IR 05000295/1988016

Insp Repts 50-295/88-16 & 50-304/88-16 on 880720-0823.No Violations Noted.Major Areas Inspected:Operational Safety Verification & Engineered Safety Feature Sys Walkdown, Surveillance Observation & Maint Observation

ML20154D924
Person / Time
Site:	Zion  File:ZionSolutions icon.png
Issue date:	09/09/1988
From:	Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20154D914	List: IR 05000295/1988016 ML20154D908
References
50-295-88-16, 50-304-88-16, IEB-80-18, IEB-86-003, IEB-86-3, IEB-87-001, IEB-87-1, NUDOCS 8809160169
Download: ML20154D924 (14)

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i U.S. NUCLEAR REGULATORY COMMISSION

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REGION III t

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s 4 Reports No. 50-295/88016(ORP); 50-304/88016(ORP)  !

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Decket Nos. 50-295; 50-304 Licenses No. OPR-39; OPR-48  ;

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L'censee

Commonwealth Edison Company i

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P. O. Box 767 l l Chicago, IL 60690 i i

Facility Name: Zion Nuclear Power Station, Units 1 and 2 i

Inspection At: Zion, Illinois j Inspection Conducted: July 20 through August 23, 1988 .

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1 t Inspectors: M. M. Holzmer l

, P. L. Eng  ;

i J. M. Jacobson  !

! J. A. Gavula i

! '. G. Brochman ,

) c' A. Van Sickle i

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J. dinc s, CN f

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Approved B - c9.e9.eg !

actor Projects ection 1A Date  :

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l Inspection Summary l

! Inspection on July 20 through August 23, 1988 (Reports No. 50-295/88016(ORP):

i E 50-304/88016(ORP))

l' Areas Inspected: Routine, urannounced resident inspection of licensee action i on previous inspection findings; summary of operations; Unit 2 auxiliary i feedwater pump check valve backleakage; Unit 1 shutdown to repair extraction steam pipe leakage; operational safety verification and engineered safety i

feature (ESF) system walkdown; surveillance observation; maintenance  :

! observation; licensee event reports (LERs); training; IE Bulletin follow-up;  ;

l and response to hRC Region !!! reques :

i Results: Of the 11 areas inspected, no violations or deviations were  !

j identified. One licensee identified violation was identified involving l l failure to completely test power-operated relief valve (PORV) logic circuitry, ,

l and one unresolved item was identified involving the need for a more detailed j response to IE Bulletin 86-03.

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l 1 8809160169 080909 i i

' PDR ADOCK 05000295 t o PDC r I

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OETAILS j

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1. Persons Contacted  ;

. *G. P11m1, Station Manager

• E. Fuerst, Superintendent, Production

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• T. Rieck, Superintendent, Services '

• W. Kurth, Assistant Station Superintendent Operations i

• R. Johnson, Assistant Station Superintendent, Maintenance  !

J. Gilmore, Assistant Station Superintendent, Planning l'

• R. Budowle, Assistant Station Superintendent, Technical Services

N. Vales, Unit 2 Operating Engineer M. Carnahan, Unit 1 Operating Engineer

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i R. Cascarano, Technical Staff Supervisor

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l A. Ockert Training Supervisor

• T. Vandevoort, Quality Assurance Supervisor (

, V. Williams, Station Health Physicist -

i *C. Schultz, Quality Control Supervisor I J W. Stone, Regulatory Assurance Supervisor l i W. T'Niemi, Master Mechanic

! A. Bless, Regulatory Assurance Engineer  !

l *R. Harwood, Engineer, Thermal Group i j *T. Saksefski, Regulatory Assurance Engineer l

• T. Printz, Assistant Supervisor, Technical Staff i l *0. Dumbacher, Engineer, Primary Group L j *W. Mammoser, Principal Engineer, PWR Engineering j

• Indicates persons present at the exit interview.

