IR 05000454/1988009

Safety Insp Repts 50-454/88-09 & 50-455/88-09 on 880517- 0630.Violations Noted.Major Areas Inspected:Licensee Action on Previous Insp Findings,Lers,Bulletins,Generic Ltrs, Operations Summary,Training & Spent Fuel Storage Racks

ML20151E767
Person / Time
Site:	Byron
Issue date:	07/11/1988
From:	Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20151E736	List: IR 05000454/1988009 ML20151E732 ML20151E754
References
50-454-88-09, 50-454-88-9, 50-455-88-09, 50-455-88-9, IEB-88-003, IEB-88-3, NUDOCS 8807260200
Download: ML20151E767 (15)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Report Nos. 50-454/88009(DRP);50-455/88009(DRP)

' Docket Nos. 50-454; 50-455 License Hos. NPF-37; NPF-66 Licensee: Connonwealth Edison Con.pany Post Office Box 767=

Chicago, IL 60690 Facility Name: Byron . Station, Units 1 and 2

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Inspection At: Byron Station, Byron, Illinois

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Inspection Conducted: May 17 -' June 30, 1988 Inspectors: P. G. Brochman N. V. Gilles J. M. Ulie

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Approved By . Hinds, Jr. Chi f OT ll. Bb l actor Projects Sec. ion 1A Date Inspection Sunr.ary Inspection from May 17 - June 30, 1988 (Report Nos. 50-454/88009(DRP);

50-455/88009(DRP))

Areat. Inspected: Routine, unannounced safety inspection by the resident inspectors and a region-based inspector of licensee action en previous inspection findings; Iicensee event reports; bulletins; generic letters; operations summary; training; spent fuel storage racks; surveillance; maintenance; operational safety; and event followu Results: Of the 10 areas inspected, no violations or deviations were identified in 9 areas; 2 violations were identified in the remaining area (failure to establish and implement adequate procedures for the Fire Protection Program - paragraph 3.a; failure to maintain en auxiliary feed.<ater pump operable during. operational mode changes - paragraph 3.b).

However, in accordance with 10 CFR 2, Appendix C, Section V.G.1, a Notice of Violation was not issued for the second violatio gDR ADOCKOSOOk]I"

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DETAILS, Persons Contacted Conmonwealth Edison Company

• R. Pleniewicz, Station Manager T. Joyce, Production Superintendent R. Ward, Services Superintendent

• W. Burkamper, Quality Assurance Superintendent

• T. Tulon, Assistant Superintendent. Operating

• G. Schwartz, Assistant Superintendtat, Maintenance

• L. Sues, Assistant Superintendent, Technical Services

• D. St. Clair, Assistant Superintendent, Work Planning T. Higgins, 0perating Engineer, Unit 0 J. Schrock, Operating Engineer, Unit 1 D. Brindle, Operating Engineer, Unit 2 T. Didier, Operating Engineer, Rad-Waste M. Snow, Regulatory Assurance Supervisor

• Flahive, Technical Staff Supervisor S. Barrett, Radiation / Chemistry Supervisor P. O'fteil, Quality Control Supervisor S. Wilson, Station Chemist W. Bielasco, Station Health Physicist

• W. Pirnat, Regulatory Assurance Staff E. Zittle, Regulatory Assurance Staff

• G. Stauffer, Regulatory Assurance Staff X. Sullivan, Technical Staff W. Walter, Assistant Technical Staff Supervisor

"F. Hornbeak, fluclear Safety

• D. Freeman, Regulatory Assurance Staff The inspector also contacted and interviewed other licensee and centractor personnel during the course of this inspectio * Denotes those present during the exit interview on June 30, 198 . Action on Previous Inspection Findings (92701)

(0 pen) Unresolved Item (454/88006-01(DRP); 455/88006-01(DRP)):

Appropriateness of using Whitman General, J-505 pressure switches in environmentally qualified applications. On March 27, 1988, a problem was identified with the qualification of Whitman General, J-505

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pressure switches. These switches are used on several safety-related components in an environmentally qualified application. The licensee !

declared some of these components inoperable and followed the appropriate !

