IR 05000219/1985028

Insp Rept 50-219/85-28 on 850923-27.No Violation Noted. Major Areas Inspected:Followup of Unit Substation Transformers 1A2 & 1B2 850809 Low Oil Level Event & Implementation of Fire Protection/Prevention Program

ML20198E221
Person / Time
Site:	Oyster Creek
Issue date:	11/05/1985
From:	Anderson C, Pullani S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20198E210	List: IR 05000219/1985028 ML20198E205
References
50-219-85-28, NUDOCS 8511130212
Download: ML20198E221 (23)

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l.' , U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /85-28 Docket N '9 License No. DPR-16 Priority --- Category C Licensee: GPU-Nuclear Corporation Oyster Creek Nuclear Generating Station P. O. Box 388 Forked River, New Jersey 08731 Facility'Name: Oyster Creek Nuclear Generating Station Inspection At: Forked River, New Jersey Jaspection Conducted: September 23-27, 1985 Inspectors: Du/lan // 05-85 S. V. Pu/1 ni" ead Reactor Engineer date Approved by: b a s T* C. J.fAnderson, Chief, date~ Plant Systems Section Inspection Summary: Inspection on September 23-27, 1985 (Report No. 50-219/85-28) Areas Inspected: Special announced inspection of: (1) followup of Unit Sub-station Transformers IA2 and 182 low oil level event on August 9, 1985 and (2)

' implementation of the Fire Protection / Prevention Program. The second' area in-spected included followup of previous inspection findings; equipment mainten-ance, inspection and tests; fire brigade training; periodic inspections and quality assurance audits; and facility tour. The inspection involved 48 in-spector-hours on site and 18' inspector-hours in office by one region based inspector.

y ' Results: Of the two areas inspected, no violations were identified. One item remained unresolved at the end of inspection (see Section 2.5.2 of this report,fordetails).

! 8511130212 DR 851107 g ADOCK 05000219 > PDR h c ___ _

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DETAILS 1.0 Persons Contacted 1.1: GPU Nuclear Corporation-(GPU) K. Barnes,- Licensing Engi_neer

 *J.~ DeBlasio, Manager-Support Engineering A. Dickinson, Supervisor-Electrical Engineering P. Fiedler, Vice President and Director T. Gaffney, Electrical /I&C Material Manager D. Holland,-' Licensing Manager
 *D. Jones, Plant Engineering R. Kilian, Plant Engineering D. Pino, Electrical Engineer T. Prosser, Fire Protection Instructor T. Quintenz,-Manager-Maintenance Engineering D. Ranft, Electrical Engineering Manager, Technical Functions G. Simonetti,-QA Audit Manager
 *W. Smith, Plant Engineering Director
 ~*K. Zimmerman, Fire Protection Coordinator 1.2 General Electric (GE)

E. Hritzo, Manager-Nuclear Plant Services, King of Prussia Office (By Telephone)

. Nuclear Regulatory Commission (NRC)

W. Bateman, Senior Resident Inspector J. Wechselberger, Resident Inspector

 * Denotes those present at the exit intervie .0 Followup of Unit Substation Transformers 1A2 and 182 Low 011 Lavel Event 2.1 Summary As a result of licensee preventive maintenance testing using an in-frared scanning method for potential hot spots on switchgear con-nections, two 4160/480 Volt unit substation transformers 1A2 and 1B2 which supply redundant 480 Volt vital loads were found to have in-sufficient cooling oi Both transformers were declared inoperable at-1800 hours on August 9, 1985. An orderly shutdown of the plant was initiated and the reactor was placed in cold shutdown in accord-ance with the Technical Specification Sufficient oil was added to
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the transformers to establish proper cooling and the plant was re-turned to power on August 10, 1985 without inciden __