2. Licensee Actions on Previous Inspection Findings (92701. 92702) l d

(Closed) Violation (304/85038-01(DRP)): Failure to make required  !

j Emergency Notification System (ENS) notification within four hours. The

> inspector reviewed the licensee's corrective actions and verified that l l they have been implemented as stated in the Ifeensee's response. The l

licensee has issued Zion Administrative Procedure ZAP 15-52-5, "NRC  !

j Notification Requirements," which identifies all NRC reporting l j requirementa and provides a list of engineered safety feature (ESF) i j equipment which requires an ENS notification when activated. The  !

inspector interviewed shif t supervisors to verify their understanding l l of the procedure and its requirements. Based on this review, this j l violation is considered close }

(Closed) Violation (295/85042-02(DRP); 304/85043-02(DRP)): Failure to J prepare adequate procedures for controlling reactor vessel (RV) water level when the vessel is drained to the midplane of the hot Irg nozzle ! The inspector reviewed the licensee's corrective actions and verified

that they have been implemented or are scheduled to be implemented, as ,

stated in the licensee's response. The inspector reviewed Revision 5  ;

] to procedure MI-6, "Filling and Draining the Refueling Cavity and Fuel

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Transfer Canal," and verified that minimum RV water levels are specified, that cross checks between the temporary tygon level indicator are made, and that the performance frequency and tolerance for these cross checks are specified. The licensee has modified the RV level indicating system by installing a new level transmitter, LT-RC22, on incere instrumentation tube numbei P-4. This permanent transmitter provides level indication to the bottom of to the hot leg nozzle instead of the midplane of the hot leg nozzle. The modification has been installed on Unit 1, but testing has not been completed. The modification will be installed on Unit 2 during its next refueling outage scheduled for October,1988. The licensee is preparing revisions to procedure MI-6 for utilizing the new ftV water level indicator after the modifications and testing are completed. This violation is considered close (Closed)OpenItem(295/80020-04(DRP);304/80021-04(DRP)): Modification of charging pump miniflow path in response to NRC Bulletin 80-18. The licensee performed an interim nodification in 1980 to the charging pump miniflow isolation valves in response to the subject bulletin which removed the automatic closure signal, and correnced an engineering review to detemine whether additional modifications were necessary. In a memorandum from the licensee's PWR engineering staff (D. Wosniak to G. Trzyna, dated March 23,1988), PWR engineering concluded that no additional changes should be made. The inspector verified that the emergency operating procedures (EOPs) have been revised to close or open the subject valves as required by reactor coolant system pressure and verified that licensed operators are familiar with this requiremen The inspector also verified that these valves are included on the inservice testing program and are tested quarterly. Based on the actions taken, this item is considered closed. Additional discussion regarding charging pump miniflow isolation valves is found in Paragraph 11 of this repor (Closed) Violation (295/85042-01(DRP); 304/85043-01(DRP)): Failure to take corrective actions for a condition adverse to quality (loss of decay heat removal capability during a refueling outage). The licensee !

has nodified the hardware for reactor vessel water level indication during refueling outages and has revised its event review prcgram to broaden its scope and prevent a repetitien of this event. Based on the action taken, this iten is considered close (Closed)OpenIten(295/86011-02(DRP)): Failure of the IB rain steam (MS)

check valve. The remaining action at the last review of this issue was the removal of depressions on the 1A and 1C MS check valves. The licensee completed the repairs during the Spring 1988 outage and reinspected all four check valves. No additional deficiencies were identified. Since this event occurred, the Unit 2 MS check valves have been inspected, and no deficiencies have been identified. To prevent recurrence, the licensee has replaced the bolts which hold the split locking device of each Unit 2 i valve with stronger material, and completed other actions which were j previously applied to the Unit 1 MS check valves to improve their

, reliabilit The inspector net with th licensee's technical staff and

! discussed the licensee's plans for future inspections of these valves.

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The licensee has ccrmiitted to perfoming a visual inspection of two of the four MS check valves during each unit refueling outage. The visual inspection will include checks for bolt elongation and alignment of the locking device. The licensee will reevaluate the frequency of these inspections after a baseline on the results has been developed. Based on these actions, this item is coasidered close (Closed) Unresolved Item (304/88014-01) Oetermination of whether the 2B auxiliary feedwater (AFW) pump discharge check valve 2 FW0012 was experiencing backleakage. On July 20, 1988, the licensee determined that 2 FW0032 was leaking and initiated repairs to the valve. Valve repair was completed on July 27, 1988. This item is closed. AFW check valve leakage is discussed further in Paragraph 4 of this repor (Closed) Unresolved Item (295/86019-02(DRP); 304/86018-02 (DRP)):