Technical Specification Action Requirements, and prepared a Justification !

for Continued Operation (JLO) for those switches left in servic Subsequently, the licensee has developed infonnation which it believes demonstrates that the J-505 pressure switches always were environmentally !

qualified. This information was provided to the NRC staff for revie i This item will remain open pending the flRC's review of this information. '

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3. Licensee Event Report (LER) Foll_cwup (92700)

(Closed) LERs (454/87011-1L; 454/88002-LL; 455/87019-1L; 455/88004-LL; 455/88005-LL;455/88006-LL;455/88007-LL): Through direct observation, discussions with licensee personnel, and review of records, the following LERs were reviewed to detemine that the reportability requirements were fulfilled, that immediate corrective action was accomplished, and that corrective action to prevent recurrence had been accomplished in accordance with Technical Specification LER N Title Unit 1 454/87011-1 Carbon dioxide system inoperable due to mispositioned valv /88002 Reactor trip due to rod drop during manual control rod motio Unit 2 455/87019-1 Reactor trip from Hi-Hi steam generator level and subsequent loss of offsite powe /88004 Main feedwater pump trip due to improper isolation of electrohydraulic control fluid supply resulting in reactor tri /88005 Operational mode changes made while auxiliary feedwater pump was inoperable due to level switch failur /88006 Reactor trip due to control rod drop caused by intermittent component failure in the rod drive syste /88007 Two Feecwater isolations on Hi-Hi steam generator level due to a feedwater valve failing to open The events described in LER 454/88002 were diicussed c in Inspection Report No. 454/88007. The events described in LER 455/87019-01 . ~e discussed in Inspection Report No. 455/87038. The supplemental aport was issued to provide additional infomation on the failure of the feedwater regulating valve and to document completion of corrective actions. The events described in LER 455/88004 were discussed in Inspection Report No. 455/88007. The events described in LERs 455/88006 and 455/88007 are discussed further in Paragraph 1 With regard to LER 454/87011, this LER describes an event in which the carbon dioxide (C07 ) fire suppression system for the station was inoperable due to a mispositioned valve. On April 15, 1587,atapproximately(1:30pm,duringtheperformanceofthe 18-month surveillance 1BHS 7.10.3.2.B.1-3) on the CO,3 fire suppression system for the diesel-driven auxiliary febdwater (AFW)

pump room, the licensee discovered that the low pressure CO system

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was inoperable. During the actuation test no CO, flowed from the spray nozzles in the AFW pump room. The lichnsee initiated a nuclear. work request to troubleshoot and repair the CO, system for the AFW pump room. In addition, the Limiting ConditTon For Operation Action Requirement for an inoperable AFW C0 system

was entere On April 16, 1987, at approximately 5:00 pm, while troubleshooting the AFW ump room C0 system problem, the system engineer (non-licensed and maintebance personnel discoWred a CO, storage tank vapor pilot valve to be in the closed position. Upbn discovery, the valve was immediately opened. This valve provides C09 (as a motive force) through the electro-manual pilot cabinets to open the pilot-operated master selector valves. The C0 2 tank is located within a locked cage in the turbine building, and the vapor pilot valve is located inside the tank's cowling, which is also locked. The master selector valves pressurize the various plant CO, headers. With the vapor pilot valve closed, the motive force to o erate all three master selector valves was removed. Consequently, the C0 7 fire suppression system would not have been capable of performing its design function, should a fire have occurred in any of the approximately 30 rooms that the system protect There are approximately of fire suppression, 22 rocms of which that use CO,0 approximately 1 rooms containas the primary mea redundant shutdown equipmen Due to construction activities in progress in the 8 upper cable spreading rooms, the primary automatic Halon fire suppression systems were also out of service for personnel safety. However, continuous and/or hourly fire watch patrols were in place between April 4 and April 16, 1987. The inspector reviewed the fire watch patrol sheets to verify this practice. However, the inspector noted that these compensatory actions were prinerily as a result of other degraded fire protection features and were not knowingly put in place by the licensee in response to an inoperable C0 2 system. On April 20, 1987, Surveill-ance Procedure IBHS 7.10.3.2.B.1-3 was successfully reperforn.ed, demonstrating the operability of the AFW pump room C0 system and

the master selector valve During a review of this event, the licensee determined that on April 4,1987, the vapor pilot valve had been demonstrated te ' e open when an inadvertent CO, actuation occurred in the Unit 2 cable tunnel area. After this ina8vertent actuation, during the tank refilling operation, a switching valve line adjacent to the vapor pilot valve was found to be leaking. This leaking valve was in close p mximity to the vapor pilot valve. The licensee believes that the vapor pilot valve was inadvertently closed to isolate this leak.'

