuation responsibh ;.a the actuation of the runback bistable. The test reestablished the condition that existed prior to the runback, using a modified ICP 2.3, and then repeating the suspected step. This time however, the N43 rod drop runback bistable was also bypassed to prevent a reoccurrence from causing another actual runbaci _

The step was repeated nine times, seven of which were observed b/ the 'nspector, without duplicating the power fluctuation. The can a of this voltage spike could not be determined and is believed to hr/e been spurious. The utility issued Licensee Event Report 266/90-006 discussing this incident.

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Unit'l Reactor Coolant System (RCS) M ak (93702)

Starting approximately July 4, Unit I reactor coolant leakage increased from a nominal value of approximately 0.03 gpm to a value slightly in excess -of 0.1 gpm.

Over the next several days, this leak rate increased to slightly greater than 0.25 gpm.

Pumping of the 23 gallon containment sump increased from less than one sump

per day to about'six sumps per day.. Boron was datected in the

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containment sump and both iodine and tritium were at' elevated levels in the_. containment atmosphere all indicative of a Reactor Coolant System (RCS) leak. The licensee made a containment entry on July.17 in an attem)t to locate' the leak. The leak was suspected to be on the vessel lead, possioly on control rod D4 pressure housing seal

. weld which had developed a leak and wa's subsequently repaired prior to startup-from the 1990 spring refueling outage. The leak was

.actually found to be on the seal weld for control' rod 13. The licensee determined that based on the location and nature of the leak, the unit should be shutdown and the leak repaired. A

controlled shutdown commenced at 2100 on July 19 and the unit was off line at 0425 July 20.

The control rod pressure housing is an extension on the reactor vessel which houses the mechanical portion of_the Control Rod Drive Mechanism (CRDM) and the rod drive shaft. The CRDM coil stack assembly fits around the'outside of the pressure housing and effects-the operation of the mechanical portion of the control rod drive through the manipulation of magnetic fields.

The pressure housing is made up of two section, upper and lower, the lower sect'on is larger in diameter than the upper to accommodate the mechar,1 cal portion of the CRDM. The upper section houses only the control rod drive shaf t when the rod is withdrawn.

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into the lower section and is sealed at the joint by an o-ring and a

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metal seal ring which is welded to both upper and lower sections of the housing. This joint is_ located approximately 6 inches above the

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CRDM coil stack when the stack is in place for operation.

During the licensee's inspection of containment on July 17 a leak was located on the vessel head and a video recording was made. The leak appeared to be from a control rod pressure housing seal weld and due to the camera orientation over the vessel head, it was (;

thought to be from control rod D4.

Further review of the video

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tape indicated that the leak was on control rod J4. Correct-identification of the location was hampered by installed equipment-

and' shielding.

It was not until af ter the unit was shutdown and equipment had been removed, that the leak was finally identified as emanating from control rod 13, which is adjacent to J4. Closer

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inspection of the-13 pressure housing seal weld identified four pin hole leaks.

While' conducting routine surveys and tours of the unit 1 containment on July 20, the licensee found evidence of another primary coolant:

leak under the "B" steam generator.

Further inspection revealed a leak on the "B" steam generator dannel head drain valve (IRC-5268).

The leak was from a very small crack in the socket weld o'n the inlet side of tre valve. This is a 3/8 inch valve and the inlet' piping is 1/2 inct 0.0.

To facilitate the repair'of this valve it was necessary _to drain unit 1 to 3/4 pipe level in. the reactor vessel-which was accimplished on July 22.

A weld repair was made to the pressure nousing of control rod 13 on July 22 a id a subsequent dye penetrant test (PT) indicated no:

further surface flaws.

The CRDM coil stack for control rod 13 had a significant buildup of boric acid crystals and was' consequently replaced with a reconditior,ed stack previously removed from the 04 control rod during its leak repair.

IRC-526B was'also repaired on a

July 22. The repair consisted of cutting the pipe as close to the:

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valve as-possibic, dressing the socket and pipe, and rewelding the

.t valve to the pipe. A PT was performed on the new weld and no indication of-flaws was evident.

