IR 05000255/1994021

Insp Rept 50-255/94-21 on 941223-950106.One non-cited Violation Noted.Major Areas Inspected:Operational Safety Verification,Engineered Safety Featured Sys,Onsite Event Followup,Matl Condition,Plant Cleanliness & Security

ML18064A575
Person / Time
Site:	Palisades
Issue date:	01/13/1995
From:	Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML18064A574	List: IR 05000255/1994021 ML18064A573
References
50-255-94-21, NUDOCS 9501240359
Download: ML18064A575 (28)

Text

U.S. NUCLEAR REGULATORY COMMISSION REG ION I I I Report No. 50-255/9402l(DRP)

Docket No. 50-255 License No. DPR-20 Licensee:

Consumers Power Company 212 West Michigan Avenue Jackson, MI 49201 Facility Name:

Palisades Nuclear G~nerating Facility Inspection At:

Palisades Site, Cov~rt, Michigan Inspection Conducted:

December 3, 1994, through January 6, 1995 Inspectors:

M. E. Parker w. J. Kropp D. G. Passehl M. M. Biamonte T. J. Kobetz D. s. Butler J. A. Lennartz R. A. Winter J. A. Isom R. L. Lerch Approved By:

1,4/ra-Date

.

Reactor 2A Inspection Summary Inspection from December 3, 1994, through January 6, 1995 (Report No. 50-255/9402l(DRPll Areas Inspected:

Routine, unannounced safety inspection by resident and regional inspectors of operational safety verification, engineered safety.

featured systems, onsite event followup, current material condition, housekeeping and *plant cleanliness, radiological controls, security, safety assessment/quality verification, maintenance activities, surveillance activities, engineering and technical support, Temporary Instruction 2515/111

- Electrical Distribution System Followup Inspection, Temporary Instruction 2515/126 - Evaluation ~f Online Maintenance, report review, and ~eeting Results: Within the 15 areas inspected, no cited violations or deviations were identified..One unresolved item pertaining the charpy V notch testing was identified (paragraph 5.b.). One noncited violation was identified (paragraph 4.b)~ Based upon this inspection, TI 2515/111 and TI2515/126 are c 1 ose The fo 11 owing is a summary of the licensee '.s performance during this inspection period:

9501240359 950118 PDR ADOCK 05000255 G

PDR

Plant Operations The licensee's performance in this area was adequate; however, there was a concern identified with the timely and appropriate assessment of the auxiliary feedwater (AFW) system following an unanticipated AFW injection into the steam generator More timely management, system engineering, and l&C involvement is warranted in this are The plant operated at essentially full power throughout the inspection perio The licensee has operated the plant for over 200 consecutive days on-line, breaking the.previous record of 176 consecutive days on-lin The inspectors observed power escalation following scheduled main turbine valve tests. The inspector observed one minor weakness with the power escalation procedure involving the method used to compare indicated to actual reactor powe Plant operators appropriately changed the procedure prior to proceeding with the power escalatio The licensee declared an Unusual Event on December 8, 1994, when the flow indicating controllers to the auxiliary feedwater (AFW) valves were declared inoperabl The licensee found that the problem was due to a failed electrical relay, resulting in the flow control valves receiving an open demand signa Plant Instrument and Control technicians replaced the relay and successfully tested the AFW system, terminating the Unusual Even The*

same relay was the cause -0f another reportable event the previous da During that event, an unanticipated injection of AFW into the steam generators occurred, during surveillance testing of the AFW system, as a result of the AFW flow control valves being in the open positio The main feedwater system compensated for the injection and maintained normal steam generator level The test was immediately terminated and the AFW system, was returned to a standby configuratio However, the failure to recognize the flow control valve position, resulted in the AFW system being in a potentially degraded condition for an extended period of tim In addition, control room turnovers and panel walkdowns by reactor operators did not identify the. degraded condition, until some 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the relay~ failur Overall material condition was adequat The inspector reviewed the radiological survey sheets for Multi-Assembly Sealed Basket #9 and found no problem Safety Assessment/Quality Verification A noncited violation was. issued for the licensee's failure to test redundant low pressure safety injection loop isolation valves prior to maintenanc A training and assessment specialist from the Human Factors Assessment Branch at NRC Headquarters conducted a review of the Palisades Performance Enhancement Program (P2EP).

The individual action plans in the P2EP were well written with clear due 1_dates and deliverable However, the inspector found several concerns including (1) A lack of measures of success for each of the action plans; (2) Items included in the P2EP tended to be too broad with a

focus on consolidating common items under one action plan; and (3) Some of the completed actions were inadequat The inspectors reviewed the licensee's proposed actions_to consolidate the presently used commitment tracking system (CTS}.

The current system has not been effective at communicating and ensuring regulatory commitments were identified, documented, and implemente A departmental action plan for a new CTS was developed that established the actions to be taken and the scheduled completion date The database for new CTS has been delayed and was now scheduled for completion in late January 199 Maintenance and Surveillance The inspectors evaluated the licensee's on-line maintenance practices in accordance with Temporary Instruction 2515/126, "Evaluation of Online Maintenance."

The inspector concluded that the process in place adequately incorporated Probabilistic Risk Assessment (PRA} insights when scheduling on-line maintenanc Surveillance activities were conducted satisfactoril Engineering and Technical Support The inspectors observed and reviewed activities associated with the loading of Multi-Assembly Sealed Basket {MSB) # The licensee experienced a minor problem during the vacuum drying proces The licensee could only achieve a

~acuum of 0.10 psia, versus 0.050 psia as specified in the loading procedur The licensee found the swagelock fitting on the vent line to be leakin Plant engineers implemented an approved modification to cover the vent line opening and proceed with vacuum dryin Further leak testing, after the temporary cover was removed and permanent covers welded into place, proceeded acceptably per the normal procedur No other evidence of leaks were found and all acceptance criteria was appropriately me The licensee discovered that the shield lid top material for MSBs used in Ventilated Storage Casks 01 through 04 were not charpy v-notch impact tested per the requirements of the Safety Evaluation Report {SER}.