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2.2 Plant Electrical Power System To provide a better understanding of the function of these two trans-formers in the overall Plant Electrical Power System, and the event itself, a brief description of the Plant Electrical Power System is given below. (see FSAR Chapter 8 for a detailed description). The Plant Electrical Power System consists of an Offsite Power System and an Onsite Power System and is shown in Attachment .2.1 Offsite Power System The unit output power is normally connected to the Jersey Cen-tral Power and Light Company (JCP&L) grid via the 230 kV Oyster Creek substation. Two sources of offsite power are provided via two separate startup transformers fed from the 34.5 kV Oyster Creek substation. Power is supplied to the 34.5 kV Oyster Creek substation from the 34.5 kV JCP&L transmission system and the 230 kV Oyster Creek substation. The 230 kV Oyster Creek sub-station receives power from the unit itself, and from the 230 kV JCP&L transmission syste .2.2 Onsite Power System The Onsite Power System consists of a non-Class IE system and two redundant Class IE (safety related) systems. The Onsite Power System consists of an ac power distribution system (4.16kV, 480/277V, 120/208V), a vital distribution system (120 .- V ac uninterruptible), and a 125 V de power distribution syste The normal source for both the non-Class IE and class IE distri-bution systems is the turbine generator, which feeds the Station Auxiliary Transformer through the generator isolated phase bu The preferred power supply for the distribution systems during startup, shutdown, abnormal or accident conditions is the Start-up Transformers, which are fed from the JCP&L transmission system via the 34.5 kV Oyster Creek substatio Two separate and independent Emergency Diesel Generators are provided as the redundant onsite standby power supplies for safety related equipmen .2.3 480 Volt Distribution System This is a subsystem of the Onsite Power system described in Sections 2.2.2 above. Unit substations are provided to step down the 4.16 kV system voltage to 480 Volts to supply the 480 Volt Distribution System. All the unit substations are fed from the 4.16 kV essential switchgear Bus Sections 1C and 10, and in turn supply power to the motor control centers and motors throughout the station.

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There are six unit substations, as shown in Attachment The unit substations'are identified,. located in pairs, and generally provide power to station auxiliaries as follows:

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Unit Substations IA1 and IB1, in the Turbine Building base-ment, for Turbine Building loads (Non-essential)

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Unit Substations IA2 and.182, in the 480 Volt Switchgear Room, for Reactor Building loads (Essential)

* Unit Substations IA3 and 183, at the Intake Structure, for auxiliaries outside the plant in the vicinity of the Intake Structure-(Non-essential)

Transformers IA2 and 182 which feed the essential Unit Sub-- stations 1A2 and 182 and which are the subject of the event, are further described in Section 2.2.5 below. Transformers 1A1, IB1, IA3, and 183 which feed the. respective non-essential unit

. substations are similar to the essential transformers except that they are of lower kVA ratin .2.4 Unit Substations IA2 and 1B2 Unit substations 1A2 and IB2 supply power to the essential (vital) loads in the Reactor Building. Attachment 2 shows the connected loads on these unit substations. The loads shown in Attachment 3 (FSAR Table 8.3-1) are those emergency loads which are required to operate in case of'a Loss of Coolant Accident (LOCA), Loss of Offsite Power (LOOP), and/or Single Failure consideration as show .2.5 Unit Substation Transformers IA2 and 182 Transformers IA2 and 182 are rated 2000 kVA, 3 phase, 4160-480V/

277V, Delta-Star with solidly grounded neutral, class OA (011 to Air, Self Cooled). The transformers are located indoors, in the 480 Volt Room in the Reactor Building. The transformers are filled with Pyranol which contains a large fraction of poly-chlorinated biphenyl (PCB). Because of its good fire resis-tance, heat transfer and electrical insulating properties, PCB containing Pyranc1 had been used for indoor applications such as 1A2 and 1B These transformers are made by General Electric, Model F957245 They are described in their Instruction Manual GEI-65074B, Sec-ondary Unit Substation Transformers - Liquid Filled. The trans-formers were believed to be shipped liquid-filled, with approx-imately 225 gallons of oi The top of the oil is normally maintained at a positive pressure with dry nitrogen to prevent intrusion of moisture.

