IR 05000245/1998216

Insp Repts 50-245/98-216,50-336/98-216 & 50-423/98-216 on 980818-1005.Violations Noted.Major Areas Inspected: Operations,Maintenance,Engineering & Plant Support

ML20195H706
Person / Time
Site:	Millstone
Issue date:	11/18/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20195H672	List: IR 05000245/1998216 ML20195H666 ML20195H690
References
50-245-98-216, 50-336-98-216, 50-423-98-216, NUDOCS 9811240078
Download: ML20195H706 (58)

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t U.S. NUCLEAR REGULATORY COMMISSION

REGION I

, Docket Nos.: 50-245 50-336 50-423-Report Nos.: 98 216 98-216 98-216

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License Nos.: DPR-21 DPR-65 NPF-49 Licensee: Northeast Nuclear Energy Company P. O. Box 128 Waterford, CT 06385

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Facility: Millstone Nuclear Power Station, Units 2, and 3

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inspection at: Waterford, CT j Dates: August 18,1998 - October 5,1998 l Inspectors: T. A. Easlick, Senior Resident inspector Unit 1 D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Cerne, Senior Resident inspector, Unit 3 ,

P. Cataldo, Resident inspector, Unit 1 S. R. Jones, Resident inspector, Unit 2

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B. E Korona, Resident inspector, Unit 3

, N. J Numberg, Project Engineer, Region 1 l G. W. Morris, Reactor Engineer, Region 1 D.'T. Moy, Reactor Engineer, Region 1 J. Higgins, NRC Contractor P. Bezier, NRC Contractor

' J. Cadwell, NRC Contractor i

L Approved by: Jacque P. Durr, Chief Inspection Branch Office of the Regional Administrator Region 1 l

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9811240078 981118 l- PDR ADOCK 05000245 lt G PDR I

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TABLE OF CONTENTS EXECUTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii U2.1 Operations ..................................................1 U2 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 U2 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . . 3 U2 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . 5 U 2.ll M aintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 U2 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 U2 M3 Maintenance Procedures and Documentation .............. 16 U 2.lli Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 U2 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 U2 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 20 U3.1 Operations .................................................25 U3 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 U3 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . 29 U3 08 Miscellaneous Operations lasues . . . . . . . . . . . . . . . . . . . . . . . 30 U 3.ll M aintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 U3 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 U3 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . 33 U 3.lli Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 4 U3 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 U3 E2 Engineering Support of Facilities and Equipment ............ 36 U3 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 37 IV Plant Support .................................................38 R1 Radiological Protection and Chemistry Controls . . . . . . . . . . . . . 38 R5 Staff Training and Qualification in Radiological Protection and Ch emis try . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 9 R8 Miscellaneous Radiological Protection and Chemistry issues . . . . 40 S8 Miscellaneous Security and Safeguards issues .............41 V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 ii I

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EXECUTIVE SUMMARY Millstone Nuclear Power Station l Combined Inspection 245/98-216;336/98-216; 423/98 216 i

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Operations l

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• At Unit 2, both Operations and Reactor Engineering Departments are making progress for fuelload. Operating procedures, Modes 6 and 5 surveillance tests, and the fuel movement operator training program are comprehensive and acceptabl Nuclear Oversight has been effective in identifying deficiencies in the process and providing their own input to plant readiness. The process for ensuring plant readiness also appears to be comprehensive. Emergent work has delayed fuelload on a number of occasions and at the end of the inspection period, the fuelload date was still being evaluated by the licensee. (Section U2.01.2)

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• At Unit 2, after the NRC identified that the indicated reactor building closed cooling

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water (RBCCW) flow to the "A" engineered safeguards room cooler was off scale l high, the cause of the condition was determined to be that the associated throttle valve, 2-RB-68.1 A, was in a fully open rather than throttled position. The NRC determined that the RBCCW valve lineup procedure was inadequate in that l instructions contained in a note did not specify that this throttled position be

! verified. As a result, the valve lineup was performed on two occasions without l identifying this mispositioned valve. The failure to establish an adequate valve j lineup procedure is considered a violation of Technical Specification 6.8. Although the safety significance of this event in the current defueled condition was minimal, the mispositioning is a concern because the licensee's corrective actions for this inspector identified issue did not address the inadequate valve lineup procedure. It also raises concerns about how the positions of other throttle valves are being verified. The NRC also considered operator performance to be weak in not investigating the high RBCCW flow to the "A" engineered safeguards room coole (Section U2.03.1)

• At Ur.it 2, the licensee's corrective actions taken to address URI 50-336/96-01 04, including the substantial effort taken to develop 12 new abnormal operating procedures for recovering lost direct current (dc) busses, were found to be acceptable. Therefore, URI .50-336/96-01-01 and Unit 2 Significant items List No.

l 8.3 are considered closed. One issue that was not part of the unresolved item l involved the licensee's corrective action to address poor labeling of breakers, which contributed to a loss of dc bus event. Although Unit 2 has no specific regulatory i

requirements for breaker labeling outside the control room, the inspector found that a number of examples of incorrect or inconsistent labels associated with de switchgear. The licensee's corrective action plan to address this concern was found to Le acceptable. (Section U2.08.2)

• At Unit 2, the concern described in Licensee Event Report (LER) 50-336/97-002-00

, involving the final safety analysis report discrepancy regarding the ability to manually operate damper 2-HV-210 is considered a violation of 10 CFR 50, iii

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l identified violation to address the documented concern were considered appropriate and consistent with its LER commitment, and ,therefore, it was characterized as a non-cited violation. LER 50-336/97-002-00and Unit 2 Significant items List No .5 and 46 are considered closed. (Section U2.08.3)

! * At Unit 2, to address IFl 50-336/98-202-14,the licensee changed the reactor building closed cooling water piping and instrumentation diagram (P&lD) to reflect the valve lineup. They did not review other P&lDs because, with the exception of locked valves, they do not plan to maintain or perform periodic reviews of P&lDs for consistency with valve lineups due to the number of engineering resources involved.

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This is inconsistent with Note 10 on the P&lD Legend, which applies to all operations critical drawings, which states that P&lDs drawings will be updated to l reflect changes in valve positions as required by changes to system operating l procedures and valve lineups. The licensee stated that they plan to evaluate the I current industry standard and change Note 10 and/or P&lDs accordingly. IFl 50- ,

336/98-202-14 remains open to address this concer j

* At Unit 2, the NRC reviewed the licensee's corrective actions for Unresolved item I

(URI) 50-336/95-42-03and conciuded that the failure to perform an engineering l evaluation (and the subsequent changing of operational mode) when reactor coolant l system heatup and cooldown rate limits were exceeded is a violation of Technical Specifications (TSs) 3.4.9.1.a & b action requirements, and TS 3.0.4. The NRC found the licensee's completed and planned corrective actions to be acceptable and therefore, no response to this violation is required. However, this violation and Significant items List 24.1 remain open pending completion of the corrective actions associated with the plant process computer software that the operators use in

, munitoring heatup and cooldown rates. URI 50-336/95-42-03is closed; VIO l

336/98-216-02is opened. (Section U2.08.1)

• Licensee management, operators , and support personnel responded well to the challenges encountered by Unit 3 personnel during this inspection perio Conservative decision-making; deliberate planning, event response and analysis; and l

appropriate corrective action review were in evidence. (Section U3.01.1)

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• Through observations of corrective actions and review of documentation related to the inoperability of the Unit 3 service water system, appropriate licensee response l was observed to the Technical Specification (TS) 3.0.3 entry caused by the f ailure of the check valves in the service water hypochlorite injection system. However, the recent modification installed valve materials which were incompatible with the hypochlorite system. This inadequate design led to the inoperability of both trains

of service water and subsequently required two entries into TS 3.0.3 and two downpowers. (Section U3 01.2)

• During a review of procedures, the licensee identified a historical violation of the Unit 3 TS with the plant in Mode 5. The licensee performed residual heat removal system testing during the transition to Mode 4 incorrectly using a one hour out of service allowance for leak testing Corrective actions were timely in that the required TS revision was requested and received prior to the next plant entry into

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service allowance for leak testing. Corrective actions were timely in that the I required TS revision was requested and received prior to the next plant entry into Mode 4. This licensee identified TS violation is considered a non-cited violation (NCV). Based on the plant condition at the time of discovery, the licensee's failure to submit the subject LER within 30 days is considered a minor violation and is included in the NCV. (Section U3 03.1)

e Licensee corrective actions to address four separate Unit 3 LERs relating to l operability concerns from failed or missed surveillances, appeared appropriately directed to the specific TS violations. Collectively, the incorporation of triggering mechanisms into operating procedures for TS required surveillances was an effective program enhancement. Operator compliance with procedure requirements, as well as cognizance of system configuration and plant status, have irr. proved since restart. The issues were properly analyzed and reported by the licenree and are considered non-cited violations. (Section U3 08.1)

Maintenance e At Unit 2, operators performed the pre-brief and surveillance test of manual safety injection actuation signal initiation well, and the test results satisfied the relevant technical specification acceptance criteria. However, the NRC noted that operators referred to an operating procedure to determine which components would actuate rather than referring to_a drawing specified by the surveillance orocedure. A subsequent comparison of the operating procedure and the drawing revealed four errors in the operating procedure attachment that lists the actuated component However, the concerns with the operating procedure adequacy had previously been identified by the licensee and the NRC considers the corrective action plan to be acceptable. Accordingly, this concern was characterized as a non-cited violatio (Section U2.M3.1)

e The Unit 3 on-line maintenance process has been structured to use probabilistic safety assessment insights and operator judgement to achieve a balance between plant safety, schedule duration, and required work completion. A sample review of the implementation of this process determined that PRA information is effectively used and schedule adjustments routinely made to address the changing plant system configuration and risk profile. For the areas inspected, the Maintenance Rule (10 CFR 50.65) objectives, in relation to the risk perspectives of work control and overall plant safety, were effectively met. (Section U3.M1.1)

e Licensee corrective actions for three Unit 3 LERs documenting IST program and technical specification vio!ations were determined to be acceptable. The licensee implemented the corrective actions in a timely manner after problem identification and before taking the unit to a higher mode of operation. No adverse safety consequences actually developed as a result of these IST program problems and omissions, which are considered licensee identified, non-cited violations. (Section U3 M8.1)

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Engineering l

e At Unit 2, system readiness reviews for the service water system and the control I

room air conditioning system, which support the transition to operational mode 6, ]

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refueling, from a defueled condition, were implemented well. The dispositioning of a licensee identified slow closure of a control room boundary isolation damper 1 l revealed a historical concern with the translation of design information into surveillance procedures. However, the licensee implemented effective corrective actions to address this concern and therefore, it was characterized as a non-cited violation. (Section U2.E1.1)

e The licensee's corrective actions for inadequate technical specification surveillances l

l of the Unit 3 solid state protection system were appropriate. The required procedural revisions were completed before the unit was allowed to change mod This is considered a non-cited violation. (Section U3 E8.1)

Plant Support e An effective radiation protection program for activities being conducted at all three l units is being implemented. The changing work scope at Units 1 and 2 has led to a review of the annual exposure goals for these units. (Section IV.R1)

i e An extensive and effective investigation of a contamination event at Unit 1 resulted ,

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in the identification and implementation of several radiological improvement (Section IV.R1)

l e An effective technical training program has been established for the continuing

education of licensee radiation protection technicians. (Section IV.RS)

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Report Details Summarv of Unit 2 Status The unit was initially shut down on February 20,1996, to address containment sump  ;

l screen concerns and has remained shut down to address the problems outlined in the 1

Restart Assessment Plan and an NRC Demand for Information [10 CFR 50.54(f)] letter l

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requiring an assertion by the licensee that future operations are conducted in accordance with the regulations, the license, and the Final Safety Analysis Repor l Unit 2 entered the inspection period with the core off-loaded. During the inspection period, l the licensee declared several Facility 1 and Facility 2 systems operable for operational mode 6, refuelin i U2.1 Operations l U2 01 Conduct of Operations 1 j

O1.1 General Comments (71707)

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, Using inspection Procedure 71707, the inspector conducted frequent reviews of ongoing l

plant operations, including observations of operator evolutions in the control room; walkdowns of the main control boards; tours of the Unit 2 radiologically centrolled area and other buildings housing safety-related equipment; and observations of several management planning meetings.

l Specifically, the inspector observed operational preparations, procedural adherence, and the  !

control of shutdown risk during portions of the following evolutions:

• Vital 4160 Volt and 480 Volt ac switchgear outages, and vital 125 Volt de switchgear outages for breaker overhauls and inspection of fire penetration seals e Transfer from protected Facility 1 to Facility 2 l

Throughout the above evolutions, the inspectors noted good sensitivity to special conditions and equipment outages that affected shutdown safet . 01.2 Preoarations for Core Reload Insoection Scone (60705)

l _ Duri.ng the current Unit 2 outage, reactor fuel was unloaded from the core in order to facilitate various maintenance and modification activities during an extended outage.

l Because the core was in mid cycle, fuel will be reloaded into the locations from which it was removed. ' With the core unloaded the reactor is in an undefined mode. Upon reloading the fuel, the reactor will be in Mode 6. It is the licensee's intent, as soon as pocsible after l fuel load, to reinstall and tension the reactor vessel head. At that point, the reactor will be

1 in Mode 5, cold shutdow '

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L The inspector reviewed the licensee's preparations for going to Modes 6 and 5. This review included operating procedures for fuel movement and refueling equipment readiness (i.e. the spent fuel pool bridge, cranes and hoists, the upender etc.); training and qualification of personnel performing fuel movement; readiness of TS surveillance tests for :

Modes 6 and 5; preparations for plant readiness; and involvement of Nuclear Oversight.

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The inspector also reviewed procedures, audit reports, refueling equipment test completion verification; held discussions with reactor engineers, Nuclear Oversight Auditors, and l operations personnel; and observed on the job training in progres Observations and Findinas l

!. As noted in previous inspections, Unit 2 has performed a complete review of all surveillance tests for compliance to Section 4 of the Technical Specification (TS), the j Technical Requirements Manual, and ASME Section XI, in service Testing for pumps and l Valves. The inspector performed a 100% review of the TS Section 4 applicable to Modes l 6 and 5 and confirmed that the licensee had performed a review of surveillance tests used

! to confirm compliance to the TS. The inspector also confirmed that deficiencies identified ( by the licensee's TS review had been corrected in TS surveillance tests applicable to

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Modes 6 and 5. In addition, operations procedures for fuel handling and testing of fuel l handling equipment have all been update The licensee is performing the fuel load using plant staff, whereas, recent past refuelings ;

l were performed by outside contractors. For this reason, the licensee has developed a i

-formal training and qualification program to train plant staff in fuel handling. Personnel are trained on plant equipment using dummy fuel elements. There is a formal qualification procedure for each person to be trained. The inspector observed some training in progress and reviewed the qualification procedure. Both appeared to be comprehensive. The  !