Pressurizer PORY (Power-Operated Relief Valve) stroke times exceeded the limit of the safety analysis. On August 21, 1986, the licensee was reviewing the safety analysis when it determined that the stroke time surveillances here nonconservative. In 1985 the PORVs were added to the licensee's valve monitoring program. A stroke time of ten seconds was specified in surveillance procedure PT-27, "Miscellaneous Valve Tests";

this criterion was based on the licensee's operational experience with the valves. The 2.5- second tire limit of the cold overpressure mitigation system (COMS) analysis was not specified in the surveillance section of the Technical Specifications, and the individual who prepared the procedure was not aware of the safety analysis. There is no t <e limit for the PORVs when the reactor coolant system is heated up to norral operating conditions, because the safety analysis relies not on the PORVs but on the pressurizer code safety valves to mitigate on overpressure event under those plant conditions. The 2.5- second time limit had been exceeded seven tirres since 1985 when the PORV5 were stroke tirre During subsequent reviews of this event, the licensee determined that the rass ficw rate utilized to generate the overpressure condition in the safety analysis was overly conservative and did not take into account f riction losses between the centrifugal charging purrps and the reactor coolant system. Westinghouse perforried another analysis usini a revised flow rate and other applicable conditions and determined that PORV stroke tires up to ten seconds were acceptable. The maximum treasured stroke tire had been nine seconds. Consequently, the safety significance of this event was lo Westinghouse has subsequently corrpleted an analysis of the reactor vessel operating curves for current and future vessel irradiation conditions and concluded that an opening time of 8.0 seconds for PORVs is adequate. The inspector reviewed the safety analysis and surveillance procedure PT-27, Revision 17, and verified that the current time limit is less than or equal to that used in the Westinghouse safety analysis. The licensee has created an additional staff position to review Technical Specification change requests against safety analyses to ensure that any assumptions in the safety analyses are properly translated into station procedure Based on these reviews, this iten is considered close .

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(Closed) Open Item (304/86031-01) Determination of whether installation of a pressurizer low pressure annunciator was feasible. The licensee determined that such a modification was feasible, and as reported in LER 304/86024-01 (see Paragraph 9), modification M22-1(2)-87-12 installs a pressurizer low pressure annunciator. This modification is scheduled for the 1988 Unit 2 outage and was installed and tested during the 1988 Unit 1 outage. This item is considered close No violations or deviations were identifie < Summary of Operations

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Unit 1 The unit operated at power levels up to 100% until July 23, 1988, when I the unit was shut down to r) pair leakage on an extraction steam (ES)

, line. During the shutdown, the reactor tripped from 10% power when the

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generator was tripped and power rose above the 10% power (P-10) setpoin i After ultrasonic testing (UT) of the suspect ES piping, weld overlay was performed as an interim repair until the scheduled August 1989 refueling outago. On July 26, 1988, the unit was tied to the grid, and the unit reached power levels up to 100% 1r load follow operation for the remainder of the inspection perio Unit 2 I The unit operated at steady-state power levels up to 100% until August 9, 1988, when the generator was taken off the grid after 309 days of continuous ope-ation to allow repairs of steam generator hand hole ;

leakage. During this outage, UT of ES piping (corresponding to that of Unit 1) was also performed. The unit was tied to the grid on August 12, 1988 and operated at power levels up to 100% for the remainder of the inspection perio No violations or deviations were identifie Unit 2 Auxiliary Feedwater Check Valve Bactleakage (93702, 92703)

l The licensee has continued to implement corrective actions to eliminate leakage from the Unit 2 steam generators into the AFW system and to pursue resolution of items listed in the Confirmatory Action Letter, i CAL-RIII-88-017, issusd on June 30, 1988. AFW check valve backleakage history is discussed in inspection report 295/88013; 304/88014, i

i The licensee determined in the latter part of June that backleakage from

the 20 steam generator was causing the elevated pump casing temperatures

) of both the 28 and 2C AFW pumps. The licensee initially thought the ,

l elevated casing temperature for the 2C AFW pump was due to backleakage

through 2C pump discharge check valve 2 FWOO33, and that the high casing ;

temperature for the 28 AFW pump was a result of conduct.ive heating along

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the common AFW discharge heade The licensee repaired 2 FWOO33 and returned the 2C AFW pump to service on July 16, 1988.