After filling and venting the RCS, a 300. psi leak test of the above repairs indicated further leakage on the 13 CRDM pressure housing at one edge of the weld repair area. The cause was thought to be either excessive grinding of the area after welding,'or localized thinning caused by lifting the welding element off the surface of the metal upon completion of welding. Vessel level was again lowered for-a second repair attempt. A subsequent leak at the edge of this second weld-repair was noted before the RCS was even fully refilled and vessel level was again lowered for a third repair attempt. The third weld repair on the CRDM seal was done July 26 and proved successful. A hydrostatic leak check of approximately 2100 psi was successfully performed on the PCS and the unit was taken critical on Saturday, July 28. Two faulty circuit cards ir, the electro hydraulic control system for the main turbine delayed

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.. placing the unit on line until the following day.

Full power was reached at 1:20 p.m. July 29.

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1 The plant took an-innovative step in placing a video-camera in tt containment to allow monitoring of CRDM 13 pressure housing seal

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weld in the control room. _The camera was left in place after startup to permit continuous observation of the affected area as the plant' continues to operate.

One drawback is that the camera is ILt

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expected to function long in the radiation field it is subjected to during plant operation, although gond data should be obtained while it lasts.

Wisconsin Electric and the CRDM vendor are evaluating the CRDM head seal degradation to determine if there are any generic concerns involved.

j The resident inspector staff augmented their coverage of this event i

with the assistance of the Kewaunee resident inspector. Monitored activities included the shutdown, cooldown, draindown, various.

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maintenance work performed during this outage, the pressure test ~

of the RCS, and the subsequent reactor startup, g.

Reduction of F(q) Limit in Technical Specifications (71707)

On June 6, the fuel vendor identified an error in'the loss of

coolant accident (LOCA) analysis that' resulted inl the plant technical specification heat flux peaking factor'(F(q)) being nonconservative. This was confirmed June 13. The error was caused i

by assuming too low of a decay heat value in the computer code which

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was used to perform the safety analysis._ Correcting the decay heat i

value in the computer code results in an analysis which preu; ts

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higher peak clad temperatures (PCT) following a LOCA, possibly exceeding the regulatory requirement of 2203 deg. F.

The fuel vendor performed a preliminary calculation whi_ch indicates.

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- that. PCT followins a LOCA will not exceed:2099 deg. F. if F(q) _is limited to 2.40. To operate under this; lower value, the licensee promulgated interim guidance to operators which restricted rod-insertion limits and-delta flux limits.

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required reducing power below 90%. The licensee then replaced the interim guidance with special.oparations_ order PBNP 90-02,_

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" Administrative Delta Flux Limits", to-control delta flux within a

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reduced band, j.

Further calculations by the vendor demonstrated that-for the remainder of.the current Unit 1 and 2 operating cycles F(q) will i

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not exceed 2.32 under the existing technical specification band for

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ax14 flux offset and rod insertion limits._ As a result, Wisconsin Electric has adopted 2.40 as an interim administrative limit for F(q), down from the 2.5 stated in the technical specifications, and

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the plant computer F(q) setpoint was adjusted accordingly. Special

operations order PBNP 90-02 was cancelled and the plant ~ reverted to

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their normal limits for axial flux offset and. rod insertion, n

The fuel'_ vendor plans to meet with Wisconsin Electric and the NRC on

~ August 7, to present its findings. Wisconsin Electric will then-I

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determine a plan for ultimate resolution of tl.is concern. This item remains unresolved pending completion of the analysis and subsequent review by the inspector (266/90014-01; 301/90014-01).

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Gas Turbine Reliability Project (71707)

The gas turbine (G05) was successfully operated for an eight-hour period on June 15. This run met the licensee's test criteria of starting the gas-turbine within one hour and operation for eight hours under station' blackout conditions as committed to the NRC.

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Previous tests had failed due to overhhting of the gas turbine auxiliary diesel (G-501). The waste hea+. ;irculated around the diesel eventually' causing it to overheat and automatically shutdown.

The plant complete a modification on the gas turbine building to d

correct the overheating problem.

This consisted of ventilation dampers installed adjacent to the G-501 radiator to allow venting.

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the diesel waste heat outside the building.