. licensee will also use refueling SROs to direct the fuelload process.~ The foreign material I

exclusion (FME) process is in place for entry on to the refueling bridge. All personnel having access to the bridge must be FMt! qualifie Operating procedures for fuel load were recently reviewed and updated in readiness for fuel load Surveillance tests have been performed on cranes and other fuel handling

.. equipment that are being used in the training process. The inspector observed some

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training in progress and the final test for a newly qualified operator. The inspector also observed that reactor engineers and nuclear oversight periodically review the training process. -The portion of training reviewed was moving fuel from the spent fuel pool to the upende The licensee cond' ucted regular meetings to review plant readiness 'for fuel load and Mode 5. Readiness for Mode 5 is critical as the licensee intends to minimize any time spent in l Mode 6. Emergent work has delayed fuel load on a number of occasions and at the end of l- - the inspection period, the fuel load date was still being evaluated by the licensee. Nuclear

[ ' Oversight is very much involved in the readiness for fuel load. They have performed three audits and regular surveillances.

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l 3 Conclusions Both Operations and Reactor Engineering Departments are making progress for fuel loa Operating procedures, Modes 6 and 5 surveillance tests, and the fuel movement operator training program appear to be comprehensive and acceptable. Nuclear Oversight has been effective in identifying deficiencies in the process and providing their own input to plant j readiness. The process for ensuring plant readiness also appears to be comprehensiv Emergent work has delayed fuelload on a number of occasions and at the end of the ;

inspection period, the fuelload date was still being evaluated by the license U2 03 Operations Procedures and Documentation O3.1 (Ocen) VIO 50-336/98-216-01: Miscositionino of Throttle Valve in the Reactor Buildino Closed Coolina Water Svstem insoection Scone (71707)

The inspector investigated the circumstances leading to high reactor building closed cooling water (RBCCW) flow to the "A" engineered safeguards room cooler and the licensee's subsequent corrective actions. This inspection involved interviews with operations department personnel, as well as a review of surveillance procedures and plant records associated with the RBCCW system.

, Observations and Findinas On July 24,1998, the inspector identified that the indicated RBCCW flow to the "A" engineered safeguards room cooler was off scale high and noted a corresponding plant process computer alarm annunciating this high flow condition. The inspector discussed these indications with the shift manager who stated that he planned to contact the system engineer and initiate a valve lineup. The licensee found that the high flow condition was caused by valve 2-RB-68.1 A being in an incorrect position. The valve was fully open rather than in its required throttled position. Condition report (CR) M2-98-2118 was generated to document the mispositionin The circumstances that led to the mispositioning of valve 2-RB-68.1 A began in April 1998, when special procedure SPROC 97-2-19, " Reactor Building Closed Cooling Water Flow Balance," was performed to determine proper positions for throttle valves that controlled cooling water flow to various components. Prior to the performance of this procedure, the RBCC'N system flow to the "A" engineered safeguards room cooler had been adjusted by throttling a manual valve,2 RB-69A. During performance of procedure SPROC 97-2-19, valve 2-RB-68.1 A was utilized to throttle RBCCW flow to the room cooler and valve 2-RB-l 69A was fully open. Valve 2-RB-68.1 A is an air-operated valve. its throttled position is l : set by adjusting a manual handwheel that limits the amount the valve opens when the l

salve is opened using the air operator. When the manual handwheel for valve 2-RB-68.1 A had been adjusted to four and one-quarter turns open, an acceptable RBCCW flow rate was established to the room cooler during the performance of procedure SPROC 97-2-1 .

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Following the performance of the procedure SPROC 97-2-19, the licensee began to process changes to form 2611C-2, "ndCCW System Alignrnent Checks, Facility 1," to specify the valve positions establist ed during procedure SPROC 97-2-19 as the required positions.

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Form 2611C-2 is assoc ated with surveillance procedure SP2611C, "RBCCW System Alignment and Valve Tests, Facility 1 & Cross Ties." These changes included a change to reflect that valve 2-RB-68.1 A would be utilized instead of valve 2-RB-69A to throttle flow to the "A" engineered safeguards room cooler, and a change to indicate the required throttle position for valve 2-RB-68.1 A. However, on June 29,1998, before changes to the RBCCW valve lineup form 2611C-2 became effective, maintenance restoration activities, including a valve lineup, were performed that left the manual handwheel on valve 2-RB-68.1 A fully ope '

Revision 23 to form 2611C-2, which incorporated the valve positions established during the performance of procedure SPROC 97-2-19, was issued on July 2,1998, and became effective on July 7,1998. Subsequently, Revision 23 of form 2611C-2 was used for complete Facility 1 RBCCW valve lineups performed for system alignment on July 14, 1998, and for surveillance testing on July 20,1998. The system alignment on July 14, 1998, required an independent verification, and, therefore, the valve position was checked by two operators. However, because the revised valve lineup was not clearly written, the handwheel on valve 2-RB-68.1 A was not placed in the proper throttled position of four and one-quarter turns open. The position specified for valve 2 RB-68.1 A in Rev. 23 to form 2611C-2 referenced Note 9, which stated, "The manual handwheel has been adjusted to

[four and one quarter] turns open to limit air operator valve stroke. The position was determined by SPROC 97-2-19." The NRC determined that form 2611C-2 was inadequate in that the instructions in Note 9 did not specify that this throttled position be verified. In addition, valvo 2-RB-68.1 A was listed with other remotely operated valves under the heading " Control Room," which led the operators to simply check the remote position indication available in the control room rather than locally verify that the valve was in its correct throttled positio The scope of the licensee's investigation for CR M2-98-2118 was focused on the circumstances that caused valve 2-RB-68.1 A to be moved from the position established at the completion of special procedure SPROC 97-2-19. The investigation attributed the event to untimely implementation of a procedure change to reflect the revised valve positions established through the special procedure and to inadequate specification of retests following maintenance activities, including the maintenance restoration valve lineup that occurred on June 29,1998. Although the investigation raised the issue of checking the position of throttling devices for remotely operated valves when their remote position indication is checked, the investigation did not note that valvo lineups performed on July 14 and July 20,1998, failed to identify the mispositioned throttling device for valve 2-RB-68.1 As corrective actions, the licensee improved the procedure change process to make revisions more timely and issued a required reading brief to operations personnel regarding when to implement changes to valve lineup procedures. However, the issue regarding the checking of the position of throttling devices on remotely operated valves was not addressed. The inspector discussed the omission of this issue from the corrective actions

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for CR M2-98 2118 with the licensee's investigator. The investigator documented this omission in CR M2 98-3067, which was initiated on October 9,199 The inspector evaluated operator performance in not investigating the high-flow alarm to the engineered safeguards room coolers. Facility 1 of the RBCCW system was returned to service in July 1998 after completion of the Facility 1 service water system repair outage that began in April 1998. When RBCCW flow to the "A" engineered safeguards room cooler was initiated on July 20,1998, the plant process computer recorded an off-scale high alarm condition, which was displayed on a monitor in the control room. The shift manager on duty at that time stated that the shift noted the alarm, but the cause was not investigated. Operators were accustomed to high flow alarms for this component because the setpoint of the high flow alarm is below the normal flow, but operators should have

[ recognized that the off-scale high alarm was abnormal. This alarm momentarily cleared and

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returned on July 24,1998, due to system testing, which caused the alarm to be displayed at the top of the control room monitor, thereby giving the operators another opportunity to l

acknowledge and investigate the cause of the alarm.

Conclusions

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- After the NRC identified that the indicated RBCCW flow to the "A" Engineered safeguards l room cooler was off-scale high, the cause of the condition was determined to be that the associated throttle valve, 2-RB-68.1 A, was fully open rather than its required throttled condition. The NRC determined that the RBCCW valve lineup procedure was inadequate in that instructions contained in a note did not specify that this throttled position be verifie As a result, the valve lineup was performed on two occasions without identifying this mispositioned valve. The failure to establish an adequate valve lineup procedure is considered a violation of Technical Specification 6.8.1.c. (VIO 50-336/98-216-01)

l Although the safety significance of this event in the current defueled condition was minimal, the mispositioning is a concern because the licensee's corrective actions for this inspector-identified issue did not address the inadequate valve lineup procedure, it also raises concerns about how the positions of other throttle valves are being verified. The NRC also considered operator performance to be weak in not investigating the off scale

high RBCCW flow to the engineered safeguards room cooler U2 08 Miscellaneous Operations issues 08.1 (Ocen) VIO 50-336/98-216-02 & (Closed) URI 50-336/95-42-03

Reactor Coolant l System Heatuo and Cooldown Rate Limits Exceeded: (Closed- Unit 2 Sianificant l Item List No. 24.11 Insoection Scone (92901)

The inspector reviewed Millstone Unit 2 corrective actions necessary to support closure of Unresolved item (URI) 50 336/96-42-03, as well as Significant item List (SIL) No. 2 The inspection included interviews, as well as the review of applicable procedures and L other documentation.

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l Observations and Findinas Licensee Event Reports (LER) 50-336/95-030-00, 96-00100/01, 96-007-00, and 96-011-

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00, as well as URI 50-336/96-42-03, documented: l l

Technical Specification (TS) violations for failure to meet the action requirements after exceeding the heatup rate (HUR) and cooldown rate (CDR) limits of the reactor l coolant system (RCS) and the pressurizer (e.g., failure to perform engineering l evaluations). (LERs96-001 and 96-007)

TS violation for exceeding Operational Mode entry time limits, i.e., failure to achieve cold shutdown (Mode 5) within the time required by TSs. (LER 96-011)

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TS violations due to operational mode changes prior to complete of TS required actions, specifically, engineering evaluations necessary to suppet continued i operation based on the determination that exceeding HUR/ CDP !.nms had no effect on the structural integrity of the RCS or pressurizer. (LERs 9b-030 and 96-001)

NRC concerns regarding (1) inadequate corrective actions from the HUR events, i.e.,

corrective actions from a similar event (LER 95-030) may have prevented the 12/12/95 event (LER 96-001),(2) plant design that created operator burdens, e.g.,

operators unable to recognize exceeding HUR/CDR limits or unable to control heatup and cooldown evolutions, and (3) operator response to unusual indications, i.e.,

recognizing abnormalindications and taking appropriate actions. (URI 96-42-03)

The licensee determined that a major underlying root cause for the TS violations discussed above, was less than adequate procedures and training for operators to monitor and control heatup and cooldown evolutions, specifically: (1) Lack of operator guidance during the transition between reactor coolant pump operations and shutdown cooling operations; (2)

Inappropriate system temperature monitoring points such that accurate and representative HURs and CDRs were not available to the operators; (3) Lack of guidance regarding the effects of noncondensable gases on plant parameters; (4) Less than adequate corrective actions resulting from the TS violation of the July 1995 HUR even Licensee corrective actions to address these concerns included the following: (1)

Procedures were revised to provide operators with appropriate guidance for monitoring and controlling heatup and cooldown evolutions, which included parallel shutdown cooling system and reactor coolant pump operation, and the establishment of a new RCS temperature monitoring point in the PPC for use during the heatup and cooldown evolutions (a principal causal factor for a majority of the TS violations); (2) Licensed operator training was performed that included not only the use of revised procedures and plant operating experience relative to the heatup and cooldown events, but also the new RCS temperature monitoring point (both in the procedures and the PPC); (3) Procedures were revised to I

provide operators with appropriate guidance to address the accumulation of nonenndensable gases during plant heatups, which was the principal causal factor in the

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pressurizer heatup rate limit being exceeded.

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While a majority of the corrective actions performed by the licensee subsequent to the LERs, Event Review Team (ERT) investigations, condition reports, and NRC commitments have been completed, a number of corrective actions remain open. For example, while an assessment of the effectiveness of the heatup and cooldown corrective actions will be performed by the licensee following the Unit 2 startup, the basis for this deferral is acceptable, and does not preclude closure of SIL 24.1. However, one corrective action yet to be completed is the PPC update that reflects a new RCS temperature monitoring poin l While this update has been completed on the simulator, the in-plant PPC has not received !

the update. This PPC update is important because the non-conservative manner the PPC l had been calculating HUR/CDR limits was the reason these limits were exceeded and had I gone undetected by the operators. However, the licensee is currently tracking this issue I within their corrective action program and have explicitly identified the issue as Mode 4 l

dependen The inspector also identified that the TS violation reported through LER 95-030, was dispositioned as a NCV in inspection report 50-336/95-31. In addition, the TS violation i reported through LER 96-011 was dispositioned without the issuance of a violation in accordance with Section Vll.B of the NRC's Enforcement Policy. However, the violation of TS 3.4.9.1.a (LER 96-001), TS 3.0.4 (LER 96-001), and TS 3.4.9.1.b (LER 96-007) remain to be dispositioned. Specifically: Violation of TS 3.4.9.1.a and b, for failure to perform engineering evaluations to determine the effects of the out-of-limit condition on the structural integrity of the RCS and determination that the RCS remained acceptable for continued operatio . Violation of TS 3.0.4, for entry into an operational mode when conditions for the Limiting Condition of Operation (TS 3.4.9.1.a) were not met, Conclusions The NRC reviewed the licensee's corrective actions for URI 50-336/95-42-03 and concluded that the failure to perform an engineering evaluation (and the subsequent changing of operational mode) when RCS heatup and cooldown rate limits were exceeded is a violation of TSs 3.4.9.1.a & b action requirements, and TS 3.0.4. (VIO 50-336/98-216-02) The NRC found the licensee's completed and planned corrective actions for the TS violation to be acceptable and therefore, no response to this violation is require However, this violation and SIL 24.1 remain open pending completion of the corrective actions associated with the PPC software that the operators use in monitoring heatup and cooldown rates. URI 50-336/95-42-03 is close .2 (Closed) Unresolved item 50-336/96-01-04: Loss of DC Bus Event: (Closed - Unit 2 l Sionificant items List No. 8 Individqditem)

l Insoection Scoce (92901)

The inspector reviewed the corrective actions taken to address Unresolved item 50-336/96-01-04; Loss of DC Bus Event.

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8 Observations and Findinas During a maintenance outage on March 12,1996, the "B" train vital dc bus was inadvertently de-energized, causing several additional problems. This event was reviewed in NRC inspection Report 50-336/96-01 and an unresolved item was written to address:

(1) the submittal of a security event report, (2) the need for additional procedures for recovering busses, (3) breaker testing, and (4) deferral of scheduled work.

The inspector reviewed the closure package that had been prepared for this item. Two ,

key documents were included in the package: Adverse Condition Report 9518, and Loss of l

Bus 201B Event Summary Report, MP-WP96-049, dated April 8,1996. These documents l

noted additional problems that occurred during the event and identified corrective action )

The analysis of the event and the defined corrective actions were reasonable. The inspector reviewed and verified a sample of the corrective actions, including the above four specific aspects of the unresolved item.

Licensee Event Report (LER) 50-336/96-028-00 was issued documenting the security event that occurred due to loss of normal security power when the de bus was de-energized.

This LER identified two procedural changes associated with the security system emergency diesel generator; these changes were subsequently made.

During the event, operators utilized procedure EOP 2528, " Electrical Emergency," to recover the de bus. Although the procedure was acceptable, it did not provide the most efficient or effective method for operators to recover the dc bus. As a corrective action, the licensee developed and approved 12 Abnormal Operating Procedures (AOPs) for the loss of dc buses and distribution panels, namely AOPs: 2505A, B, & C, 2506 A-D, and 2507 A-E. These have been included in the licensed operator training program and are now in effect. The procedures provide guidance for actions on loss of buses and how to restore power to the buses. The licensee also has AOPs for the loss of 4160 Volt,480 Volt and instrumentation buses.

The licensee wrote work orders and performed testing of circuit breakers per the test procedure requirements of PT 21424B. Some discrepancies were identified and corrected.

