IR 05000416/1999005

Insp Rept 50-416/99-05 on 990321-0501.Violations Identified, Being Treated as non-cited Violations.Major Areas Inspected: Aspects of Licensee Operations,Maint,Engineering & Plant Support

ML20207D348
Person / Time
Site:	Grand Gulf
Issue date:	06/27/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20207D338	List: IR 05000416/1999005 ML20207D335
References
50-416-99-05, 50-416-99-5, NUDOCS 9906030314
Download: ML20207D348 (19)

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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-416 License No.: NPF-29 Report No.: 50-416/99-05 Licensee: Entergy Operations, In Facility: Grand Gulf Nuclear Station l

Location: Waterloo Road j Port Gibson, Mississippi 39150 Dates: March 21 through May 1,1999 Inspectors: Jennifer Dixon-Herrity, Senior Resident inspector John Russell, Acting Senior Resident inspector Peter Alter, Resident inspector I

Approved By: Joseph Tapia, Chief, Project Branch A l

ATTACHMENT: Supplemental Inforrnation ,

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9906030314 990527 6

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l 4 EXECUTIVE SUMMARY Grand Gulf Nuclear Station NRC Inspection Report 50-416/99-05 This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection.

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Operations l

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The failure of operators to establish the standby liquid control system flow path prior to l starting Pump A, as directed by the quarterly surveillance, resulting in overpressurization 4 l of the discharge piping, is a violation of Technical Specification 5.4.1.a. This Severity l Level IV violation is being treatad as a noncited violation consistent with Appendix C of

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the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR-GGN-1999-0423 (Section 01.2).

Inappropriate restoration directions for the control rod drive pump, part of a r onsafety- :

related system, resulted in momentary overpressurization of the suction piping and exercising the relief valve each time the system was restored from maintenance (Section 01.3).

• The material condition inside containment, based on inspectors' tours, was acceptable; however, small debris was present, some housekeeping was not good, paint was deteriorating, and a containment foreign materials log was not current. None of these items represented an operability concern for emergency core cooling equipment. The inspectors also observed one example of inattention to detail in that operators had not ,

identified loose latches on the standby gas treatment units during their rounds i (Section O2.1).

• The inspectors identified a poor Operations practice. Operations personnel allowed fuel pool cleanup and reactor water cleanup precoat tank high level annunciators (r.onsafety-related annunciators) to remain in alarm without taking any action to address the condition causing the alarm or to rectify an inconsistency in the procedures (Section O3.1).

• The inspectors found that operators were not aware of the existence of indication flags on Bus 17AC degraded voltage relays or how to reset them following an automatic start and loading of the high pressure core spray diesel generator. No training on this aspect of the equipment had been provided to the operators (Section 04.1).

• The failure to conduct a surveillance to verify the electrical lineup within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of declaring the diesel inoperable on October 9,1998, was a violation of Technical Specification 3.8.1. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 1998-1075. This closed LER 98-005-00

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(Section 08.1).

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Maintenance l

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' Eight maintenance and testing activities observed were performed properly with the

- exception of the following concerns. A maintenance activity involving troubleshooting leakage in the standby service water system demonstrated a potential inadequacy in the

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. existing site program for equipment control in that there was no procedural guidance to q L determine when a clearance or protective tagging is required or to direct personnel to J

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which method of equipment control should be used. Although the equipment was retumed to the appropriate configuration following maintenance, informal configuration L

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control and poor communications resulted in personnel in the field not being aware that a tank they were using for indication had been isolated so that work had to be repeate During a different maintenance activity, poor communications between system i engineering and work planning groups, during the planning process, resulted in

- replacement of the least suspect valve during troubleshooting and repair of CRD12-13 directional control valves (Section M1.5).

• The failure of instrument and controls technicians to follow a surveillance procedure, l

! resulting in the inadvertent closure of reactor core isolation cooling containment inboard )

steam isolation Valve E51F063 on February 7,1999, is a violation of Technical -

Specification 5.4.1.a. This Severity Level IV violation is being treated as a noncited l

violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in l the licensee's corrective action program as CR-GGN-1999-0167. This closed LER 99-002 (Section M8.1).

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• The engineering evaluation conducted in response to overpressurization of the standby

, liquid control system discharge piping was thorough and technically sound -

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- Plant Support

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• Locked high radiation doors were properly controlled, high radiation and contamination l areas were properly posted, and radiological area survey maps accurately reflected radiological conditions in the respective areas (Section R1.1).