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Attachment 4 shows the front view of the model. The transformer consists of a rectangular tank of welded construction with a relief valve, tap changer attachment, and a vent plug on the top of the tank, and 206 cooling fin tubes (103 fins on both sides arranged in 13x8 array). A liquid level gauge, liquid temper-ature indicator, and a pressure vacuum gauge are provided to monitor the condition of the transformer during operatio Attachment 5 shows the instrumentatio The transformers are rated for a 65 C rise over an ambient of 30 C. The nominal liquid level at 25 C is 10.5 inches below the reference point which is 0.25 inches above the top of the tank (See Attachment 6). The nominal nitrogen pressure is approx-imately 2-3 psig. The relief valve is set to relieve the ni-trogen pressure if it exceeds 5 psi .3 Description of the Event 2.3.1 Plant Conditions Prior to the Event The reactor was operating at a thermal power of 1981 MWt with the reactor mode switch in RUN position. The turbine generator was on line producing approximately 622 MWe of electric powe .3.2 Details of the Event Thermographic photographs were taken of the IA2 and 182 trans-formers on June 21, 1985 by Asplundh Infrared Services, licen see's contractor. These transformers were not in the scope of the original thermographic survey which was planned for iden-tification of potential hot spots in the switchgear connection The thermographic photograph was taken incidentally on 182 transformer which indicated that a problem might exist with the 182 transformer. The photograph was evaluated on July 12, 1985 which indicated a minor degradation of 182 transformer cooling capability. The IA2 transformer also was subsequently surveyed which also indicated a similar condition. The licensee evalu-ated the degraded condition of the transformers and determined that it would not prevent the transformers from performing their safety functio To better define the problem and to determine a means to restore the transformers to their full rating, the licensee contacted General Electric, the transformer manufacturer, to survey the transformers with special thermographic equipment and take oil samples to determine if the cooling fin tubes were plugged due to sludging. General Electric conducted the survey on August 7, 1985. It showed that at normal loads limited oil flow was occurring. A decision was made to perform a load test on IA2 to determine if the condition was sludging or low oil level.

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The'1A2 ' transformer. was chosen because thermographic photographs indicated that it had less oil flow in its fin tubes than 18 The load test on IA2 was conducted on August 8, 1985. During thel test, it was noticed that the liquid temperature gauge lo-cated on a top fin tube header did not move from the 32 C mar The tank temperature was 76.1*C, as measured with a contact 4 pyromete Prior to the test, 32 out of a total of 206 tubes had flow; and after the test, an additional 64 tubes had flow (see Attachment 7). This indicated that, at higher loading of the transformer with resultant heating and volume increase of the oil, more tubes received flow of oi On August 9, 1985, a review of the above test results and other available information indicated that, due to low liquid level _in both transformers, their cooling capability had been degrade The transformers were declared _ inoperable at 1800 hours on August 9, 1985. Since the transformers should not be filled while energized, it was decided to shutdown the plant to add transformer oil. An orderly shutdown of the plant was initiated and performed in accordance with the plant Technical Specifica-tion .3.3 Apparent Cause of the Event The apparent cause of the event was insufficient oil in the fin tubes. As a result of variable tube heights as the tubes extend into'the fin tube headers, and the headers not being completely

' full of oil, flow of oil would not necessarily occur in all fin tubes. The licensee's investigations indicate that this con-

'. dition has existed since the original plant installation. This

'is based on the following reasonin During the subsequent filling operation, the licensee measured the actual transformer oil levels and temperatures and back-calculated the equivalent levels at 25*C based on the name plate data of 0.39 inches rise in level /10 C rise. The calculated levels at 25 C were 11.63 inches and 11.42 inches for IA2 and 182, respectively, below the top of the tank (See Reference 15).

These values are equivalent to 11.88 and 11.67 inches below the GE reference level shown in Attachment 6. These levels are 1.38 and 1.17 inches less than the nominal value of of 10.5 inches below the reference level. The above as-found levels are also insufficient to establish natural convection flow through all tubes at normal operating temperatures, as evidenced during the event. As discussed below, the amount of oil withdrawn from the transformers as test samples does not account for the low level condition. Apparently this condition existed since the original plant installatio .

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_ The licensee estimates that approximately five quarts of oil