The SER requires charpy impact testing of all MSB pressure boundary materials, parts, components at temperatures of -50°F, with toughness not lower than 15 ft-lb The impact test requirement on the pressure boundary constitutes the basis for the allowed movement of the MSB above ambient temperatures of 0° The licensee intends to have charpy impact testing performed on sample cou~ons from the original shield lid material for the affected shield lid *

DETAILS Persons Contacted Consumers Power Company

• R. A. Fenech, Vice President, Nuclear Operations

• T. J. Palmisano, Plant General Manager

• K. P. Powers, Plant Engineering and Modifications Manage *R. M. Swansdn, Director, NPAD

• 0. w~ Rogers, Operations Manager

• S. Y. Wawro, Outage and Planning Manager

• K. M. Haas, Safety & Licensing Director R. B. Kasper, Maintenance Manager

• R. C. Miller, NECO Deputy and Special Projects Manager

• C. R. Ritt, Administrative Manager

• R. J. Gerling, Reactor and Safety Analysis Manager

• J. L. Hansen, Plant Support Engineering Manager 0. J. Vandewalle, System Engineering Manager

• P. J. Gire, Licensing Engineer 0. G. Malone, Shift Operations Superintendent

• 0. J. Malone, Radiological Services Manager

• R. A. Vincent, Licensing Administrator

• O. P. Fadel, NECO Engineering Program Manager J. P. Broschak, NECO Ory Fuel Storage Engineer

• .J. P. Pomaranski, NECO Project Manageme*nt and Modificatipns Manager

• K. A. Toner, Design Engineering Manager Nuclear Regulatory Commission

• M. E. Parker, Senior Resident Inspector *

• O. G. Passehl, Resident Inspector W. J. Kropp, Section Chief, Riii J. A. Lennartz, Operator Licensing Examiner, Riii S~ Butler. Electrical Inspector, Riii R. A. Winter, Electrical Inspector; Riii M. M. Biamonte, Human Perfc~mance Evaluator, NRR T. J. Kobetz, Senior Resident Inspector, Point Beach R. M. Lerch, Operational Programs Inspector, Riii

. J. A. Isom, Senior Resident.Inspector, 0. C. Cook

• Denotes those attending the exit interview conducted on January 6, 199 The inspectors also had discussions with other licensee employees, including members of the technical and engineering staffs, reactor and auxiliary operators, shift engineers and electrical, mechanical and instrument maintenance personnel, and contract security personne.

Plant Operations (71707, 93702)

The plant operated at essentially full power throughout the inspection perio The licensee has operated the plant for over 200 consecutive days on-line, breaking the previous record of 176 consecutive days On-lin Operational Safety Verification (71707)

The inspectors verified that the facility was being operated in conformance with the license and regulatory requirements and that the licensee's management control system was effective in ensuring safe operation of the plan On a sampling basis, the inspectors verified proper control room staffing and coordination of plant activities; verified oper~tor adherence with procedures and technical specifications; monitored control room indications for abnormalities; verified that electrical power was available; and observed the frequency of plant and control room visits by station managemen The inspectors reviewed applicable logs and conducted discussions with control room operators throughout the inspection perio The inspectors observed a number of control room shift turnover The turnovers were conducted in a professional manner and incl~ded log reviews, panel walkdowns, discussions of maintenance and surveillance activities in progress or planned,.

and associated Limiting Condition for Operation time restraints, as applicabl )

Auxiliary Feedwater System On December 7, 1994, at 7:42 p.m. (EST), during surveillance test M0-38, "AFW System Pumps Inservice Test Procedure" of the auxiliary feedwater (AFW) pump PBA, an unanticipated injection of approximately 165 gallons of AFW into the steam geherators occurre This was a result of a failure of an electrical relay that sent an open demand signal to the AFW flow control valve ~he AFW flow control valves actually went open upon failure of the electrical relay. Operators*

immediately recognized that an inadvertent AFW injection* *

occurred and secured the tes The system was returned to the original normal *lineup,*and event was reported as an engineered safety features (ESF) actuation per 10 CFR 50.72 (b)(2)(ii). However, after securing from the surveillance, the operating shift did not recogni~e that the AFW flow control valves, CV-0727 and CV-0749, remained in the open position. *These valves remaining in the open position could have resulted in a possible pump trip from a runout condi~io In restoring the system following the surveillance, the operating shift believed that the event was caused by the associated test switch (SS-3/PBA/B) not functioning properl The function of the test switch was to ground out

the flow indicating controllers signal, thus overriding the open demand signal and providing a close signal to the flow control valves. Operators were not cognizant of the flow control valve's position, as the valve position was not available in the control roo Only valve demand signal and AFW flow rat~s were available. Approximately ten hours later on December 8, 1994, at 5:35 a.m. (EST), control opefators recognized a full open signal was being demanded on AFW flow controllers FIC-0727 and 0749 in the control room, and subsequently determined locally that the flow control valves were actually full ope The AFW flow control valves, normally closed, throttle open on an AFW pump start to control demanded flo The failed relay had caused the fl ow contra 1 valves to go from the normally full closed position to the full open positio The licensee failed to recognize the open position of the AFW flow control valves during the surveillance test, and subsequent troubleshooting following the tes Following discovery of the open AFW flow control valves, the associated controllers were declared inoperabl An Unusual Event was declared at 6:57 a.m. (EST) based upon the need for heightened awareness and the potential for a plant shutdown required by technical specification Instrument and control technicians were able to determine that the open demand signal was caused by a failed electrical relay (SSX-3/P8A/B).

The relay was replaced and the Unusual Event was exited, prior to the init{ation of a plant shutdow In reviewing the event, the inspectors had the following observations:

The relay had failed on December 7, 1994, at 3:00 (EST), over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the declaration of Unusual Even The inspectors also noted that both.

FIC-0727 and 0749 have black reference dots associated with the The reference dots were intended to as~ist control operators during the conduct of control panel walkdown Panel walkdowns were required of control operators every shift. Thus several shift turnovers occurred along with the required panel walkdowns, without the demand signal bein-g recognized out of th normal positio *

The surveillance test, M0-38, was conducted by the operating shift without the support of system engineerin While system engineering assistance was not requi~ed to perform the surveillance, the operating shift did brief system e~gineering by telephone on the even However, system engineering did not provide subsequent onsite support and relied on the operating shift's assessment of the situation

which did not include any troubleshooting of the equipment involved in the event. On-site support by system engineering could have aided in a more timely identification and could have supported the shift with a more appropriate assessment of the AFW syste *

Since the plant does not have I&C maintenance coverage around the clock at power, there was a delay iN troubleshooting efforts and timely restoration of full system operabilit The inspectors will continue to followup on the licensees actions with regard to timely assessments of system operability in response to Licensee Event Report (LER}

255/9402 )

Power Escalation Following Turbine Valve Testing The inspectors observed power escalation following schedule main turbine valve tests. Plant operators reduced reactor power to approximately 85 percent to perform the testin The evolution was performed without significant complicatio Prior to the power escalation, plant operators held a thorough pre-job brief with a good discussion of contingencie The inspectors observed one minor weakness with the power escalation procedur Plant operators appropriately changed the procedure, prior to continuing with the power escalatio~.