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Reoort Details

. Summarv of Plant Status

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The plant operated at 100 percent power throughout the inspection perio l. Operations

~ 01 ' , Conduct of Operations ,

O1.1 General Comments (71707) -

The inspectors' performed control room observations to ascertain operator knowledge and performance. Operations shift tumovers and briefings were thorough and well conducted. Operators were knowledgeable of the status of equipment, and applicable Technical Specification limiting conditions for operations were appropriately documented.- ,

The inspectors also observed off-normal operations in the control room and in the plan These observations included operator response to an unexpected automatic start of the high pressure core spray (HPCS) diesel generator. This infrequently performed evolution was well controlled by control room operator .2 Standbv Liauid Control (SLC) System Overoressurization Inspection Scooe (71707)

On April 4,1999, during surveillance testing, operators started SLC Pump A with no available discharge flow path. This resulted in lifting SLC Pump A discharge relief Valve 1C41F029A and damaging local pump discharge pressure Gage 1C41R003. The inspectors reviewed sun /eillance Procedures 06-OP-1C41-M-0001," Standby Liquid Control Operability," Revision 101, and 06-OP-1C41 O-0001, " Standby Liquid Control Functional Test," Revision 10 Observations and Findinas Following completion of the monthly surveillance on SLC Train B, as had been standard practice, the operators immediately performed the quarterly surveillance of SLC Pump A. In this case, the operators did not completely restore the system valves to their normal standby lineup before lining up the system to perform the quarterly -

surveillance. Operators closed recirc to test tank isolation Valve 1C41F220, which was open.for the Train B monthly surveillance, but did not open recirc to test tank isolation

' Valve 1C41F221 before they started SLC Pump A for the quarterly surveillance. When operators started SLC Pump A, they observed that the 0-2000 psig local Gage 1C41R003 was reading off scale high and that discharge relief Valve 1C41F029A lifted. The operators immediately secured the pump. The shift superintendent directed the operators to isolate the SLC Pump A discharge from SLC Train B, declared SLC Train A inoperable, entered Technical Specification 3.1.7.A., and initiated CR-GGN-1999-0423. The licensee determined that the nonficensed operators who performed the valve lineup to restore from the SLC Train B monthly surveillance and

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prepare for the SLC Pump A quarterly surveillance did not complete the valve restoration in step 5.15 of Procedure 06-OP-1C41-M-0001 and did not perform the valve lineup in step 5.1.6 of Procedure 06-OP-1C41-O-0001. The effect of the overpressurization is discussed in Section E1.1. The operators declared SLC Train A :

operable following successful completion of the quarterly surveillanc l Technical Specification 5.4.1.a states, in part, that procedures recommended in !

Appendix A of Regulatory Guide 1.33," Quality Assurance Program Requirements (Operations)," Revision 2, shall be implemented. SLC system surveillance procedures are covered by Regulatory Guide 1.33, Appendix Conclusions The failure of operators to establish the SLC system flow path prior to starting Pump A, as directed by the quarterly surveillance, resulting in overpressurization of the discharge piping, is a violation of Technical Specification Section 5.4.1.a. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy (NCV 50-416/9905-01). This violation is in the licensee's corrective action program as CR-GGN-1999-042 .3 Control Rod Drive (CRD) Hydraulic System Overoressurization Inspection Scoce (71707)

On April 19,1999, while performing a partial removal of a clearance for postmaintenance testing of CRD Pump A seal water check Valve 1C11F434, operators overpressurized the CRD Pump A suction piping. The inspectors reviewed Clearance GG-99-0754, the partial clearance removal forms, and P&lD M-1081 A,

" Control Rod Drive Hydraulic System," Revision 3 I Observations and Findinos The plant supervisor authorized a partial clearance removal on check Valve 1C11F434 to leak check the union after replacement of the union gasket. Based on a review of !

Clearance GG-99-00754 and an interview with the plant supervisor involved, the inspectors established the following sequence of events. When operators opened CRD pumps positive pressure isolation Valve 1C11F017 to pressurize the CRD Pump A positive pressure sealline, water came from the open CRD Pump A vent Valve 1C11F019A. Operators immediately closed Valve 1C11F017, and the partial clearance removal was amended to close Valve 1C11F019A before opening Valve 1C11F017. After closing Valve 1C11F019A, the positive pressure sealline was pressurized by opening Valve 1C11F017. At this time, the operators observed that the CRD Pump A suction pressure exceeded 150 psig and that the pump suction relief Valve 1C11F001 A lifted. Operators isolated the seal water from CRD Pump A and the relief valve reseated. The shift superintendent ordered the original clearance rehung, declared CRD Pump A out of service, and wrote Condition Report CR-GGN-1999-0439 to document the even I

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Subsequent engineering evaluation determined that the pressure relief valve provided adequate protection for the CRD Pump A suction piping because of flow limiting orifices in the seal water supply line from the operating CRD Pump B. Based on conversations with the shift superintendent and an operations superintendent's assistant, the inspectors determined that the valve slignment sequence that caused the overpressurization was the normal sequence for restoration of the CRD pumps following a system tag-out. Procedure 01-S-06-1, " Protective Tagging System," Revision 40, step 6.7.4.b states "He [the operator] will remove the tags in the order specified, and place the equipment in the position indicated on the Clearance Removal form." The operator I followed the procedure and caused the overpressurization of the system.