From the time of the CO, tank recharging on April 4, until the AFW pump room CO, surveillahce failed, no documented work was performed in the locke8 C09 supply tank cage. The licensee believes this explanation to bB the most probable reason for the mispostNning of l the vapor pilot valve, and based on inspector review, this explanation is considered to be plausibl .

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The inspector detennined that prior to this event, the licensee' , procedures had failed to specifically require surveilling the proper

position of the 00 system tanks' vapor pilot valves. Technical Specification 6.8.7I.h requires that written procedures be established, implemented, and maintained for activities involving the Fire Protection Progra ~

The failure to include the vapor pilot valves'in appropriate procedures as described in the Notice of Violation is considered a violation of Technical Specification 6.8.1.h (454/88009-01(DRS);

455/88009-01(DRS)). The procedural inadequacies were a result of the design drawings not showing the two CO, System vapor pilot valves. In addition, these deficiene.ies are attributable in part to the vapor pilot valves being a pa:t of the C0p tank skids, and not a part of the engineering specification The licensee's corrective actions for this event included the following:

• Other fire protection skid-mounted components were immediately reviewed to determine if any other valves were overlooked. The only other valve found was the identical vapor pilot-valve on tank. The licensee innediately the riverthis cher.ked screen valvehouse and foun CO, d it to be open as required.On January 19, 1988, the inspector visited the river screen house and also verified that the installed C02 tank vapor pilot valve was locked in the open position

Both vapor pilot valves were given unique identification numbers and locked in the open position. The valves were added to the station's "Locked Valve Surveillance." On January 19, 1988, the inspector confirmed that the CO tank vapor pilot valve located in the turbine building was 2 )

locked open. As mentioned previously, the river screen hou m l C0 tank vapor pilot valve was also verified to be in the i lo$kedopenposition. In addition, the inspector was l provided the monthly C0 2 system valve position Surveillance Procedure OBOS 7.10.3.1-1, Revision 2, approved on July 20, 4 1987, which now includes both C0 tanks' vapor pilot valves '

identifiedas"MasterVaporPilokValves"numberedOC05002 and OC0500 *

Drawing change requests have been submitted to add these valves to the design drawings. On January 19, 1988, the ,

inspector confinned that drawing nos. M-58, Revision AD, i dated June 2, 1987, and M-58, Revision J, dated June 2, 1987, now include each of the required vapor pilot valve *

The System Valve Lineup Procedures have been updated to include the vapor pilot valves. On January 19, 1988, the inspector verified that System Valve Li eup Procedures B0P C0-M1, Revision 5, approved en July 17, 1987, and 80P C0-H2, Revision 3, approved on August 13, 1987, include these vapor pilot valve . .

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The inspector considers the licensee's corrective actions to t'e adequate, and this item is therefore considered close '

As a result of C09system problems identified during this event, the inspector is concerned about the design reviews which were performed on other fire protection systems, and whether procedures for operation of fire protection systems are adequate. Therefore, the licensee is requested to take the necessary additional steps-to ensure that appropriate design reviews have been perfonned to determine if any other procedural revisions for other fire protection systems are necessary, so as to assure the operability of fire protect 1 .: systems. This is considered in open item

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(454/88009-02(DRS); 455/88009-02(DRS)) pending NRC review of licensee actions to ensure that appropriate design reviews have been performed, b. With regard to LER 455/88005, this LER describes an event in which operational mode changes were made at 11:55 pm on May 6, 1988, and at 1:11 am on May 7, while the 28 diesel-driven AFW pump was inoperable due to its fuel oil day tank level .being below the Technical Specification limit. The root cause of this event was the failure of the 28 AFW pump fuel oil day tank low level switch to actuate a main control room annunciator. A contributing cause to the length of time the condition existed was the fact that two non-licensed Equipment Attendants (EAs), who had noted th out-of-tolerance condition during their rounds and had circled the out-of-tolerance value on their round sheets, did not recognize the significance of the low level condition and did not notify senior control room personne The reason the EAs did not recognize the importance of the low level condition was a placard affixed to the day tank that specified that the Mvel be maintained greater than 50%, leading the EAs to excuse tne out-of-tolerance condition