General Operating Procedure GOP 5, "Power Escalatibn After Synchronization," Rev.13, Attachment 4, required the crew to use non-safety related primary coolant system (PCS} loqp delta-T recorders to compare with power range nuclear instrument reading The purpose was to determine how well actual reactor power compared with indicated reactor power, bas~d on PCS loop delta-When the Loop Delta-T recorder temperatures were compared with indicated reactor power on Attachment 4, indicated reactor power was slightly less than actual reactor power and GOP 5 required the power escalation tq be stoppe the crew's diagnostics were goo The Shift Supervisor directed the crew to use alternate indications available (i.e. safety-related loop temperatures, feedwater temperature, generator megawatts} to determine if indicated reactor power was indeed less than actual power.. When the safety related loop temperatures were utilized to calculate loop delta-T, the crew determined that indicated and actual reactor power were equal and the non-safety related loop delta-T recorders were reading in erro Feedwater temperature and generator megawatts were also consistent

with indicated reactor powe Additionally, the SS informed plant nuclear engineering personnel, who obtained incore data that agreed with the crews assessmen The SS informed Operations management and stopped the power escalation until the appropriate procedure change could be processe After the procedure change was in place the power escalation was completed without any additional problem Engineered Safety Feature CESF) Systems (71707)

During the inspection period, the inspectors selected accessible portions of several ESF systems to verify status. Consideration was given to the plant mode, applicable Technical Specifications, Limiting Conditions for Operation requirements, and other applicable requirement Various observations, where applicable, were made of hangers and supports; housekeeping; whether freeze protection, if required, was installed and operational; valve position and conditions; potential ignition sources; major component labeling, lubrication, cooling, etc.; whether instrumentation was properly installed and functioning and significant process parameter values were consistent with expected values; whether instrumentation was calibrated; whether necessary support systems were operational; and whether locally and remotely indicated breaker and valve positi6ns agr~e '

During the inspection, the accessible portions of the following systems were walked do~n:

Auxiliary Feedwater Train A

Emergency Diesel Generator Train B Onsite Event Follow-up (93702)

Durin~ the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.7 The inspectors pursued the events onsite with licensee and/or other NRC official In each case, the inspectors verJfied that any required notification was correct and timel The inspectors also verified that the licensee initiated prompt and appropriate action The specific events were as follows:

As previously stated, on December 7, 1994, during surveillance testing of the auxiliary feedwater (AFW)

system, an unanticipated injection* of AFW into the steam generators occurred, as a result of the AFW system control valves being in the open position. This resulted in the AFW

• system injecting a~proximately 165 gallons of water to each steam generato The main feedwater system compensated for the injection and maintained normal steam generator level Th~ test was immediately terminated and the AFW system was returned to its standby configuratio On December 8, 1994, the licensee declared an Unusual Event when AFW flow controllers FIC 0727 and FIC 0749 were declared inoperabl The licensee entered Technical Specification 3.5.3 which required that the plant be in hot standby within six hours when both flow controllers were inoperabl Instrument and Control technicians later determined that electrical relay SSX-3/PSA/B faile The Instrument and Control technicians replaced the relay and the licensee exited the Unusual Event approximately two hours late The failed electrical relay was the root cause for both of the reportable events described above~ Current Material Condition (71707)

The inspectors performed general plant ~s well as selected system and component walkdowns to assess the general and specific material condition of the plant, to verify that work requests had been initiated for identified equ1pment problems, and to evaluate housekeepin Walkdowns included an assessment of the buildings, components, and systems for proper identification and tagging, accessibility, fire and security door integrity, scaffolding, radiological* controls, and any unusual condition Unusual conditions included but were not limited to water, oil,.or other liquids on the floor or equipment; indications of leakage through ceilin~, walls, or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and

lightin Overall material condition was adequat Some minor items were identified and are described belo *

The inspector found one Appendix "R" emergency light, ELU-6, in the "fast charge mode during a routine tour of the turbine building rather than in the normal "trickle charge

state. The inspector contacted the system enginee The system engineer reviewed trend information and found the ELU consumed approximately eight ounces of electrolyte per month over the past few month The system engineer had recently started to trend electrolyte usage, as well as other problems with the emergency lighting unit The system engineer explained that the high ambient temperature at the ELU's location, combined with the unit switching to the fast charge mode, would explain the higher than normal electrolyte usag The system engineer issued a work

request to perform a full duration test on the EL Also, the engineer requested that the ELU be scheduled for replacement in the next few week The system engineer exhibited a clear sense of ownership in response to this iss~e. The engineer issued a letter outlining the above actions, possible causes for the observed problems, and planned actions to resolve the issu *

The inspectors reviewed the licensee~s response to the control room annunciator for safety injection tank T-820 Hi-Lo level. Technical Specifications, procedures SHO 1,

Technical Specification Surveillance Procedure," and RI 15C, "Safety Injection.Tank Level Channel Calibration," and SOP 3, "Safety Injection Tank Level Alarm Verification,"

were reviewed with operations and engineering staffs. The licensee had taken appropriate corrective actions including annotation of the surveillance data sheets and issuing a work order to recalibrate the level instrumen The instrument, LIA-0374, was apparently affected by changes in containment temperatur The licensee was considering replacement of the level instrument with a temperature compensated model as long term corrective actio Housekeeping and Plant Cleanliness (71707)

The inspectors monitored the status of housekeeping and plant cleanliness for fire protection and protection of safety-related*

equipment from tntrusion of foreign matte No significant concerns were identified this inspection perio Radiological Controls (71707)

The inspectors verified that personnel were following healt physics procedures for dosimetry,~protective clothing, frisktng, posting, etc., and randomly examined radiation protection instrumentation for use, operability, and calibration.. *The inspector reviewed the radiological survey sheets for Multi-Assembly Sealed Basket #9 and found no problem Security Each week during routine activities or tours, the inspectors monitored the licensee's security program to ensure that observed actions were being implemented according to the approved security pla The inspectors noted that persons within the protected area displayed proper photo-identification badges and those individuals requiring escorts were properly escorte The inspectors also verified that thecked vital areas were locked and alarme Additionally, the inspectors also observed that personnel and packages entering the protected area were searched by appropriate equipment or by han.