The failure to provide adequate procedures for the startup of the CRD system is a violation of Technical Specification 5.4.1.a. However, the system is a nonsafety-related system, and the safety significance of the overpressurization was low as the equipment was not damaged because the safety relief valve performed its design function. This failure constitutes a violation of minor significance and is not subject to formal enforcement action. Operations personnel plan to place a caution in the procedure and to revise the standard tag-out to prevent overpressurization of the syste Conclusions Inappropriate restoration directions for the CRD pump, part of a nonsafety-related system, resulted in momentary overpressurization of the suction piping and exercising l the relief valve each time the system was restored from maintenanc Status of Facilities and Equipment O2.1 Plant Walkdowns I Insoection Scope (71707)

During the inspection report period, the inspectors walked down areas of the plan Observations and Findinos

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l On April 2 and 7,1999, the inspectors toured inside containment. The material condition inside containment was generally acceptable with several minor exception Minor debris was present in the cable trays and on the floors. Debris included plastic

, wraps, dust, and wire. The debris was too small to clog the suppression pool suction

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l strainers, so it did not represent an operability concern for emergency core cooling pumps. Paint had worn off many components. Housekeeping was poor adjacent to the l primary sample sinks; a pair of pliers had been left half in and half out of the contaminated area, an unlabeled ladder was staged adjacent to the sampling sink, and sampling equipment was left inside the sample sink. In addition, the inspectors noted that a foreign material log located outside the personnel access to containment did not appear to be current. The log was intended to be used to record all equipment taken in j and out of containment. The log's purpose was to confirm that items taken into j containment were removed. As a result of the inspector's questions, the licensee found

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that some items taken out of containment had not been logged out. The licensee I removed the pliers and updated the containment foreign materials log.

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On April 23,1999, the inspectors observed that one latch on one door in each train of the standby gas units was left undone. The inspectors informed the plant supervisor in the control room of the concern. The supervisor had the latch tightened. Each of the doors on the units have six latches, so the leakage into the unit would have been minimal. The licensee initiated CR-GGN-1999-0452 to document the issue. The l inspectors found that operators on rounds exhibited inattention to detail in not identifying

! the loose latches, Conclusions l The material condition inside containment, based on inspectors' tours, was acceptable; however, small debris was present, some housekeeping was not good, paint was deteriorating, and a containment foreign materials log was not current. None of these items represented an operability concern for emergency core cooling equipment. The inspectors also observed one example of inattention to detail in that operators had not identified loose latches on the standby gas treatment units during their round Operations Procedures and Documentation O3.1 Annunciator Continuousiv in Alarm l Insoection Scoce (71707)

The insoectors reviewed the procedures and alarm response instructions related to the reactor water cleanup (RWCU) and fuel pool cooling and cleanup (FPCC) precoat tank level high annunciators after observing that the annunciators were continuously in alarm during plant tours.

1 Observations and Findinas

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The inspectors observed that the RWCU and FPCC precoat high level annunciators were illuminated on the local status panels in containment and that the level was high in the tanks. Through discussions with personnel, the inspectors found that the control room operators were unaware that this local annunciation was in alarm. During previous l plant walkdowns, the inspectors noted the same annunciators illuminated and informed the operating crew on watch at that time. The inspectors discussed the annunciators with the acting operations manager and determined that the operating procedure directed operators to fill the precoat tank to a level above the annunciator set point. The l annunciator response instruction directed operators, when the annunciator illuminated, ,

to lower the precoat tank level below the annunciation setpoint if necessary. Because j the operating procedure and the annunciator response instruction did not agree with respect to tank level, the high level condition had apparently been accepted or unnoticed by operators and the annunciators were no longer serving their function. The acting operations manager agreed to resolve the proceduralinconsistency. The inspectors found that operations personnel had not been aggressive in ensuring that changes to the procedures were made in order to provide consistency. The safety significtmce of maintaining the tank levels above the annunciator setpoints was low, because the purpose of the annunciator was to prevent spills from the tank. The tanks were not overflowin ,

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The inspectors identified a poor Operations practice. Operations personnel allowed '

RWCU and FPCC precoat tank high level annunciators (nonsafety-related annunciators)

to remain in alarm without taking any action to address the condition causing the alarm or to rectify an inconsistency in the procedure l 05 Operator Training and Qualification O Division lli Encineered Safety Features (ESF) Bus Undervoltaae a, inspection Scooe (71707)

On March 24,1999, one of two incoming 500 KVAC lines to the site was lost causing a I momentary drop in voltage to the Division 111 ESF Bus 17AC. As a result, a degraded {

bus voltage trip occurred, causing the Bus 17AC feed from ESF Transformer 12 to '

open, the HPCS diesel generator to start, and the HPCS diesel generator output breaker to close, re-energizing Bus 17AC. The inspectors observed the operator !

response to the Bus 17AC degraded voltage and reviewed Procedure 04-1-01-P81-1, !