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On July 20, 1988, the licensee informed the resident inspector that the

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heat-up rates for the 28 AFW pump casing before and after repair of the l 2C AFW pump discharge check valve were identical. The licensee stated that repairs to 28 AFW pump discharge check valve 2 FWC032 were planne ;

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On July 26, 1988, the licensee began repairs on 2 FW0032. Investigation

of the internals of the 2 FWOO32 valve revealed that the disk and seat were not mating properly. The licensee lapped the valve disk and seat i and reassembled the valve on July 27, 1988. The licensee performed a e

gross leak check on the valve which exhibited no leakage. The 20 AFW t J pur.p was returned to service on July 29, 198 ;

Temperature data for the 28 AFW pump casing indicates that backleakage

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through 2 FWC032 has stopped; casing temperatures remain at approximately anbient levels.

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j Temperature data for both the 2B and 2C AFW pump casings af ter repairs to both discharge check valves indicate that 2 FWOO32 and 2 FWOO33 are i perfoming their functions. AFW pump casing temperatures for both pumps j hav'e remained below 90 degrees. The licensee has since reverted to

monitoring AFW pump casing temperatures on a shiftly basis, as specified i

by nomal operating procedure The licensee has completed the walkdown of the affected AFW piping and has nut idertified any degradation or thermal damage which may affect AFW !

system operability. Results of the temperature surveys for each of the  !

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four AFW injection lines prior to repairs to the AFW pump discharge check j i valves revealed that the temperature of the line from the 2D steam -

l generator was approximately '70 degrees higher than those of the remaining ;

1 three lines. This temperature difference persisted from the containment l l piping aenetrations to the point upstream of where the four lines join a 1 l common wade Prior to the valve repairs AFW piping temperatures were 1 over 200 degrees from the stean generators to within approximately 30 feet l downstream of the AFW pump discharge check valve ;

J j The licensee determined that the normal operating pressure in the AFW  ;

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t piping between the AFW pump discharge check valves following valve repairs was approximately 740 psi. This pressure ccmparcs with the observed pressures for Unit 1. The associated saturation temperature for i i this pressure is 511 degrees. The highest observed AFW piping temperature {

j obtained during the walkdown was 350 degrees. The licensee has therefore [

concluded that the probability of a water hammer event due to steam femation in the AFW piping is extremely low. The licensee also stated that the AFW piping system generally follows a downward slope from the j steam generatars to the pumps and does not include any bends tasceptible ;

J to steam condensation and associated water accumulatio ;

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{ The licensee has provided an analysis of the themal stress effects on

{ the affected AFW piping and components, including the themal cycles and  ;

i number of purp starts since the last startup. Review of the AFW piping

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themal stress analysis by the NRC is considered to be an unresolved item

(304/88016-01).

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No violations or deviations were identifie . July 23, 1988 Unit 1 Shutdown to Repair Extraction Steam pipe Wall Thinning (93702, 92703)

At 11:22 a.m. on July 22, 1988, with the unit at 98% power, a steam leak was identified in the extraction steam piping to the No. 16 heaters near the turbine nozzle. Unit I was shutdown to perform detailed ultrasonic testing of both the leaking piping (south end) and the corresponding piping configuration on the opposite side of the turbine (north end).

During the shutdown, the reactor tripped from 10% power when operators tripped the generator while reactor power was increasing slowly. A slow power ramp had started due to the addition of cold feedwater into the steam generators. As soon as reactor power reached 10% (the P-10 setpoint), the reactor tripped as designed. Operators apparently failed to notice the ramp increase prior to tripping the generato Circumstances surrounding this reactor trip will be reviewed in a future inspection as part of the follow-up to LER 295/88017.

. lhe ES piping is 16-inch diameter ASTM A-106, Grade B, with a nominal I wall thickness of 0.500 inch. Results of the UT of the south end showed areas adjacent to the pipe-to-nozzle weld to be degraded to approximately

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O.120-inch wall thickness. Results of the UT of the north end showed a degraded wall with a thickness of approximately 0.220 inc The licensee performed wall thickness calculations and determined that a minimum wall of 0.300 inch would be sufficient to pennit operation until the scheduled August 1989 refueling outage. Weld overlay was applied to i the areas where wall thicknass was less than the required 0.300 inch.