The new ventilation system functioned as required during the test although G-501 still-

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tripped on high temperature.

Further troubleshooting revealed that the trip setpoint was set 8 deg F too low and the temperature gauge read approximately 5 to 10 deg F higher than actual.

The trip setpoint was recalibrated and raised an additional 5 deg F:as

allowed by diesel technical manual. The subsequent test was completed successfully. Outside air temperature during the test was about 55.deg F.

An eight hour run was reattempted on July 25 with outside air temperature about 85 deg F.

This attempt failed as described in paragraph 5.b.

The-cause of the failure is not believed to be due to the higher. temperature and the licensee is planning another 8-

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hour run under summertime air temperature conditions.

Blackout start testing of the_ gas turbine will continue on a monthly basis to determine'its reliability in this mode. To be considered an acceptable alternate AC source, the gas turbine must_ demonstrate 95% reliability within two years of. receipt of the NRC safety evaluation report on Point Beach station blackout. The inspector

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will continue to follow the licensee's progress in this area.

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Inadvertant Reactor Trip Signal (93702)

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On July 23, the licensee notified the NRC via the Emergency _

Notification System (ENS) regarding an inadvertant initiation of the Unit I reactor protection system (RPS) while the unit was shutdown. While performing procedure ICP 2.9, " Intermediate Range Nuclear Instrunentation Testing", one of'the control power fuses for intermediate channel N36 blew.

Loss of control power deenergized the reactor trip bypass circuitry associated with this channel, allowing the RPS to sense tha test signal being inputted. At the time the fuse blew, the test signal was above the reactor trip

setpoint. Consequently, when the RPS sensed this signal, it initiated protective action.

Since the plant was already shutdown

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with'the trip breakers open and racked 'out, no protective. action-i

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-The licensee's initial. investigation could determine no occurred.

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cause for the fuse to blow. This fuse is believed to have been in

.r service for the twenty year life of the plant and may.have grown

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weak with age. There was no procedural or personnel error involved.

The inspector discussed this event with the licensee and had no

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- further concerns. Wisconsin Electric willLissue a licensee event i

veport discussing this event which the inspector will review.

j, Zebra Mussel Monitoring (71707)

The inspector requested a briefing on any monitoring programs the company has undertaken to detect the presence of zeb.4 mussels at the Point Beach facility in light of the spread of + s infestation i

across the Great Lakes. Wisconsin Electric is collecting lake water

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samples weekly at five of their power plants including Point Beach.

The samples are analyzed by the University of Wisconsin Sea Grant Institute.

Pieces of plexiglass have also been set up as artificial

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-substrates for mussel colonization to monitor for free swimming zebra mussel larvae. Additionally, bio boxes are planned for installation in the plant service water systems to monitor for any

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mussel infestation in plant piping.

No mussels have been found at Point Beach or any of the company's other. plants.

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In addition to the monitoring activities, the company has a task force to examine chemical.and other methods' of controlling the mussels once'tby reach this area. Thermal treatment-is one method the company believes has good potential for minimizing mussel growth. Wisconsin Electric is coordinating.research activities with other utilities and with the Electric Power Research Institute..

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A formal agreement was signed with Niagara Mohawk to exchange information. The inspector will continue to monitor this area.

These reviews and observations were conducted to verify that facility

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operations were conducted safely and in conformance with requirements established under technical specifications, federal regulations, and

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4.

Radiological Controls (71707)

The inspectors. routinely observed the licensee's radiological' controls

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and practices during nonnal plant tours and the inspection of work activities.

Inspection in this area includes' direct observation of the s

use of Radiation Work Permits (RWPs); normal work practices inside contaminated barriers; maintenance of radiological barriers and signs;

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and health physics (HP) activities regarding mon'itoring, sampling, and

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surveying. The inspector also observed portions of the radioactive waste system controls associated with radcte precessing.

From a radiological standpoint the plan' is in good condition, allowing access to most sections Lof the facility Durbg tours of the facility, the inspectors noted that barriers and signs also were in good condition.

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Whei. minor discrepancies were identified, the HP staff quickly responded to correct any problems.