"High Pressure Core Spray Diesel Generator," Revision 4 Observations and Findinas in preparation for shutdown of the HPCS diesel generator, the plant supervisor sent a nonlicensed operator to Bus 17AC to verify that no relay trip flags were showing faults on the bus. The inspectors observed the nonlicensed operator scan Bus 17AC for relay trip indicating flags. Since there were no overcurrent relay trip flags showing, the l nonficensed operator reported to the control room that there were no relay trip flags showing. The inspectors observed that 11 of 12 degraded or undervoltage relay flags were showing on Bus 17AC. Following shutdown of the HPCS diesel generator, the inspectors asked the plant supervisor if he was aware that degraded voltage Relay 127-2A-17AC did not trip. The plant supervisor was not aware of any undervoltage relay flags on Bus 17AC. Discussions with the operators revealed that they did not know what the orange flag on the undervoltage relays indicated or how to reset i The shift superintendent wrote CR-GGN-1999-0364, documenting the lack of knowledge of the Bus 17AC degraded and undervoltage relays on the part of the nonficensed operators. The operator training department conducted "just-in-time" training on

" Resetting Undervoltage Relay indicating Flags" for alllicenced and nonlicensed

, operators. In addition, the operators had electrical maintenance bench test j Relay 127 2A-17AC. The relay bench tested satisfactorily, l

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-6- Conclusions The inspectors found that operators were not aware of the existence of indication flags on Bus 17AC degraded voltage relays or how to reset them following an automatic start and loading of the HPCS diesel generator. No training on this aspect of the equipment had been provided to the operator Miscellaneous Operations issues (92700,92901)

0 (Closed) Licensee Event Report 50-416/98-005: Delinquent limiting condition for operation action due to inadequate work practices. Technical Specification 3.8.1 was not met on October 9,1998, when operations personnel failed to perform a required surveillance to verify the electricallineup within one hour of declaring the Division til diesel inoperable. The licensee identified the root causes as less than adequate personal accountability for the completion of limiting conditions for operation actions and personnel failing to communicate vital information. The corrective actions taken or

. identified included issuing a memo to all senior reactor operators to reinforce the l expectation that limiting conditions for operation actions are taken within the required time limits and revising the procedure used to control limiting conditions for operation so that entrance into limiting conditions for operation is communicated to the control roo The issues identified in this licensee event report were appropriately addressed. The failure to conduct the surveillance within one hour of declaring the dieselinoperable was a violation of Technical Specification 3.8.1. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-416/9905-02). This violation is in the licensee's corrective action program as CR-GGN-1998-107 .2 Administrative Closure of Violations Based Upon Chanaes in the Enforcement Policy The inspectors performed an in-office review of violations that are outstanding in the operations area. The Severity Level IV violation listed below was issued in a Notice of Violation prior to the March 11,1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy).

Because this violation would have been treated as noncited violation in accordance with Appendix C, it is being closed out in this report. The inspectors verified that the licensee j had generated a corrective action program reference (CR, nonconformance report l (NCR), or both) for the violation listed, in addition, the violation was generated with no response required.

l Violation Number Description CA Program Reference

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l 50-416/9813-01 Failure to install temporary CR-GGN-1998-0014-04 restraining cables on floor gratings Review of the effectiveness of the corrective actions for selected violations will be performed in the future as a routine part of the review of the corrective action program.

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M1 Conduct of Maintenance M1.1 General Maintenance Comments i Inspection Scope (62707)

The inspectors observed portions of maintenance activities, as specified by the following maintenance action items (MAls):

• 19890069 Install modified flow control trip reference card

= 252667 Troubleshoot and repair standby service water (SSW) Train B i leakage ,

• 252022 Average power range monitor modem installation  ;

• 251746 Sample oil in HPCS diesel generator bearings  ;

• 250939 Meg residual heat removal Pump C motor via dummy breaker l Observations and Findinas The inspectors found the performance of this work to be satisfactory, with the exception of the concerns discussed in Sections M1.2 and M1.3. All work observed was conducted in accordance with the instructions and procedures provided in the work packages. The technicians performing the tasks were knowledgeable of the equipment and used good work practices. Operations personnel were aware of the number of annunciators that would alarm during the modem installation and took extra precautions to ensure that no other work that would affect the control room was conducte i M1.2 Troubleshootina SSW Leakaae

Inspection Scope (62707)

The inspectors observed system engineers, mechanics, and an electrician perform !

portions of MAI 252667 in order to troubleshoot and repair SSW Train B leakage. The inspectors spoke with the plant supervisor controlling portions of the plant configuration associated with the maintenance and reviewed portions of Procedure 01-S-07-1,

" Control of Work on Plant Equipment and Facilities," Revision 34, l Procedure 07-S-01-228, " Troubleshooting," Revision 2, Procedure 01-S-06-1,

" Protective Tagging System," Revision 40, and Procedure 02-S-01-2, " Control and Use of Operations Section Directives," Revision 3 Observations and Findinas On April 4,1999, operators ran SSW Train B to add chemicals. When the operators l stopped the SSW Pump B, they noted that SSW head tank level began to decrease, such that automatic makeup initiated about every 10 minutes. The SSW head tank was

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located on the 208-foot level of the auxiliary building, and supplied makeup water and l static pressure to prevent system voiding for all three loops of SSW. Each loop had a

-8-normally open isolation valve from the head tank. SSW Train B Basin level also began to rise, indicating leakage through one or more of three normally shut valves; SSW Train B loop return to the cooling tower isolation Valve 1P41F005B, SSW Pump B recirculation to the basin isolation Valve 1P41F0068, and SSW Pump B to the loop isolation Valve 1P41F001B.