No violations, deviations, unresolved, or inspection followup items were identified in this are Safety Assessment/Quality Verification (40500 and 92700). Licensee Event Report (LER) Follow-up (92700, 81502)

Through direct observations, discussions with licensee personnel, and review of records, the following event report was reviewed to determine that reportability requirements were fulfilled, that immediate corrective action was accomplished, and that corrective action to prevent recurrence had been or would be accomplished in accordance with Technical Specifications (TS):

(Closed) LER 255/94019: Failure to Test Redundant Equipment Per Technical Specification 3.3.2.f Prior to Removal of Electrical Breakers From Service For Planned Preventive Maintenance:

On November 9, 1994, plant personnel identified a failure to implement a Plant Technical Specification requiremen The requirement stated that prior to initiating repairs to certain safety injection system components, all valves in the system that provide the duplicate function shall be tested to demonstrate operabilit *

'

On November 6, 1994, the electrical supply breaker for one of four low pressure safety injection loop isolation valv~s (M0-3014) was removed from service for preventive maintenance on the breake The licensee failed to test the other three duplicate valves prior to starting the maintenanc A similar event occurred again on Novemb~r 8, 199 This time low pressure ~afety injection loop isolation valve M0-3012 was rendered inoperable without performing the required operability testing on the other three duplicate valve As reported in the LER, there were three causes foi' this event:

During a prior revision to the breaker preventive maintenance document, maintenance personnel fail~d to include the redundant equipment testing requirement from the Technical Specification *

The licensee's second level review of the proposed revision to the preventive maintenance document failed to identify the discrepanc *

Plant operators failed to identify the required testing prior to approving the work order for start of the wor The failure to test the remaining low pressure safety injection loop isolation valves is a licensee identified violation of

Technical Specification 3.3.2.f with low safety significanc At the time M0-3014 was inoperable, there was no other inoperable safety injection ~quipment. Similarly, at the time M0-3012 was inoperable, there was no other inoperable safety injection equipmen The licensee returned M0-3014 and M0-3012 to operable status well within the allowable Limiting Condition for Operation timefram Corrective actions included properly revising the preventive maintenance documents so that required Technical Specification testing is performe In addition, the plant administrative procedure No. 5.14, "Periodic and Predetermined Activity Control,"

that addresses second level reviews, was appropriately revise This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation met the criteria specified in 10 CFR 2, Appendix C, Section VIl.B(2). Therefore, the violation will not be cited. This LER, is close Palisades' Performance Enhancement Program (40500)

During the week of December 5, 1994, a training and as~essment specialist from the Human Factors Assessment Branch at NRC Headquarters conducte9 a review of the Palisades Performance Enhancement Program (P2EP).

The inspector identified several strengths in the P2E First, the s~ope of the program was limited and designed to address "item~ with similar root causes rather then just to address individual symptom Secondly, the individual action plans were well written with clear due dates and deliverables. However, the inspector did identify the following three concerns with P2EP:

There was a lack of measures of success for each of the P 2EP *

action plan Althoug~many of the action plans contain a step that requires developing a verification and validation (V & V) method, this method was not required until the actions in the plan were complet Discussions with the individuals responsi.ble for action plans determined that there was not always a common understanding of the specific improvements desired from each of the plan Given the lack of a common understanding of the goals, the V & V process when developed after the fact, could become a measure of the tompleteness of the activities rather than a m~asure of success to bring.about the original desired chang Items included in the P2EP tend to be broad with a focus on consolidating common items under one action plan. This was a concern since this often results in generic fixes that do not always appear to address the cause of specific problem For example, errors due to equipment tagging problems have occurred several times over the last 6 month There were

• three P 2EP action plans related to tagging, with two of the

. three already close Further investigation determined that although the closed P2EP items provided underlying support, such as clearer management expectations to improved tagging, specific changes to the tagging process were still outstanding. These changes were included in a grou~ of action plans (DMAPs} which were separate from the PEP and were assigned to individual department Therefore, individual actions in the P2EP have been closed without adequately completing all of the appropriate corrective actions to prevent equipment tagging errors from occurrin The P 2EP contains action plans designed to improve the root cause proces Some focus has been placed on improving the efficiency of the proces However, several current practices present challenges to the overall effectiveness of the root cause determination process and may impact the licensee ability to correct human performance issues after a single occurrenc Although the root cause action plan calls for additional staff to be trained in root cause analysis, untrained staff was currently allowed to perform a root cause determinatio Addition~lly, management does ~ot require that a root cause determination always be made by

fo.llowing the standard methods of investigation, thereby circumventing the system designed to ensure the appropriat level of analysis to determine the true root caus Further, individual departments involved in the issue or event were conducting the root cause determination The l~ck of independent analysis combined with the lack of training and the lax process standards were indications that the licensee has not yet succeeded in improving the root cause proces Current practices suggest that the licensee may not be able to adequately determine the root cause and, therefore, may still experience recurring problems in the area of human perfor~anc *

Discussions with licensee management on the completeness and effectiveness of P 2EP action plans resulted in the identification of several management initiatives, including the monthly NPAD report, that the licensee believes will adequately monitor ongoing performance and assure overall succes Licensee management also noted that the Management and Safety Review Committee (MSRC}, an independent group established by the licensee in response to Diagnostic Evaluation Team findings, also focuses on monitoring performanc These efforts appear comprehensive but were at a higher level thari the actions planned in the P2E However, minutes of the September 13, 1994 meeting of the MSRC indicate that there was a discussion on measuring effectiveness of

corrective actions in the P2E The director of NPAD, noted that P

2EP actions could be completed without really solving underlying problem The meeting minutes further noted that the focus of all performance improvement efforts must remain on fixing the

underlying problem Although the P2EP action plans were weak in the area of measuring the effectiveness of completed action, the licensee has proven a sensitivity to the.issue and believes other monitoring measures will indicate if success has been achieved in the appropriate area Initial reviews of the equipment tagging issue suggest that the level of monitoring was being successful in identifying on-going tagging problems but not in preventing recurrenc Furthe~ observation of licensee management oversight was needed to determine the effectiveness of the monitoring in detecting declining trends of human performance before those trends contribute to an operational issu Commitment Tracking (40500)

The inspectors reviewed the licensee's proposed actions to consolidate the presently used commitment tracking system (CTS)

into a more user friendly and effective syste The system now being used by the licensee has not been effective at communicating and ensuring regulatory commitments were identified, documented,*

and implemente At present the licensee has assigned two individuals, an administrator and a clerk, to develop the new CT A departmental action plan for a new CTS was developed that established the actions to be taken and the scheduled completion dates. * The database for new CTS has been delayed and was now*

scheduled for completion in late January 199 The inspectors believe the new CTS will improve the effectiveness.of ensuring closure of regulatory commitment Until the new CTS has been determined to be effect~ve, the*licensee will continue to utilize the old CT To improve the effectiveness of the present system, the licensee has assigned. three individuals to overview the closure of regulatory commitment This overview consists of independently verifying*the basis for closur The inspectors

• Will continue to monitor the licen~ee's progress in establishing an effective CTS*.