LiOH Chemistry Control (71707)

The plant is instituting. tighter f lithium concentration in the reactor coolant system to a o narrower pH band. The objective is to minimize the amm crud in the steam generators, thereby reducing the radiation fielo levels in the vicinity of the

. steam generators and allow for reduced personnel exposures during maintenance.

Radiation levels around-the steam generators have remained constant for years at Point Beach, while other utilities have been able to reduce theirs. Despite this, Point Beach still manages to achieve lower than average total exposures.

By reducing'their-radiation levels, the plant hopes to reduce exposure levels even further. The-lithium control program is being implemented through more frequent monitoring of lithium concentration in the coolant, a tighter control baad, and more frequent lithium adjustments in the coolant.

i All activities were conducted in a satisfactory manner during this inspection period.

5.

Maintenance /SurveillanceObservation(627031(61726),

Maintenance (62703J,

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Station maintenance activities of safety related s) stems and j

components listed below were observed / reviewed to ascertain i

that they were conducted in accordance with approved procedures, j

regulatory guider and industry codes or standards and in conformance with. technical-specifications.

l The following items were considered during this review:

the limiting. conditions for operation were met while components or

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systems were removed from service; approvals were obtained prior to initieting-the work; activities were accomplished using approved

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procedures and were inspected as applicable; functional testing

and/or calibrations were performed prior to returning components

or systems to service; quality control records were maintained;-

-l activities were accomplished by qualified personnel; parts and

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materials used were properly certified; radiological controls were

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implemented; and fire prevention controls were implemented.

Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety-related equipment i

maintenance which may affect system performance.

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Portions of the following maintenance activities were

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observed / reviewed:

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P328 Service Water Pump Repacking

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2P2C. Charging Pump Seal Replacement

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The maintenance procedure for this job RMP 3, requires that six specific fire zones (142,148,151,.156,165, and.166) be

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checked twice per shift while the 2P2C pump is out of service.

The Primary Auxiliary Building (PAB) Operator's log sheet for-these Appendix R checks only lists general areas in the PAB to

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be toured. When questioned by the inspector, the operator stated that he checks the general areas listed on his logs as

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indicated, but was not aware of any requirement ta check the.

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six specific fire zones. The Duty Shift Supervisor was aware-of these requirements and modified the operator's logs to

reflect this af ter a discussion with the inspector. This issue'

r remains unresolved pending an evaluation by the licensee of the adequacy of the operator logs anc subsequent review by the NRC

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(266/90014-02;301/90014-02).

Control Rod 13 Pressure Housing Seal Leak Repair

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Details of the activities regarding the repair of this item are contained in paragraph 3.f.

"B" Steam Generator Channel Head Drain Valve Leak Repair

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Details of the activities regarding the repair of this item are contained in paragraph 3.f.

b.

Surveillance (61726')

The inspector observed surveillance testing and verified that

testing was performed in accordance with adequate procedures; that

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test instrumentation was calibrated; that limiting conditions for-q operation were met; that removal and restoration of the affected

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components were. accomplished; that test results conformed with

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technical specifications and procedure requirements and were reviewed by personnel other than the individual (iirecting the test; and 'that any deficiencies identified during the testing were properly: reviewed and resolved by appropriate management personnel.

The inspector witnessed and reviewed the.following test activities:

a ICP 2.11 (Revision 6)

Ana:og Rod Position Periodic Test

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ICP 2.3 (Revision 20)

I&C Surveillance Test Reactor

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ProtectNn. System Logic (Long)

.IT-200(Revision 20)

Inservice Test of Auxiliary

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Feedwater System Check Valves & Flow Indication, (Unit 1)

IT-10 (Revision 18)

Inservice Test of Electrically Driven

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Auxiliary Feedwater Pumps (Monthly)

PC-29(Revisian13)

Monthly Gas Turbine and Auxiliary

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Diesel Load Test

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The gas turbine tripped less than one half hour after starting.

w due.to high; turbine. thrust bearing temperature.