On April 5,1999, licensee personnelimplemented MAI 252667 to determine which of the valves was leaking. Each of the valves was a 20- or 24-inch, motor-operated, butterfly valve. The maintenance and engineering personnel used an enhanced sound monitor to listen for flow noises across each valve and verified valve position by removing an access plate and checking the position of a key-way that rotated as the valve disc rotated. The licensee personnel initially verified no leakage across Valve 1P41F005B, th9n some leakage across Valve 1P41F006B. In accordance with MAI 252667, a knife Ewitch was installed in the Valve 1 P41F006B actuator, in order to prevent electrical rr.ovement of the valve, and the closed limit switch was adjusted to provide full closure of the valve, which appeared slightly open.

The work described above was performed without the use of protective tags, which were not prescribed by the work authorization. Operations personnel had, as a prudent measuru, racked out and opened the SSW Pump B breaker, disabled the Division ll standby diesel generator from automatic start, and closed head tank to SSW Train B isolation Valve 1P41F107B. The positions of Valve 1P41F1078 and the SSW Pump B breaker were controlled through use of a status board in the main control room.

Operations personnel explained that this practice was allowed by step 6.10.5 of Procedure 02-S-012. This section addressed temporary component status changes, such as opening air valves or taking manual control of controllers. The inspectors found that not using a more formal method of equipment control, such as red tags or a procedure to control the positions of Valve 1P41F1078, the pump breaker, and the emergency diesel status, was a poor practice. In this case, the barriers to inadvertent operation and to ensure the system was returned to service properly (independent verification, the presence of a red tag on the component) were not in place.

Procedure 07-S-01-228 stated to ensure proper safety concerns are addressed including red tags where needed. Procedure 01-S-07-1 only contained a checklist with tagging listed under "obtain permits". The purpose of red tags, as stated in Procedure 01-S-06-1, was to provide an administrative control of equipment to prevent personnelinjury or damage to equipment. This procedure contained a note that stated that some work processes could be controlled with approved procedures or work control documents and might not require a protective tag clearance. Step 6.2.2 of the Procedure 01-S-06-1 stated that "When equipment is tagged and associated equipment could be damaged if operated, then the associated equipment will also be tagged. . .

This also includes assessing pump minimum flow requirements when flow paths are to be isolated, and tagging the associated pump if minimum flow would not be available."

In this case, there were no red tags or clearances; however, the diesel could be damaged while the SSW pump breaker was racked out and the pump flow path was affected during the troubleshooting because the pump discharge and system return to the basin were being manipulated. The assistant operations superintendent explained that this paragraph did not apply because no clearance or tagging had been requeste l I

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-9-The inspectors were concerned that there was no guidance in the procedures directing when a clearance and tagging were required or who was responsible for making the determination. Discussions with tagging personnel indicated that the only guidance was the purpose statement in Procedure 01-S-06-1. The inspectors discussed this concern with the operations superintendent. The superintendent reviewed the concern and stated that it was management's expectation that the tagging program or MAI work instruction steps should have been used to control the evolution. CR-GGN-1999-0462 was initiated to address the concer The inspectors noted that some engineering personnel involved in the troubleshooting activity were not aware that Valve 1P41F107B was closed when flow noises were checked at Valves 1P41F005B and 0068. The engineers were unable to determine if the lack of flow noise at Valve 1P41F005B was caused by Valve 1P41F1078 being closed and consequently isolating the source of water for flow past Valve 1P41F005 Some of the troubleshooting had to be repeated as a result of this system alignmen The inspectors found that the engineers' lack of knowledge concerning system alignment during the troubleshooting activity was indicative of poor communication M1.3 CRD Directional Control Valve Replacement Inspection Scoce (62707)

Maintenance technicians replaced CRD 12-13 withdraw exhaust directional control Valve 1C11F420CC. The licensee identified that the valve that should have been replaced was CRD 12-13 insert exhaust directional control Valve 1C11F421CC. The inspectors reviewed MAI 252661," Troubleshoot to Determine the Cause of Control Rod [12-13) Not Moving," and available written guidance from systems engineering to the work week managers regarding the rework of CRD 12-13 directional control valve Observations and Findinos On April 3,1999, operators were unable to withdraw control Rod 12-13 during routine control rod exercising. The control rod was fully inserted, in accordance with applicable procedures, and CR-GGN-1999-0406 was written to determine the cause of the problem with CRD 12-13. Systems engineering and mechanical maintenance performed troubleshooting on CRD 12-13 directional control valves, in accordance with mal-252661. On April 15,1999, system engineering developed a work plan to replace insert exhaust directional control Valve 1C11F421CC as rework under the same troubleshooting work package. The CRD system engineer sent a written work plan to the work week manager and verbally discussed the plan with the mechanical work planner. The work instructions were written to replace withdraw exhaust directional control Valve 1C11F420CC. On April 20,1999, Valve 1C11F420CC was replaced. The error was discovered by the control room operators prior to postwork testin CR-GGN-1999-0441 was written, and the MAI was amended to replace Valve 1C11F421CC. The safety significance of the error was low because both valves could have been causing the problem, but Valve 1C11F421CC was more suspect. On April 21,1999, Valve 1C11F421CC was replaced and CRD 12-13 was retested satisfactoril !