One noncited violation was identifie No deviations, unresolved~ or inspeciion followup items were identified in this area. * Maintenance/Surveillance (62703 and 61726) Maintenance Activities (62703)

Routinely, station maintenance activities were observed and/or reviewed to ascertain that the activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with technical specification *

The following items were also considered during this review:

LCOs were met while components or systems were removed from service; approvals were obtained prior to initiating the work; functional testing and/or calibrations were performed prior to returning

components or systems to service; quality control records were maintained; and actiyities were accomplished by qualified personne Portions of the following maintenance activities were observed or reviewed:

Work Order 24414828:

Remove Diesel Generator 1-2 Fuel Oil Priming Pump, Disassemble and Rebuild Work Order 24414701:

Replace Valve and Tubing for MV-DE-662, Diesel Generator 1-2 Lube Oil Pressure Switch PS-1487 Isolation Valve Work Order 24414506:

Perform Preventive Maintenance on Diesel Generator 1-2 Air Compressor C-38 Work Order 24412151, "load Ventilated Storage Cask No. 05 with Multi-Assembly Sealed Basket No.9" Work Order 24202678, "Replace Relay SSX-3/P-8A/B" on the AFW system The inspector ob~erved portions of the above activiti~s (Work Orders 24414828, 24414701, and 24414506) during a scheduled maintenance outage on Diesel Generator 1~2. Following the maintenance outage, the inspector found several work request tags for minor maintenance hanging on the Diesel Generato Followup revealed that the work requests had either been c~nceled or change The system engineer agreed to remove and update the tags as necessar Surveillance Activities (61726)

During the inspection period, the inspectors observed technical specification required surveillance testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that results conformed with technical specifications and procedure requirements and were reviewed, and that any deficiencies identified during the testing were properly resolve The inspectors also witnessed or reviewed portions of the *

following.surveillances:

o SHO 1, "Technical Specification Surveillance Procedure"

RI 15C, Safety Injection Tank Level Channel Calibration

M0-38, Auxiliary Feedwater System Pumps Inservice Test Procedure

M0-7A-1, EOG 1-1 (K-6A)

M0~7A-2, EOG 1-2 (K-6B)

SOP-8, Testing of Main Turbine Valves/Protective Trips No violations, deviations, unresolved, or inspection followup items were identified in this are.

Engineering and Technical Support (83750, 37700, 92720)

The inspectors monitored engineering and technical support activities at the site including any support from the corporate offic The purpose was to assess the adequacy of these functions in contributing properly to other functions such as operations, maintenance, testing, training,*

fire protection, and configuration managemen Fuel Loading of Multi-Assembly Sealed Basket (MSB) #9 The inspectors observed the following licensee.activities associated with the loading of MSB #9:

Loading of*the MSB and licensee verification of fuel bundles and location in the MSB; Installation of the shield lid onto the MSB; Movement of MSB Transfer Cask out of the spent fuel pool into the washdown pit;.

Decontamination of the MSB Transfer Cas~ and MSB; Vacuum dryi~g, welding, and helium backfilling of the MSB; Transporting the MSB and Ventilated Storage Cask (VSC) *to the storage pad*.

Briefings for ~he work were well conducte Most activities proceeded as planne The licensee experienced a minor problem during the vacuum drying proces Procedure FHS-M-32, "Loading And Placing The VSC Into Storage," Rev.IO, required that the MSB achieve and maintain for 30 minutes a vacuum of 0.050 psi The licensee could only achieve a vacuum of 0.10 psi Plant management suspended further activities and promptly conducted a forma 1 revie Plant management approved a course of actfon to backfill the MSB with helium to pinpoint the location of the lea The licensee found the swagelock fitting on the vent line to be leakin The vent line is used to draw the vacuum and facilitate drying of the MS After further review by plant management, plant engineers implemented an approved modification to cover the vent line

opening and proceed with vacuum dryin The licensee then successfully conducted the vacuum drying evolutio The inspectors found the licensee's actions to be acceptable, as the confinement capability of the MSB was not compromise No credit is taken in the safety analysis for the swagelock fitting as a pressure retaining componen Further leak testing, after the temporary cover was removed and permanent covers welded into place, proceeded acceptably per the normal procedur No other evidence of leaks were found and all acceptance criteria was appropriately me The inspectors discussed the above issue with cognizant personnel from NRC Region III and NRC Office of Nuclear Material Safety and Safeguards (NMSS).

Both groups found the licensee's handling of this issue to be acceptabl The licen~ee has implemented

~ppropriate corr~ctive actions to preclude a reoccurr~nce of this proble Multi-Assembly Sealed Basket Shield Lid Top Plate Charpy Impact Tests On December 22, 1994, the licensee identified that.~he shield lid top material for Multi-Assembly Sealed Baskets (MSB) used in Ventilated Storage Casks (VSC) 01 through 04 were not tested to the requirements of paragraph 3.3.1.a of Safety E~aluation Report dated, April 28, 1993, for the VSC syste That paragraph of the Safety Evaluation Report required charpy impact testing of the MSB pressure boundary materials, parts, components at temperatures of-50°F, with toughness not lower than 15 ft-lb The impact test requirement on the pressure boundary constitutes the basis for the allowed movement of the MSB above ambient temperatures of 0° The *license~ intends to have charpy impact testing performed on sample coupons from the* original shield lid material for the affected shield lid The licensee considers the Multi-Assemb1y Sealed Baskets used in Ventilated Storage Casks 01 through 04 to be operable ~hile at rest on the storage pad based on the following:

A tip over of the MSBs were not possible on the storage pad based on licensee calculations;

-The MSB shield lid top plate was a secondary pressure boundary, while the MSB structural lid plate, bottom lid, and shell were the primary pressure boundar All primary pressure boundary components meet the charpy impact test requirement *

The VSC system continues to meet the postulated accident scenarios as described in the Safety Analysis Repor >-

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The licensee expects to receive the charpy impact test results for the affected MSBs within the next several week The lack of charpy impact testing of the MSB pressure boundary materials, parts, components at temperatures of -50°F, with toughness not*

lower than 15 ft-lbs is considered an unresolved pending further NRC review (50-255/94021-01).

No violations, deviations, unresolved, or inspection followup items were identified in this are.

(Closed) Temporary Instruction 2515/111. "Electrical Distribution System Functional Inspection Followup (Closed) Information Followup Item (255/91019-0l(DRSll:

The EDSFI team identified that the 1988 and 1989 Electrical Load Study did not use the worst case cable loading conditions when calculating the cable voltage drop The following concerns were identified:

..

The study assumed a 75°C temperature for cable sizes No. 8 and smaller, and 65°C for cable sizes No. 6 and larger, when the maximum conductor rating was 90°C for in~talled cable Reactance values used were not applicable to the type of cable installed in the plan Circuit breaker contacts and fuse impedances were not considered in the load stud The "worst case loads" had not included all running motors.

