IR 05000286/1987001

Insp Rept 50-286/87-01 on 870106-0217.Major Areas Inspected: Plant Operations Including Shift Logs & Records,Reactor Trips/Engineered Safeguards Actuation,Surveillance,Maint & Followup to Generic Ltr 83-28 & TMI Action Items

ML20207S553
Person / Time
Site:	Indian Point
Issue date:	03/05/1987
From:	Linville J, Meyer G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20207S550	List: IR 05000286/1987001 ML20207S549
References
RTR-NUREG-CR-4565, TASK-1.A.1.3, TASK-2.K.3.05, TASK-2.K.3.12, TASK-TM 50-286-87-01, 50-286-87-1, GL-83-28, IEIN-86-106, NUDOCS 8703200028
Download: ML20207S553 (21)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No: 50-286/87-01 Docket N Licensee: Power Authority of the State of New York 10 Columbus Circle New York, New York 10019 Facility: Indian Point Nuclear Generating Station, Unit 3 Location: Buchanan, New York Dates: January 6,1987 to February 17, 1987 Inspectors: P. S. Koltay, Senior Resident Inspector R. S. Barkley, Resident Inspector J. C. Linville, Section Chief F. P. Paulitz, Reactor Engineer G. S. Barber, Reactor Engineer (Examiner)

Reviewed by:

pnnMeyer,Reactogngineer date Approved by: btdue-tr ,a -?

/3ames C. Lidv1Tle, Chief // ' /date'

LR'eactor Projects Sectifr( 2C, DRP Inspection Summary:

Inspection on January 6,1987 to February 17, 1987 (Inspection Report 50-286/87-01)

Areas Inspected: Routine onsite regular and backshift inspection of plant operations including shift logs and records; licensee actions on previously identified inspection findings; facility operations; reactor trips / engineered safeguards actuation; No. 31 component cooling water heat exchanger leak repairs; plant tours; system walkdowns, six of which used the guidance provided in NUREG-4565, "Probabilistic Safety Study Application Program for Inspection of the Indian Point Unit 3 Nuclear Power Plant"; surveillance; maintenance; followup to Generic Letter 83-28; TMI action items followup; emergency diesel generators service water cooling followup; steam, feed and condensate system surveys review; cold weather preparation; and followup of an allegation. The inspection involved 276 hours0.00319 days <br />0.0767 hours <br />4.563492e-4 weeks <br />1.05018e-4 months <br /> by the resident and region based inspector [2hD G

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Results: Each of the two reactor trips during this period were followed by unexpected equipment responses. Corrective actions were completed by the licensee and verified by the inspectors after each reactor trip, prior to returning the unit to power operatio Improvements were noted in the post-trip review process. Corrective actions initiated following violation 86-21-01 were reviewe _ . . . _ _ _= _ _ _. _

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. DETAILS

' Persons-Contacted

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. Within this report _ period, discussions were conducte'd with members of the licensee management and staff to obtain the necessary information pertinent to the subjects being inspecte . Licensee Actions on Previously Identified Inspection Findings

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(0 pen) Violation (286/86-21-01) The subject report addresses the licensee's failure to meet the requirements of the Technical Specifica-tions, Section.3.3.A.I.d and 3.3.B.1.6, during plant startup from cold

shutdown condition. The inspector verified that the licensee initiated the following immediate corrective actions, which were completed prior to

returning the unit.to power operation Pre-warmup check-off list COL-RPC-1 was reissued and safety related system lineups were reverified in the field and in the control roo Senior reactor operators'/ shift supervisors' leadership functions were reiterated to all shift crew The immediate corrective actions provided assurance that the requirements

of the Technical Specifications and applicable procedures were met prior

} to returning to power operations.

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The licensee also committed to develop long term corrective actions _that will prevent recurrence of the subject violation. The inspector verified that the following long term corrective actions have been completed:

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The pre-warmup check-off list has been reissued and split into two

distinct procedures: <

COL-RFC-1A, Pre 200 F. Check Off List dated, November 5,1986 4 COL-RPC-1B, Pre 350 F. Check Off List dated, November 5,1986

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The procedures must be completed by the-senior reactor operater and the shift supervisor on watch at the time cold shutdown is to be exceeded. Section 9 of procedure 1A and section 6 of procedure IB requires the review of the Startup Prerequisite List, PFM-49.