-10-l Based on interviews with the CRD system engineer and the work week managers, the inspectors determined that the error in the valve identification occurred due to poor communications between the system engineer and the mechanical work planner and the unplanned absence of the assigned work week manager during the week of April 2 During the package review, the inspectors questioned why the as-found data for the condition of the directional control valve manifold filters and the position of the withdraw speed control needle valve had not been documented in the completed work packag The inspectors noted that P&lD M-1081B did not show the location of the directional control valve manifold filters. The licensee stated the data would be added to the work package and that the filters would be added to the drawing.

M1.4 General Surveillance Comments Inspection Scope (61726)

The inspectors observed portions of the following surveillances:

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• 06-OP-1C11 W-0001 Control Rod Operability l

• 08-S-04-954 Postaccident Liquid in-Line Chemistry Analysis and Grab Sampling

• 06-OP-1 P81-M-0002 HPCS Diesel Generator 13 Functional Test Observations and Findinas The inspectors noted that the surveillance procedures provided clear guidance and properly implemented Technical Specification requirements. Measuring and test equipment was verified to be within its current calibration cycle. As necessary, instrumentation was removed from service, applicable limiting conditions for operation were entered, and the instrumentation was properly returned to service. The operators and technicians were very knowledgeable and qualified. The personnelinvolved demonstrated good communications and attention to detail.

M1.5 Conclusions on Conduct of Maintenance i

Eight maintenance and testing activities observed were performed properly with the !

exception of the following concerns. A maintenance activity involving troubleshooting l leakage in the SSW system demonstrated a potentialinadequacy in the existing site program for equipment control in that there was no procedural guidance to determine -

when a clearance or protective tagging was required or to direct personnel to which method of equipment control should be used. Although the equipment was returned to )

the appropriate configuration following maintenance, informal configuration control and i poor communications resulted in personnel in the field not being aware that a tank they l were using for indication had been isolated so that work had to be repeated. During a i different maintenance activity, poor communications between system engineering and j work planning groups, during the planning process, resulted in replacement of the least j

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suspect valve during troubleshooting and repair of CRO 12-13 directional control valve !

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-11-M8 Miscellaneous Maintenance issues (92700,92902)

' M8.1 (Closed) Licensee Event Report 99-002: Engineered safety features actuation, due to inattention to detail. This event involved an inadvertent closure of reactor core isolation

. cooling (RCIC) containment inboard steam isolation Valve 1E51-F063 on February 7, 1999, while instrument and control technicians were performing Attachment 12, "RCIC ,

Steam Pipe Tunnel, High Temperature Calibration, Channel F,".of J Procedure 06-IC-1E31-A-1002," Main Steam Line Tunnel, RCIC Steam Pipe Tunnel, and RCIC Equipment Room High Temperature Calibration (PCIS, RCIC, and RWCU lsolation)," Revision 103. The technicians had used a " Fluke" digital voltmeter, set to the Ohms mode, to verify an open circuit between two terminals in Panel 1H13-P64 The technicians left the voltmeter attached and, when a lead previously lifted was landed, the inadvertent RCIC isolation occurred. The voltmeter provided a circuit path that caused the RCIC isolation. Technical Specification 5.4.1.a states, in part, that procedures recommended in Appendix A of Regulatory Guide 1.33," Quality Assurance Program Requirements (Operations)," Revision 2, shall be implemented. Step 5.19.8 of Procedure 06-IC-1E31-A-1002 directed the technicians to verify no continuity between Terminals AA-36 and AA-38 and did not direct that test equipment be installed for longer than the duration of the verification. Procedure 06-IC-1E31-A-1002 is applicable to Regulatory Guide 1.33. The failure to implement Procedure 06-IC-1E31-A-1002 properly is a violation Technical Specification 5.1.4.a. This Severity Level IV violation is 4 being treated as a noncited violation, consistent with Appendix C of the NRC '

Enforcement Policy (NCV 50-416/9905-03). This violation is in the licensee's corrective action program as CR-GGN-1999-016 ,

Operator actions, once the inadvertent isolation occurred, were good. Technical Specification limiting conditions for operation Action 3.5.3 was entered, maintenance l work was stopped, and RCIC was restored in about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, a time less than the 14-day limiting conditions for operation allowable outage time for RCI M8.2 (Closed) Licensee Event Reoort 99-003: Manual reactor scram due to decreasing condenser vacuum. The issues in this event report were addressed in NRC Inspection Report 50-416/99004, Section M2.1 and Section 01.1. The event report was complete and accurat M8.3 Administrative Closure of Violations Based Upon Chanaes in the Enforcement Poliev The inspectors performed an in-office review of violations that are outstanding in the maintenance area. The Severity Level IV violation listed below was issued in a Notice of Violation prior to the March 11,1999, implementation of the NRC's new policy for .