! Though the repair weld appeared rather rough to the NRC inspector, no l

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unacceptable indications were found during the final magnetic perticle examinatio The licensee had instituted a fonnal inspection program to monitor pipe wall thinning in response to NRC Bulletin 57-01, "Thinning of Pipe Walls in Nuclear Power Plants." However, the affected areas of ES piping were

not included in the licensee's program. The licensee stated that, using

the EPRI guidelines, the failed area was modeled as a straight length of pipe and as such, was considered a low priority area for examinatio The previous examination of this Es line at locations downstream of the high pressure (HP) turbine nozzle resulted in the repair / replacement of several components due to wall thinning. Some wall degradation of the extraction nozzle area had also been found during previous inspections at other CECO facilities. This area of the steam sptem apparently warrants a higher priority for future examinatio With regard to other extraction stages, the licensee perfomed an engineering evaluation. The ES lines for Heater Nos. 11, 12, 13. and 14 operate at lower temperatures and pressures than those of the No. 16 heater lines. These differences reduce the potential for severe erosion

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j in these areas. Additionally, these ES nozzles are located within the condenser, a configuration which substantially mitigates the effects of a line rupture. The ES lines for the cold reheat also operate at a Icwer temperatures and pressures than those of the failed lines and have substantially greater wall thicknesse On August 9,1988, Unit 2 was removed from the grid to repair steam

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generator hand hole leakage. During this outage, the HP turbine ES nozzle area for the No.16 heaters were UT examined. The results of

, the examination showed areas adjacent to the pipe-to-nozzle weld to be degraded to approximately 0.370 inch on the north end and 0.190 inch on the south en ! The licensee performed wall thickness calculations and determined that a minimum wall of 0.250 inch would be sufficient to permit operation until the upcoming October 1988 Unit 2 refueling outage. Weld repairs were

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made to those areas having less than the required 0.250-inch wal The analyses associated with the minimum wall thickness requirements were reviewed by an NRC regional inspector. The piping for this specific

Unit 1 extraction steam line was originally evaluated in April 1988. This effort was part of the recently initiated erosion / corrosion monitoring program. During the initial reviews, two elbows and two tees were evaluated for minimur.: wall requirements from a sustained load, expansion i

stress and projected life perspective. Stresses were based on finite j element piping analyses, and wear rates were conservatively calculated

! using UT data from each component. In all four cases the components met 4 ANSI 831.1 requirements and had projected lives ranging from 50 to 125 months.

) Additional evaluations were performed in July 1988 for the Unit I nozzle

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areas after the steam leak was discovered. Minimum wall requirements

, were calculated and overlay thicknesses were evaluated based on conservatively determined values of the wear rate. A similar evaluution was performed on the corresponding nozzle areas in Unit 2 in August 198 The NRC inspector reviewed the results of the above actions performed on i

this nonsafety-related piping and had no further questions at this tin No violations or deviations were identified, l

i 6. Operational Safet) Verification and Engineered Safety Features System Walkdown (71707, 71709, 71710 and 71881)

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The inspectors perforced routine observations of control room operations, reviewed applicable logs and conducted discussions with control room

operators from July 20 to August 23, 1988. During these discussions and observations, the inspectors ascertained that the operators were alert, I fully cognizant of plant conditions, and attentive to changes in those

conditions, and took prompt action when appropriate. The inspectors j verified the operability of selected emergency systems, reviewed tagout

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records and verified the proper return to service of affected component Tours of the auxiliary and turbine buildings were conducted te observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenanc The inspectors by observation and direct interview verified that selected physical security activities were being implemented in accordance with the station security pla The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. From July 20 August 23, 1988, the inspectors walked down the accessible portions of the safety injection, containment purge, charging, component cooling, service water, diesel generator and auxiliary feedwater systems to verify operabilit These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under Technical Specifications, 10 CFR, and administrative procedure No violations or deviations were identifie . Monthly Surveillance Observation (61726)

The inspector observed Technical Specifications required surveillance testing of the 2B and 2A auxiliary feedwater pumps and verified whether testing was performed in accordance with adequate procedures, whether test instrumentation was calibrated, whether limiting conditions for operation were met, whether removal and restoration of the affected components were accomplished, whether test results conformed with technical specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and whether any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne The pector witnessed portions of the following test activities:

, PT-7 Auxiliary Feedwater System Checks and Tests

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! No violations or deviations were identified.

l l 8. Monthly Maintenance Observation (62703)

Station maintenance activities on the safety-related systems and components

! listed below were observed or reviewed to ascertain whether they were

conducted in accordance with approved procedures, regulatory guides,

! industry codes or standards, and in conformance with Technical Specifications.