The shift supervisors must verify that all equipment required to be operable by procedures COL-RPC 1A and IB meet the requirements of the Technical Specifications for operability and surveillance

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Plant Operating Procedures (P0P) have been revised in a manner that clearly identifies the operability requirements of the recirculation pumps, containment spray pumps and high head safety injection pump The control room shift and relief turnover checklist has been expanded. The new list requires that the oncoming senior reactor operators and shift supervisors review each control panel with their offgoing counterparts. The turnover list incorporates appropriate detail to allow operators to identify and discuss status changes of essential equipmen The resident inspectors verified that detailed shift turnovers are conducted in a professional manner by all shift personnel. The inspectors continue to observe and evaluate the effectiveness of the licensee's long term corrective action By letter dated February 18, 1987, the NRC granted the licensee's request for an extension until March 11, 1987 to respond to the Notice of Violatio . Facility Operations During this period, the unit operated at 100% power through January 3 On January 31, the reactor tripped from full power due to low steam generator level. The trip was followed by a temporary loss of one of the two motor-driven auxiliary feed pumps. (See Section 4.1 of this report.)

Power operation was resumed on February 2, and the unit returned to and operated at 100% power through February 1 On February 11, No. 34 instrument bus output breaker opened on overload, eventually resulting in an unexpected reactor trip and safety injection signal. The licensee later determined that there is a high probability for reactor trip and safety injection signals to be generated upon the loss of the No. 34 instrument bus. Applicable off-normal procedures failed to address this scenario. (See Section 4.2 of this report.)

Full power operations resumed on February 1 On January 28, the licensee identified a 3/8 inch diameter hole in the component cooling water heat exchange Temporary relief from the ASME code was granted to allow the licensee to continue operations with a temporary heat exchanger repai . Reactor Trips / Engineered Safeguards Actuation Two reactor trips from 100% power, occurred during the inspection perio A spurious safety injection signal was generated following the second reactor trip. No actual safety injection took place since the reactor coolant system pressure did not decrease below discharge pressure of the safety injection pumps. No major equipment was out of service and no unusual activities were underway prior to the reactor trips. Both trips were caused by equipment failures. After each event, the reactor was

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stabilized in the hot shutdown condition. The Safety Parameter Display System (SPDS) provided detailed sequence of events, records and historical data on all critical plant parameter Licensee activities following the reactor trip on January 31, 1986, were observed and verified by the resident inspectors. Licensee activites following the reactor trip on February 11, 1986 were observed by the resident inspectors and two region based specialists. NRC activities on site were coordinated by the project section chie .1 Reactor Trip on January 31, 1987 4. Summary of Events On January 31, at 2:05 p.m., the reactor tripped from 100%

power due to low level in No. 33 steam generator. Steam generator levels were lost when one of the two turbine driven main boiler feed pumps unexpectedly tripped result-ing in reduced feedwater flow. Operators were unable to reduce unit load rapidly enough to match the reduced feed flow. Initially all systems operated as designed, and the unit was stabilized in the hot shutdown condition. Approx-imately eleven minutes after the reactor trip, one of the two motor-driven auxiliary feed pumps, No. 33 pump, tripped on an overcurrent condition. The operator reset and restarted the auxiliary feed pump from the control roo No additional problems were experienced with the auxiliary feed syste The licensee determined that small particles of foreign materials in the No. 32 Main Boiler Feed Pump (MBFP) con-trol oil system blocked orifices in the multiple orifice assembl Loss of control oil pressure tripped the MBF . Auxiliary Boiler Feed Pump (ABFP) No. 33 Trip Immediately following the reactor trip, in accordance with Emergency Operating Procedure E-0.1, " Reactor Trip Response," Step 36, the reactor operator verified that both electric motor driven ABFP started and a minimum flow of 415 gpm to the steam generators had been establishe Approximately 11 minutes following the reactor trip, No. 33 motor driven ABFP tripped. The reactor operator was able to immediately reset and restart the pump. Both ABFPs continued to operate throughout the event. At that time, the operator also throttled the discharge valves of the ABFPs to cut back on feed flow to the steam generator in order to preclude overfeedin .

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The discharge valves of the motor driven ABFP receive a full open signal upon a reactor trip; however, a redundant control circuit protects the pumps against a " runout" con-dition by overriding the valve open signal if' discharge pressure drops below 1200 psig. Thus the controller will maintain 1200 psig discharge pressure with a minimum flow of 415 gpm from each pum The licensee's investigation determined that the subject controller for No. 33 ABFP was improperly set, allowing the pump discharge pressure to drop to approximately 1140 psig, resulting in a " runout" conditio The licensee calculated that during this " runout" condition, the motor current reached 637 amps, which is well above the 609 amp setting of the overcurrent protection circuitry of -