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treatment of Severity Level IV violations (Appendix C of the Enforcement Policy).

Because this violation would have been treated as a noncited violation, in accordance with Appendix C, it is being closed out in this report. The inspectors verified that the licensee had generated a corrective action program reference (CR, NCR, or both) for the violation listed. In addition, the violation already has a docketed respons l

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-12-Violation Number Description CA Program Reference 50-416/9805-04 Failure to ensure clearance from CR-GGN-1998-0298-00 safety-related equipment was evaluated Review of the effectiveness of the corrective actions for selected violations will be performed in the future as a routine part of the review of the corrective action progra Ill. Enaineerina E1 Conduct of Engineering l

E1.1 Evaluation of SLC Pioina Overoressurization l

l a. Insoection Scope (37551)

The inspectors reviewed Engineering Request 99/143-00," Evaluation of Overpressurization of SLC Pump C001 A Discharge Piping" and Calculation MC-Q1C41-99006,"SLC Pump Discharge Piping Overpressurization," l Revision I

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b. Observations and Findinas The evaluation of the components and common piping between the SLC Trains A and B that had been overpressurized was thorough. The calculation determined that the SLC l '

system pressure reached an estimated 2212.9 psig and that there were no adverse effects on the affected system components, with the exception of the pump discharge i pressure gage,1C41R003, which was replaced. With the exception of l Gage 1C41R003, all equipment was rated or tested to 2250 psi or greate Conclusions The engineering evaluation conducted in response to overpressurization of the SLC system discharge piping was thorough and technically soun E8 Miscellaneous Engineering issues (92700,92903)

E8.1 (Closed) Insoection Followup Item 98-17-01: Review current transformer root cause analysis. This item was opened to assess the results of licensee current transformer inspections and to assess root cause of the current transformer and ground detector

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degradations. The inspectors reviewed data assembled by engineering personnel l concerning the results of the inspections and interviewed engineering personne Approximately 10 percent of the safety-related current transformers and ground detectors encapsulated in the epoxy compound had softened or reverted back to liquid (25 of the 256 total). Approximately 3 percent of the nonsafety-related encapsulated components inspected had softened or reverted back to liquid (9 of the 285 total inspected, with 285 being about one half the total plant population). No component failures resulted from the softening or reversion.

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l-13-l The inspectors noted that the current transformers and ground detectors were used in

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480 volt,4.16 kV, and 6.9 kV applications. Higher voltage applications contained a separate insulator, between the current transformer and the switchgcar or breaker sta Lower voltage (480 volt) applications contained mounung components, for the current transformer, that were secured in the epoxy. Consequently, if lower voltage current transformers liquified, the transformer could directly contact the breaker or switchgear stab and cause a short circuit. Higher voltage applicaticns would be less likely to cause a short circuit if the epoxy liquified because of the separate insulator and because the transformer mounting was not secured by the epoxy. The possibility of failure was generally limited to the lower voltage current transformers. The function of the red epoxy was to provide structural integrity and insulation for voltage or current excursions caused by lightning strikes. The licensee tested various current transformers that had degraded, and the results confirm that no component failures had taken place. Based on the lack of component failures, the inspectors found that the safety significance of the as-found current transformer degradation was low; however, potential failure of low voltage applications did give the degradation significance.

l The licensee replaced some of the susceptible safety-related current transformers with components not susceptible to the degradation and planned to replace all susceptible safety-related components. The inspectors found that this would alleviate concerns that the inspection frequency for these components was greater than the 18-month l frequency recommended in a 1989 Asea Brown Boveri 10 CFR Part 21 report. The licensee also planned on placing the susceptible components in Category a(1) of j 10 CFR 50.65, the Maintenance Rule. The inspectors found these actions pruden The licensee generally determined that the progression for degradation of the red epoxy on susceptible components was as follows: (1) the red epoxy would exhibit a shiny glossy sheen, (2) soften, (3) become tacky and fail a thumbnail imprint test, and (4) revert to liquid. Factors influencing the degradation were the amount of hardener used in the epoxy (more hardener leading to a greater propensity to degradation) and the humidity in the component's environment (higher humidity leading to a greater propensity to degradation). The licensee determined that the components being in service did not appear to affect the propensity for degradation. The 18-month frequency for inspection recommended in the 10 CFR Part 21 report appeared to be sufficient to ensu,e that failure would not occur, if the component was replaced when softening or degradation was noted. The inspectors found that licensee actions to understand the progression of the degradation were goo E8.2 (Closed) Licensee Event Report 99-001: Plant shutdown due to inoperable diesel generator. The issues in this event report were addressed in NRC Inspection Report 50-416/98-17, Sections O1.3 and E1.1., and are addressed in Section E8.1 of this report. Tha event report was complete and accurate.