The impedance used for buried cables from the switchyard to Safeguards transformer were different than actual cable i mp_edance *

"

In response, the licensee revised Engineering Analysis EA-ELEC-VOLT-014, Rev 1, to address the above concern The difference in cable voltage drop from the original analysis was minima The inspectors reviewed the engineering analysis and concluded the license~ had adequately addressed the above concern This item

.is close (Closed) Information Followup Item {255/91019-02{0RS)):

The EDSFI team was concerned that system operating procedures did not address potential *safeguards buses high voltage conditions that could result from a stuck safeguards transfo!mer tap changer; In response, the licensee determined that the 2400 volt Clasi IE*

buses should be maintained < 2530 volts to prevent exceeding the voltage limitations of the 2300V and 460V motor Standard operating procedures were tentatively scheduled to be updated by April 11, 199 The operators log the safeguards buses voltage

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once per shif In addition, the expected switchyard voltages were well documented over the past 10 years and no excessive voltage conditions were identified on the safeguards buse The inspectors concluded the licensee had adequately addressed this issue. This item is close (Closed) Information Followup Item (255/91019-03(DRS)):

The EDSFI team was concerned that Startup Transformer 1-2 feedP.r cables to the safeguards buses could exceed their 90°C continuous duty temperature rating when supplying design basis accident loads..

In response, the licensee performed a calculation to determine the time that the cables could be operated at the 105°C emergency overload temperatur The analysis indicated that the cables would not exceed the 105°C limit. However, analyses were ongoing to determine the length of time that the cables could be overloade Once completed, the time limits will be incorporated in the appropriate operating procedure The normal offsite power supply to the safeguards buses was through Safeguards Transformer 1-The team verified Transformer 1-1 feeder cables were adequately size In addition, the emergency diesel generators were also available to supply the safeguards buse The inspectors concluded that ample power sources were available to supply the safeguards buses until the operating procedures were update This item is close (Closed) Information Followup Item (255/91019-04(DRS)):

The EDSFI team questioned the ability for two feeder cables between the plant and station power transformer No. 2 to withstand postulated fault current The potential exists for the two rubber insulated cables to exceed their 200°C emergency overload t~mperature prior to the fault being cleare In response, the licensee revised the FSAR to clarify that the two cables in question (All08/All-X51/l and Al306/Al3-X50/l) could exceed the 200°C. requirement for a short period of time until *

breakers cleared the faul The licensee reviewed the *cables.

routing and determined the cables were not routed with any Class IE cable In addition, the licensee contacted an industry cable exper The expert concluded the cables could withstand the fault current; however, th~ cables would require replacement following exposure to the maximum available fault curren The inspectors reviewed the licensee's analysis and concluded the undersized cables did not represent an operability concer This item is close (Closed) Information Followup Item (255/91019-05(DRS)):

The EDSFI team concluded that nonconservative values for system voltage and cable temperature were used in engineering analysis No. EA-E-ELECT-FLT-10/91-The analysis was prepared to determine the fault duties for the 4160, 2400 and 480 volt circuit breaker In response, the licensee performed engineering analysis N EA-ELECT-~LT-007, Rev 0, to determine if the 4160, 2400 and 480 volt circuit breakers could withstand and interrupt the maximum available short circuit curren As a result, Breaker 52-1112 was recommended for replacement to provide greater interrupting margi The inspectors reviewed the licensee's proposed corrective actions and found them to be acceptable. This item is close (Closed) Information Followup Item C255/91019-06CDRSll:

The EDSFI team noted that existing plant procedures did not provide adequate guidance on how to identify a ground fault on the ungrounded 2400 volt syste In response, the licensee revised Alarm Response Procedure (ARP) No. 3, "Electrical Auxiliaries and Diesel Generator Scheme EK-05," to provide guidance on identifying and isolating a ground fault on the 2400 volt syste The inspectors reviewed the procedure revision and concluded th changes were acceptable. This item is close CC.losedl Information Followup Item C255/91019-07<DRS)):

The EDSFI team was concerned that the 2400 volt electrical system, which was designed to be ungrounded, was susceptible to high voltage *

• transients caused by intermittent ground fault This item was referred to NRR for revie In response, NRR identified that 23 other nuclear and non~nuclear utilities used ungrounded low and medium voltage distribution system A survey of these utilities did not identify any adverse problems attributed with ungrounded system NRR concluded that

~ the use of an ungrounded 2.4 KV distribution system at Palis~des was acceptable. *This item is close (Closed) Information Followup Item (255/91019-0S(DRS)):

The. EDSFI team was concerned that insuffi~ient procedure guidance was provided to the operators as to what switchyard voltage would be acceptable for transferring from the EDGs to offsite power.*

In response, the licensee calculated the minimum switchyard voltages for transferring to the safeguards, startup or station power transformers.. Standard operating procedure No. 30, "Station Power, 11 was currently under revision to incorporate the appropriate switchyard value The inspectors reviewed the proposed procedure changes and concluded the changes were reasonable. This item is close (Closed) Information Followup Item (255/91019-09CDRS)):

The EDSFI team was concerned that the EOG loading calculation did not reflect actual magnitude, start time, and duration of manually started EOG load,*.

'.

In response, the licensee reviewed the current EDG loading profile with Operations. A revised EDG loading calculation was issued and appropriate operating procedures were revised to control. EDG loadin The inspectors reviewed the operating procedures and the loading calculation, and concluded the licensee had adequately addressed this issue. This item is close (Closed) Information Followup Item (255/91019-lO(DRS)):

The EDSFI team noted that certain EDG trips did not use coincident logi The potential exits for spurious tripping of the EDGs when required to mitigate a design basis accident. These trips included the following: o Generator trip on undeispeed ( < 600 rpm) through the field shutdown time *

Engine and generator trip on engine underspeed ( < 120 rpm).

• Engine and generator trip on jacket wate~ low pressure, start circuit B onl *

Engine and generator trip on generator overcurren In response, the licensee stated that several modifications were being prepared to improve EDG reliabilit The above items were included in Faciltty Change (FC) No. 94 This modification was tentatively scheduled for implementation during the 1995 refueling outag The inspectors reviewed the proposed logic changes and concluded the changes should correct the EDSFI team coricern This item is close (Closed) Unresolved Item (255/19019-llCDRSl):

The EDSFI team noted that the load shedding capability of certain equipment were not positively identified during surveillance testin In response, the licensee revised surveillance procedure No. RT-8C, aEngineered Safeguards System - Left Channel," and No. RT-80,

"Engineered Safeguards System - Right Channel," to better document equip.ment load shedding capabilit In addition, the licensee identified that relay No. 194-41 (left channel) contacts that trip feed breaker No. 152-303 would not be tested d~ring the performance of RT-S Instead, the breaker would be verified to trip from relay No. 194-42 (right channel) contacts onl The inspector~ informed the licensee that all safety related contacts need to be tested,' including parallel logic scheme The licensee agreed that breaker No. 152-303 and No. 152-302 (similar testing arrangement) should have both logic paths teste The licensee indicated that a testing method would be developed and implemented during the 1995 refueling outag This was acceptable to the inspector The inspectors did note that the above surveillance procedures did verify that the breakers would trip from the one parallel set of logic contact In addition, the procedures

• positively identified that the above relays had functionally operate Based on the above, the inspectors concluded the breakers and relays were functionally operabl This item is close.