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as indicated by their round sheets. At 10:20 am on May 8, a third EA reviewed the logs from the previous shift and noted the out-of-tolerance condition which had been recorded on the previous shift and informed the Reactor Operator (RO). The R0 directed the EA to imediately fill the day tank to a level greater than the Technical Specification limi l Technical Specification 3.7.1.2 requires that one direct-driven diesel auxiliary feedwater pump be operable and capable of being powered from a direct-drive diesel engine and an operable Diesel Fuel Supply System consisting of a day tank containing a minimum of 420 gallons of fuel. This specification is applicable in l Modes 1, 2, and 3. With one auxiliary feedwater pump inoperable, '

the Technical Soecification Action Requirement allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore the pump to an operable status. The licensee did not l exceed the 72-hour time limit; however, Technical Specification l 3.0.4 prohibits entry into an operational mode unless the conditions i for the Limiting Condition for Operation are met without reliance cn provisions contained in the Action Requirements, i

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The changing of operational modes while relying on provisions contained in the action requirements of Technical Specification 3.7.1.2 is a violation of Technical Specification 3. (455/88009-03(DRP)). However, this violation meets the tests of 10 CFR 2, Appendix C, Section V.G.1; consequently, noJotice of Violation will be issued, and this matter is considered close Becluse the operational mode changes were made before the EA's daily check of the AFW pump fuel oil day tank level, the violation would have occurred even if the EA had recognized the level _was below the Technical Specification limit. However, eight separate reviews of the rounds sheets were performed by six dif ferent licensed individuals (three R0s and three Senior Reactor Operators

[SR0s]); all of the individuals failed to recognize the out-of-tolerance condition, which was circled in red and clearly indicated that the day tank level was below the Technical Specification limit, and signed off cn the round sheets for their shifts. The inspectors are seriously concerned about this breakdown in management oversight and review of the status of safety-related systems by licensed individual The licensee's corrective actions included replacement of the day tank low level switch and a calibration check of the local level meter. A new operating procedure (80P AF-1) will be implemented to require verification of adequate diesel-driven AFW pump day tank level, along with other parameters important to AFW pump' operabilit Procedures which require the operation of the diesel-driven AFW pump will be revised to require the performance of BOP AF-1. The placard affixed to the day tank has been revised to clarify the level requirements. Finally, the "Equipment Daily Logs Adminis-trative Procedure," (BAP 350-5) is being revised to require that all (errphasis original) out-of-tolerance readings be brought to the attention of the operating shif t superviso One violation was identifie . NRCComplianceBulletinFollowup(92701) (Closed) Bulletin (454/88001-3B;455/88001-88): Defects in ,

Westinghouse Circuit Breakers. The NRC staff has reviewed the '

licensee's response to this bulletin and concluded that it is !

acceptable, in accordance with a letter from L. N. 01shan to H. Bliss, dated April 22, 1988. Based on this review, this bulletin is considered c1cse (Closed) Bulletin (454/88003-BB;455/88003-BB): Inadequate Latch !

Engagement in HFA Type Latching Relays Manufactured by General l

- Electric (GE) Company. The inspector has reviewed the licensee's '

response to Bulletin 88-03. The licensee has completed its review pursuant to the request outlined in Bulletin 88-03 for Byro Byron Station does not utilize HFA type latching relays i

that are ' subject to the bulletin, and no further actions are l required. Based on this review, this bulletin is considered close !