A. fault was M

found Jn1 the turbine cooling system and subsaquently corrected.-

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The test was restarted and the turbine ran several hours before

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the auxiliary diesel-tripped on high temperature, taking the l

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turbine down with it.. Temperature readings on the auxiliary

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' diesel were normal and troubleshooting revealed a_ fault in the-

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~ diesel protective system circuitry. The-licensee plans to

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i repair this fault and reschedule the test. The inspector will

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continue to follow this arogress in this area.

Paragraph 3.h

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contains additional information on gas turbine testing.

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No other discrepancies were noted duricg the-observance of any of

.the above tests, j

6.

._ Emergency Preparedness (71707)

's Antinspection'of emergency preparedness activities was performed to l

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assess the licensee's implementation of the' site emergency plan and

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implementing procedures. The inspection included monthly review and tour of emergency facilities and equipment, discussions with_ licensee staff, and a review of selected procedures.

All activities were conducted in a satisfactory manner during this inspection period.

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Security (71707)

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The:i'nspector, by direct observation and interview, verified-that i..

Jportions-of the physical. security program were being i.mplemented'in _

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c accordance with the station. security plan.- This included checks that

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identification badges were properly displayed, vital areas werel locked ;

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and alarmed, and personnel and packages l entering the protected. area were

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appropriately searched.

All activities were conducted in'a satisfactory manner during this-

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inspection period.

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Engineering and Technical Support (71707)

4 4"

The inspector evaluated licensee engineering and technical support p

' activities-to determine their invA vement and support of facility

operations. This-was accomplished during the course of routine

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evaluation of facility events and concerns through direct observation-

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of activities and discussions with engineering personnel.

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i All activities were conducted in a satisfactory manner during this inspection period.

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- Safety Assessment / Quality Verification (71707) (90712) (927001 The' licensee's quality assurance programs were inspected to assess-the implementation and effectiveness of programs associated with management

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control, _ verification, and oversite activities.

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was given to issues which may be-indicative of overall management involvement in quality matters such as self improvement programs, response to regulatory and industry initiatives, the frequency of management plant tours and control room observations, and management-personnel's attendance at *::hnical and planning / scheduling meetings, a.

' Licensee Event Report (LER) Review (90712)

The inspector reviewed LERs submitted to the NRC to verify that the details ~ were ie0rl.y reported, intluding accuracy of the description and corrective action aken. The inspector determined whether further inforintion was required, whether generie implications were indicated, and wiiethv. the event warrant d onsite followup. The following LERs were reviewed and closed:

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301/89007-Unanticipated Safety Injection Signal

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a On October 27, 1989, a safety injection (SI) signal was generated I

during installation of a modification in the containment high pressure logic circuit for Unit 2.

The modification involved the replacement of several test switches in the logic circuitry. Prior to replacewnt, the old switches were placed in the test position to prevent R initiation upon the circuit sensing a loss of AC power. ' AC and DC power were then secured to the circuit. Due to an

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inadequate installation procedure, the new switches were installed

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with their position set to normal.

Conspquently, when DC power was -

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reapplied, a safety injection signal resulted. No injection of:

i water occurred because since the unit was in a refueling shutdown with the core unloaded, the SI system had been placed in a-condition

which precluded SI pump operation. The licensee revised:the t

installation-procedure to require placing the test switches to their test position after installation and completed the modification on the other SI train without incident.

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• 266/89008-01 AMSAC Not Enabled as Required by Technical Specifications During a power reduction on Se 10, 1989, the anticipated

- transient without scram (ATWS)ptember mitigating system actuation circuitry.

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(AMSAC) was automatically bypassed at about 42% reactor power.

Technical Specifications require AMSAC to be in operation above 40%

j reactor power.

Power was reduced below 40% to comply with the Technical Specification (TS).

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The cause for the early bypass signal is due the circuit's sensing of turbine 1st stage pressure for its reactor power input.

Fower, as indicated by 1st stage pressure, is lower than reactor power

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during power reductions in this range. An investigation by the

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licensee determined that the design basis of AMSAC intended it to be in operation above 40% power as derived from 1st stage' pressure.

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The phrase:'as derived from ist stage pressure', appears to have been inadvertently left out of the TS when AMSAC was installed.

Consequently, the licensee submitted TS revision 138 on March 30, to clarify that turbine power is to be used as the parameter for the AMSAC enabling setpoint.