(Closed) Violation (255/91091-12CDRS)):

The EDSFI team was_

concerned that EDG surveillance procedure No. M0-7A-l, "Emergency Diesel Generator 1-1 (K-6A)," and.No. M0-7A-2, "Emergency Diesel Generator 1-2 (K-6B)," start time testing did not include all of the emergency start circuit components in the response time determination (10 seconds). In response, the licensee evaluated the response time of the-untested com~onents, such as the engine start relay (ESR) and the cranking relay (CR).

The licensee determined that the ESR and CR relays actuated in 0.125 second As a result, the licensee revised the monthly EDG surveillance procedures acceptance criteria to verify the EDGs start within 9.5 seconds. *This was acceptable to the inspectors since the acceptance criteria was conservative to actual measured value This item is close (Closed) Violation (255/91019-13(DRS)):

The EDSFI team determined that post modification test procedure No. T-FC-687-001 did not test the control functions associated with Handswitch HS-152-*

106RLTS contacts 3/3C, 4/4C, 5/5C and il/ll In response, the licensee reviewed the above test procedure against the electrical schematics..

The licensee concluded that contacts 3/3C and 11/llC were adequately tested in the test procedur The licensee also verified that contacts 4/4C and 5/5C, though not verifi~d to reopen in the test procedure, were in fact verified open during normal operator verification of Safeguards Bus IC operating curren The inspectors reviewed the test procedure and concluded contacts 3/3C and 11/llC had been adequately teste In addition, the inipectors agreed that the-~

opening of contacts 4/4C a*nd 5/5C would be verified by the operators during normal bus current verification. However, 10 CFR 50, Appendix B, Crite~ion XI, requires that applicable acceptance limits be incorporated into test procedure Verification that contacts 4/4C and 5/5C had opened should have been part of the test procedure acceptance criteria. This item is close (Closed) Deviation (255/91019-15(DRS)):

The EDSFI team concluded that the current EOG starting* circuit design did not conform to FSAR Section 8.4.1.3 requirement The FSAR indicated that each EDG had two independent start circuits on sepafate DC source When in fact, if either the B starting circuit source breaker or the field flashing unit fuse failed, the EDG would not be capable of starting within the required 10 second In response, the licensee indicated that the original purchase specification required dual electric control circuits only for the

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• air start motor The current design does meet this requiremen The licensee is revising the FSAR to clarify the current EOG control circuit desig This was acceptable to the inspectors and this item is close (Closed) Violation (255/91019-16CDRSl):

The EDSFI team noted that on July 18, 1989, September 17, 1990 and September 17, 1991, the Emergency Diesel Generators (EOG) Technical Specification (TS)

limit of 750 amperes load was exceeded during surveillance testin In response, the licensee revised monthly EOG surveillance Procedure Nos. M0-7A-l and M0-7A-The maximum allowable current is now more clearly controlled by these procedure The*

inspectors reviewed the procedures and concluded they were acceptable. This item is close (Closed) Information Followup Item (255/91019-17(DRS)):

The EDSFI team identified several minor discrepancies that existed between single line diagram E-8, Sheets 1 and 2, and other relevant engineering document *

In response, the licensee corrected the discrepancies by DCRs 950-91-1194 and 950-92-28 The licensee performed additional drawing review Several minor discrepancies were identified and were corrected by DCRs 950-93-382, 950-93-347 and 950-93-37 This wa~ acceptable to the inspectors and this item is close (Clo~ed) Violation (255/91019-20(DRS)):

The EDSFI team was concerned that a testing program had not been established to verify the safety related battery chargers could meet their 200 ampere ratin In response, the licensee verified that ~ach ~harger's rated output could be provide In addition, steps were added tJ the refueling outage battery performance and service tests to monitor*

the battery charger output curren The inspectors reviewed the last battery tests and verified each charger could provide 200 amperes of current.* A Periodic and Predetermined Activity Control (PPAC) document was being prepared to schedule a special performance test of each charger once per 5 years. This was acceptable to the inspectors and this item is close (Closed) Deviation (255/91019-21(DRS)):

The EDSFI team identified that the EOG Remote/Local hands~itch alarm*, "Control Switch Not in Automatic," did not exist in the control roo~ as stated in FSAR Section 8.4. In response, the licensee conducted a review of other EOG process parameters, indicators and alarms to determine if other licensing commitments had been misse The licensee concluded that certain

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.

EOG process parameters would require upgradin Modifications were tentatively scheduled for the 1998 refueling outage to upgrade the EOG process control system The inspectors walked down the EOG Remote/Local, Unit/Parallel and voltage regulator Auto/Manual handswitche Black dots were used to identify the correct position of critical control switche Critical control switch positions were independently verified five times per shif In addition, the above switches were verified to be in the correct

_position prior to heat~up at the completion of an outage via

. operation's checklist No. CL 2 Use of the switches were procedurally controlled through standard operating procedure N SOP-22 or EOG monthly.surveillance procedure Nos. M0-7A-1 and M0-7A-The inspectors concluded the licensee had adequate administrative controls in place until appropriate modifications could be implemente This item is close (Closed) Information Followup Item (255/91019-22(0RS)):

The EOSFI team identified several discrepancies in the design documentation associated with the EOG fuel oil storage tank The discrepancie~

included the following: *

Fuel consumption tests were not documente *

• Calculations were inconsistent regarding the capacities of*

the EOG daytanks and belly tank * *

The low level daytank alarm setpoints did not provide for sufficient daytank inventor *

The FSAR, TS and Variou~ engineering analyses stated different EOG running time capabilitie *

The surveillance program did not include a test to verify the EOG daytanks* could be emergency fille In response, the licensee determined the EOGs fuel oil consumption rates and performed an analysis to determine the fuel oil storage tank and daytank usable volume Based on the test results, the licensee concluded the existing fuel oil storage tank low level setpoints were acceptabl Analyses were performed which confirmed that sufficient usable volume existed in the various fuel oil tank In addition, the licensee proceduralized the various emergency fill method The inspectors reviewed the above items and concluded the 1 icensee had-adgquately addressed the discrepancies. This item is closed. -