. samples could have been taken since the transformer installa-tion. However, there was no accurate records of the volume of oil withdrawn as samples. The only record available was for a 500 milli-liter (approximately 1/8 gallon) sample taken on December 6, 1982 (Reference 18). The licensee's estimate of the sample volume does not account for the insufficient as-found oil levels. Furthermore, there was no apparent indication of leak-age on or around the transformers. The transformer manufacturer
.did not have a record of the liquid level when it was shipped to the site, approximately 16-17 years ago. Because of the inad-equacy of records, it could not be positively determined if the transformers were installed with insufficient oil or if exces-sive oil was .ost during the operation because of sampling or other reason Some problems with instrumentation were discovered during.the licensee's investigation. The liquid temperature indicator on the 1A2' transformer did not give an accurate reading of the oil temperature. This also contributed to the event in that the instrument was not accurately indicating the status of the transformer. The temperature indicator is installed in a cool-ing fin tube header. To display an accurate liquid temperature reading, its sensor must be submerged in the_ transformer oi This particular cooling fin tube header was one of those that
. did not receive any oil flow as a result of the-low oil leve During licensee testing of the vital transformer, a portable pyrometer was used to measure the o_il temperature. Once the oil-flow in the cooling fin with the installed temperature device was established, the pyrometer and installed temperature sensor compared favorably. With the newly established higher levels 'in the transformers, this problem will not exist oecause the sen-sors of the liquid level indicators will be submerged in oil all the tim Another instrument problem was the liquidlevel gauge. The ac-curacy of the level gauge required to sense small level changes in the transformer cooling headers is critical. The present
+ level gauge may not have the required accuracy to indicate these
'small level changes in the cooling header to the extent that an operator could determine.the onset of cooling degradation. In addition, the level indicator is not graduated to show the nor-mal levels at various temperatures. It shows an acceptable range of level with minimum and maximum levels, the center point being the nominal level at 25 C (see Attachment 5). With the newly established higher levels in the transformers, the licen-see plans to recalibrate the liquid level gauges to provide an accurate indication of the expected levels at various operating temperatures, or alternatively, provide a table or chart so that the operator can immediately determine if the levels are within acceptable limits.

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In addition to the insufficient oil levels in both transformers, IA2 transformer installation was off-level by 1/2 inch vertic-ally over the width of the transformer (approximately 8-feet).

This was the reason one side of the IA2 transformer had signif-icantly more tubes having flow than on the other side, as observed during the thermographic observations (See Attachment 7). However, the contribution to the event by this condition is determined to be less significant than those discussed pre-viousl .3.4 Safety Evaluation of the Event Technical Specifications require that the reactor be placed in a cold shutdown condition, if the availability of power falls below that required by specification 3.7.A. Due to low fluid level, the cooling capability of both of-these redundant vital transformers was degraded. A single transformer failure would result in the necessary LOCA loads being supplied through one transformer. Under certain conditions (see discussion below), this would result in an overload situation. This design deft-ciency was previously reported in LER 85-09, 480 Volt USS Over-

, load, dated June 14, 198 .LER 85-09 resulted from an electrical overload study performed by the licensee (Reference 6). The study indicated that the 480 Volt Unit Substations 1A2 and 182 may be overloaded during a LOCA without a LOOP and con' current loss of one unit substatio Without a LOOP, the non-essential loads will not get an under-voltage trip and will continue to run until manually trippe Therefore, this is the worst case overload scenario. The cause of this deficiency has been determined to be the combination of both a design problem and the impact of plant modifications re-sulting in increased bus loading. If the unit substations are run in the anticipated overload condition, it will result in de-creased transformer lif A Standing Order (Reference 7) has been written, instructing Control Room personnel to monitor the loads on USS 1A2 and USS 182 after a LOCA, to shed unnecessary loads if amps drawn are too high, and to initiate automatic load shedding by transferr-ing the buses to the diesel generators if manual shedding of loads is not sufficient to reduce transformer overload. This Standing Order will remain in effect until long term modifica-

, tions to correct the overload problems are complete.

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Long term actions ~to eliminate USS 1A2 and 182 transformer over-load problem include:

   ' Addition of fans to the transformers for USS 1A2 and 182 which will increase their capacity by 15% and bring the anticipated worst case loading within the rating of all the USS component . Addition of an overcurrent alarm to the ammeter circuits for USS:1A2 and 1B2 in the Control Roo The licensee committed to complete action item 1 during the April 1986 refueling outage (11R) and action item 2 during the October 1985 mini-outage (10M). Further, the licensee committed to strictly con-trol the addition of further loads on the essential buses and update-the load' study pe'riodicall .4 Reporting of the Event The details of the transformer event are reported in LER 85-14, Unit Substation Transformers IA2 and 182 Low Oil, dated September 11, 1985
  . Corrective Actions 2.5.1 Immediate Corrective Actions The immediate corrective action taken was to initiate an orderly plant shutdown and then add oil to unit substation transformers IA2 and 1B2. Sixteen (16) gallons of transformer oil were added to-the IA2 transformer. Twelve (12) gallons of transformer oil were added to the 182 transformer. After the. oil was added, thermographic photographs were taken which verified that all cooling fins in both transformers had proper. oil ~ flow. The four (4) non-essential unit substation transformers at the site (IA1, 1A3, 181, and 1B2) were also tested and found to be in satis-factory conditio The final levels in IA2 and 182 transformers were 8.25 inches at 44 C and 8.875 inches at 46*C below the General Electric reference point. These values when corrected to 25 C, work out to be 8.99 inches and 9.69 respectively compared to 10.25 inches nominal level indicated on the transformer _name plate. There-fore, the final levels in 1A2 and 182 transformers at 25 C were 1.51 and 0.80 inches above the nominal level. At the newly established final levels, the top fin tube headers will be    '