The inspector evaluated the test and preventive maintenance (PM) frequency for the breakers, given the problems that were identified during the testing. The licensee stated that they are currently reevaluating these frequencies in conjunction with the manufacturer, General Electric (GE). As of August 1998, all breakers of this type were being overhauled which includes changing out the old " black" grease in all circuit breakers with a new, more reliable, and longer lasting Mobil " red" prease (Specification D6A15A1). To ensure the reliable operation of the breakers on an ongoing basis, the licensee is in the process of developing the Millstone Unit 2 Low anc Medium Voltage Circuit Breaker Maintenance Program. This new program incorporates industry recommendations and establishes the PM cycle and overhaul cycle for the breakers.

Regarding the deferral of scheduled work, the licensee performed an evaluation of the deferral titled, " Evaluation of Mechanical and Electrical PM's Deferred During RFO 12,"

MM-97-046, dated July 1997. This evaluation found that during refueling outage RFO 12,

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t i between October 1994 and August 1995, there were 3193 PM work orders issued. Of

-these,1285 were deferred (closed with no work performed). The evaluation reviewed all l 1285 and identified 20 that should not have been deferred. As a result, condition reports

. were issued to address these 20 work orders. The licensee also issued a new procedure, l U2-CBM-105, " Preventive Maintenance Prograrn Changes and Deferrals for MP2," which i requires that all PMs be performed with a grace period of 25% If it cannot be performed 1 within the grace period, then a deferral must be documented and approved.

L The inspector also toured the switchgear rooms and observed the electrical equipment, including: buses, circuit breakers, battery chargers, inverters, and batteries. Selected procedures noted above were walked down in the plant. Procedures appeared clear and workable. Housekeeping and material condition also appeared good. Some labeling discrepancies were identified, as discussed belo j One of the contributing factors to the event, as noted in the Event Summary Report, MP-( WP96-049, was " Labeling on the A and B switchgear is very poor." As a result, one of the recommendations of the report was to " Remove all current labeling on the A and B l switchgear, and relabel..." Although this relabeling was done, the inspector found that the j labeling for Facility designation (e.g., Z1, Z2, .. 25) and related Facility color-coding was

incorrect or inconsistent. Current examples of inconsistent or incorrect labeling, noted by i

the inspector included: . one component with the wrong Facility code (battery charger 201C had " Facility 1

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or Facility 2" when it is Facility Z5),

. white labels that do not have a Facility color code (many on battery chargers 201 A, B & C), l

. components with two different Facility codes written on them (battery chargers l 201 A & B),

. sometimes the Z code was on the label and sometimes not (many examples of each !

i in switchgear rooms),  ;

.' method of designating the Z code was not consistent (e.g., Z1 or Z-1 and several different types of colored labels),

. old handwritten labels still present (breakers D0103 and D0202).

! . conduits with inconsistent color coding (Z1, Z2 & Z5 conduits with yellow labels; L

Z2 conduits with white labels; Z2 conduits with only hand-printed coding in black);

cable trays with inconsistent color coding (tray Z24Pf 07 with white label, yellow Jacketed cables and a red triangle label; tray Z24P^.' with white label, yellow jacketed cables and a yellow triangle label). Sirmar conduit an cable tray issues i- were identified by Parsons as part of the UC 2 ICAVP Program and documented in Discrepancy Report DR-0680, a confirmed Nvel 3 condition. The licensee has

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issued CR M2-98 2757 to address this DR. The aspects of cable trays and conduits identified here will be adequately encompassed by the actions to address the D *

The licensee has no guidance that defines the correct label color for a vital load being supplied from a swing bus. This results in components with two (or more)

labels - each with a different color (breaker D0204 yellow & orange; breaker D0203 yellow and red; breaker D0104 red and orange; Panel DV 10 black, white and orange; Panel DV40 black, white, and red; Panel DV 30 black, white and green).

There also is no guidance that defines the correct color label for non-vital loads being supplied from a vital bu The inspector found that Unit 2 has no administrative procedure that defines the color coding breakers outside the control room. Final Safety Analysis Report (FSAR) Section and Table 8.7-4 discusses Facility color-coding for wiring, cables and raceways but does not specifically discuss components such as breakers. Procedure OA9, " System and Component Labeling," and Specification SP-EE-261, " Design Standards for the Modification of Control Panels," revealed that while Procedure OA9 does call for color coding, the e is no clearly-specified, approved guidance for Facility labeling and color coding in Unit 2 outside of the main control room. This led to the inconsistent application in the switchaear rooms, and the condition that contributed to the loss of bus event. The inspector noted i that NRC guidance on train labeling and color coding exists in NUREG-0700, Rev.1,

" Human System Interface Design Review Guideline," and NUREG-1192, "An investigation of the Contributors to Wrong Unit or Wrong Train Events."

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The licensee issued Condition Report M2-98-2484 to address the concern regarding inconsistent and incorrect labels. The corrective action plan includes actions to develop an l Operations Department Instruction that will identify component label color coding enhancements that will provide a consistent method to address this concern. The plan also specifies relabeling riecessary components after it has been approved and removing old or incorrect labels. The licensee designated these corrective actions for completion following restart. Following discussions with the inspector, the licensee's plan now specifies that the first three items listed above, which involve examples of breaker labels that are incorrect or misleading, would be corrected prior to restar Conclusions The licensee's corrective action taken to address URI 50-336/96-01-04, including the l substantial effort taken to develop 12 new AOPs for recovering lost busses, were found to be acceptable and this item is closed. One issue that was not part of the unresolved item involved the licensee's corrective action to address poor labeling of breakers, which contributed to the loss of bus event. Although Unit 2 has no specific regulatory requirements for breaker labeling outside the control room, the inspector found a number j of examples of incorrect or inconsistent labels associated with switchgear. The licensee's corrective action plan to address this concern was found to be acceptable, i

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! 08.3 - (Closed) LER 97-002-00: Damner 2-HV-210 Cannot Be Manuallv Ooerated Within

. Tin Minutes as Reauired in the Accident Analvsis (Cla==<i - Unit 2 Sianificant items List Nos 9.5 and 48)

j' Insoection Scoos (92901)

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Licensee Event Report (LER) 97-002-00 was submitted to document the discovery that

' l damper 2-HV-210 cannot be operated manually within ten minutes as required for safe '

response to an accident scenario. The inspector reviewed the licensee's actions to resolve ,

the documented deficienc l l i

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i Observations and Findinas

! ' In the event of.a loss of coolant accident in Unit 2, an engineered safety actuation signal

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would initiate the Control Room Emergency Filtration System (CREFS) and a control room i j -- alarm. In that event, damper 2-HV-210 could fail to open requiring operations personnel

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L action to restore filtration. This' action is the manual opening of the damper within ten '

l minutes. On January 8,1997, in a review of an accident scenario, the licensee questioned

.the feasibility of opening the damper manually within the ten minute criteria. Since the ,

damper is located about 9 feet above the floor and does not have a hand operator, the l

licensee determined that the required actions were not possible. The plant was in Mode 6 l -at the time of the discovery. LER 97-002-00 was prepared and submitted pursuant to 10 CFR 50.73(a)(2)(ii) documenting the discovery. The LER included a commitment "to

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' perform an evaluation of 2-HV-210 and associated procedures and other operator actions l which are included in the safety analyses."

The licensee had earlier issued Adverse Condition Report (ACR) M2-96-0860 identifying the concern that a single failure of supply damper 2-HV-210 could prevent the operation of the

, safety related recirculation / filtration function. Upon the discovery of the deficiency l reported in the subject LER, the licensee issued ACR M2-97-0029 to develop corrective l actions to resolve the concern. The corrective actions included the temporary action, to l fail open damper 2-HV-210 to assure the required action of CREFS, and the permanent

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action, to leave the damper open and make this position its normal position, in the safety evaluation performed to support the permanent modification, it was determined that the action of cross tying damper 2 HV-213 could degrade control room ventilation, and this l damper was permanently closed as a part of the corrective action.

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' The inspector reviewed 'the Design Change Request (DCR) M2-97012 issued to process the

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modifications and the included Safety Evaluation S2-EV 97-00-0049. The end result of the modification was to maintain damper 2-HV-210 open in all cases but during the Emergency Fresh Air intake Mode, and to disable the controls and weld the shaft on damper 2-HV-

- 213,'so that the damper is permanently closed. For damper 2-HV-210, the modification

. required Instrumentation & Control (l&C) and electrical changes implemented with Design b ' Change Notice (DCN) DM2-00-287-97. ' The physical ch .n.1es included the removal of L interlocks, the disconnecting of cables and the deletion ot electrical jumpers. For damper t

2-HV-213, the modification also involved l&C and electrical changes. These were

! implemented with DCN DM2-00-0288 97, and included removal of a control switch, l^

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l l 12 indicator lights, a limit switch and associated cables, the damper motor and the capping of instrumentation tubing. The mechanical design change for this damper was implemented with DCN DM2-00-0363-97. The design package appeared complete and the safety evaluation concludes that the modifications will not degrade safet The inspector reviewed the changes made to plant drawings and operating procedures that reflect the modifications. The changes appeared comprehensive, and were consistent with the modifications showing damper 2-HV-210 open and damper 2-HV-213 locked l closed with controls inhibited. The changes to Final Safety Analysis Report Section 9.9 I

also were made to reflect the modification In an additional effort to satisfy its commitment, the licensee performed a comparison of

" time assumed" operator actions against time expectations in training materials and procedures. As a result of this effort CR M2-98-0241 was issued and Technical Evaluation

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MP-EV-98-0172 was prepared to clarify and update credited operator actions.

I l Conclusions

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The concern described in LER 50-336/97-002-00 involving the FSAR discrepancy regarding the ability to manually operate damper 2-HV-210 is considered a violation of 10 CFR 50, Appendix B, Criterion Ill, Design Control. The actions taken by the licensee to address the documented concern are considered appropriate and consistent with its LER commitmen This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vil.B.1 of the NRC Enforcement Poliev. (NCV 50-336/98-216-03) LER 50-336/97-002-00 is considered closed.

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08.4 (Closed) LER 50-336/97-026-00: Invalid Enaineered Safeauards Actuation Svstem Actuation While Shiftina from the Normal to Reserve Station Transformer l Insoection Scoce (92901)

The licensee experienced a loss of engineered safety features bus 24C during the transfer of the electrical supply from the normal station service transformer (NSST) to the reserve station service transfer (RSST). This event has previously been discussed in NRC Inspection Report 50-336/97-203, and the licensee had also reported this event in Licensee l Event Report (LER) 50-336/97-026-00. The inspectors reviewed Condition Report (CR)

M 2-97-1469, the associated root cause analysis, the contents of the shift briefing, Engineering Work Request (EWR) M2-98013, and procedures OP 2343, ARP 2590A and

OP 200.1 to evaluate the licensee's problem evaluation and corrective actions.

l l Observations and Conclusions l

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The licensee had determined that a contributing cause of the event was a blown fuse in an engineered safeguards actuation system (ESAS) cabinet that had left that system in an indeterminate state. As part of the submittal of the LER, the licensee committed to provide a briefing to operations regarding the need to analyze equipment which is planned to be left

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in an indeterminate state and to perform a root cause analysis. The inspectors reviewed i the documentation associated with both items and had no further concern l The inspectors reviewed EWR M2 98013 and agreed that the enhancements requested for the coordination of power supplies for the ESAS RSST trip logic and actuation circuits could be delayed until after restart. The inspectors also agreed with the changes made to l the operating procedure and annunciator response procedure as a result of this event, i Conclusions '

l The inspectors concluded that the licensee had adequately evaluated the loss of bus event caused by the blown fuse in the ESAS actuation cabinet and had taken appropriate corrective actions. LER 50-336/97-026-00 is close .5 - (Onen) Follow-uo item 50-336/98-202-14: Valve Positions on P&lD Inconsistent with Ooerations Procedures i

l' Insoection Scone (929.Q11 l The inspector reviewed the corrective actions taken to address the Follow-up Item 50-336/98-202-14; valve positions on P&lD inconsistent with operations procedures.

j Observations and Findinas L During an inspection to assess the effectiveness of the Configuration Management i

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Program, the Special Projects Office inspection team performed a walkdown of the Facility 2 portion of the reactor building closed cooling water (RBCCW) system to observe material

- conditions,-'and to verify that as-built system configuration matched the latest piping and i l instrumentation diagrams (P&lDs). The team determined that the great majority of valve L positions, represented on the RBCCW P&lDs, were accurately depicted. However, on one L P&lD, the positions for butterfly valves 2-RB-4.1C and D and 2-RB-251 A and B were l- shown open, but should have been closed, and valve 2-RB-211F was shown closed, but i should have been open. The licensee initiated Condition Report (CR) M2 98-0915 and issued Design Change Notice (DCN) DM2-00-0597-98 to update the P&lDs. The inspector reviewed CR M2 98-0915 and DCN DM2-00-0597-98 and verified that the subject P&lD had been appropriately updated. However, discussions with licensee management indicated that although the RBCCW P&lD was updated, they did not review other P&lDs because, with the exception of locked valves, they do not plan to maintain or perform periodic reviews of P&lDs for consistency with valve lineups due the engineering resources involved. For locked valves, a review and update of the P&lDs against the locked valve list is made every 6 months. The licensee considers their practice acceptable because operators are trained not to rely on P&lDs for operational configuration control i: because the " normal" position of many valves varies with plant conditions. However, the

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inspector noted that their practice of not updating P&lDs to reflect changes in valve lineups ;

is inconsistent with Note 10 on the P&lD Legend (which applies to all operations critical drawings) which states:

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"P&lD drawings reflect locked valves in accordance with Operations Department l Instruction 2-OPS-1.32 - Locked Valves. P&lDs drawings reflect valves in the i position required for 100% system operation, determined by valve lineups, system operating procedures, technical specifications, and design basis. P&lDs are not to I be used to maintain operational configuration control of valves. System operating - j procedures shall be used when determining proper valve positions. P&lDs will be  !

updated to reflect changes in valve positions as required by changes to system '

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operating procedures, valve lineups, technical specifications, design basis, and ODI l

- 2 OPS-1.32." Conclusions To address IFl 50-336/98-202-14, the licensee changed the RBCCW P&lD to reflect the l l: valve lineup. They did not review other P&lDs because, with the exception of locked

. valves, they do not plan to maintain or perform periodic reviews of P&lDs for consistency l j

with valve lineups due to the engineering resources involved. The inspector found this to i i be inconsistent with Note 10 on the P&lD Legend (which applies to all operations critical l

drawings) which states that P&lDs drawings will be updated to reflect changes in valve positions as required by chances to system operating procedures and valve lineups. The l licensee stated that they plan to evaluate the current industry standard and change Note i -10 and/or P&lDs accordingly. IFl 50-336/98-202-14 remains open to address this concer .6. (Closed) Follow-uo item 50-336/98-202-15: Sealed Valves Not included in Ooerations Procedures Insoection Scone (92901)

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Inspector Followup ltem (IFI) 50-336/98-202-15 concerned the fact that vent valves in reactor building closed cooling water (RBCCW) system were sealed but these vent valves were not identified as sealed on the valve lineup sheets. This was identified during a v- . e containment walkdown when evaluating the RBCCW supply to the containment air

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recirculation (CAR) system and coolant units.

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! Observations and Findinas The inspector reviewed procedures OPS Form 2611C-2, "RBCCW System Ahnment .