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The following items were considered during this review: the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; f tnctional testing and/or calibrations were performed prior to retJrning components or systems to service; quality control records were maintained; a tivities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemente Work requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performanc The folloving maintenance activities were observed or reviewed:

263854 1C Steam Generator Feedwater Regulattng Val',e Repair Z69929 Inspection of 2C Auxiliary Feedwater Pump Motor Splices 271925 Disconnect of 2C Auxiliary Feedwater Pump Motor Z72776 Repair to Unit 1 H6gh Pressure Extraction Steam Line

! Z73056 Repair to Unit 2 High Pressure Extraction Steam Line Z72531 Repair of 28 Auxiliary Feedwater Pump Discharge Check Valve Following completion of maintenance on the discharge check valve for the 28 AFW pump, the inspector verified that the system had been returned to service properl ! No violations or deviations were identifie . Licensee Event Reports (lei's) Follow-up (92700)

Through direct observations, discussions with licensee personnel, and review of records, the following event reports were review 9d to determine that reportability requirements were fulfilled, that immediate corrective action was accomplished, and that corrective action to prevent recurrence

) had been accomplished in accordance with Technical Specifications. The j LERs listed below are considered closed:

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LER N DESCRIPTILN

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88003-01 Quarterly Composite Sample Unable to Meet LLO Requirements

! 88005 Reactor Trip due to Steam Generator Level Transient af ter

> Feedwater Pump Test 88011 Reactor Trip Oue to Generator Trip /0ver Excitation l

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88013 Reactor Trip Due to Feed Flow Square Root Extractor Failure 88014 Incomplete Channel Calibration of Pressurizer Power Operated Relief Valves (PORVs)

88015 ESF Bus 147 Undervoltage UNIT 2 LER N DESCRIPTION 05029-02 Purge Isolation Due to Low Temperature and High Radiation Signal - Revision 2 '

86024-01 Pressurizer low Pressure Transient Due to Pressure Controller Shifting to Manual - Revision 1 Regarding LER 295/88003-01, this LER was revised to show the correct event date. The original LER was already closed in report 295/8801 This item is considered close Regarding LERs 295/88005, 295/88011, and 295/83013, these three reactor trips were caused by equipment failures involving feedwater regulating valve sluggish response, corrosion on Phase B in the primary of the generator exciter potential transfonner circuit, and failure of a fecawater flow transmitter square root extractor, respectively. The licensee's responses to these equipment failures were reviewed and are considered acceptabl Regarding LER 295/88014, the licensee identified an inadequacy in procedure PT-27. "Refueling Outage Miscellaneous Valve Tests," in which a complete channel calibration of pressurizer PORVs had never been performe Pressurizer pressure channel calibration, which verifies that an open signal would be sent to the FORVs at 2335 psig, and stroke timing of the PORVs had been properly perfortned. Untested portions of the channel included relays, switch contacts and wiring. When tested, these components operated as designed. Since these corponents worked when tested, and since no credit is taken for PORY operation to mitigate the consequences of an accident, the safety significance of this finding is lo PORY channel calibratien is required by Technical Specification 4.3.1. Because this violation meets the criteria of 10 CFR 2 Appendix C.!!!. this will be considered a licensee-identified violation for which no citation will be given (29E/88016-01). This item is considered close Regarding LER 295/88015, this ESF bus undervoltage was caused by voltage fluctuations outside the station, and the safny-related equipment operated as designe This iten is considered close . . - _ - - - _ _ _ _ _ _______ ___ __ _ _- - ___ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _

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i Regarding LER 304/86024-01, this revision updated corrective action +o

. show that modification M22-1(2)-87-12 would install a pressurizer low pre',sure alarm during the 1988 refueling outages for Units 1 and 2. This item is considered close ;