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• 301/90001 Inadvertent Start of Auxiliary Feedwater Pump On April 5,1990, while testing a wiring modification in the-Auxiliary Radwater (AFW) pump undervoltage start circuitty, an inadvertent actuation signal was sent to the "A" electric AFW pump.

This was caused by a current sneak path through a push _-to-test light whose detail's did not appear on the elementary wiring diagrams.

Since engineers were not aware of this circuit path, it was not properly isolated for the modification work'. After troubleshooting uncovered this deficiency, appropriate isolations were made and the modification testing completed without incident.

The licensee then

[o briefed responsible engineers and technicians on the potential current path through push-to-test lamp circuitry. The licensee is in the. process of updating elementary wi ing diagrams with schematics of the push-to-test lamp circuits.

• 266/90002 MainSteamSafetyValve1-MS-2013Setpdint Nonconservative Ouring testing on April 2,1990, MS-2013 failed to relieve at its code defined setpoint of 105% of steam generator design pressure.

It lifted instead at 116% and 115% of design pressure. This.

nonconservative setting left the "A" steam generator with less than the required everpressure protection.

In accordance with TS, two additional safety valves were tested and the test results were acceptable. Safety valve 1-MS-2013 was then sent to.a certified repair agent for analysis and repairs.

Its setpoint was adjusted, the valve was recertified and restored to service.

The licensee's investigation found no anomalies with the aalve. The setpoint is believed to have been. improperly set after,-the valvr. was refurbished in May '1986 since the set screw seals were stili intact.

The other seven safety valves were also.-refurbished at that same time but have all since been retested satisfactory as'part of a five year safety valve program which began its cycle in 1986. This was-the last valve to have been tested. A review by the inspector of.

the retest data on the other seven valves-was found acceptable.

266/90006 Nuclear Instrumentation Turbine Runback On June 19, Unit 1 experienced a turbine runback from 100% to'85%

power. The runback was caused by a spurious signal, believed to have been a negative spike on nuclear instrumentation channel N43 power range detector.

Details are provided in paragraph 3.e.

b.

LER Followup (92700)

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The LERs denoted' by asterisk above were selected for additional followup. The inspector verified that appropriate corrective action was taken or responsibility was assigned and that continued operation of the facility was conducted in accordance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59.

Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewed,

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P, lag gnt Changes (71707)

On July 2, the Plant Manager was promoted to Senior Manager, Nuclear Engineer _ing and transferred to the company's corporate headquarters in Milwaukee. The General _ Superintendent of Operations became the new Plant Manager.

The licensee briefed the inspector on these changes.

• L0n July-13, the Superintendent of Training left Wisconsin Electric-for a management position with another nuclear' utility. His billet'

was filled by a former assistant.

On July 27, the Superintendent of Technical Services left Wisconsin Electric to work for another company. _His billet will be filled by-the Superintendent of Maintenance.

In view of the fact that much of the good performance'of Point Beach is directly attributable.to the ' experience level' of its employ +e,

the decline in retention being observed among senior personnel im

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recent months is cause for concern. This becomes even more so since

the nuclear department is attempting a major increase _in the size'of

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its staff. Additionally, 5 of 15 Duty Technical Advisors have left the company this year. The inspector will continue to evaluate this area to determine -if a trend is -developing.

All actihities.were conducted in a satisfactory manner during this inspection ~ period.-

10. Temporary Instructions (TI)

a.

(Closed) TI 2515/103-Loss of_ Decay _ Heat Removal (Generic Letter

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88-17) '10 CFR 50.54(f) Programed Enhancements (Long -Term) Review

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The objective of this TI was to verify. the licensee's preparation for non-power operation in accordance with the programmed-

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enhancements phase of " Loss of. Decay Heat Removal (Generic Letter !

W 88-17), 10 CFR 50.54(f)," October 17,1988. The TI require the

. inspector to review the licensee's efforts in five areas, ci instrumentation, procedures, equipment, analysis and Technical y

Specifications. The following are the-inspector's findings in

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-each of the six areas.