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No violations or deviations were identifie . Generic Letters (GLs) (92701) (0 pen) GL (454/88003-HH; 455/88003-HH): Potential for disabling auxiliary feedwater pumps due to steam binding. The licensee has submitted a response for this GL, which is being reviewed by the NRR staff. This GL will remain open pending the completion of the staff's revie (0 pen)GL(454/88005-HH;455/88005-HH): Boric acid corrosion of carbon steel reactor coolant system pressure boundary component The licensee has submitted a response for this GL, which is being reviewed by the NPR staff. This GL will remain open pending the ccepletion of the staff's revie No violations or deviations were identifie . Sumary of Operations Unit 1 operated at power levels up to 98% until 12:16 am on May 28, 1988, when the unit was shut down to repair a tube leak in the 1A steam generator (see paragraph 12.a). The unit was restarted at 4:01 am on June 11, 1988, and was synchronized to the grid et 7:30 am on the same day. The unit operated at power levels up to 98% for the rest of the report perio Unit 2 operated at power levels up to 94% until 6:40 am on June 2,1988, when the unit tripped on a high negative neutron flux rate (See paragraph 12.b). The unit was restarted at 12:44 pm on June 3 and was synchronized to the grid at 8:41 am on June 4. The unit operated at power levels up to 95% until 4:54 pm on June 23, when the turbine was taken off the lire due to secondary chemistry problems (see paragraph 12.c). The unit was synchronized to the grid at 1:48 pm on June 24 and operated at power levels up '.o 95% for the rest of the report perio . Training (41400 & 41701)

The effectiveness of training programs for licensed and non-licensed personnel was reviewed by the inspectors during witnessing of the licensee's performance of routine surveillance, maintenance, and operational activities and during review of the licensee's response to events which occurred during May and June 1988. Personnel appeared to ba knowledgeable of the tasks being performed, and nothing was observed which indicated ineffective trainin No violations or deviations were identifie . Spent Fuel Storage Racks (50095)

The licensee has submitted a rcquest to anend the operating licenses for Units 1 and 2 to increase the storage capacity of the spent fuel

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pit (SFP). This is to be accomplished by replacing the existing fuel storage racks with high density racks, which hold a larger number of sper.t fuel assentlies per given volume. The NRC staff has been reviewing the licensee's request and has requested additional information on reracking the SFP. In anticipation of the NRC's approval of the .

amendment, the licensee had previously removed most of the old spent fuel racks from the SFP before they had become contaminated. The SFP presently contains the discharged portion of the Unit 1. Cycle 1, reactor core. However, there is an inadequate amount of storage space to store the discharged reactor cores from the upcoming Unit 1 and 2 refuelings. Consequently, the licensee has reinstalled three of the old spent fuel racks. The licensee has received most of the new (higher density) spent fuel racks; however, they cannot be installed until the license amendment is issue The inspector reviewed the licensee's procedures for reinstalling the old spent fuel racks. The inspector verified that requirements for lifting heavy loads over the SFP were rnet and that mechanical stops and limit switches were in place on the SFP building bridge cran The inspector verified that the installation procedures specified the torquing requirements for the spent fuel rack hold down bolt The inspector observed installation of one of the old fuel racks and the activities of the diver in the SFP. The inspector observed the health physics and radiation protection activities related to sending a diver into the SF The inspector met with the licensee's staff to review the progress of the SFP activities. The licensee believes that activities perfonned in the fuel handling building to support the two upcoming refueling outages would interfere with the removal of the old fuel racks and installation of the new fuel racks. Consequently, the licensee does not plan on installing any new fuel racks before spring 1989, should

, the license amendment be issue No violations or deviations were identifie . Monthly Surveillance Observation (61726)

Station surveillance activities of the safety-related systems and components listed below were observed or reviewed to ascertain that they were conducted in accordance with approved procedures and in confonnance with Technical Specification ,

1A auxiliary feedwater pump monthly test 18 diesel generator monthly test Unit 2 incore flux map monthly surveillance Deep well purps OA and OB surveillance test The following items were censidered during this review: the limiting conditions for operation were met while affected components or systems were removed from and restored to service; approvals were obtairied prior

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to initiating the testing; testing was accomplished in accordance with

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approved procedures; test instrumentation was within its calibration interval; testing was accomplished by qualified personnel; test results-confortred with Technical Specifications and procedural requirements and were reviewed by personnel other than the individual directing the test; and any deficiencies identified during the testing were properly documented, reviewed, and resolved by appropriate management personne No violations or deviations were identifie . Monthly Maintenance Observation (62703)

Station maintenance activities of the safety-related systems and components listed below were observed or reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance with Technical Specification Eddy current examination of the 1A,1B, and 1C steam generator u-tubes The following items were considered during this review: the limiting conditions for operetion were met while components or systems were removed from and restored to service; approvals were obtained prior to initiating the work; activities were accomplished using approved 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; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemented. Work requests were reviewed to determine the status of outstanding jobs and to asture that priority is assigned to safety-related equipment maintenance which may affect j system performanc No violations or deviations were identifie . Operational Safety Verification (71707, 71709, & 71881)

l The inspectors observed control reoni operation, reviewed applicable !