Checks Facility 1" and procedure OPS Form 2611D-2, "RBCCW System Alignmer.t Checks, )

Facility 2". The inspector observed that CAR cooler vents listed in these lineups are now identified as sealed valve Conclusions 1'

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The issue identified by this 'Fl l has been completed based on recent changes to the RBCCW

- . system alignments...The failure to reflect the CAR cooler vents are sealed valves on the RBCCW valve lineups constitutes a violation of minor significance and is not subject to j < formal enforcement action. IFl 50-336/98 202-15 is considered closed.

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U2.ll Maintenance l

U2 M1 Conduct of Maintenance

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l M 1.1 General Maintenance Observations

! Insoection Scone (61726/62707) i i

L During routine plant inspection tours, the inspectors observed, on a random sampling basis,

! maintenance and surveillance activities to evaluate the propriety of tha activities and the L . functionality of systems and components with respect to technical specifications and other requirement Observations and Findinas

The inspectors reviewed surveillance procedures and maintenance work orders and

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interviewed licensee field personnel to verify the adequacy of work controls. The inspector observed all or part of activities performed under the following procedures or work orders:

l * AWO M2-97-04222 "A" RBCCW Heat Exchanger Eddy Current inspection

- - AWO M2-98-OO486 "B" Shutdown Cooling Heat Exchanger RBCCW Outlet

, Stop Valve Striker Plate Fabrication

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• AWG M2-98-07373 Breaker and Cubicle inspection for Bus 24A (Including

, Electroplating of the Cubicle " Tulips" for the "C" l Circulating Water Pump)

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• SP 2404-AN Spent Fuel Pool Area Radiation Monitor Functional Test, Channel "B" (RM8142)

The inspectors found the work was being performed in accordance with approved l l

procedures ar.d work orders that were present at the work site. A review of the work l packages found that they were complete with respect to work authorizations, procedures, and inspection and retest requirements. Interviews with the workers demonstrated that j . they had a good understanding of the principles involved in the eddy curront data collection and the electroplating processes.

Conclusions The inspectors concluded that the work performed under these procedures and maintenance work orders was thorough and satisfied the objectives of the activity. The plant staff used the appropriate procedures and completed the work as outlined in the work packages. The work packages provided comprehensive information regarding the scope

and performance of work activities.

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U2 M3 Maintenance Procedures and Documentation l

l M 3.1 Channel Functional Test of Facility 2 Safety Iniection Actuation Sianal (SlAS)

Manual Push Button Insoection Scone (61726)

The inspector observed the pre-test brief for and the performance of surveillance procedure i SP2604R, "SIAS Manual Push Button Test," for Facility 2 on September 10,1998. The I

inspector also reviewed procedure SP2604R and the surveillance test results to assess conformance with techniel specification requirements.

l Observations and Findinas The objective of the channel functional test of the Facility 2 SIAS manual push button test is to demonstrate that depressing the push button starts the Facility 2 emergency diesel generator (EDG) and trips the Facility 2 actuation modules for the SlAS, the containment isolation actuation signal (CIAS), and the enclosure building filtration actuation signal .

(EBFAS). These actuation signals cause changes in the operating state of numerous components that are not necessary to be verified for the satisfactory completion of the

test. Accordingly, Prerequisite 2.1.3 of procedure SP2604R specifies that the shift

! manager review the " Engineered Safety Logic Acteated Equipment Tabulation," drawing -

l 25203-28150, Sheet 2, and determine the equipmem actuations resulting from the test l- that could affect plant operations. This allows operators to prevent the actuation of components that may be undesirable in the current plant conSguratio 'The inspector observed the pre-test brief and found it to be thorough and well execute Following the brief, the unit supervisor and control operator reviewed plant status and determined which component actuations should be prevented. However, the inspector noted that the unit supervisor used attachment 3, " Facility 2 Actuation relay to Plant

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Equipment Cross Reference," to procedure OP2384, "ESAS (engineered safeguards actuation system] Operation," Revision 13 rather than using orawing 25203 28150, Sheet 2, as specified in Prerequisite 2.1.3. The inspector discussed this concern with the shift

manager who subsequently performed a line by line comparison of expected equipment actuations between drawing 25203-28150, Sheet 2, and attachment 3 to procedure OP2384. This comparison identified the following four discrepancies in attachment 3 to procedure OP2384: ' (1)'an incorrect valve identifier (2 RB-28.3B should be 2-RB 28.3D),

(2) an incorrect actuated position of a purge isolation valve (2-AC-11 should be closed j rather than open), (3) an omission of the actuated state for a fan (F13B), and (4) an omission of a damper actuation (2-EB-42). These errors did not affect the performance of

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the procedure SP2604R in the current plant conditio The surveillance test was conducted without incident. The inspector observed the

, equipment actuations that occurred and the performance of the operators and determined

' that the surveillance test was executed in a well controlled manner. The inspector reviewed the results of the surveillance test against relevant technical specification acceptance criteria and found that the objectives of the surveillance test were satisfied.

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l 17 On September 17,1998, the licensee initiated a procedure change request for procedure OP2384, attachment 3, to correct the four discrepancies identified associated with Facility 2 components. However, the procedure change request did not specify a review for similar l errors in attachment 2 to procedure OP2384, " Facility 1 Actuation Relay to Plant i Equipment Cross Reference." The inspector noted that three of the discrepancies were applicable to corresponding components on the Facility 1 list. Another concern with attachments 2 and 3 is that many of the listed components are shaded, and there is a note that states that the shaded bloch have normally closed contacts associated with the However, discussions with shift managers revealed that they did not completely understand what the note intended to communicate regarding the effects on ESAS operation. These procedural deficiencies are a concern because procedure OP 2384, Section 4.4, " Restoring ESF Actuation Cabinet 5," and Section 4.5, " Restoring ESF Actuation Cabinet 6," refer to attachment 2 and 3 for the identification of component actuations and these procedure sections are annotated as containing emergency operating procedure (EOP) related materia The inspector was subsequently informed that deficiencies associated the attachments to procedure OP2384 (as well as similar attachments in surveillance procedures) had been previously identified and were documented in Condition Report M2-97-0680, which was initiated on April 29,1997. The corrective action plan for CR M2-97-0680 includes: (1)

correcting discrepancies in drawing 25203-28150, sheet 2; (2) developing a new controlled drawing that contains more detailed information on ESAS operation; and (3) conducting a review of the new controlled drawing to determine if procedures can refer to the new controlled drawing rather than the attachments. These corrective actions were classified as enhancements with post-restart due dates. Although the inspector found the general content of the corrective actions acceptable to address the issues described above, the post-restart due date for the corrective actions and the absence of a specific reference to procedure OP2384 in the corrective actions were concerns with regard to the potential for plant operation at power with deficient EOP related material. In response to this concern, the licensee developed an additional corrective action assignment to revise procedure OP2384 to eliminate incorrect equipment designations and equipment actuation information prior to operational Mode 4, hot shutdow Conclusions Operators performed the pre-brief and surveillance test of manual safety injection actuation signal initiation acceptably , and the test results satisfied the relevant technical specification acceptance criteria. However, the NRC noted that operators referred 1) an operating procedure to determine which components would actuate rather than referri.m to a drawing specified by the surveillance procedure. A subsequent comparison of the operating procedure and the drawing revealed four errors in the operating procedure attachment that lists the actuated components. However, the concerns with the operating l procedure adequacy had previously been identified by the licensee and the NRC considers

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the corrective acticr. pMn to be acceptable. Accordingly, this non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcen,ent Poliev. (NCV 50-336/98-216-04)

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U2.Ill Enaineering U2 E1 Conduct of Engineering E Svstem Readiness Reviews for Ooerational Mode 6. Refuelina Insoection Scone (37551)

The inspector evaluated the licensee's process for system readiness reviews of the service water system (SWS) and control room air conditioning (CRAC) systems for operational mode 6, refueling. The inspection included a review of selected condition reports, unresolved itern reports, operability determinations (ODs), and engineering documents; attendance at system readiness review and plant operations review committee (PORC)

meetings; and walkdowns of the system Observations and Findinas The licensee conducted the system readiness reviews on the basis of exception. When all issues associated with a system for a specific operational mode are dispositioned as acceptable (either by implementing corrective action addressing the issue or by determining the system is operable, although degraded or nonconforming, through an operability determination), that system was considered operable for that operational mode. The inspector discussed th;s approach with personnel from the engineering department and operations department, and the inspector found the approach acceptabl The inspector reviewed the disposition of a sample of condition reports, unresolved item reports, ODs, and other engineering documents relating to either the SWS or CRAC system. The inspector found that allissues related to the SWS were adequately dispositioned, but an issue involving the CRAC system was initially improperly dispositione Condition Report (CR) M2-98-2022 documented that the valve stroke time for the "A" train normal exhaust damper, 2-HV-207, was 14 seconds. This isolation time significantly exceeded the desired isolation time of 5 seconds or less. Subsequent investigation and testing determined that the cause of the slow isolation of damper 2-HV-207 was the long run of tubing between the air operator for the damper and the controlling solenoid operated valve. The long run of tubing acts as a restriction in the vent path from the damper's piston operator. The licensee developed preliminary OD MP2-022-98 which concluded there was a reasonable expectation for continued operability of the CRAC system for a Unit 3 accident based on satisfactory isolation of the CRAC system intake damper for the "A" train,2-HV-202, which would block direct intake from the postulated radioactive plume from a Unit 3 loss of coolant accident (LOCA).

.The final OD MP2-022-98, Rev. O, provided additionalinformation supporting the operability of the CRAC system with the slow closure time of damper 2-HV-207. This OD conservatively estimated the total additional exhaust flow caused by the slow closure at 132 cubic feet. Because this additional exhaust flow after isolation of the intake path l

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would reduce the pressure in the control room, the infiltration of potentially contaminated air into the control room would increase until the infiltration flow made up for the excess exhaust flow. The OD documented that, based on engineering judgement, the slow closure time has a negligible effect on operation of the CRAC system and that the damper and the system remain fully operable and fully qualified. The Unit 2 PORC approved OD MP2-022-98 on August 17,1998. Because this OD documented the CRAC system as fully operable and fully qualified, operations department personnel cleared the O The inspector reviewed calculation UR(B)-453, "MP-2 Control Room Operator Doses Following a MP 3 LOCA Assuming Duct Leakage and Damper Bypass," Rev. O, which included the current design basis assumptions for the CRAC system. Although the calculation specifically addresses only the closure time of the intake air dampers, the calculation assumes that control room isolation is achieved, and the rate of air infiltration is reduced to the value established for an isolated control room when these dampers close.

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Because the rate of air infiltration for an isolated control room is based on measurements j taken with the exhaust dampers closed, the calculation assumption for control room

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isolation is valid only if both the intake and exhaust dampers close within the assumed closure tim The inspector discussed the concerns regarding the qualification of dampr 2-HV-207 for l- its function as a control room exhaust isolation damper with the CRAC sysbm enginee The system engineer acknowledged that he had similar concerns with the qualiiWtion of damper 2-HV-207. Subsequently, the system engineer initiated CR M2-98-2924, which documented issues involving qualification of damper 2-HV-207 and other CRAC system dampers that function to establish the control room isolation boundar The investigation of CR M2-98-2924 determined that the initial conclusion of full

qualification of damper 2 HV-207 was based on historicai testing of only the control room

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intake damper closure times for establishment of the control room isolation boundary. The j licensee determined that the CRAC systerr. exhaust dampers were also required to close l within the time specified for the intake dampers to satisfy the assumptions used in j calculation UR(B)-453. The corrective action plan for CR M2-98 2924 includes the f following actions: (1) issue a revised OD documenting damper 2-HV-207 as operable but

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not fully qualified; (2) evaluate testing requirements for CRAC system isolation boundary dampers; and (3) provide corrective action for slow closure time of damper 2-HV-207 by either revising engineering documents to allow for the existing closure time of 14 seconds or modifying the damper configuration to achieve a closure time of 5 seconds or less.

L Revision 1 to OD MP2-022 98, which documents damper 2-HV-207 as operable but not

! fully qualified, was approved on October 15,1998. The inspector found these corrective actions acceptabl The inspector determined that the safety significance of the slow closure of damper 2-HV-207 was minimal because it was one of two redundant isolation dampers in the exhaust

, flow path and the damper was merely slow in its operation because of its installed

[ configuration rather than degraded by damage or wear. The effect of this slow isolation on

operator dose in the event of a Unit 3 accident would be negligible, even with a failure of i the redundant damper.

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> 1 Conclusioca .

l The inspector concluded that the system readiness reviews for the SWS and the CRAC

! system, which support the transition to operational mode 6, refueling, from a defueled

! condition, were implemented well. The dispositioning of a licensee identified slow closure I of a control room boundary isolation damper revealed a historical concern with the translation of design information into surveillance procedures. However, the licensee

, implemented effective corrective actions to address this concern. This non-repetitive, I i- licensee-identified and corrected violation is being treated as a Non Cited Violation

[ consistent with section Vll.B.1 of the NRC Enforcement Poliev. (NCV 50-336/98-216-05)

l-U2 E8 Miscellaneous Engineering issues E (Closed) LER 50-336/96-036-00: Inadeouate Seismic Qualification of 4160 Volt l Switchaear due to Circuit Breakers in the Racked-Down Position i i

l Insoection Scone l The question of seismic qualification of circuit breakers in positions other than the operating position had been previously addressed by the industry during the electrical distribution system functional inspections in the early 1990s. The licensee identified on November 8,1996, a deficiency in their previous review of seismic capability of their l

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vertical lift 4160 Volt breakers as a result of their review of a similar discovery at the Susquehanna Steam Electric Plant.- The 4160 Volt safety-related circuit breakers at Millstone Units 2 and 3 are transported between their racked down position on the floor into their operating position with an internal elevator mechanism in each breaker cubica When in the fully racked down position, the circuit breakers rest on wheels on the floo The inspectors performed an in-office review of the licensee's closure package for LER 50-l 336/96-036-00 by reviewing the original adverse condition report (ACR M2-96-0631),

l engineering record correspondence (ERC) ER-96-0358, operating procedure OP 2348A, f 6900 and 4160 Volt Breaker Operation, Rev.1, changes 1 through 6, and related industry l' correspondence to assess the licensee's corrective action Observations and Findinos The inspectors confirmed that licensee entered the concern into their corrective action program, evaluated the condition and initiated corrective actions by revising the operating procedure. He confirmed that the operating procedure, OP 2348, had been revised to ensure that the Jrcuit breakers were restrained by the lift elevator mechanism at all times except when the breakers were being removed from their cubicals. The operating procedure explicitly states that the switchgear buses were seismically qualified when the

- breakers were fully withdrawn, resting on the floor and when restrained by the elevator mechanism used to lift the breakers into the operating position. =The inspector also

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confirmed that the basis for the seismic restraint capability of the elevator mechanism was founded in the calculation included in the ERC. However, it was found that there was no reference in the ERC to the original seismic requirements or qualification, and there was no i

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evidence that the conclusions of the ERC had been reviewed by the equipment manufacturer who had performed the original seismic qualification for the switchgear.