covered and the transformers will have convection cooling flow through all fins at all operating temperatures. The licensee has requested General Electric to review the adequacy of the newly established levels and their cooling problem in general (References 14 and 15).

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2.5.2 Long Term Corrective Actions Long term corrective actions will include: Periodic thermographic testing of the six (6) oil filled transformers on redundant plant buses; and

 - Obtain information and issue guidance for the sampling and filling of these transformers, and issue procedures where require With respect to item 1, the licensee committed to perform the thermographic testing every refueling outage. However, the licensee is-taking credit for the recent thermographic tests and are not planning to do such tests during the April 1986 refuel-ing outag Item 2 involves development of sampling and filling procedures and guidances. This item also includes the recalibration of the liquid level gauge's to provide proper operator guidance on its use. The licensee committed to complete this item by the end of the April 1986 refueling outag The completion of items 1 and 2 should solve the level proble 'Once the modifications discussed in Section 2.3.4 of this report are. implemented, the transformer overload problem under the postulated' emergency conditions will also be solved. The trans-formers would then be capable of supporting the postulated emergency load The licensee's corrective actions and commitments discussed in Sections 2.3.4 and 2.5.2 will be followed up in a' future in-spection. This is-an unresolved item pending completion of the above licensee actions and its review by NRC (50-219/85-28-01).

2.6 Conclusion The licensee's corrective actions were adequate; when fully imple-mented wi11' prevent the recurrence of the proble .0 Fire Protection / Preventive Program Implementation

'The inspector reviewed several documents in the following areas of the program to verify that the licensee had adequately implemented the pro-gram consistent with the Fire Hazard Analysis (FHA), Final Safety Analy-sis Report (FSAR), and Technical Specifications (TS). The documents reviewed, the scope of review, and the inspection findings for each area of the program are described in the following section E,
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3.1 Followup of Previous Inspection Findings

 - (Closed) Unresolved Items (50-219/84-21-01) Lack of Procedure for Surveillance Testing and Inspections of Fire Dampers The-licensee developed a procedure'645.6.026, Fire Damper Func-tional Test, Revisio.' 0, for surveillance testing and inspection of safety related fire danper The inspector reviewed the procedure for technical adequacy and found it acceptabl This item is resolve (Closed) Deviation (50-219/84-21-02) Penetration in the Soutt. west Stairwell of the Reactor Building Allows Smoke Infiltration On July 25, 1984, the licensee issued work-request No. 19976 no seal the duct penetration noted in the deviation. The penetratior was sealed on July 29, 1984 to prevent smoke infiltrations into the Re-actor Building stairwell. The licensee has also initiated a pre-ventive maintenance check sheet to visually inspect all stairwells-
 .for unsealed penetrations and through the wall cracks as committed in their letter _ dated September 23, 1985. This completes all corrective actions committed in the licensee response letter dated December 11,-1984. The inspector reviewed all corrective actions and found them acceptabl This item is close ~ Equipment Maintenance, Inspection and Tests The inspector reviewed the-following randomly selected documents to determine whether the licensee had developed adequate procedures which established maintenance, inspection, and testing requirements for the plant fire protection equipment:
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 * Surveillance Test Procedure 645.4.001, Fire ' Pump Operability Test, Revision 0*
 * Surveillance Test Procedure 645.4.018, Fire Pump Insurance Test, Revision 10*
 * Surveillance Test Procedure 645.6.012, Fire Pump Functional Test, Revision 5*
 * Surveillance Test Procedure 645.6,013, Fire Suppression Halon System Functional Test,~ Revision 4*
 * Surveillance Test Procedure 645.6.016, Fire Suppression Low Pressure CO 2 System Functional Test, Revision 2*

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Surveillance Test Procedure 645.6.026, Fire Damper Functional Test, Revision 0 In addition to reviewing the above documents,.the inspector reviewed the