logs and conducted discussions with control room operators during May l and June 1988. During these discussions and observations, the inspectors '

ascertained that the operators were alert, cognizant of plant corditions, and attentive to changes in those conditions, and that they took prompt action when appropriate. The inspectors verified the operability of i selected emergency systems, reviewed tagout records, and verified the ;

proper return to service of affected components. Tours of the auxiliary, !

fuel-handling, rad-waste, and turbine buildines were conducted to observe l plant equipment conditions, including potential fire hazards, fluid leaks, !

and excessive vibrations, and to verify that maintenance requests had '

i been initiated for equipment in need of maintenanc ;

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The inspectors verified by observation and direct interviews that the physical security plan is being implemented in accordance with the station security pla The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. The inspectors also witnessed portions of the radioactive waste system controls associated with rad-waste shipments and barrelin ,

The observed facility operations were verified to be in accordance with the requirements established under Technical Speci#ications, 10 CFR, and administrative procedure No violations or deviations were i t ntifie . Onsite Follow-up of Events at Operating Reactors (93702)'

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The inspectors performed onsite follow-up activities for events which occurred during May and June 1988. These follow-ups included reviews of operating logs, procedures, Deviation Reports, Licensee. Event Reports-(where available), and interviews with licensee personnel. For each event, the inspector developed a chronology, reviewed the functioning of safety systems required by plant conditions, and reviewed licensee actions to verify consistency with procedures, license conditions, and the nature of the event. Additionally, the inspector verified that

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l the licensee's investigation had identified the root causes of equipment malfunctions,and/or personnel errors and that the licensee had taken appropriate corrective actions prior to restarting the unit. Details ,

of the events and the licensee's corrective actions developed through L inspector follow-up are provided in paragraphs a throu0h c below: Unit 1 - Steam Generator (SG) 1A U-tube Leak At 12:16 e.m. on May 28, 1988, the unit was taken off line to repair !

a u-tube leak in the 1A SG. The leakage rate was naasured at 125 gallons per day (gpd). The Technical Specification limit for u-tube

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i leakage is 500 gpd. Unit I was previously shut down on March,11 -)

1988, due to a u-tube leak in the ID S '

q The licensee performed eddy current testing on all row 1 u-tubes and on all u-tubes which had indications of cracks from the previous refueling outage eddy current tests in the 1A, 1B, and 10 steam I generators. The leaking tube was located at row 1, column 2 of .

the 1A SG. The leak was located at the apex of the tube, identical '

' to the location of the leak in the ID SG. No other'through-wall l leaks were identified. However, other indications were identified, and the licensee plugged an additional 24 tubes in the 1A SG and 1 ;

tube in the IC S '

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The unit was returned to sitryice at 7:30 cm on Jure 11, 1988. The, licensee has used approximately 16% of the available tube plugging limit per the current safety analysis. The licensee is evaluatin \

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. whether to perfonn stress relieving on the row 1 tubes fer all four Unit 1 SGs or to plug the tubes now. The inspectors will

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review the licensee's course of actio b. -Unit 2 - Unit Taken Off Line Due To Secondary Chemistry Excursicn At 10:45 am on June 23, 1988, the licensee entered Byron Abnormal:

Operating Procedure (BOA) SEC-2, "Steam Generator High Conductivity,"

when steam generator blowdown samples indicated a cation conduct-ivity of approximately 340 micromhos per centimeter and a sulfate ,

concentration of approximately 2000 ppb. The excursion was caused by a leaking acid valve in the condensate makeup demineralizer system which allowed acid to leak into the makeup system for approximately 10 minutes, until the leak was discovered and isolated. Makeup water was being added to the main condenser at the time, allowing a path for the. acid to enter the condensate