the motor circuit breaker. The licensee determined that at 637 amps, the breaker long time delay overcurrent protection system would actuate about 9-1/2 minutes after such a con-dition was established. The computer generated sequence of events report and historical data log report retrieved through the licensee's Safety Parameter Display System (SPDS). support the licensee's calculation The. inspectors reviewed applicable surveillance and pre-ventive maintenance tests on the auxiliary feedwater pumps and their associated controller Preventive Maintenance Procedure, Instrument Package No. IC-PM-P-406B, includes the inspection and calibration of all the instrumentation related to the ABFP discharge pressure controllers. Pro-cedure completion is on a two year cycle, adjusted for the nearest refueling outage. The last completion date was November 1984. The next completion date is scheduled for the 1987 refueling outage. The inspectors noted that while the operability of each component is verified and the output signals were calibrated, the actual setting of the pressure controllers, which determine the discharge pres-sure of the pumps, was not set or verifie The inspectors also reviewed surveillance test 3PT-R7, Revision 6, "ABFP - Full Flow Test." This test is con-ducted at refueling intervals, with the last test dated April 1986. The list established minimum flow require-ments; however, discharge pressures were not verifie The inspectors noted that existing surveillance tests fail to verify ABFP discharge pressures and, therefore, do not functionally test the discharge pressure controllers. This issue was discussed with the licensee. The licensee committed to revise surveillance test 3PT-R7 to include the functional testing of the pressure controller. The inspec-tors will verify the implementation of the proposed change .

. 7 4. Corrective Actions Prior to returning the power operations, the licensee completed the following corrective actions:

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MBFP control oil system was inspected, cleaned and teste ABFP pressure controllers were adjusted to maintain 1200 psig discharge pressure at a minimum flow of 415 gpm for each ABF Test No. ENG-244, Revision 0, was developed to verify ABFP performance. Through the completion of the pump test, the licensee also determined that No. 31 ABFP motor drew 449 volts and 560 amperes of current and No. 33 ABFP motor drev 460 volts and 580 amperes of current at the set pressure and flo Inspected and verified the settings of the overcurrent devices associated with the ABFP breaker No violations were identifie .2 Reactor Trip and Inadvertent Safety Injection System Actuation on Feoruary 11, 1987 4. Summary of Events On February 11, 1987 at 8:28 a.m., a reactor trip occurred on a steam flow / feed flow mismatch signal coincident with low water level on the No. 34 steam generator. Almost simultaneously, a safety injection system actuation occurred due to a high steam flow signal coincident with low steam line pressure. All safety systems responded as expected. No water was injected into the reactor coolant system (RCS) since the RCS pressure remained above 2000 psi. The plant was stabilized in hot shutdown. A detailed sequence of events outlining what occurred prior to and following the reactor trip is outlined in paragraph 4. The cause of the reactor trip and the inadvertent safety injection system actuation was the trip of the output breaker of the No. 34 static inverter. That inverter feeds the No. 34, 118 volt AC Instrument Bus which supplies power to a number of instruments with inputs to the Reactor Protection System (RPS) and the Safety Injection Actuation Syste The loss of No. 34 Instrument Bus resulted in the following events of significance:

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. 8 1) The loss of 33 Power Range Nuclear Instrumentation Channel causing a dropped control rod turbine runbac ) The loss of power to the Main Boiler Feed Pump speed changers which caused both main feed pumps to runback to minimum spee ) The trip of two low steam generator pressure bistables (for 32 and 33 steam generators) required for the

"High Steam Flow with Low Steam Generator Pressure" Safety Injection actuation signa As a result of the runback of the main boiler feed pumps, feed flow to the steam generators rapidly dropped of Since steam flow remained relatively constant, a reactor trip on steam flow / feed flow mismatch coincident with low steam generator level ensued. The reactor trip caused an immediate turbine trip. Turbine impulse pressure rapidly dropped off as a result. Since the high steam flow safety injection signal setpoint is a function of turbine impulse pressure, the setpoint also rapidly dropped off. However, because steam flow did not drop off as rapidly and twa steam generator low pressure bistables were already tripped, the logic for the high steam flow coincident with low steam generator pressure SI was made u (The SI initiating condition reset four-tenths of a second later as steam flow dropped below the high steam flow set point; however, the SI signal was already sealed in.) This SI signal also initiated closure of the Main Steam Isolation Valves (MSIVs).

All safety systems responded as designed. The rapid closure of the MSIVs caused a pressure spike in the steam generators. The pressure spike on steam generator No. 22 was sufficient to cause one of the steam generator coda safety valves to lif It failed to properly reseat when the pressure was relieved. No excessive cooling of the RCS

! occurred due to the stuck open safety valve. The licensee later determined that the valve stuck partially open because

a cotter pin which retains a collar on the valve stem brok This allowed the collar to vibrate down the valve ste When the valve attempted to reseat, this collar hung up on the manual operating arm of the valve, preventing its full closure. The licensee later returned the collar to its normal position, allowing the valve to properly reseat.