- maintenance / inspection / test records of the items identified by an asterisk (*)

to verify compliance with Technical Specifications and established procedure No unaccepta.ble conditions were identifie .3 Fire Brigade Training 3.3.1 Procedure Review

 .The inspector reviewed the following licensee procedures:
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Procedure 101.2, Fire Protection Organization Responsi-bilities and Controls,-Revision * Oyster Creek Fire Protection Program Manual

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Procedure 1780.0, Fire Brigade Training, September 22, 1983

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Safety Evaluation Report by NRR, November 13, 1979 and its Supplements 1, 2, and The scope of' review was to verify that the licensee had developed administrative procedures which included: Requirements for announced and unannounced drills; Requirements for fire brigade training and retraining at prescribed _ frequencies; c.- Requirements for local fire department coordination and training; and Requirements for maintenance of training record No unacceptable conditions were identifie .3.2 Records Review The inspector reviewed randomly selected training records of randomly selected fire brigade members for calendar years 1984 and 1985 to ascertain that they had successfully completed the required quarterly training / meetings, annual fire brigade drills, and triennial hands-on fire extinguishment practic No unacceptable conditions were identifie ^5g ] y

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3 * 1 Annual Audit The inspector reviewed-the reports of the following annual audits:

 * S-0C-84-19 performed ~on September 7-15, 1984 l
 * S-0C-85-09, performed on June 14-July 19, 1985
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 - The' scope of review was to verify that the audits were performed in accordance with-TS 6.5.3.2.a. and the audit findings were being resolved in a timely and satisfactory manne ;

No unacceptable conditions were identifie ' 3.4.2 Biennial Audit The inspector reviewed the report of the following audits:

 * S-0C-83-08, performed on October. 19-28, 1983

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 * S-0C-85-09, performed on June 14-July 19, 1985 The scope of review was to verify that the audits were performed in accordance with TS 6.5.3.1.f. and the audit findings were being resolved in a timely.and satisfactory manne No unacceptable conditions were identifie .4.3 Triennial Audit-Prior to January 1984, the licensee was not required to perform a triennial audit of their fire protection and loss prevention program by an outside qualified fire consultant. F ' ' ::e n se amendment 69 dated January'12, 1984, Technical Spe, .:ati on 6.5.3.2.b, the licensee is required to perform suci audit at intervals no greater than 3 years. The licensee's st such audit is scheduled to be conducted during the fall o. 198 No unacceptable conditions were identifie .5 Facility Tour The inspector examined fire protection water systems, including fire water piping and distribution systems, post indicator valves, hy-drants and contents of hose houses. The inspector toured accessible

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vital and nonvital plant areas and examined fire detection and alarm

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systems, automatic 'and manual fixed suppression systems, interior hose stations, fire barrier penetration seals, and fire doors. The

 ' inspector observed general plant housekeeping conditions and randomly checked tags of portable extinguishers for evidence of periodic in-spections. No deterioration of equipment was note No unacceptable conditions were identifie .0 1 Unresolved Items Unresolved items are matters about which more~information is required to ascertain whether they are acceptable items, violations or deviation An unresolved item disclosed during the inspection is discussed in Section 2. .0 Exit Interview
,The inspector met with licensee management representatives (see Section 1.0 for attendees) at the conclusion of the inspection on September 27, 1985. -The inspector summarized the scope and findings of the inspection at that tim The inspector and the licensee discussed the contents of this inspection report to ascertain that it did not contain any proprietary informatio The licensee agreed that the inspection report may be placed in the Public Document Room without prior. licensee review for proprietary infor-mation.(10 CFR 2.790).

At no time during this inspection was written material provided to the licensee by the inspecto >ZM rh*- a

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ATTACHMENT 2 UNIT SUBSTATIONS 1A1, 1A2, 1A3, 181, 182, and 182 AND CONNECTED LOADS

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FSAR UPDATE TABLE 8.3-1 (Sheet 1 of 1)

         .