'and feedwater syste The leaking valve had not closed completely following the acid portion of the demineralizer regeneration process due to the wire valve tag getting caught up in the valv B0A SEC-2 identifies action levels associated with steam generator '

chemistr The criterion for entering Action Level 3 (highest level) for cation conductivity is greater than 7 micrombos per centimeter. The criterion for entering Action Level 2 for sulfates is greater than 100 ppb (there is no Action Level' 3 for sulfate concentration). At 10:56 am, the licensee begarta controlled power reduction in accordance with 80A SEC-2, which requires that the unit be taken to hot standby (Mode 3) within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of entering Action f.evel 3 on any chemistry parameter. The licensee reduced power to approximately 10%, reduced Tave to its no-load value, and at 4:54 pm, tripped the main turbine to satisfy the intent of 80A'

SEC-2, while romair.ing in Mode 1. While this action was not in accordance with the licensee's precedures, remaining in Mode 1 allowed faster cleanup of ' secondary chemistry du,e to increased steam generator blowdown rates. Station management made the decision to remain in Mode 1 after discussions with the corporate chemist and corporate' management. The licensee is in the process

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of' revising BOA SEC-2 to allow operation in Mode 1 with the unit off line and Tave at nr below its no-load value when in, Action Level 3 on steam generator secondary chemistr ,

The licensee exited Action Level 2 on cation conductivity at '

7:00 a.m. on June 24, and exited Action Level 2 on' sulf ates at 10:20 a.m. the same day. This allowed the licensee to increase Tave and to bring turbine power to 25%. At 1:48 p.m. on June 24, the unit was synchronized to the grid, end turbine power was increased to 25%. At 2:40 a.m. on June 25, the licensee exited all action levels for steam generator chemistry and began ramping '

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The licensee believes that no short term effects on steam generator integrity will be seen from the chemistry excursio This is based on the expeditious cleanup of the secondary coolant, the corresponding small amount of time that the contaminants remained in the steam generators, and on the metallurgical and design characteristics of the D-3 steam generators installed in Unit 2. This steam generator design is not expected to be as susceptible to the effects of "denting," whfch is one of the major concerns with contaminants entering the steam generators. Denting i-occurs when the gap between a tube and support plate increases during cold plant conditions due to differential expansio >

Corrosion products deposit in the hole in the support plate. When the unit is heated, tae differential expansion closes the ga Since the hole is new smaller due to the corrosion products, the tube can actually be dented, and its integrity threatened. To minimize this effect, the D-5 model of steam generators are designed with machined "quatrefoil" openings in the support plate. These openings combine the tube support holes and the steam flow hole Only a small, portion of the opening between tube and plate is close i to the tube. Also, since there is more flow around the tube, there is less probability of corrosion prcducts being deposited. This model of steam generator is also less susceptible to corrosion darage because of the use of stainless steel support plates, versus the carbon steel suppcrt plates used in older model SG The itcensee is planning a 24-hour hold point at 350 degrees F during the shutdown 'for the upccming Unit 2 refueling outage (January 1989). The purpose of the hold point is to allow any '

sulfates which may be "hiding out" in crevices in the steam generators to come out, which is-most likely to happen at this temperature. The licensee is also planning a hideout study in

, July 1988, in which a small, known quantity of sulfates will be

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injected into the steam generators to determine how long it takes for all of the sulfates to be removed. The licensee and the industry hope to gain a better understanding of how sulfates behave I in the environment fcund in steam generators from these types ,

of studies. Based on its observations, the licensee does not l believe that this incident will have any serious effect on the '

l integrity of the steem generator Unit 2 - Reactor Tripj ae to Dronpd Control Rods and Feedwater Isolations During Scattt [ j At 6:40 a.m. on June 2,1988, with reactor pcwer at 94%, a reactor i trip occurred on high negative flux rate on the power range nuclear  ;

instruments. The negative flux' rate trip was caused by control >

l rods dropping into the reactor core. . All systems functioned normally following the trip, except thatt the R0 manually reerergized  ;

the source range instruments when one of the intermediate range  !

channels-appeared to be undercompensated. He thought the under-compensation would delay automatic reenergization. However, the

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reenergization.

. 4 Innediately following the rea:: tor trip, the rod drive (RD) power .