I When the SI signal was generated, all nonessential loads on l

the 480 volt safety-related busses were shed, including the nonessential service water pumps. Since these pumps supply seal water to the circulating water pumps, all six pumps tripped shortly thereafter. Several minutes later, the

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vacuum breakers for the condenser were opened per normal operating procedure. The vacuum breakers allowed cool air to enter the condenser. Because there was no circulating water flow to cool the condenser, the air was heated by the large amount of hot metal in the condenser and rapidly expanded. This pressure buildup was relieved by the rupture of 11 of the 12 rupture disks on the low pressure turbine hoods. Thus, the condenser was unavailable after the trip. RCS heat removal continued via the atmospheric relief valve Approximately six minutes after the reactor trip /SI, an Instrumentation and Control-(I&C) supervisor noted the output voltage of the No. 33 inverter oscillating. The static inverter was tripped and subsequently reset. When the No. 33 static inverter was tripped, power was momen-tarily removed from the reactor first out alarm panel, clearing all the alarms on that panel. In addition, this resulted in a momentary loss of voltage to a second instrument bus, resulting in a second SI actuation signal, this time on high containment pressure. However, since the first SI signal was still sealed in, no changes in equipment status took place. When the No. 33 inverter was reenergized, the initial alarms and first out annun-clators cleared while new alarms annunciated (i.e.,

Containment High Pressure SI). The output voltage of the inverter then remained constant. Subsequent testing of the inverter revealed a number of component problem Work Request (WR) 6682 was later issued which replaced the affected components. The unit was satisfactorily retested and returned to servic The operators performed all the required actions of Emer-gency Operating Procedure E-0, " Reactor Trip or SI,"

following the reactor trip and concluded that the safety injection actuation was inadvertent and that all safety systems had responded as expecte They then reset the SI signal, Subsequent to the reactor trip /SI actuation, plant person-nel in various locations reported seeing " flashes of light"

, or " electrical disturbances." A contractor employee in the

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Primary Auxiliary Building (PAB) reported receiving an electrical shock to the elbow during one of these flashe He was sent to a nearby hospital, examined and release No evidence of an electric shock was noted. The licensee later conducted an investigation into the source of these

" flashes."

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. 10 The investigation revealed that due to the stripping of the 480 volt safety-related busses when the SI signal was received, lighting in the plant was deenergized. As per design, the lighting cannot be restored until the SI signal is reset. During the reactor trip /SI recovery, and prior to resetting the SI signal, a Nuclear Plant Operator (NPO)

twice attempted to restore plant lighting by closing a lighting breaker in the PAB. A subsequent test by the licensee revealed that when an attempt is made to close that lighting breaker before the SI signal is reset, the breaker will close and then reopen almost instantaneousl However, during that brief time interval when the breaker is closed, the fluorescent lights flash brilliantly, giving the appearance of an electrical discharge in the air. This effect was reproduced on the day following the reactor trip. The licensee believes this characteristic of the lighting was the cause of the electrical flashe Examina-tion of numerous pieces of electrical equipment and cable trays in the PAB failed to produce any evidence of elec-trical short-circuiting, etc., which could otherwise be the cause of such an electrical phenomeno . Sequence of Events Initial Plant Conditions

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Unit operating at steady state full power (970 MWe)

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Reactor Coolant System (RCS) average temperature is 566 RCS pressure is 2235 psig

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No inajor equipment out of service Time Description of Event 8:28:08 #34 Inverter, which supplies 118 Volt AC Instrument Bus #34 tripped. A turbine runback occurred on the loss of power range channel II :28:45 The operator defeated the turbine runback (approximate time) per ONOP-EL- :28:54 Reactor trip on steam generator D steam flow / feed flow mismatch coincident with low steam generator leve . . , . .

. 11 8:28:54.5 Safety Injection actuation on high steam flow coincident with low steam line pressure. All safety systems responded as expected. No RCS injection occurred as pressure remained above 2000 psi. The MSIVs closed on this SI signal. (Also, nonessential service water pumps, which supply water to the bearings of the six circulating water pumps were stripped from the bus'at this time. All six circulating water pumps tripped momentarily thereafter.)

8:28:54.9 The high steam flow signal returned to normal. However, the SI signal was already sealed in at this tim :34 An I&C supervisor observed the output voltage on #33 inverter oscillating. The inverter was tripped and subsequently reset. The output voltage returned to normal. This created a second SI signal on high containment pressure.

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8:35 The SI signals were rese :50 NRC Operations Center notified.

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4. Review of Problems with Instrument Bus No. 34 The licensee conducted an investigation into the cause of the No. 34 inverter output breaker trip. The cause of the trip was determined to be an overcurrent condition which occurred when a solenoid operated valve, S0V-1197, shorted to ground. The ground was such that it caused the inverter output breaker to exceed its 90 ampere rating. This inverter output breaker has an electronic overcurrent device that trips the breaker immediately upon exceeding 90 amperes. However, the distribution circuit breaker feeding S0V-1197, which has a setpoint well below 90 amperes, is a thermal overload device that requires a finite time period to trip on overcurrent. Thus the inverter output breaker opened before the distribution breaker, shedding not only the short circuited S0V-1197, but also Instrument Bus N .