The inspector was aware that Millstone Unit 3 had identical circuit breakers. He confirmed that Unit 3 had obtained a supplemental seismic qualification report from the manufacturer to address the racked down condition. It was noted that the Unit 3 breakers were supported by the elevator mechanism in the racked down position and not the floor as was proposed by Unit 2. In response to the inspectors concern, the Unit 2 engineers indicated that Unit 3 had informed them of their approach and had supplied them a copy of the Unit 3 qualification. The Unit 2 engineers also indicated their seismic requirements were based on NRC Generic Letter 87-02, " Verification of Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors, Unresolved Safety issue (USI) A-46," which differed from the Unit 3 commitment to IEEE 344-1975, " Recommended Practice for Seismic QualificF m of Class 1E Equipment for Nuclear Power Generating Stations." The Unit 2 enginea indicated that their approach, based on the ERC, was intended for both the present condition of the plant (i.e. shutdown), when the only time a breaker would be racked down would be when the related facility switchgear was taken out of service for maintenance, and during plant operation, when a breaker would be required to be racked down to perform maintenance on the powered motor or pump. Additional discussions with the licensee indicated that they were in the process of modifying the control circuit for the high pressure safety injection (HPSI) pump on the swing bus 24E which would permit that breaker control switch to be left in the " pull-to-lock" position when the pump was not required. Following this change, all safety-cetated 4160 Volt circuit breakers would normally be maintained in the full-up, operating position during normal plant operation, Conclusions The failure to maintain the safety-related switchgear in its seismically qualified condition when the circuit breakers had been in their racked-down position was a violation of 10 CFR 50, Appendix B, Criterion Ill, Design Control. However, the inspectors concluded that the licensee had identified a deficiency in their seismic qualification for their 4160 Volt switchgear through their review of industry experience and took appropriate corrective action. In addition, it appeared that adequate communication existed on this subject between the Millstone units. Therefore, this non-repetitiva, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policv. (NCV 50-336/98-216-06) LER 50-336/96-036-00 is considered closed.

E8.2 (Closed) LER 50-336/97-014-00 & 01: Insufficient Reactor Buildina Closed Coolina Water Flow to Hiah Pressure Safety iniection Pumo Seal Coolers Insoection Scoog (92700)

r The licensee determined during an in-service test that flows in the reactor building closed cooling water (RBCCW) system loops to the HPSI pumps were below the required design values. The licensee issued Licensee Event Report (LER) 50-336/97-014-00 and made commitments to re-evaluate the system and to implement corrective actions as necessar l l

The inspector reviewed the licensee's closure package for this LER, which included engineering evaluations, design modifications, and associated adverse condition reports (ACRs) and condition reports (CRs). The inspector also performed an in-plant walkdown of the installed modification of the RBCCW piping to the "A" HPSI pump. Observations and Findinas RBCCW flow is supplied to the HPSI pumps in order to cool the pump bearings and seal coolers. The initial design RBCCW flow required for HPSI pump cooling was 35 gpm per pump, as determined by Combustion Engineering (CE). Measured flows in January 1997 for the three HPSI pumps ranged from 16 to 29 gpm per pump. As a result, the licensee issued LER 50-336/97-014-00 and ACRs M2-97-0083, M2-97-0155, and M2 97-0312 to address the surrounding issues.

The licensee contacted the HPSI pump vendor, Ingersoll Dresser Pump, who performed calculation TR-9764. This was reviewed and accepted by the licensee in Engineering Evaluation M2-EV-0070. Thesu calculations determined that the minimum required RBCCW flow for each HPSI pump was 14.2 gpm, which the licensee then rounded up to 15 gpm.

Appropriate assumptions were clearly noted in the calculation. Therefore, the licensee concluded that the pumps had sufficient flow to ensure their operability. As a result of inese new lower design values, the licensee re-evaluated the reportability of this item and in supplement 1 to the LER noted that the item was not safety significant and not reportable. The inspector reviewed the calculations and other documentation and had no comments.

During the reviews that were performed, the licensee determined that the RBCCW piping to the "A" HPSI pump (P-41 A) seal coolers had been connected in reverse (sup7ty and return piping were installed backwards) and that the RBCCW flow to the P-41 A seal cooler was notably lower than to the other two HPSI pumps, due to a longer run of small diameter pipe. Therefore, modification DCR M2-97025 was developed and installed to correct these items. The inspector reviewed the documentation and observed the three pumps in the plant, including the RBCCW seal cooling arrangement, the locked throttle valves, and the installed modification. No discrepancies were identified.

Subsequent to the modifications, the licensee performed SPROC 97-2-19, "RBCCW System Flow Balance," to verify and set flows in the RBCCW System for each cooled component.

This test verified flows for the five different plant conditions pertinent to RBCCW, including both normal and post-accident conditions. The acceptance criteria for flow to the HPSI seal coolers was set above the minimum calculated value of 15 gpm. The inspector reviewed the test procedure and results and evaluated the basis for actual acceptance criteria in the SPROC and whether it considered an allowance for degradation and instrument error. Design Engineering provided Attachments to Calculation No.97-169 and Memo MP2-DE 98-0044, dated February 6,1998, that provided an allowance of 1 gpm for instrument error and 1 gpm to the seal coolers for pump degradation. The SPROC had a verification step that showed that the operators could reset the throttle valves to the specified number of turns open and achieve the required flow per the procedure. The

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inspector also verified that the throttle valve settings from the SPROC results were incorporated into the RBCCW valve lineup procedures, i

, Conclusions

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i The licensee re-evaluated an event reported to the NRC, and determined that the HPSI pumps and seal coolers were operable and that this event was not risk significant or l reportable. Additionally, the licensee identified and corrected some additional problems with the ROCCW supply to the HPSI pumps. A special test was run to properly set the RBCCW flows to all components in the system. The inspector concluded that the

. licensee's corrective actions for this event were adequate and LER 50 336/97-014-00 and -

01 are close Report Details Summarv of Unit 3 Status .

Unit 3 began the inspection period in cold standby (Mode 4), commencing a reactor startup l following the repair of a leaking auxiliary feedwater valve. The reactor was taken critical at 22:36 on August 19,1998 and returned to power operation (Mode 1) at 9:29 on August

'20,.1998. Operators increased power to 100 percent on August 24 where it remained until August 27 when power was reduced, eventually to approximately 47 percent, to facilitate a main condenser tube leak repair. The tube repair was completed and power restored to 100 percent on August 3 Ga September 10 operators began a Technical Specification required shutdown per TS 3.0.3 when check valves in the service water- hypochlorite injection system failed their surveillance tests. These check valves isolate the nonsafety related hypochlorite system from the safety related service water system. Because check valves protecting both trains

of service water failed the surveillance, both trains of service water were declared L inoperable, leading to the entry into TS 3.0.3 Operators stopped the power reduction at 80 percent power, when operability was restored to one train of service water. Power was returned to 100 percent later that day. See Section U3.01.2 for further details.

l l On September 15 operators manually tripped the reactor when high conductivity in the condensate system was detected while restoring steam generator blowdown. The reactor trip was performed in accordance with alarm response procedures and was not required per TS. Following investigation into the alarms, the reactor was taken critical at 23:43 on September 1 On September 18, while at apprcximately 30 percent power, the licensee performed the

- confirmatory surveillances on the aforementioned hypochlorite check valves, as required by e operability determination. The valves failed the tests and operators again entered TS 3.0.3. The reactor shutdown was terminated at approximately.27 percent power when operability was restored to one train of service water via replacement of the check valves with blank flanges.100 percent power was subsequently achieved on September 2 . - . - . - .- - _ _ - . _ - --- , - - - -, .- - - -

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Operators again entered TS 3.0.3 on October 1 following a blown fuse on safety-related inverter 1. Operators declared the inverter inoperable, which affected the operability of the

"A" train of the recirculating spray system (RSS). Since the "B" train of RSS was out of service for planned maintenance, TS 3.0.3 was entered. Operators stopped the power reduction at 54 percent when the "B" train of RSS was restored. After discussions with the vendor and the decision to operate with "B" train equipment protected, power was returned to 100 percent on October 5, the last day of the inspection perio U3.1 Ooerations U3 01 Conduct of Operations 01.1 General Comments (717021 The inspectors conducted frequent reviews of ongoing plant operations, including observations of operator evolutions in the control room; walkdowns of the main control board; inspection-tours of plant areas housing safety systems in operation or standby conditions; and observations at several morning and shift turnover meetings. Specifically, an inspector witnessed the following operational activities, to include direct observation of the liaison between the operators and other plant departments in site preparations, system restorations and train swaps, technical specification (TS) compliance, and response to plant transient .e site preparations on August 26,1998 for the possibility of hurricane force winds and other storm damage resulting from a hurricane formed in the Caribbean, with potential tracking up to New England (note: while some wind and heavy rain were eventually experienced at the site, most of the storm did not affect Millstone Station.)

e a manual reactor trip from full power on the swing shift, September 15,1998, resulting from a secondary water parameter (condensate pump discharge conductivity) exceeding the limits allowed by operating procedures e a manually controlled power reduction (i.e., initiating a plant shutdown) on October 1,1998, as a result of an inverter failure in conjunction with equipment in the redundant train being out of service for planned preventive maintenance (note:

shutdown was stopped with reactor power at 54 %, with recovery activities restoring the plant to full power on October 5,1998.)

With regard to the storm preparations on August 26,1998, the licensee was deliberate and diligent in its planning activities. Work was scheduled immediately to restore a circulating water pump that was out of service for maintenance, to be followed by backwashing the main condenser waterboxes. . Maintenance and security personnel were place on round-the-clock shift coverage to clean the intake structure trash racks... A site inspection, building roof checks, and the lashing-down of equipment commenced in preparation for high winds, while contingency planning for ordering extra emergency diesel generator fuel, establishing secure communications links, and providing additional meteorology service was initiate '

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The inspector observed management meetings and planning activities in progress, reviewed operating procedure (OP) 3215, " Response to intake Structure Degraded Conditions", and conducted a site tour of various areas where the site preparation work was ongoing. With the arrival of the storm, the weather was not as severe as was anticipated and the unit withstood the storm effects wel Regarding the reactor trip on September 15,1998, the inspector responded to the control l room and witnessed the operators controlling plant conditions in accordance with reactor l trip procedures. The inspector observed telephone notification to the NRC headquarters l duty officer, efforts to secure the turbine plant equipment and initiation of boration to take the reactor coolant system to the shutdown requirements of hot standby (Mode 3)

conditions, operator actions to take manual control of pressurizer level to restore it to the expected band, and the use of auxiliary steam to maintain a condenser vacuum. Crew

! activities were deliberate and controlled, communications and briefings were clear, and shift management responded to equipment questions (e.g., pressurizer level, shutdown margin monitor inoperability) appropriatel Subsequently, the licensee convened an Event Review Team (ERT) to evaluate the cause of this event, which was determined to be the result of the restoration of the steam generator blowdown (BDG) system to closed-cycle operation with some salt water (approximately two gallons) having been introduced into the piping back to the condenser hotwell. The inspector attended the ERT management briefing and observed group interactions and i questions, with the ultimate determination that the likely cause of the salt water intrusion was a procedural deficiency that allowed vacuum conditions to result in the backflow of seawater, from the BDG system operating open-cycle, into a "deadlegged" portion of the blowdown piping. The inspector noted that the corrective actions specified for plant restart included a complete flush of the blowdown system, in addition to the revision of the affected operating procedure After implementation of the required corrective measures, the inspector witnessed startup evolutions over the ner.t several days, with the reactor taken critical (Mode 2) on

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September 16, Mode 1 power operations achieved on September 17, the turbine generator synchronized to the grid on September 18, and the power ascension essentially completed

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on September 20,1998. During the licensee's ERT review, it was noted that a similar salt-l water intrusion event, not resulting in a reactor trip, had occurred in 1993. The inspector

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reviewed the plant incident report, PIR 3-93-319, which had recommended a procedure change, which apparently had not been effectively implemente The power reduction on October 1, caused by the inverter failure (further discussed in Section E1.1 of this inspection report) was the result of a collaborative decision between operations shift management and unit licensing personnel that plant conditions required

entry into a limiting condition for operation (LCO) 3.0.3, directing that a plant shutdown be

initiated. The inspector reviewed a Regulatory Compliance Position on Cascading TS, dated September 18,1998, which when applied to the situation of inverter failure on one

) train with the redundant train of RSS out of service for maintenance, resulted in both trains of RSS being declared inoperable. The inspector discussed this decision with the Regulatory Compliance Manag6r (RCM) and concurred that the entry into TS 3.0.3, while

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] 26 conservative, was both prudent and properly reached given the guidance provided by the September 18 Regulatory Compliance Position. Additional training of operatc,rs on the

[ proper application of cascading technical specifications was deemed to be an appropriate initiative that the RCM agreed to pursue.

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j in evaluating the licensee response to the inverter failure, the inspector reviewed a previous

commitment to a licensee event report (LER 97-025-00) regarding entry into TS 3.0.3 upon

loss of a vital ac (VIAC) bus. With the loss of the inverter on October 1, while one power

[ supply path to VIAC-1 was lost, the bus itself never lost power. Therefore, entry into TS e

3.0.3 became an operator judgement issue on cascading TS, instead of a corrective action

requirement. However, in discussing this issue with regulatory compliance personnel, the

, licensee reserved the option to revisit the commitment made in LER 97-025-00. If changes

are decided upon, the licensee indicated that they would be formally transmitted to the

1 NRC on the Unit 3 (50-423) docke ; Conclusions i

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Licensee management, operations, and support personnel responded well to the challenges

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presented to Unit 3 during this inspection period. Conservative decision-making, and deliberate planning, event response and analysis, and corrective action review were in l evidence. The inspector discussed with the responsible plant managers, including the unit director, the cd m. aJnional training and an enhanced approach to prevent problem recurrence to reduce, where possible, the number of future challenges to plant operatio .2 Technical Soecification 3.0.3 Entrv Due to Inocerable Service Water System Caused by the Failure of Sodium Hvoochlorite Check Valves Insoection Scone (71707. 37551)

On September 10, the licensee entered Technical Specification (TS) 3.0.3 which requires a plant shutdown. The TS entry was made following the failure of some leak test surveillances conducted on the sodium hypochlorite-service water injection system check l valves. The inspector discussed the event with operations and engineering personnel and observed actions taken in the control room and service water cubicles by operations, maintenance and engineering personnel to assess the organization's response to the failures. In addition the inspector reviewed associated documents and discussed the planned and completed corrective actions with the responsible design and system engineer Observations and Findings Sodium hypochlorite is injected into the Unit 3 service water system to help control or eliminate fouling of service water cooled heat exchangers due to mussel growth. The original system injected a hypochlorite solution into the suction bells of each of the four service water pumps. This method of injection caused hypochlorite to be discharged to the intake basin when the strainers, located downstream of the pumps, automatically blew down due to high differential pressure. This resulted in the potential for violating the state

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environmental permit (NPDES) controlling discharges from the unit. A timed blowdown of the strainers was prevented via a temporary modification to preclude violations of the l permit. Instead, operators would control this periodic blowdown by first taking

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hypochlorite out of service and then restoring it after the blowdown was completed, in 1997, after committing numerous violations of their NPDES permit, the licensee initiated a modification to relocate the injection point of sodium hypochlorite into the service water j system. The modification, DCR M3-97062, relocated the injection point downstream of each of the four strainers, thereby precluding automatic blowdowns and violations of the permit. The new system utilized two, in-series check valves per line to provide boundary l isolation of the Class 3, safety related service water system from the nonsafety related hypochlorite system. Therefore eight check valves were used, two per service water pump. This modification was installed in the first quarter of 1998 and turned over to operations in August. Testing was to be conducted quarterly in accordance with special procedure (SPROC) 97-3-18, Hypochlorite System Flow Test, to verify leak tightness of the in-series check valve On September 9, the SPROC was performed on the valves for the "B" service water pump and failed. Operators appropriately entered the applicable technical specifications for the inoperable "B" train of service water. A 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limiting condition action time is associated with this TS. Subsequent testing on the "D" service water pump /hypochlorite system

- check valves also failed. The licensee then decided to test the other train of service water and although the "C" valves passed the surveillance, the "A" valves did not. At this point operators declared both trains of service water inoperable and entered TS 3.0.3, which I required a plant shutdown. Operators commenced the power reduction from 100 percent power. This power reduction was stopped at 80 percent power when the "A" check valves were reseated, restoring operability of the "A" train. Operators exited TS 3.0.3 and remained in the previous LCO for one inoperable service water train. The train "B" check valves were subsequently reseated and the I.CO was exited based upon operability determination (OD) MP-111-98, which required a compensatory leak check to be performed in accordance with the SPROC every week in addition to visual inspection of the internals of the check valves every two weeks. This was based on the fact that the system had seen this degradation in one month's time and a longer period was not thought to be defensible. The inspector determined that this compensatory action was reasonable, based on the information available to the license After one week of operation, all check valves failed the confirmatory SPROC on September 18 and TS 3.0.3 was again entered. At this time, the plant was at 30 percent power, and I a power ascension was in progress following the unrelated manual reactor trip discussed in ( the previous section of this report. A temporary modification (TM) to install blank flanges

in the place of the check valves, effectively disabling the new modification had been j approved after the initial failures and was installed while in TS 3.0.3. Once the flanges j were installed on one service water train, TS 3.0.3 was exited and the power reduction

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was stopped at 27 percent power. Upon installation of all blank. flanges, the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO

! was also exited. The licensee subsequently returned to the previous method of

! hypochlorite injection to the service water pump suction bells.