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cabinet fuses were inspected for blown fuse indications.. The' .

l' licensee determined that rods dropped from the-1AC rod drive -

f power cabinet',- initiating the event, and that thme stationary

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gripper phase fuses were blown dur,ing the event. Other stationary t/ ripper phase- fuses receinedmintact and were capable of maintaining all control rods in their withdrawn position .Therefore, the three blown fuses alone could not have caused multiple dropped rods. The rod drive motor generator (MG) sets'

protective relays were checked for targets indicating trouble, and none were found. The RD bus duct was checked for shorts, but n shorts were found. The-rest of the stationary phase fuses were checked, and the licensee discovered 23 stationary phase fuses to

'be either cracked or electrically unacceptable;.therefore, all stationary phase fuses in all power cabinets were replaced. The ,

fuses leading out to tto control. rod drive mechanism (CRDM) coils  !

were resistance checked and the fuse clips tightened. Fourteen '

fusas were found to be cutside the acceptence criteria, but none had '

degraded enough to have caused rods to drop. .All 14 fuses were  ;

replaced. The cables to~ the stationary coils on the reactor head -

pacLage from RD power cabinet 1AC were checked for short circuits, ,

and none were found. At 3:07 a.m. on June 3, the RD system was >

energized and ireset, but an urgent failure alann remained actuated en RD power cabinet 1CDE. .After troubleshooting and swapping out the associated firing circuit card and the signal processing circuit - >

card, the urgent alarm vas cleared and detennined to be due to a-loose card edge connector on the-stationary gripper firing circuit card. A cracked solder connection on 'a capacitor'was fixed and the card edge connectors tightened. Troubleshooting effortt failed to determine a root cause for the dropped rods, r

The licensee exercised the control rods to ver'fy proper operation, j and Unit 2 was taken critical at,12:44 pm on June 3, 1988. At j 1:27 p.m. a feedester isolation and turbine trip occurred form ,

approximately 2% power while operators were controlling the feed- l water system in manual during.the startup. The isolation occurred 1

,/ on a Hi-Hi level in the 2D steam generator. The isolation was  !

caused by a rapid swell in steam generator levels which ' occurred l when the operator'could not open the prchester bypass .valvefor the  ;

2C steam generator. Levels W. t% 1A, 1B, tnd ID steam generators i increased while the IC steam generator. led ' decreased. lne .

preheater bypass valve was opened by a~n op"rator locally, but the ID steam generator level reached'the HieHi level setpoint, causing

' the autonatic feedwater isolation and turbine > trip. During the recovery from this .feedwater ti'ansient, another feedwater isolation'

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signal , occurred due to Hi-Hi level"in the 1A stecm generator. Livels '.

were restored, the feedwater isolation signal was uset, and the .)

plant'startup was continued. The' unit was synchronizeo to the grid l l

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at 8:41 a.m. on June 4, after the licensee identified a problem with one of the generator output breakers which was causir.g the turbine governor valves to cycle, and subsequent level and pressure oscillations in the steam generators. The licensee synchronized the unit using the other generator output breaker and initiated repairs to the faulty cutput breake No violations or deviations were identifie . Open Items Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRL or licensee or both. An open item disclosed during the inspection is discussed in paragraph . Violations for which a "Notice of Violation" Will Not Be Issued The NRC uses the Notice of Violation as a standard rethod for formalizing the existence of a violation of a legally binding requirement. However, because the NRC wants to encourage and support a licensee's initiatives for self-identification and correction of problems, the NRC will not generally issue a Notice of Viciation for a violation that meets the tests of 10 CFR 2, Appendix C, Section V. These tests are: (1)

the violation was identified by the licensee; (2) the violation would be categorized as Severity Level IV or V; (3) the violation was reported to the NRC, if required; (4) the violation will be corrected, includf measures to prevent recurrence, within a reasonable tire period; and (5) it was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation. A violation of regulatory requirements identified during the inspection for which a Notice of Violaticn will not be issued is discussed in paragraph . Exit Interview (30703)

The inspectors met with the licensee representatives denoted in paragraph 1 at the conclusion of the inspection on June 30, 1988. A telephone exit was held with licensee representatives on June 21, 1988, ;

to discuss the inspector's findings on LER 454/67011 (see paragraph ;

3.a). The inspectors sunrr.arized the purpose and scope of the inspection and the findings. The inspectors also discussed the likely informational content of the inspection report, with regard to documents or processes revicwed by the inspectors during the inspection. The licensee did not identify any such documents or processes a: proprietar l l

15