The licensee, in consultation with the inverter manufac-turer, Westinghouse, later concluded that the electronic overcurrent device was not needed. Jumper No. 861 was later installed to defeat the device. Thus, on a similar electric fault in the future, the distribution breaker

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should open before the inverter output breaker, preventing s

the loss of Instrument Bus 3 The licensee reviewed the loading and arrangement of instrumentation on Instrument Bus No. 34 as well.as the other instrument busses. The review revealed that with the present arrangement of instrumentation on the bus, it is almost certain that both a reactor trip and a SI actuation will occur if Instrument Bus No. 34 is lost again. The inspectors noted that the Off Normal Operating Procedure (0NOP) EL-3, " Loss of an Instrument Bus," tailed to specify the actions that would occur when Instrument Bus No. 34 was lost including the likelihood of a reactor trip and a SI actuation. The inspectors also noted that the licensee's response to IE Bulletin 79-27, " Loss of Non-Class-1E Instrumentation and Control Power System Bus During Operation," failed to denote this arrangepent of instru-mentation on Instrument Bus No. 34. The re-review of their response to Bulletin 79-27 was identified by the licensee as a long-term corrective action. This item is unresolved pending completion of this revie (50-286/87-01-01)

4.2.4 Operator Response to the Reactor Trip and SI Actuation The inspectors interviewed the Senior Reactor Operator (SRO) present during the event to determine if the proce-dures in use mitigated the event. The SR0 stated that the Reactor Operators rapidly diagnosed the loss of the instru-ment bus, and they proceeded to then implement ONOP-EL- However, the reactor tripped before the procedure could be completed. Once the reactor tripped, the SRO implemented E-0, " Reactor Trip /SI." The SR0 proceeded through E-0, performing the actions as required. When the procedure was completed and he determined that the SI was not needed, the SRO implemented ES-1.1, "SI Termination."

The inspectors concluded that the Emergency Operating Procedures (EOPs) were adequately implemented by the oper-ators and that they helped the operators cope with the reactor trip, SI actuation and the subsequent complication The SR0 on shift also expressed satisfaction with the way the E0Ps helped them cope with the event.

! The resident inspector was in the control room at the time of the trip and witnessed the operators' response to the event. The inspector observed the operators properly and promptly perform the actions dictated by the E0Ps. He l noted that they readily placed the plant in a safe con-dition in spite of the number of complications discussed i in section 4.2.1 above and alarm annunciations which l ensued.

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-13 4. Corrective Actions The inspectors met with the licensee on Thursday, February 12, to discuss the cause of the reactor trip /SI actuation and the corrective actions planned to prevent a similar occurrenc During the meeting, the licensee committed to implement the following short term corrective actions:

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Replace S0V-1197 coil and three other SOV coils in the Weld Channel and Containment Penetration Pressurization System (WCCPPS).

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Defeat the electronic overcurrent trip function of the No. 34 inverter output breaker as' suggested by the manufacture Provide additional information to the operator in ONOP-EL-3 with regard to the consequences of losing either Instrument Bus No. 33 or No. 3 The inspectors verified that these actions were completed prior to reactor startup on Friday, February 1 In the long term, the licensee is reviewing the following proposed corrective actions:

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Installing a different type of speed controller on the main boiler feed pumps which fails in the "as-is" positio Eliminate the need for the SOVs by redesigning the syste Supplying the two steam generator pressure instruments which are powered from Instrument Bus No. 34 from different power supplie Review their response to IE Bulletin 79-27 and update it as necessar The licensee presented the results of their post trip review to Regional management during a conference call on February 12. Regional management had previously discussed the events surrounding this reactor trip /SI during a con-ference call with the licensee on February 11. No safety concerns were raised by regional management following the licensee's discussion of their post trip review finding No violations were identifie .- -__ . .-