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J The inspector attended meetings between maintenance, engineering, and operations, and observed good communication of issues and concerns. The inspector also walked down the service water pump area and observed performance of the SPROC. Once the check l

valves were removed from the system, the inspector noted oxidation products on the check valve internals. Licensee engineering personnel contacted the check valve vendor to discuss the situation and perform a failure analysis and test of the materials. This testing I confirmed that the monel used in the fabrication of the check valves was subject to the )

l noted oxidation and degradation (e.g. leak tightness failures) in the presence of the '

hypochlorite solution used at Unit Several CRs were issued and a root cause determination was in progress at the end of the inspection period. Through observations of corrective actions and review of documentation related to the inoperability of the servico water system, the inspector noted appropriate response to the Technical Specification 3.0.3 entry caused by the failure of the hypochlorite check valves. The inspector concluded, however, that the modification installed valve materials which were incompatible with the hypochlorite system. This poor design led to the inoperability of both trains of service water and subsequently tequired  ;

two entries into TS 3.0.3 and two downpowers. This modification was implemented in the same time frame as the RSS cubicle sump pump modification. The underlying causes for this deficient service water modification appear to be related to those described in IR 98- l 208, which describes an unresolved item (URI) on the RSS sump modification. The l inspector will follow the licensee's corrective actions in response to these design change  ;

problems during further review of URI 98-208-0 ' Conclusioris  ;

Through observations of corrective actions and review of documentation related to the i inoperability of the service water system, appropriate response to the Technical Specification 3.0.3 entry caused by the failure of hypochlorite injection system check valves was observed. However, the recent modification installed valve materials which were incompatible with the hypochlorite system. This inappropriate material selection led to the inoperability of both trains of service water and subsequently required two entries into TS 3.0.3 and two downpower U3 03 Operations Procedures and Documentation l

l O3.1 (Closed) LER 50-423/97-037-00. " Residual Heat Removal System (RHS) Testina Durina Transition to Mode 4 Incorrectiv Usino RHS One Hour Out-of-Service ( Allowance" Insoection Scone (90712)

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i The licensee identified that plant operators historically interpreted the requirement to L maintain at least one RHS system in operation during Mode 5 incorrectly, in permitting the i removal of the operating system from service, while entering the one-hour limiting

condition for operation to permit RHS leak testing just prior to entering Mode 4. The j inspector performed an in-office review of the condition report (CR) M3-97-1451, which I

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1 documented and evaluated the event; action request (AR) 97011696, which assigned corrective actions; licensee event report (LER 50-423/97 037-00), which reported the event in accordance with 10 CFR 50.73(a)(2)(l); licensee letter number B16636, dated August 29,1997, with attached technical specification (TS) change request; and associated operating procedures to assess the licensee's problem identification and corrective action response. Observations and Conclusions The inspector reviewed the licensee's condition report, action items, and TS 3.4.1.4.1 revision and had no technical concerns. The inspector also confirmed the associated procedure EOP 3505, Loss of Shutdown Cooling and/or RCS Inventory (Revision 9), added an entry condition upon loss of the operating reactor coolant pump when it is the only pump being used to provide core cooling during heatup to Mode 4.

The inspector observed that the licensee's initial reportability review on May 21,1997 indicated that the condition was reportable, but failed at that time to identify the requirement of 10 CFR 50.73 for reporting violations of the unit technical specifications within 30 days of the discovery of the event. Upon further licensee review, the licensee recognized the reportability requirements on June 24,1997 and submitted LER 97-037-00 on July 22,1997. Conclusions The subject historical violation of the Unit 3 TS was discovered with the plant in Mode 5, during a review of procedures. Corrective actions implemented by the licensee were timely in that the required TS revision was requested and received prior to the next actual plant entry into Mode 4. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Eglicy. NCV 50-423/98-216-07. Based upon the plant condition at the time of discovery, the failure to submit the subject LER within 30 days constitutes a minor violation, consistent with Section IV of the NRC Enforcement Policy, and will not be cited. , LER 97-037-00 is hereby closed.

U3 08 Miscellaneous Operations issues 08.1 Licensee Event Reoort Review - Ooerational/ Surveillance issues Ir soection Scoce (92700)

The inspector reviewed four Licensee Event Reports (LERs), documenting operational or surveillance problems identified while the unit was in Mode 5. Three of these event reports discuss surveillance procedure inadequacies, while the fourth documents an inadequate system configuration event. All four events constitute violations of the Unit 3 technical specifications. An onsite verification of completed licensee actions, to include procedure revisions, operator training, and calibration record checks, was conducted as appropriate,

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to assess the programmatic acceptability of the corrective measures directed to operator performance and surveillance implementation.

l Observations and Findinas The following four LERs were reviewed and closed, with the inspector evaluating the commonality of the causal analyses of these events, particularly with regard to surveillance program deficiencies and operator cognizance of the plant status during the performance of surveillance activities: )

e LER 50 423/97-44-00, " Missed Technical Specification Surveillance of ESFAS l Isolation instrumentation" e LER 50-423/97-049-00, " inadvertent Reactor Coolant System Positive Reactivity l Addition While Entered into the Limiting Condition for Operation Action Statement is a Violation of the Technical Specifications"

'e

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LER 50-423/97-052-00, " Deficiencies identified in the Performance of Surveillance for PORV instrumentation"

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e LER 50-423/97-53-00, " Channel Check Surveillance Requirements not in l Compliance with Technical Specifications" The inspector reviewed several operating and surveillance procedures, verifying i ~ implementation of condition surveillance triggering mechanisms, intended to remind operators of the need for certain surveillance testing requirements, prior to continuing with the procedure. The inspector also selected certain work orders for review to spot-check l whether instrument calibrations and channel checks that had been previously missed, were

!~ now being conducted with appropriate acceptance criteria delineated in the applicable surveillance procedure. Operators were interviewed and the expectations for procedure l l usage, pre-job briefings, and on-shift knowledge of the plant configuration, as it affects

operational evolutions and surveillance activities, were discussed. The documented  !

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corrective measures for each of the four LERs were evaluated and determined to be j adequat Conclusions Licensee corrective actions to address four separate LERs, relating to operability concerns from failed or missed surveillances, appeared appropriately directed to the specific technical specification (TS) violations. Collectively, the incorporation of triggering mechanisms into operating procedures for TS required surveillances was viewed as an effective programmatic enhancement. Operator compliance with procedure requirements, as well as cognizance of the system configurations and plant status, have improved since the initial mode changes and return of the unit to full power. These issues have been properly analyzed and reported by the licensee as TS compliance concerns. .These licensee-identified and corrected violations are being treated as Non-Cited Violations, consistent

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with Section Vll.B.1 of the NRC Enforcement Poliev. LERs 97-44-00, 97-49-00, 97-52-00,

& 97-53-00 are hereby closed as NCVs 50-423/98-216-08 through 98-216-11, respectively.

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U3M Maintenance l' U3 M1 Conduct of Maintenance M 1.1 Mse of Risk Assessment in the Work Plannino Process Insoection Scone (62707) i

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The inspector conducted a review of on-line maintenance and scheduling practices to determine how the effects of unavailable equipment were considered with respect to the required performance of system safety functions. Specifically, the program for on-line scheduling was reviewed, work planning personnel were interviewed, and selected situationc of equipment removed from service for preventive maintenance were examined to evaluate compliance with the requirements of 10 CFR 50.65 for overall risk assessment consideration Observations and Findinas l

The inspector reviewed the Unit 3 work management procedure U3-WC-14, Revision 2, for

"On-line Scheduling", the twelve-week work process overview, and the twelve-week on-line schedule improvement plan. The inspector also interviewed a work control supervisor and work week manager to evaluate how risk assessment information was used to plan major equipment outages in the maintenance work week schedule. During one work week, the removal from service of a train of containment recirculation and residual heat removal equipment was inspected for probabilistic risk assessment (PRA) review and handling of supporting component (e.g., ventilation system) outages. The inspector noted that procedural requirements specify PRA concurrence of the final work and system outage schedules for weeks T-2, T-1, and the execution week performance activities, as well as PRA review of any additional work week changes extending outage time or removing related equipment from servic The Unit 3 procedural controls delineated in U3 WC-14 specify the systems for PRA review and provide a Millstone Unit 3 Risk Matrix. The schedule development for the outages of risk significant systems begins in work week T-8 and continues with the incorporation of the preventive maintenance with required surveillance activities through successive work weeks. Special consideration of containment systems work, so as not to be scheduled concurrent with a risk significant train, is also developed in the preliminary work week planning. The inspector verified that during the execution week, the operators on shift and operations work control personnel are directly involved in component outage and timing change The inspector attended several maintenance planning meetings on the specific days of

! scheduled work for risk significant equipment. The interaction and coordination between

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operations, maintenance, work control, and engineering personnel were observed; and the i

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inspector noted the routine cancellation of work or request for PRA review of emergent work requirements, where requested by operations personnel based upon the existing

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l workload or risk perspectives. The inspector also determined that several improvements to the twelve-week on-line work schedule process are in progress, including the prioritization of backlogged work with operator impact, proper operator work control staffing, and l review of the methods for changing or adding to the existing work scope. The appropriate

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consideration of risk perspectives appeared evident in all these activities. Conclusions The Unit 3 on-line maintenance process has been structured to use probabilistic safety assessment insights and operator judgement to achieve a balance between plant safety, schedule duration, and required work completion. A sample review of the implementation of this process determined that PRA information is effectively used and schedule adjustments routinely made to address the changing plant system configuration and risk profile. For the areas inspected, the Maintenance Rule (10 CFR 50.65) objectives, in relation to the risk perspectives of work control and overall plant safety, were effectively met.

U3 M8 Miscellaneous Maintenance issues M8.1 Review of Licensee Event Reoorts insoection Scone 192700)

The inspector reviewed the following three Licensee Event Reports (LERs), assessing the adequacy of the identification, reporting, evaluation, and resolution of each individualissue.

The review was conducted onsite and included examination of the associated condition reports, related safety evaluations, and a selected sample of corrective actions, Observations and Findinas (Closed) LER 50-423/97-027-00. " Corrective Actions Not Met for Trendina Valve Leakaae" i

With the unit in Mode 5, the licensee determined that the trending and corrective action requirements of Section XI of the American Society of Mechanical Engineers (ASME) Code for the in-service testing (IST) of valves had not been met. While twenty-three instances where a containment penetration had exceeded its maximum leakage limit were identified during the past five refueling outages, containment integrity was not compromised by the individual code infractions, since the total containment penetration leakage did not violate its technical specification limit.

The inspector reviewed the Millstone 3 Appendix J Program Manual to confirm that all Type C penetra+ ions, as listed in the Unit 3 Final Safety Analysis Report (FSAR), were included in the IST program. The inspector also reviewed engineering calculation 3-ENG-084, establishing the administrative limits for 10 CFR 50, Appendix J testing and verified acceptance criteria consistent with the technical specifications, the FSAR, and the allowable leakage limits specified in surveillance procedure SP36128.4. The administrative and maximum allowable leakage limit calculations were spot-checked, found to have been

corrected, and determined to be currently acceptable. The licensee's corrective actions documented in LER 97-027-00 were evaluated and deemed appropriat (Closed) LER 50-423/97-040-00. " Quarterly IST Closure Testina of Service Water System Check Valves 3SWP"705. 706. 707 and 708 Not Performed" With the unit in Mode 5, the licensee identified a historical violation of the ASME Code and IST program requirements during the first operating cycle of Unit 3. During this period, the four listed service water system check valves had not been exercised quarterl Subsequently, the licensee disassembled and inspected the valves, confirming their capability to perform the closure function, and received relief from the NRC for use of this alternate test method on a staggered basis at a refueling outage (RFO) frequenc The inspector verified that the four subject service water system check valves had been incorporated into engineering procedure EN31123, Revision 4, for check valve inspectio The data sheets for all four valves were reviewed for the acceptance criteria utilized during the RFO 5 inspections conducted in 1995. The inspector also reviewed the Millstone 3 IST Program document, ISI-3.0 (Revision 5), dated April 5,1998 to confirm adequate inclusion of these valves in the current program. Licensee corrective actions for this historical violation, as described in LER 97-40-00, were deemed to be acceptabl (Closed) LER 50-423/97-042-00. " Reactor Coolant Dilution isole% Valves inocerable Due to Not Beina included in the in-Service Test Proaram Pesults in the inocerability of the Emeraencv Boration System" With the unit in Mode 5, the licensee determined that three valves in the chemical and volume control system (CHS), with an active safety function to remain closed to prevent the diversion of boric acid flow or inadvertent dilution for primary grade water, had not been included in the Millstone 3 IST program. No surveillance procedure had been developed to specify test provisions for these valves and therefore, the valves had not been tested in accordance with ASME Secaon XI and technical specification requirement The inspector reviewed IST document, ISI-3.0 (Revision 5) and surveillance procedure SP3604C.7 (Revision 1), verifying that the subject CHS valves had been added to the Unit 3 IST program and procedural requirements now exist to test the valves on a quarterly basis. The inspector confirmed that all three valves passed the stroke-time testing criteria in the surveillance procedure, conducted earlier in 1998. The corrective actions described in LER 97-042-00 were found to be acceptable and were verified by the inspector to have been implemented prior to Unit 3 entry into Mode Conclusions Licensee corrective actions for all three LERs, documenting IST program and technical specification violations, were determined to be acceptable. The licensee implemented the