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-14-1 E8.3 Administrative Closure of Violations Based Upon Chanaes in the Enforcement Policy i l The inspectors parformed an in-office review of violations that are outstanding in the engineering area. The Severity Level IV violation listed below was issued in a Notice of

. Violation prior to the March 11,1999, implementation of the NRC's new policy for I

treatment of Severity LevelIV violations (Appendix C of the Enforcement Policy).

Because this violation would have been treated as a noncited violation, in accordance j with Appendix C, it is being closed out in this report. The inspectors verified that the I licensee had generated a corrective action program reference (CR, NCR, or both) for the violation listed. In addition, the violation already has a docketed respons Violation Number Description CA Program Reference 50-416/9813-02 Failure to follow procedures CR-GGN-1998-0560-00 1 resulting in near drop of tool ring Review of the effectiveness of the corrective actions for selected violations will be performed in the future as a routine part of the review of the corrective action progra IV. Plant Support R1 Radiological Protection and Chemistry Controls R General Comments (71750)

The inspectors made frequent tou s of the radiological controlled area and observed radiological postings and worker adherence to protective clothing requirements. The inspectors found that locked high radiation doors were properly controlled, high radiation and contamination areas were properly posted, and the radiological area survey maps

, accurately reflected radiological conditions in the respective areas. The health physics

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technicians observed during the maintenance tasks were aware of radiological conditions and the work being performed. The inspectors observed as a chemistry technician sampled residual heat removal Train B, as discussed in Section M R8 Miscellaneous Radiological Protection and Chemistry lasues (92904)

R (Closed) Escalated Enforcement Issue 9811-01: Use of neutron monitor. This issue was addressed in NRC Inspection Report 50-416/9814 and noncited Violation 50-416/9814-01 was identifie V. Manaaement Meetinas l

X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 5,1999. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

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ATTACHMENT

, PARTIAL LIST OF PERSONS CONTACTED Licensee D. Bost, Manager, Plant Maintenance C. Bottemiller, Superintendent, Plant Licensing B. Carroll, Superintendent, Operations D. Cupstid, Manager, Operations Technical Support W. Eaton, Vice President

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B. Edwards, Manager, Work Control K. Hughey, Director, Nuclear Safety and Regulatory Affairs C. Lambert, Director, Design Engineering J. Roberts, Director, Quality Programs NRC P. Sekerak, NRR Project Manager INSPECTION PROCEDURES USED 37551 Onsite Engineering 61726 Surveillance Observations 62707 Maintenance Observation 71707 Plant Operations 71750 Plant Support Activities 92700 Onsite Followup of Written Reports of Nonrcutine Events at Power Reactor i Facilities j 92901 Followup - Operations 92902 Followup - Maintenance 92903 Followup - Engineering 92904 Followup - Plant Support ITEMS OPENED. CLOSED. AND DISCUSSED Ooened 50-416/9905-01 MCV Failure to Follow Procedures Resulting in Overpressurization of Standby Liquid Control (Section 01.2)

50-416/9905-02 NCV Delinquent Limiting Conditions for Operation Action Due to inadequate Work Practices (Section 08.1)

50-416/9905-03 NCV Engineered Safety Features Actuation Due to Inattention to Detail (Section M8.1)

Closed 50-416/9905-01 NCV Failure to Follow Procedures Resulting in Overpressurization of Standby Liquid Control (Section 01.2)

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50-416/9905-02 NCV Delinquent Limiting Conditions for Operation Action Due to inadequate Work Practices (Section 08.1)

50-416/9905-03 NCV Engineered Safety Features Actuation Due to Inattention to Detail 3

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(Section M8.1)

50-416/98-005 LER Delinquent Limiting Conditions for Operation Action Due to inadequate Work Practices (Section 08.1)

50-416/99-001 LER Plant Shutdown Due to Inoperable Emergency Diesel Generator (Section E8.2) i 50-416/99-002 LER Engineered Safety Features Actuation Due to inattention to Detail )'

(Section M8.1)

50-416/99-003 LER Manual Reactor Scram Due to Decreasing Condenser Vacuum (Section M8.2)

50-416/9805-04 VIO Failure to Ensure Clearance from Safety-Related Equipment ,

(Section M8.3)

50-416/9813-01 VIO Failure to Install Temporary Restraining Cables on Floor Gratings i (Section 08.2)

50-416/9813-02 VIO Failure to Follow Procedures Resulting in Near Drop of Tool Ring (Section E8.3)

50-416/9817-01 IFl Review Current Transformer Root Cause Analysis (Section E8.1)

i 50-416/98 11-01 eel Incorrect Use of Neutron Monitor (Section R8.1) 4 l

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