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5. No. 31 Component Cooling Water Heat Exchanger Leak Repairs On January 28, 1987 at 5:30 a.m., a small leak was identified on the outlet water box of component cooling water heat exchanger No. 31. The outlet water box contains service water which flows through the tube side of the heat exchanger and cools the component cooling water system. The leak was a 3/8 inch diameter hole in the wall of the outlet water bo Following identification of the leak, the licensee isolated the heat exchanger and entered a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> Limiting Condition for Operation per Technical Specification 3.3.E.2.C. The licensee performed an engineering evaluation of the leak and determined that the heat exchanger was capable of performing its design function even with the hole in the water bo Furthermore, a permanent repair of the hole per the ASME Boiler and Pressure Vessel Code was determined to be too lengthy to complete in the time constraints of Technical Specification 3.3.E.2.C and would require a plant shutdown. Therefore, the licensee chose to install a temporary seal to terminate the leakage. A permanent Code acceptable repair is planned for the next refueling outage scheduled in May 198 Nuclear Safety Evaluation (NSE) 87-03-012 AC, Rev. O was performed, per the requirements of 10 CFR 50.59, which justified continued plant operation with the No. 31 component cooling water heat exchanger in this condition. A mechanical sealing device was then installed on the heat exchanger, per MWR 9779, to isolate the leak. The heat exchanger was returned to service on January 28, 1987 at 8:00 On January 29, 1987, a conference call was conducted between NRR, Region I and the licensee concerning the leak and subsequent temporary repair to the heat exchanger. Discussions with the licensee revealed that the provisions of Section XI of the ASME Code were applicable to this repai Since the licensee's temporary repair to the heat exchanger is not an acceptable repair per the Code, the licensee was required to request relief from the Code from NRR for this repair per the provisions of 10 CFR 50.55a(a)(3). At that time, the licensee had not made such a relief request and was unaware of the requirement. In addition, concerns were raised by Region I that the full extent of the corrosion / erosion of the heat exchanger water box did not appear to be known by the license The licensee subsequently conducted an ultrasonic (UT) examination of 30 separate locations of the outlet water box. No wall thinning below the required minimum wall thickness was noted. Most of the UT data indicated that the wall thickness of the water box was nearly that of the original manufactured thickness. These findings confirmed that the corrosion /

erosion of the water box was localized. The licensee believes that the hole in the water box was caused by a local discontinuity of the internal corrosion resistant linin Based on the UT results and the NSE previously conducted on the adequacy of the mechanical sealing' device, the licensee claimed that the requirements of ASME Code Section XI for this repair represented an undue

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. 15 hardship without a compensating increase in quality and safety. Thus, they submitted a request for relief from the Code to NRR, per the provisions of 10 CFR 50.55a (a)(3), on January 30, 1987. The relief request was approved on February 5, 1987, contingent on the provision that the licensee completes a Code acceptable repair during their next scheduled refueling outag The inspectors reviewed the data from the licensee's ultrasonic examinations of the heat exchanger water box. They also inspected the completed installation of the mechanical sealing device on the heat exchanger. No leakage from the seal was note With respect to the above issue, no violations were identified. The inspectors will review completion of permanent repairs to the heat exchanger during the next refueling outag . Plant Tours The inspectors conducted routine entries into the Control Building, Turbine Building, Primary Auxiliary Building, Fuel Storage Building and the Intake Structur The inspectors observed Central Control Room activities, including shift turnovers, log entries and responses to alarm annunciators, as well as maintenance and surveillance activities in progress. Particular note was taken of the presence of quality control inspectors, quality control evidence and housekeeping. The inspectors interviewed operators, technicians, mechanics, supervisors and plant management. The purpose of the inspection was to affirm the licensee's commitments to and compliance with 10CFR, Technical Specifications and licensee administrative procedure No violations were identifie . System Walkdowns 7.1 Using the licensee's approved checkoff lists, the inspectors per-formed walkdowns of the following systems:

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Control Room Ventilation System per the applicable portions of COL-V-1, Rev. 2

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Fire Protection System per the applicable portions of COL-FP-1, Rev. 5 7.2 Probabilistic Risk Analysis Based Inspections In addition, using the Probabilistic Risk Analysis (PRA) inspection guidance provided by NUREG-4565, "Probabilistic Safety Study Appli-cations Program for Inspection of the Indian Point Unit 3 Nuclear

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c Power Plant," the' fospectors performed modified waIdowns outlined in the NUREG for the following systems: ,

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Accumulator System 3

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7.3 Findings ,j, No violations were identihs s

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8. Surveillance g i i

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.tance criteria tests of to ~ determine Technical Specifications:yhy.har the results met\the accep\

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3PT-M2S, R4 . 8,' Central Control Room Vjn akibaTest

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3PT-AS, Rev. 2[lntake Structure Electrical Heat Trace Test '

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3PT-M37A, Rev.~ 3' Fire Syst;m Check, Technical Speciffcation

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3PT-M4, Rev. '6', Pressurize?f tevel'An31og Channel Functional , l Test \ k '

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3PT-M42 3 Rev. 6, Fire Pumps Functional Test

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PASS-RE-CS-042, Rev. 7, Sampling Reactor Coolant During Accident Conditions

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8.2 Findings:

The results of RE-CS-042, an annual test of the Post Accident Sampling System are contpared to routine reactor coolant Nstem samples. Acceptarice c-1 ceria require that the results df the post accident sampling \nuiti,te within 20% of the result 4 of,the routine [( 4 samples. The licessea identified a 32% error in thy hydrogen -

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l samples and a 25% error da the total gas activity. The licensee is V investigating the cause of the discrepancies. The ,tfi ,t will be repeated following appropr'qte corrective action. -

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. Maintenance

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The insx ctors observed or reviewed the following maintenance activities,