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corrective measures in a timely manner after problem identification, before taking the unit

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to a higher mode of operation. No adverse safety consequences actually developed as a result of these IST program problems and omissions. The licensee recognized these issues l

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i as technical specification violations and appropriately reported the conditions in accordance I with 10 CFR 50.73. These non-repetitive, licensee-identified and corrected violations are '

being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Poliev. LERs 97-027-00, 97-040-00, and 97-042-00 are hereby closed as non-cited violations, NCVs 50-423/98-216-12,13, & 14, respectivel U3.Ill Enaineerina U3 E1 Conduct of Engineering E Review of Emeroent and Onaoino Enaineerina Activities Insoection Scone (37551. 92903)

The inspector assessed the role of engineering in addressing emergent work, plant i modifications, and previously identified operational issues involving design consideration l Coordination amongst the various plant departments and work groups, in effecting engineering investigations and work implementation, was observed. The inspector conducted followup inspection of specific engineering tasks with operational impact and evaluated the effectiveness of the organizational interfaces involved in the problem-solving processes. Observations and Findinas Specifically, the inspector reviewed engineering activities related to the following technical issues:

e approval and installation of temporary modifications: TM 3-98-054, for the elimination of " noise" affecting the operability of channel 1 of the shutdown margin monitor; and TM 3-98-062, for conserving water inventory, as well as maintaining adequate levelin the demineralized water storage tank while feeding the steam generators with the auxiliary feedwater pumps e recommended short and long term action plans for the containment RSS loop seal fill surveillance and venting evolutions, based upon past surveillance failures resulting from a small accumulation of gas over time in the horizontal leg of the RSS piping e implementation of immediate corrective actions and development of a

- troubleshooting plan for a blown fuse and resultant loss of the inverter supplying the 120Vac vital bus, VIAC 1 The inspector reviewed the safety evaluations, procedure revisions, engineering sketches, and loop diagrams, as applicable to the design documentation and implementation details for the above issues. Field inspection tours were conducted to examine the affected components, confirm proper work control provisions, and check the status of approved engineering installation details. In certain cases, the cognizant design and technical

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support engineers were interviewed regarding system impact and operability, and plans for future monitoring of the recommended modifications or troubleshooting activitie Particularly with regard to the inverter No.1 (3VBA*lNV1) inoperability, the inspector reviewed the related operability determinations, OD Nos. MP3-115 98 & MP3116-98, the condition report (CR M3-98-4308) discussing the blown fuse, and two earlier CRs documenting blown fuses within this inverter panel within the previous six weeks. In response to the latest event, the licensee replaced the blown fuse and all five instrument cards controlling the firing of the silicon controlled rectifier (SCR) circuitry. The inverter vendor (Elgar) was contacted and failure analyses on all five firing cards was arranged, ultimately with negative results; and a temporary modification (TM) installed on 3VBA*lNV1 with the intent to monitor SCR firing. This TM was not successfulin providing useful data and was subsequently removed. Thermography testing was performed on both inverter No.1 and the opposite-train inverter No. 2, for the purpose of comparison and attempting to find " hot spots." The testing did not identify the cause of the fuse failure The inspector observed engineering meetings discussing immediate and longer-term troubleshooting and contingency plans, given that the inverter, while operable and in savice, had not been repaired with complete confidence that another fuse failure would not recur. In light of this uncertainty, the "B" train of equipment for which the non-problem inverter no. 2 provides support, has been carried as the " protected" train through to the present time. While the licensee's engineering staff pursues options te monitor the in-service performance of inverter No.1, the inspector has requested ralt ted Elgar documents for review and continues to evaluate the li:ensee's progress on this tr,chnical concer ' Conclusions l

The review of engineering activities for emergent component and system problems identified during this inspection has resulted in no unacceptable conditions or advt.rse I findings. The licensee has implemented appropriate corrective measures to restore inverter 3VBA*lNV1 to an operable status. However, since the cause of the recurrent fuse failures i has not been established, the potential degraded condition of this component remains a l concern. The licensee continues to explore options to address this concern. Pending NRC review of the requested vendor documents and understanding of further licensee action and contingency plans for the observed multiple fuse failures on inverter No.1, this issue i remains unresolved. (URI 50-423/98 216-15)

U3 E2 Engineering Support of Facilities and Equipment l l

E (Closed) LER 50-423/97-063-00. "lnadeauate Ooerator Resoonse Time for inadvertent Safety iniection (SI) Event" l Insoection Scoce (90712) 1 The licensee identified that the operators may not be able to respond quickly enough to an inadvertent Si to prevent an overfill of the pressurizer and the resulting water relief through l

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1 the pressurizer power operated relief valves (PORV). Those valves had been specified for 1 steam relief and had not been previously qualified for water relief, The inspector performed an in-office review of the LER, action request (AR) 97029879, design change record (DCR)  !

M3-98003 Executive Summary, correspondence from Westir.ghouse and Stone & Webster l on the qualification of the valves and piping respectively, and related calculations and j drawings to assess the licensee's corrective action ' Observations and Findinos The inspector confirmed that the licensee had evaluated the PORV, PORV block valves and associated downstream piping and supports for the potential water relief condition. The DCR executive summary also indicated that the thermal overloads for the PORV block valve l actuator motors were to be removed. The inspector confirmed that the electrical I elementary diagram for the block valves showed the thermal overload relay contacts were removed from the actuator circuit, to ensure that the block valves would be available to be opened, but remained in the alarm circuit, to provide some protection for the valve  !

actuator, Conclusions The inspector concluded that the licensee had correctly identified a potential for a condition outside the design basis for the pressurizer relief components and had initiated timely and effective corrective actions. LER 97-063-00 is hereby close U3 E8 Miscellaneous Engineering issues E Closed) LER 50-423/97-58-00. "inadeauate Technical Soecifications Surveillances of the Solid State Protection Svstem" With the unit in Mode 5, the licensee identified a deficiency in the way certain Solid State Protection System (SSPS) logic circuits are tested. This testing problem, which had been raised as a generic industry issue, resulted in the discovery of historical surveillance

inadequacies for three specific SSPS safety functions. The licensee reported the applicability of this issue to Millstone 3 as a violation of the Unit 3 technical specifications

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(TS).

The inspector reviewed the safety significance of the identified deficiency from a historical perspective and determined that since the safety circuitry in question is actuated during periodic operational evolutions, any failures would not have gone undetected over i successive shutdown /startup cycles. However, the monthly SSPS operational test procedure required revision to address the concern of a potentialinternal card failure that l had not been previously postulated. The inspector reviewed surveillance procedure l SP3446B11, Revision 10, and verified that additional steps had been incorporated to check that the logic circuit is operating properly. The inspector also sampled the test records for

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a number of past monthly tests.

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The required procedural revisions were completed before the unit was allowed to neatup to Mode 4 conditions. The inspector also noted that licensee corrective actions included a review of the general SSPS test design to confirm that no additional circuit testing logic deficiencies of a similar nature were in existence. The licensee's overall approach to corrective actions to this design problem was found to be adequat The licensee properly reported this TS violation in accordance with 10 CFR 50.7 Analysis of the event and implementation of timely corrective measures were validate This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NBC Enforcement Poliev. LER 97-58-00 is hereby closed as NCV 50-423/98-216-1 IV Plant Suooort (Common to Unit 1, Unit 2, and Unit 3)

R1 Radiological Protection and Chemistry Controls Insoection Scoce (83729 & 83750)

A review of the radiation protection programs at all three units was conducted. During the inspection period, Unit 3 was operating at or near full power, Unit 2 was in an extended i

shutdown, and Unit 1 we permanently closed. Areas of inspection focus were based on the following regulatory requirements from 10 CFR Part 20:

20.1101 Radiation protection program 20.1601 Control of access to high radiation areas 20.1602 Control of access to very high radiation areas 20.1902 Posting requirements 20.1904 Labeling containers 20.2103 Records of surveys

in addition, a review of the circumstances resulting in the contamination of radiological L workers in the Unit 1&2 Chemistry laboratory and in the Unit 1 liquid radwaste facility was l conducted, including an evaluation of the licensee's corrective actions for previously identified deficiencie The review of these program areas was conducted by examination of licensee records, tours of various radiological controlled areas (RCAs), and interviews with cognizant l personnel, Observations and Findinas l Unit 3 resumed operations in July 1998 following a 29-month shutdown. Significant

! reductions in plant general area dose rates were observed during this shutdown due to radioactive decay. As a consequence, the radiation protection staff developed an extensive plan for periodic monitoring and surveillance of plant facilities to track the

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increased area dose rates during power ascension and operations. Detailed area survey

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maps were made available to all workers entering the RCA, while appropriate regulatory postings and additional informational postings in support of the program for maintaining occupational exposures as low as is reasonably achievable (ALARA) were located throughout the unit. During the inspection period, direct observation of licensee preparations for an at-power entry to the containment was also made. Pre-job planning and briefing of workers involved in this evolution were handled in a professional manner, with significant time devoted to reviewing industrial safety and radiological conditions expected to be encountere Radiological activities at Unit 2 were devoted to work that would lead to unit restar During September 1998, the reactor was defueled, with the cavity flooded. An extensive tour of the Unit 2 containment, including the two pump bays, indicated that the facility had instituted appropriate radiological controls, including regulatory postings, informational postings in support of the ALARA program, and that the radiological housekeeping program was being effectively implemented. On September 15,1998, a unit ALARA committee meeting was held to discuss revising the annual unit ALARA goal in order to reflect current plant status and anticipated remaining work for 1998. While no final decision was made at this meeting, the discussion appeared appropriate to support an effective ALARA progra In July 1998, the licensee announced its decision to permanently close Unit 1. During this inspection period, activities within the Unit RCA were extremely limited, pending management determination of decommissioning activities. On September 15,1998, the l Unit ALARA committee met and revised the unit annual ALARA goal to approximately 5

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person-rem, to reflect the current unit configuration and anticipated scope of work, Unit 1 issued two condition reports (CRs) during the summer of 1998 to document two significant radiological contamination events. One involved worker clothing contamination following entry to the liquid radwaste facility, while the other involved both a clothing contamination and unplanned skin exposure during work in the combined Unit 1/ Unit 2 chemistry laboratory. The second event, initially documented as a shoe contamination, led to a root cause review that identified a number of deficiencies in the way radioactive materials were being controlled and handled in the chemistry laboratory. The review of this program area by the licensee was thorough, and resulted in the identification and completion of several reasonable corrective actions. Additionally, the shallow dose equivalent calculation for skin of the hand exposure to one worker was reviewed and determined to be appropriat Conclusions An effective radiation protection program for activities being conducted at all three units is being implemented. Changing work scope at Units 1 and 2 has led to a review of the l annual exposure goals for these units. An extensive and effective investigation of a contamination event at Unit 1 resulted in the identification and implementation of several radiological improvements.

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R5 Staff Training and Qualification in Radiological Protection and Chemistry Insoection Scone (83729 & 83750)

The program for continuing training of staff radiation protection personnel was reviewe This review was accomplished primarily by attendance at several training sessions and review of licensee records and lesson plans for these activities.

, Observations and Findinas l

Health physics technicians are provided continuing training throughout the year by the technical training staff, based on lesson topics and training plans developed by the appropriate curriculum advisory committee (CAC). For the fall of 1998, five week-long training sessions were scheduled, with each session to include training on:

l - responding to a medical emergency in the RCA

! - whole body counter theory and operation

- 10 CFR 20 changes

- radiological monitoring team Each lesson plan was presented in a professional manner by qualified members of the l technical training staff. Quizzes / examinations were utilized following some of the lessons j to verify the students appropriate understanding of the subject materia Conclusions An effective technical training program has been established for the continuing education of licensee radiation protection technicians.

l R8 Miscellaneous Radiological Protection and Chemistry issues

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l R (Closed) Unit 2 Item D of VIO 50-336/98-207-16 & Unit 3 LER 50-423/98-025-00 and (Ocen) Unit 2 LER 50-336/98-008-00: Failure to Perform Technical Soecification Reauired Full Loon Channel Calibration of Meteoroloaical Monitorina Instrumentation Insoection Scoce (92904)

l The inspector reviewed the licensee findings and corrective actions taken to resolve the conditions reported in item D of Violation 50-336/98-207-16, as well at the two related licensee event reports, LER 50-336/98-008-00 for Unit 2 and LER 50-423/98-025-00 for Unit 3. The substance of this item was that a fullloop calibration was not performed on l the wind speed instrumentation as required by Technical Specification (TS) surveillance requirement 4.3.3.4. The calibration was required to be performed every 184 day .

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l l 40 Observations and Findinas l

Table 3.3-8 of Unit 2 TS 3/4.3.3.4 requires that the instrument minimum accuracies of the meteorological monitoring instrumentation channels (wind speed, wind direction, and delta temperature) be measured semiannually. Prior to April 24,1998, the instrument monitoring accuracy of the wind speed channels were not measured as required by the above cited TS. This resulted , as stated, in the violation and LER 50-336/98-008 00 for Unit 2. Since this is a common system for both Units 2 and 3, the licensee issued LER 50-423/98-025-00 for Unit 3 on the same subjec In response to these items, the licensee issued: . Condition Reports (CRs) M2-98-1204 and M3-98-2195, and violation response letter, B17350, dated July 20,1998, to the NR The violation response letter contained a commitment to perform surveillance procedure C SP 400.2, " Meteorological Instruments Calibration," for the meteorological wind speed loops. Additionally, the commitment made by the licensee in LER 50-336/98-008-00 was to revise the appropriate surveillance procedure to include the following checks for the meteorological tower wind speed loops: 1) verification of anemometer starting threshold,

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and 2) rotation of the anemometer on the tower to a known rpm and a readout of the plant process computer. LER 50-423/98-025-00 contained a licensee commitment to prepare, approve, and perform a site-wide surveillance procedure to perform a full-loop calibration of the meteorological monitoring system's wind speed instrumentation.

l l The inspector reviewed the licensee's response to Violation 50-336/98-207-16, LER 50-

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336/98-008-00 for Unit 2, LER 50-423/98-025-00 for Unit 3, as well as the associated {

CRs, CR M3-98-2195 and CR M2-98-1204. The inspector also reviewed CR M3-98-1437, l CR M3-98-2909 and a Root Cause Investigation Report, all of which dealt with i meteorological program weaknesses, but were not the direct subject of the violation. The

licensee purchased new anemometers and changed procedure C SP 400.2, " Meteorological l Instruments Calibration," to require that each anemometer be connected to an anemometer drive with an associated tachometer to measure rpm. Each anemometer, at each level of  ;

the weather tower, is then to be driven at a measured speed, while the readout of the final

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l instrument is compared with the known rpm input to determine if the instrument output is within the required accuracy. The licensee' was in full compliance with Table 3.3-8 of Unit 2 TS 3/4.3.3.4, regarding the wind speed loop calibration on May 6,199 Conclusions in response to a violation, the licensee has replaced the wind speed measuring anemometers, revised the procedure C SP 400.2, to require the full loop channel calibration l

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. of the wind speed anemometers, and has calibrated all of the wind speed anemometers to specifications using full loop techniques. Tho corrective actions taken by the licensee to correct item D of Violation 50-336/98-207-16 are regarded as adequate. Unit 2 Violation t 50-336/98-207-16 and Unit 3 LER 50-423/98-025-00 are closed. Unit 2 LER 50-336/98-