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Regarding LER 304/85029-02, this revision updates the root cause analysis to indicate that voltage spiking on the power supply to 2RT-PR09C caused

the purge isolation. This item is considered close ! No violations or deviations were identified. One licensee identified j violation was identified, i

1 Training (41400)

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During the inspection period, the inspectors reviewed abnormal events and unusual occurrences which may have resulted, in part, from training

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deficiencies. Selected events were evaluated to determine whe.her the I classroom, simulator, or on-the-job training received before the event

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was sufficient to have either prevented the occurrence or to have

> mitigated its effects by recognition and proper operator actio In 1 addition, the inspectors determined whether lessons learned from events

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were incorporated into the training progra Events reviewed included the events discussed in this report. In i addition, LERs were routinely evaluated for training impact. No events

, reviewed this period were found to have significant training deficiencies l as contributor No training sessions were attended by the resident inspectors.

l No violations or deviations were identifie . IE Bulletin Closeout (92703)

(0 pen) IE Bulletin 86-03, "Potential Failure of Multiple ECCS Pumps Due to the Single Failure of a Valve in the Minimum Flow Recirculation Line,"

(295/86003-BB; 304/86003-88): Licensees were requested to determine l whether or not a single-failure vulnerability exists in the minimum flow

recirculation line of any ECCS (emergency core cooling system) pumps

that could cause a failure of more than one ECCS train. The licensee's j response, in a letter from I. M. Johnson to J. G. Keppler, dated

, November 14, 1986, stated that "We have completed a review of this

) issue as it applies to. . . Zion. . . Station and determined that the i single-failure problem does not exist at any of our stations." During l a review of this response and the response associated with Open i Items 295/80020-04 and 304/80021-04 and IE Bulletin 80-18, the inspector identified that a single-failure problem could exist in the high head

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portion of the ECCS syste The high head portier, of the ECCS system includes two centrifugal charging pumps. These two pumps share a common recirculation line which l

allows water to recirculate from the discharge of each pump to the pumps'

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suction heade In this line are two motor-operated valves in series, MOV-VC8110 and MOV-VC811 In response to Bulletin 80-18, the licensee removed an auto-close signal from these valves and revised its emergency operating procedures to direct the reactor operator to close the valves if rnactor coolant system pressure drops below 1250 psig during a safety injection and to reopen the valves before pressure rises above 2000 psi To be able to perform this action, the motor operators must remain energize Because these valves remain energized, the potential exists for the valves to be closed spuriously, inadvertently, or deliberately, before or during a safety injectio Loss of the minimum flow recirculation line could render both centrifugal charging pumps inoperabl This Bulletin will remain open pending determination by the licensee of whether this potential single failure could represent a problem as described in IEB 86-03, and revision, if appropriate, to the licensee's November 14, 1986 respons No violations or deviations were identifie . Follow-up on Region III Requests (92701)

On July 27, 1988, the resident inspectors were alerted to a concern with Foxboro M/62H style B controllers identified at the Prairie Island Nuclear Generating Plant. A request was made by telephone that the resident inspectors verify whether these controllers are in use at Zion Station. The inspectors determined that no Foxboro M/62H style B controllers, or any other Foxboro controllers, are in use in safety-related applications at the Zion statio No violations or deviations were identifie . Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, itais of noncompliance or deviations. One Unresolved Item disclosed during this inspection is discussed in raragraph . Licenses Identified Violations In accordance with 10 CFR Part 2, Appendix C, General Statement of Policy and Procedure for NRC Enforcement Actions, the NRC will not generally issue a notice of violatics for a violation that meets all of the following tests: It was identified by the licensee; It fits in Severity Level IV or V; It was reported, if required; It was or will be corrected, including measures to prevent recurrence, within a reasonable time; and

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, It was not a violation that could reasonable be expected to have been prevented by the licensee's corrective action for a previous violatio One licensee-identified violation disclosed in this inspection is discussed in Paragraph 9 of this repor . Exit Interview (30703)

The inspectors met with licensee representatives (denoted in Paragraph 1)

throughout the inspection period and at the conclusion of the inspection on August 23, 1988, tosummarizethescopeandfindingsoftheinspection activities. The licensee acknowledged the inspectors comments. The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any such documents or processes as proprietary, 14