(Closed) Information Followup Item (255/91019-25(0RS)):

The-EOSFI -

team identified that the EOGs ability to start at minimum hot standby conditions (90°F lube oil and jacket water temperature:

and 65°F room temperature) had not been demonstrate In response, the licensee performed a test at an EOG room temperature of 58 +/- 2°F, and a jacket water, lube oil and engine block temperature of 85° The EOGs successfully started at these minimum design condition In addition, the licensee added the minimum design temperature conditions to the operator round sheet The inspectors reviewed the test procedure and concluded the licensee had adequately demonstrated the EDGs capability to start at their minimum design temperature. This item is close (Closed) Information Followup Item (255/91019-26CDRS)):

The EOSFI team noted that plant procedures did not specifically dictate switchyard work policy when an EOG had been removed from service for maintenance or testin In response, the licensee provided administrative procedure No. 402, "Control of Equipmerit." Specifically, paragraph No. 9.5, "Maintenance LCO Policy," provided guidelines on how to minimize plant risk if an EOG was removed from servic The inspectors reviewed the procedure and concluded the procedure would adequately control switchyard work if an EOG was removed from service. This item is close (Closed) Violation (255/91-019-27CORS)):

The EOSFI team identified that the post modification test* for FC-839 inadequately tested the

_blocking function of charging pump No. P55B low suctirin pressure and low lube oil pressure trips w~en the pump was powered from the alternate pqwer source. *

In response, the licensee satisfactorily tested the above trip function As part of the corrective actions, the licensee evaluated seven additional post modification test The seven modifications were adequately teste In addition, engineering guideline No. EGAD-PMC&T-02, "Guideline for Preparing Modification Test Procedures," was strengthened to include negative testing review This review was used to identify improper logic inputs and to identify the effects of improper output Specifically, to identify that all logic states (open and closed, or on and off)

were verified and that no unexpected operating states were introduce The inspectors reviewed the revised test procedure for FC-839 and concluded the licensee had adequately retested the above trip function This item is close *

The actions of TI 2515/111 were complet No violations, deviations, unresolved, or inspection followup items were identified in this are.

(Closed) Temporary Instruction 2515/126, "Evaluation of Online Maintenance" An evaluation of the impact on safety of the licensee's procedures and practices regarding the removal of equipment from service for on-line

• ..

' '

...

...,).....

maintenance was conducted in accordance with inspection procedures contained in Temporary Instruction (Tl) 2515/12 The inspectors had the following observations:

Probabilistic Risk Assessment (PRA) insights had been incorporated into the scheduling of on-line maintenance including examples of deferred maintenance/testing due to PRA inpu The PRA was conducted using the IPE to determine how significant the increase

.in risk was for that particular day given the equipment that would be unavailable for testing/maintenanc However, the initial PRA was conducted at the request of the operations department through an informal process which did not require the PRA group to receive information regarding degraded and/or inoperable equipment and nd threshold of "significant increase of risk" had been established. Additionally, nothing in place would require a second PRA to be performed if equipment that affected risk became degraded and/or inoperable subsequent to the i nit i a 1 PR *

The licensee's conduct of operations during on-line maintenance avoided other testing and maintenance that would increase the likelihood of a transient.such as no maintenance allowed on PRA risk significant systems during turbine valve testing..

Additionally, the licensee's on-line maintenance guidelines did restrict maintenance activities on systems required to mitigate events if the probability of that particula~ event was increase For examP,le, maintenance was not allowed on systems required to mitigate a LOOP event if the probability. of that event was increased (i.e. weather conditions).

The licensee's process to plan and schedule on~line maintenance would appropriately modify the testing. and maintenance schedules to acc6uni frir degraded or inoperable equipmen The process included meetings conducted twice weekly to discuss the scheduled maintenance at various planning stages which were observed by the inspector One meeting discussed T-6 and T-4 schedules (six and four weeks prior to performing scheduled mairitenance) and the second meeting discussed T-2 and T-1 schedules (two and one week prior to performing scheduled maintenance).

Information specific to each maintenance week such as changing plant conditions, equipment availability, engineering issues, and parts c

avail~bility, were discussed and the maintenance schedules were modified as.necessar *

The inspectors *interviewed various plant personnel and determined that maintenance and operations personnel involved with the planning and scheduling of on-line maintenance were very

.

knowledgeable of the process and its intended implementation structur However, plant personnel not directly involved with scheduling and planning (i.e. shift operators, system engineering)

did not fully understand the intended implementation structur The inspectors attributed -this to the current on-line maintenance process being relatively new (only six weeks old) and that all appropriate plant personnel have not been adequately-informed about the new process and its intended implementation structur The inspectors concluded that the process in place adequately incorporated risk insights when scheduling on-line maintenance and that the schedule would be changed appropriately to account for degraded/inoperable equipmen Additionally, personnel directly involved with planning and scheduling of on-line maintenance were very knowledgeable of the proces However, the licensee's program had been in place for only six weeks and was not proceduralize (The licensee intended to proceduralize the on-line maintenance program around February 1995). On-line maintenance "guidelines" were being used to implement the process and were subject to continuous review and change as part of the d~velopmental stages. Additionally, all appropriate plant personnel have not been adequately informed of the new process and its intended implementation structur *

The actions of TI 2515/126 are complet No violations, deviations, unresolved, or inspection followup item~ were identified in this are.

Report Revi~w During the inspection period, the inspectors reviewed the licensee's monthly operating report for November 199 The inspectors confirmed that the information provided met the reporting requirements of TS 6.9.1.C and Regulatory Guide 1.16, "Reporting of Operating information."

No violations, deviations, unresolved, or inspection followup items were identified in this are Unresolved Items Unresolved items are matters about which more information is req~ired in order to ascert,in whether they are acceptable items, violations, or deviation An unresolved item disclosed during the inspection is discussed in paragraph *

1 Meetings and Other Activities (30703)

On-December 13, 1994, a public meeting was held in Region III to discuss ongoing engineering programs at Palisade The meeting was attended by G. E. Grant, Director, Division of Reactor Safety, T. 0. Martin, Deputy Director, Division of Reactor Projects and X. P. Powers, Engineering Manager, Consumers Power Company, and their respective staffs. -The meeting was held to discuss the state of various engineering programs at Palisades and the licensees actions with regard to these program.

Exit Iritervi ew The inspectors met with the licensee representatives denoted in paragraph 1 during the inspection period and at the conclusion of the inspection on January 6, 199 The inspectors summarized the scope and results of the inspection and discussed the likely content of this inspection repor The licensee acknowledged the information and did not indicate that any of the information disclosed during the inspection could be considered proprietary in natur