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Instrumentation The TI recommended that two independent RCS level indicators be installed to monitor RCS level in a non-power condition. -The licensee had one detector installed to monitor shutdown RCS level (LT-447) and installed a second identical' detector (LT-447A).

The licensee also uses a standpipe of Tygone tubing as a third means of

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level indication but it is only used when the RCS is depressurized.-

After a review of the. system drawings and operating procedures, the l

inspector determined that all three means of level detection-use the same variable leg tap off. This common variable leg tap off can be

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,1 isolated by any one of three manually operated valvec. Also any-flow obstruction in this common line would effect the performance-of all three-level indications.

Based on the use of a common variable leg-tap off it does not appear that the instrumentation used.to monitor level is truly independent.

The two level transmitters (LT-447 and 447A) also do not cover the

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full range of RCS level.

The result of this less than full RCS -

level range is that there is a blind band between the bottom of the:

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pressurizer level instruments and the top of the RCS. shutdown levels of. approximately 2000 gallons.

This blind ~ spot is addressed in OP-4D (Revision 32), " Draining the-Reactor Coolant System".

The'-

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inspector contacted other fccilities of a similar design and found

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that other facilities provided at least overlap level coverage so

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the entire range of RCS -level is visible to the operator.

Further review of the. independence and instrunant range issues by NRR is necessary to dete'rmine the intention of Generic Letter 88-17.

This issue remain unresolved pending completiot of this review (255/90014-03;301/90014-03).

The licensee informed the inspector of its intention to replace the-Tygon tubing level standpipe with a stainless steel standpipe using

.a magnetic float.

This modificction wiil reduce the possibility of leakage from the standpipe level instrument and will allow for greater utilization of the instrument.

This-is viewed as an

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enhancement to the level instrumentation and is planned to be completed in future refueling outages.

The inspector also reviewed temperature indication' that is available during conditions of decay heat removal system operation. Two-incore thermocouples will remain operational while the reactor vessel head.isLinstalled and will provide indication of RCS temperature and:an alarm to the Plant Process Computer System (PPCS). Once the head is removed RCS temperature is monitored by-J three Residual Heat Removal (RHR) system temperature instruments, two indicators and one stripchart recorder.

These three RHR temperature monitors do not provide any alarm function, however,

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all are available in the control room to the operator.

Procedures

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The inspector reviewed the various procedures used to drain the RCS, operate the RCS in a reduced inventory condition, and operation with a degraded RHR system. The following procedures were included in this review:

OP-4D (Revision.32) Draining The Reactor Coolant System

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OP-4F (Revision 1) Reactor Coolant System Reduced Inventory Requirements OP-SA (Revision 19) Reactor Coolant Volume Control OP-7A (Revision 26) Placing Residual Heat Removal System in

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Operation A0P-9C(Revision 3)DegradedRHRSystemCapability

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'During the-course of the procedure review the following concerns

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4J were identified by the inspector:

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A blind spot exists between pressurizer. level off-scale low andu

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a on-scale.high for' level instruments LT-447 and 447A.

The blind.

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spot is'approximately 2000 gallons and it.noted in OP-4D. The-

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operator is cautioned not to drain more than 3000. gallons.while in this blind spot. However, no direction is given to the

. operator on how to determine when 3000 gallons-has been

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drained.

Procedures.0P-4D, 4F, and.5A do not tell the operators to take

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the two level alarms associated with LT-447 and 447A out of!

bypass. ~ Furthermore the procedures do not provide. gu idance.on '

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thelsetpoints to,be used for the alarm:.

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OP-4D'does not. reference AOP-9C'until late in the. procedure

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after-the vesse1~is at 40% level as indicated on LT-447 and=

,;l c447A.

l Several points in the procedures describe actions and cautions;

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however they only reference LT-447: and do not mention'LT-447A.-

OP-4D has the operator drain the RCS in several stages. After

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each stage the' operator is only told to stabilize level,Ln guidance is given' if the stabilization does not occur.'

-OP-4D provides no guidance on RCS pressure or' temperature

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changes and corrective actions should non-conservative changes occur.