EMERGENCY BUSES AUTOMATIC LOADING SCHEDULE LOOP + LOCA + LOOP * LOOP + LOCA* Single Failure Time

    '

Delay Bus IC Bus ID Bus IC Bus ID Bus 1C or ID Loads (hp)

     (sec) (hp)  (hp) (hp) <(hp)
         - -
        -

Isolation valves (load not included 0 - - since it is too brief to add to peak h load) 5 Lighting, Instrumumtation and Controls, 0 45 440 45 440 45 (440) 9-R Ventilation, Security, Battery Chargers,  % miscellaneous small motors and trans- former losses, 40 - - 300 300 300 Containsent Spray Pump 45 - - 400 400 400 Emergency Service Water Pump l 60 250 250 250 250 250 Control Rod Drive Feed Pump 0** - - 500 500 1000 Core Spray Pump 5 - - 300 300 600 Core Spray Booster Pump

          -

Service Water Pump 120 250 250 - -

         ~
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Reactor Building Closed Water Pump 166 200 200 - - U j' * LOOP - Loss of Offsite Power, LOCA-Loss-of-Coolant Accident

** Immediately, however injection will begin when Reactor Coolant System pressure drops below the cperational range of the syste ..s

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ATTACMMENT 5 TRANSF0kMER INSTRUMENTATION

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ATTACHMENT 6 SKETCH OF TRANSFORMER SHOWING THE NOMINAL OIL LEVEL

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ATTACHMENT 7 SKETCH OF FIN TUBES SHOWING FLOW

.

BEFORE AND DURING LOAD TEST ON 1A2 BEFORE AFTER

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. ._   - _ - - _  _ _ _ -  _ _ _ - _  _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ - _  _

I * ' ATTACHMENT 8 ] THERM 0 GRAM 5 OF 182 SHOUING OIL FLOW BEFORE, DURING s i

,      AND AFTER FILLING        1

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h[  !;! Figure 3. Thermegram (During) Figure 4. Thermogram (After) ' i i Explanatory Note: Figure 1 is a normal photograph of south side cooling fins l l of 182. Figures 2, 's, and 4 are thermograms of the same before, during, and after fillin Dark area in Figure 2 indicates lack of flow in the left side tubes. Figure 3 shows partial establishment of flow in these tubes during fillin Figure 4 shows the flow fully established.

.._ - . - _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ .   ..- -. . _ _ _ . _ _ _   - . _ - - - . .. ]~   ATTACHMENT 9 y   REFERENCES
~ Licensee Event Report (LER) 85-009, 480 Volt USS Overload, June 14, 198 . LER 85-014, Unit Substation Trar.sformers IA2 and 182 Low 011 Level, September 11, 198 . Oyster Creek FSAR Section 8.3, Onsite Power Systems, Revision 0, E December 1984 General Electric Instruction GEI-650748, Secondary Unit Substation Transformer . Oyster Creek Technical Specifications, Section 3.7, Auxiliary Electrical Power Oyster Creek Load Study (Draft). Standing Order 37, Overload of USS 1A2 and USS 182 during INCA without Loss of Offsite Power, Revision 0, June 21,198 ' Preventive Maintenance Check Sheet (PM No. 1316), Record Temperatures and Lnad on Transformers IA1, IA2, IA3, IB1, 182, and 18 . Thermographic Survey Photographs taken on June 21, 1985 by Asplundh Infrared Service . Licensee Internal Memorandum dated June 11, 1985, from M. Filippone, Plant Engineering to R. Chisholm, Manager-Electrical Power and Instru-mentation, Subject: 460V Unit Substation 1A2 and 182 Transformers Cooling Fin . - Licensee Internal Memorandum dated August 9, 1985 from R. Chisholm, Manager-Electrical Power and Instrume.ntation and D. Ranft, Electrical Power Manager to W. Smith, Plant Engineering Directo . ' General Electric Report dated August 8,1985 on their Thermographic Survey of Transformers 1A2 and 182 conducted on August 7, 198 . General Electric Report dated August 28, 1985 on the Inspection of Transformers IA2 and 18 . GPU letter to GE dated September 4,1985, A. Dickinson to E. Hritzo requesting information on the transformers related to the event described in LER 85-01 . GPU letter to GE dated September 19, 1985, A. Dickinson to E. Hritzo, requesting additional information on the transformers related to the event described in LER 85-10 . ' Plant Engineering Department Incident Critique dated August 20, 198 . S.D. Myers, J. J. Kelly and R. H. Parrish, A Guide to Transformer Main-

. tenance, Published by. Transformer Maintenance Institut . Job Order No. 82-0097 dated December 6, 1982 for taking 500 milli-liter of oil from Transformer IA1, IA2, 1A3, 181, 182, and IB . Resident Inspector's Inspection Report 50-219/85-23, Section 11, 480 Volt Unit. Substation Transformer Low 011 Leve ' o }}