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Approved procedures, adequate to control the activity, were being used by qualified technicians

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\- Evidence of QC involvement in the activity I

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Proper radiological controls were implemented (where needed)

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/, - -i Oyerali internal condition of disassembled equipment, paying (~' 3 particular attention for signs of excessive wear and/or corrosion

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Adequate post-maintenance testing was conducte MWR-9/31 - Ultrasonic Examination of Component Cooling Water (CCW) Heat

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Exchanger No. 31 bi , , MWR-9779 - Repairs to Seal a Leak on CCW Heat Exchanger No. 31

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As described in paragraph 5 of this report, the outlet water box (service

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water side) of the component cooling water heat exchanger developed a 3/8 inch * diameter hole in its wall. The licensee conducted an ultrasonic

< examination of the outlet water box and determined that erosion / corrosion S

of the wall was limited to that hole. The licensee used a mechanical

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.\ sealO3 device, consisting of an elastomer patch backed up by a metal l  ? platehnd held _in place by two nylon straps, to seal off the leak. The

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instecte.rs examined the installed seal on several occasions during the report priod. They also reviewed the ultrasonic examination results on

' s the water box. No problems were identified.

'y sw 10, Followta to Generic Letter 83-28 (ATWS) per T.I. 2515/64

The inspectors reviewed NRC Safety Evaluation Report (SER) for Indian l Point Unit 3 regarding Generic Letter 83-28, Item 4.5.1. The NRC staff

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determined,that the licensee's response meets the guidelines of the Generic Le'.te Theh nspector verifiec that the licensee performs surveillance tests of l the undervoltage trip assembly (UVTA) and the shunt trip attachment of the, reactor trip breakers. On a monthly basis, in accordance with j surveillance procedures 3PT-13A and B, Reactor Protection Logic Channel l I,

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Functional Test, on-line fuactional testing of the reactor trip breaker (r operation is. '/erified. On refueling outage intervals, in accordance with I 'W - 3PT-R91, tbo licensee verified reactor trip breaker and bypass breaker

• response tiae, independently for UVTA and shunt trip, using the steam

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tested by manually tripping the reactor trip breakers. This is accomplished in accordance with Plant Operations Procedure, P0P-1.2,

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By Safety Evaluation Report (SER) dated- February 2,1987, the NRC ste,ff found the licensee's design to permit oq1fne functional testing of the t reactor trip system acceptable. Thus, the licensee also meets the '

requirements.of, Item 4.5.1 of Generic Letter 83-2 ' J-y '

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No violations were Identified.-

m j 11. TMI Action Items Fo710wup x .

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"The inspectors verified that the-licensee incorporated the necessary changes to applicable documents in order to meet the-requirements of the

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following TMI items:

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A ItemI. Ail.3-MinimumShiftCrewComdosition. Technical Specification "

@ amendment'No.138,. dated October 7, 1981, Section 6, Table 6.1-2,

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[ incorporates the required minimum shift crew requirements. Routine inspections of control room manning indicate that the minimum shift crew

,, requirements have been met.

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-Iteri II.K.3.5 - Automatic Trip of Reactor Coolant Pumps. The TMI Action Plan, required that' the licensee develop reactor coolant pump tripping

criteria under transient and loss of coolant accident conditions. Addi-tional guidelinessand criteria'were provided by the NRC to the licensee in various documents including SECY-82-475 and Generic' Letter 83-10.' ' ;

The NRCJstaff completed the-review of the licensee's submittals. In a-

-Safety Evaluation, dated November 29, 1986, the NRC staff accepted the

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, licensee's treatment of the reactor coolant pump trip criteria. The inspectors verified that the operator actions based on the selectedisub-

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cooling margins used for normal and adverse containment conditions have

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, been incorporated into the applicable emergency operating procedure L Licensed operators received classroom and simulator training in this

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Item II.K.3.12 - Anticipatory Reactor Trip Upon Turbine Trip. This action item required the confirmation of the existence of an anticipatory >veactor trip upon turbine trip. The anticipatory reactor trip upon turbine trip prevents unnecessary challenges to the power operated relief valves by reducing the reactor coolant pressure transients following a reactor tri The inspectors verified that such an anticipatory reactor trip upon tur-bine trip at or above 10% of full power is part of the Unit 3 Reactor Protection System. Amendment No. 68 to Facility Operating License No.