The inspectors had a meeting with licensee operations management '

personnel and discussed each~of the above concerns. The licensee-

- agreed with the inspectors regarding.these concerns and indicated a

that the procedures would be revised to' provide better direction' to the operators, Completion of this item will be tracked along with the unresolved item for instrun Latix independence discussed'above a

.'(266-90014-03; 301 90014-03).

- As part of the. procedural review, the inspector observed use of a

OP-4D to drain the reactor vessel to allw for repairs-to control-

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rod-13 pressure housing. The drain dowa occurred after the

- discussion'with the licensee-regarding the concerns with the procedures. During the evolution, the inspector noted that interim

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administrative guidance had been provided to the operator regarding

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4, the blind zone and the level alarms. This demonstrated good

responsiveness on the part of the licensee to correct apparent inadequacies-in the procedure.

The evolution was performed in a controlled.and professional manner with no problems identified.

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Equipment

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The inspector reviewed the equipment needed for decay heat removal during periods of reduced inventory as well as equipment needed

.to_ mitigate possible RHR or. RCS degradation. The inspector found that all required equipment appeared to be in adequate states of operability for periods of reduced inventory. This included prcvision for the anticipated use of safety equipment and communications equipment.- Procedures used for periods of reduced inventory identified the necessary equipment and directed that equipment _to be in the proper configuration for possible use.

Analysis

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The licensee has conducted analysis on the operation of the RHR system during periods of low vessel level. This information is conveyed to operation personnel in'the various procedures used and appears adequate for the needs of the facility. Analysis has also i

been perfctmed to determine the effects of decay heat on temperature of the RCS during periods of loss of RHR flow. A graph showing the tic.e to reach 200 degrees following a loss of RHR is attached to

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A0P-90 for the operators use.

. Technical Specifications Based on the review of the licensee's response to the NRC dated February 2, 1989, it appears that changes to the licensee's-Technical _ Specifications are not applicable for this facility.

Perturbations The licensee does discuss the entry of. educed inventory condition

at. pre-outage' meetings and appears to be very conscious of-activities-during this condition Based on the review completed by the inspector as described above, requirements of this Ten.porary Instruction 'are considered complete

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and this item is closed.

b.

(Closed) TI 2315/65 TMI Action Plan Requirements

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TMI Item II.F.2.6 ' Instrumentation for Detection of Inadequate Core

Cooling - Subcooling Meter'

This item was completed in 1987 but its closure was not completely _

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documented.

For administrative purposes, this area'was reinspected using the TI as guidance. The inspector verified that subcooling

meters were properly installed on both units during February 1987,

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in accordance with licensee comitments and HRC requirements.

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Appropriate procedure changes were made and personnel were trained on the new equipment. The meters are calibrated and being used in

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accordance with approved procedures.

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E Thel inspection determine ~d that the. licensee meets the -intentiof this:

pi requirement. This Tl is closed.

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0utstandin'g-Items-(92701)'

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Unresolved Items.

l Unresolved. items.~are matters about which more information is required.

in order-to ascertain whether they are acceptable items, items of

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_ noncompliance, or deviations. Unresolved items: disclosed during.the-J

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inspection are discussed in paragraphs 3.g, 5.a and -10.a.

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112..' Management Meetings (30702)'

a A meeting was held between NRC Region III' management and 'pinnt management l

' onlJuly 2-to discu.e; items of interest and foster improved communications ;

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between:the. licensee and the NRC.

Items of dist.ssion~ included

' electrical inspection findings and corrective actions,-plant management _

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changes, Unit =2' steam generator. replacement' plans, and status of

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l addressing current'plantLopen items,

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A A meeting wasLheld between NRC Region III management.and corporate j

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management on July 7;to discuss the licensee'.s corrective actions

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program and other items of~ mutual interest.

'13.

Exit Interview ~(30703)

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lA-verbal summary of preliminary findings was provided to the= licensee-

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representatives; denoted in Section l' on August 2,;1990, at.the conclusion-

!ofmthe inspection. LNoiwritten inspection material was__provided:to.the-b licensee.during:theLinspection.

m Thellikelyiinformational content cf the-inspection. report with regard to Jdocumet or processesireviewed.during the: inspection was alsoLdiscussed.

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LThe lice: seeldid not identify 1any documents or processes as proprietary.

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