!. DPR-64, issued on October 6, 1986, incorporates appropriate changes to the

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Technical Specifications regarding this trip function including limiting operating conditions and minimum frequencies for checks, calibrations and tests of the instrument channel No unacceptable conditions were identifie . Emergency Diesel Generators (EDG) Service Water Cooling The inspector followed up on a concern identified by the Indian Point Unit 2 licensee regarding restricted service water flow from the EDG jacket water and lubricating oil coolers. The source of the restriction was thought to be a failed disk on one of two redundant discharge flow control valves installed on parallel service water line Loss of flow through both of the normally open valves would render all EDGs inoperable. Subsequently, the Indian Point Unit 2 licensee determined that both valves were in the open position, while the original concern was attributed to inadequate flow data and erroneous interpretation of inservice inspection results generated by radiograph The Indian Point Unit 3 EDG service water cooling design is similar to Unit 2 with one notable exception. The redundant flow control valves

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designated as FCV 1176 and FCV 1176A, on the parallel discharge lines, are normally maintained in the closed position. Pneumatic valve position controllers are designed to open the valves upon an EDG start signa Upon loss of their power supply, the valves fail to the open positio The inspector reviewed the following applicable surveillance procedures:

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3PT-V16, Rev. 9, Diesel Generator Functional Test The above test requires the monthly starting and loading of the EDGs. Acceptance criteria require thst specified jacket water temperatures (150 F. - 180 F.) and lubricating oil temperatures (160 F - 185 F.) must be met. Failure to meet the specified temperature ranges requires corrective actio PT-Q16, Rev. 3, Inservice Inspection Test, Service Water Valves FCV 1176 and 1176 The above quarterly operational readiness test of the flow control valves requires that the valves cycle open and closed in 60 seconds or les In conclusion, the subject system and its associated valves and components meet the requirements of the applicable criteri No violations were identifie ,

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13. Steam, Feed and Condensate System Surveys In accordance with NRC Temporary Instruction Procedure TI-87-02, the inspectors reviewed the licensee's activities in response to Information Notice 86-106, Feedwater Line Break. Based on a review of the events detailed in the subject Information Notice, the licensee developed an inspection program to determine the integrity of the main feedwater system piping upstream of the main boiler feed pumps. Currently there are no plans to repeat the progra Ultrasonic Testing (UT), using a USL 38 KRAUTKRAMER instrument with 1/2 inch by 1/2 inch 5mHz transducers at 0 degrees, was conducted at pre-selected locations. The locations of the readings were identified for future testing. The readings were taken while the plant was at 100 percent power. Fluid temperature in the tested pipe was 360 The acceptance criteria was calculated based on nominal pipe wall thickness. All but two readings exceeded the criteria. The two readings were within 95 percent of the nominal values. Calculated minimum acceptable wall thickness was exceeded in all case No violations were identifie . Cold Weather Preparation 14.1 Documents Reviewed:

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FSAR

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Technical Specifications

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3PT-A5, Rev. 2, Intake Structure Electrical Heat Trace Test 14.2 Findings:

The inspectors reviewed the above documents and discussed cold weather preparation with the operations, performance, and instru-mentation and control supervisors. They determined that the licensee is implementing protective measures for cold weather protectio The inspectors verified freeze protection for sections of the service water system, the refueling water storage tank, fire protection tanks, and the condensate storage tan The licensee's " rover" log sheet includes daily verification and recording of water temperature of the fire protection water storage

, tank. The inspectors noted that while a formalized cold weather preparation program is not in place, the licensee routinely maintains freeze protection equipment in good working order.

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The inspectors noted that there was an extended period of sub-freezing temperatures during this report period. No problems with freezing of safety-related equipment were noted during that perio No violations were identifie . Inspector Followup of an Allegation Concerning Work Conducted on the Boric Acid Evaporators On February 3, 1987 at 9:55 p.m. an anonymous call was received by the resident inspector's office. The male caller made the following statement: " Boric acid evaporators 31 and 32'are being cut out without Operation's clearance. This violates AP 10.1." The caller then hung u The' inspectors reviewed the modification procedure MOD 86-03-122 CVCS, governing the scope of the work on the boric acid evaporators. The modification consists of the removal of the No. 31 and No. 32 Boric Acid Evaporators, the Concentrates Holding Tank equipment, and associated piping, valves and electrical connections. This system is not an engineered safety feature and has not been used in five years. The Operations Department, in accordance with Administrative Procedures (AP-9 and AP-10), issued appropriate Operating Orders (503767; 505760; 503772; 503774), work permits and clearances for the removal of the subject equipment. The inspectors verified that STOP TAGS were properly place The equipment cutout locations were clearly identified on drawings and in the field. The job is being accomplished under Work Request (MWR 9530)

using appropriate work step lists and Quality Control hold point Radiation Exposure Authorization 3023 was issued to cover the activit Continuous Health Physics coverage is provided. The job appears to be well planned and carefully executed within the requirements of licensee procedure In conclusion, the inspectors could not substantiate the allegatio No violations were identifie . Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection scope and findings. An exit interview was held on February 24, 1987 to discuss this report period. During the discussion, the licensee did not identify any 10 CFR 2.790 materia . __ _ _ _ _ _ . - - . . - _ _ _ . _ _ - . _ ._.. _ _ . _ _ _ _ _ __-__ _ ._