. 008-00 will remain open since it addresses additional issues that are unrelated to the l1 violation that are still under review by the licensee,

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l S8 Miscellaneous Security and Safeguards issues l

S (Closed) IFl 336/96-05-16: Vital Area Barrier Penetration Insoection Scoce (92904)

A plant operator identified and reported an opening that constituted a barrier penetration between the Unit 2 health physics area, a protected area (PA) and the Unit 2 spent fuel

pool area, a vital area (VA). The area was being compensated for with measures that no longer met licensee standards, and therefore, were considered by the licensee as obsolet Station security immediately implemented additional interim compensatory measures. This item was an inspector follow item (IFI) to confirm the licensee closure of the opening in the barrie Observations and Findinas On May 1,1996, an opening was discovered in a wall enclosing the vital spent fuel pool (SFP) area. The opening was found in the wall between beams that form the boundary ,

between the SFP and the health physics area. A notice was made to the NRC pursuant to j 10 CFR 50.72(b)(2)(iii)(C), as a condition that alone could have prevented the fulfillment of the safety function needed to control the release of radioactive material, l

After discovery of the opening, the licensee, in conjunction with NRC security inspectors, I

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determined that dedicated compensatory security measures should be established at the site of the opening untilit could be covered adequately. The licensee's engineering investigation determined that the opening had existed since original plant constructio During the time that the opening existed, two qualitative tests had verified operability of the ventilation system. The first test was conducted in April 1975, during plant startup and the second functional test was performed in June,1992. Each of these tests monitored actual air flow across the spent fuel pool by visually monitoring generated smoke flow. On May 8,1996, a final operability evaluation demonstrated that the emergency spent fuel pool ventilation system was in fact operable. On May 15,1996, the licensee l completed a reportability determination that stated that the presence of this opening was I not a reportable event, since the opening did not interfere with the SFP ventilation system performance and was not a condition outside the design basis of the plant. Additionally, the existence of the opening was not regarded as a security breach by the licensee, and therefore, was not regarded as a reportable inciden I

The inspector reviewed NRC inspection Report 50-336/96-05, Section S8.5, nonconformance report (NCR) 296-073, adverse condition report (ACR) 11878, design l change notice (DCN') DM2-0378-96, work order M2-96-03567, and the drawings related to

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the installation of a steel 1/4 inch thick plate, approximately 11X32 inches, which was l welded across the opening. The inspector viewed the steel plate and verified it was !

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42 Conclusions l The licensee has taken appropriate actions in closing an opening that constituted a barrier l

penetration between a protected area and a vital area by welding a 1/4 inch thick steel !

plate over the opening. The licensee also verified that the SFP ventilation system had not l been previously adversely affected by the presence of the opening. IFl 50-336/96-05-16is i considered close l l

V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at separate meetings for each unit at the conclusion of the inspection period. The licensee acknowledged the findings presente X2 Management Meeting Mr. H. Miller, NRC Region i Regional Administrator, and other NRC managers visited Millstone on August 20 and 21 to meet with the NRC resident staff and senior licensee managers and tour the plant. Mr. Miller's visit was prompted by the NRC decision earlier that week to delegate responsibility for the oversight of all Millstone site activities to the Region i Regional Administrator. The Director of the Office of Nuclear Reactor Regulation was given responsibility for all Millstone licensing and technical review activities, including the ICAVP review. This decision eliminated the Special Projects Office (SPO) and integrated SPO responsibilities into the Region I organization with a direct reporting line to the Office of the Regional Administrator.

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INSPECTION PROCEDURES USED 37551 Onsite Engineering 60705 Preparation for Refueling 61726 Surveillance Observations 62707 Maintenance Observations 90712 Inoffice Review of Written Reports of Nonroutine Events at Power Reactor Facilities 92700 Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities 92901 Followup - Plant Operations 92903 Followup - Engineering 92904 Followup - Plant Support 83729 Occupational Exposure During Extended Outages 83750 Occupational Exposure

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ITEMS OPENED, CLOSED, AND DISCUSSED ITEMS OPENED TYPE NUMBER DESCRIPTION SECTION VIO 336/98-216-01 MISPOSITIONING OF THROTTLE VALVE IN THE RBCCW U2.0 VIO 336/98-216-02 TS NON-COMP ASSOCIATED WITH HEATUP/COOLDOWN EVENTS U2.0 NCV 336/98-216-03 FSAR DISCREPANCY - ABILITY TO MANUALLY OPERATE DAMPER U2.0 NCV 336/98-216-04 CHANNEL FUNC. TEST OF FAC 2 SIAS MANUAL PUSH BUTTON U2.M NCV 336/98-216-05 TRANSLATION OF DESIGN INFO INTO SURV. PROCEDURE U2.E NCV 336/98-2164 6 FAILURE TO MAINTAIN THE S/R SWITCHGEAR IN QUAL. CON U2.E NCV 423/98-216-07 RHS TESTING DURING TRANSITION TO MODE 4 U3.0 NCV 423/98-216-08 OPERABILITY CONCERNS - FAILED OR MISSED SUR U3.0 NCV 423/98-216-09 OPERABILITY CONCERNS - FAILED OR MISSED SUR U3.0 NCV 423/98-216-10 OPERABILITY CONCERNS - FAILED OR MISSED SUR U3.08.1

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NCV 423/98-216-11 OPERABILITY CONCERNS - FAILED OR MISSED SUR U3.0 NCV 423/98-216-12 IST PROGRAM AND TS VIOLATIONS U3.M NCV 423/98-216-13 IST PROGRAM AND TS VIOLATIONS U3.M NCV 423/98-216-14 IST PROGRAM AND TS VIOLATIONS U3.M URI 423/98-216-15 HANDLING OF ENG. ACTIVITIES FOR EMERGENT PROBLEMS U3.E NCV 423/98-216-16 INADEOUATE TS SURVElLLANCE OF SSPS U3.E8.1 l

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ITEMS CLOSED ITEM NUMBER SECTION l l

URI 336/96-01-04 U2.0 l LER 336/97-002-00 U2.0 NCV 336/98-216-03 U2.0 LER 336/97-026-00 U2.0 IFl 336/98-202-15 U2.0 NCV 336/98-216-04 U2.M NCV 336/98-216-05 U2.E !

LER 336/96-036-00 U2.E NCV 336/98-216-06 U2.E LER's 336/97-014-00/01 U2.E LER 423/97-037-00 U3.0 NCV 423/98-216-07 U3.0 LER 423/97-044-00 U3.0 LER 423/97-049-00 U3.0 LER 423/97-052-00 U3.0 LER 423/97-053-00 U3.0 NCV 423/98-216-08 U3.0 NCV 423/98-216-09 U3.0 NCV 423/98-216-10 U3.0 NCV 423/98-216-11 U3.0 LER 423/97-027-00 U3.M LER 423/97-040-00 U3.M 8.1 l LER 423/97-042-00 U3.M NCV 423/98-216-12 U3.M NCV 423/98-216-13 U3.M NCV 423/98-216-14 U3.M8.1 i

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.LER 423/97-063-00 U3.E LER 423/97-058-00 U3.E NCV 423/98-216-16 U3.E VIO 336/98-207-16, ITEM D IV.R LER 423/98-025-00 IV.R IFl 336/96-005-16 IV.S URI 336/95-042-03 U2.0 THE FOLLOWING ITEMS WERE DISCUSSED IN THIS REPORT:

IFl 336/98-202-14 SECTION U2.0 LER 336/98-008-00 SECTION IV.R g

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. LIST OF ACRONYMS USED i' ACR(s) ; adverse condition report (s) '

ALARA - as low as reasonably achievable

'AOP(s) abnormal operating procedure (s)

AWO(s) . automated work order (s)

BDG' steam generator blowdown '

CAC(s) . curriculum advisory committee (s) '

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CDR(s) cooldown rate (s)

CFR- Code of Federal Regulations CHS volume control system I

- CIAS containment isolation actuation signal CR!s) ' condition report (s)

CRAC ~ control room air conditioning CREFS- control room emergency filtration system DCN(s) design change notice (s)  ;

.DCR design change record  ;

DR . discrepancy repor ;

1EBFAS . -enclosure building filtration actuation system '

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EDG(s) emergency diesel generator (s)

EOP(s) emergency operation procedure (s)

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o l- ERC engineering record correspondence

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ERT' . event review team l ESAS engineered safeguards actuation system l ESFAS' emergency safety features actuation system p EWR engineering work request t

FME- foreign material exclusion FSAR Final Safety Analysis Report gp gallons per minute

HPSI- high pressure safety injection

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~ HUR(s) heatup rate (s)

ICAVP Independent Corrective Action Verification Program IFl .- inspector follow item .

' LCO limiting condition for operation l' ' LER(s) licensee event report (s)

LOCA- loss of coolant accident NCR(s) nonconformance report (s)

. NCV(s) non-cited violation NEA Nuclear Engineering Advisory Council NRR Nuclear Reactor Regulation  !

NSIC Nuclear Safety Information Center )

NSST- normal station system transformer i NUREG Nuclear Regulation  !

OCA Office of Congressional Affairs OD operability determination

.OED Office of Executive Director for Operations PAO Public Affairs Office

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PDR Public Document Room

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PIR(s) plant information report (sl

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PM(s) preventive maintenance

" 'TPORC plant operation review committee PORV(s) . power operated relief valve (s)

PPC plant process computer -

PRA- probabilistic risk assessment-RBCCW .- reactor building closed cooling water i RCM Regulatory Compliance Manual -

RCS reactor coolant system RFO refueling outage GHS residual heat removal system-RSS recirculation spray system

RSST reserve station service transformer

'SCR silicon controlled rectifier SFP spent fuel pool SIAS safety injection actuation signal I SIL significant item list

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!SPROC- - : opecial procedure SRO(s) senior reactor operator (s)

.'SSPS solid state protection system SWS service water system TS(s) technical specification (s)

UFSAR updated final safety analysis report URl(s) unresolved item (s)

USl . unresolved safety issue VIAC vital ac l : VIO violation L

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ENCLOSURE 3 l UNIT 1 OPEN ITEMS /LERS VIO 95-007-01 CONTROL ROOM HABITABILITY /USE OF SCBA'S URI 95-028-02 - REFUELING EVOLUTIONS CONTRARYTO~ DESIGN BASIS URI 95-034-01 SPENT FUEL POOL ISSUES eel 95-082-03 FAILURE TO EVALUATE THE SFP IMPACT ON SBGT SYSTEM eel 95-082-08 SFP MODIFIED FOR RE-RACKING TO HOLD MORE CONTROL RODS URI 95-082-13 VERIFY SAT RESOLUTION OF FLOWS TO SDC HXS ,

eel 95 082-19 SWITCH FROM 1/4 TO 1/3 FUEL CORE OFFLOADS eel 95 082-20 FAILURE TO CHANGE CORE OFFLOAD STATUS l URI 96-009-03 ORGANIZATIONAL CHANGES  ;

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VIO E 96-034 LWMS CHANGE -- eel 96-003-01 01172 VIO E 96-145 SFP RERACK MODIFICATIONS - eel 95-082-04 01012 VIO E 96-145 RBCCW SYSTEM - eel 95-082-14 01022 VIO E 96-145 SFP COOLING SYS eel'S 95-082-10,11,18 01032 '

VIO E 96-145 SFPC SYSTEM MODIFICATION - eel 95-082-09 01182 VIO E 96-145 SFPC SYSTEM - eel 95-082-12 04013 LER 96-033-00 CONTROL ROOM EXHAUST FANS FAIL / TRIP AFTER RADIATION CONTROL ROOM ISOLATION SIGNAL LER 96-034-00 REFUEL FLOOR RAD MONITOR PARTIALLY BLOCKED BY SHIELD PLUG LER 96-043-00 INADEQUATE INSTRUMENT CAllBRATIONS LER 96-042-00 STACK GAS SAMPLE FLOW SURVEILLANCE MISSED LER 96-033-01 CONTROL ROOM EXHAUST FANS Fall TO TRIP AFTER HI RAD CONTROL ROOM ISOLATION SIGNAL URI 97-001-01 SPENT FUEL POOL CLEANLINESS

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! VIO 97-001-08 FAILURE TO MONITOR GASEOUS EFFLUENTS FROM RADWASTE STORAGE BUILDING L URI 97-002-02 RP-4 INTERFACE'WITH LOWER TIER REPORTING PROCESS LER 96-065-00 LIQUID RW EFFLUENT LINE MONITOR NOT SET PER REQUIREMENT OF TS LER 97-013-00 EVALUATION OF IMPACT LOAD OF REFUELING PLANT FUEL

, GRAPPLE MAST LER 97-020-00 LlOUlD RW EFFLUENT MONITOR FUNCTION TEST SURVEILLANCE NOT IN ACCORDANCE WITH TS l

LER 97-019-00 LIQUID DISCHARGE WITHOUT SW OR RECIRC WATER AVAILABLE LER 97-030-00 STACK SAMPLER FLOW RATE SETPOINTS LER 97-033-00 UNMONITORED AIRBORNE RADIOACTIVITY RELEASE PATHS LER 97-037-00 ' UNMONITORED RELEASE PATH DUE TO RADIOACTIVE ASH IN HOUSE HEAT BOIL I LER'96-023-01 MOVEMENT OF NEW FUEL ASSEMBLIES OVER SFP - CONDITION "

OUTSIDE DESIGN BASIS URI 97-001-03 INACCURATE PERSONAL QUALIFICATION STATEMENTS - SIL 1 URI 97 085-02 TRAINING PROGRAM' DEFICIENCIES - CAL ITEM 8 SIL 14.1/1 URI 97-085-03 ESTABLISH TRAINING STAFF PRIOR STAFF LEVELS SIL.14.1/14.2 l

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Enclosure 3 - Page 2

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UNIT 1 CLOSED ITEMS /LERS URI 90-001-02 URI 90-001-03 URI 91-014-02 URI 91-081-04 URI 92-030-02 URI 93-024-04 URI 94-001-12 URI 94-005-02 URI 94-005-04 URI 94-014-01 DEV 94-023-05 VIO 94-031-01 IFl 94-201-03 VIO 94-201-98 IFl 95-001-01 VIO 95-007-02 VIO 95-007-04 IFl 95-028-01 URI 95-031-01 VIO 95-031-02 VIO 95-042-02 VIO 95-044-02 IFl 95-082-01 IFl 95-082-02 IFl 95-082-05 IFl 95-082-06 IFl 95-082-07 IFl 95-082-15 IFl 95-082-16 IFl 95-082-17 95 177/01013 95-177/02013 LER 95-020-00 LER 95-024-00 VIO 96-001-02 IFl 96-001-03 IFl 96-004-02 URI 96-004-06 URI 96-004-07 IFl 96-004-16 URI 96-005-01 URI 96-005-02 URI 96-005-03 URI 96-005-04 URI 96-005 05 l IFl 96-005-06 URI 96-006-01 URI 96-006-02 LER 95-029-00 URI 90-008-04 URI 96-008-05 IFl 96 008-21 eel 96-009-02 eel 96-009-08 URI 96-009-11 URI 96-012-01 VIO 96-013-03 LER 96-001-00 LER 96-008-00 LER 96-006-00 l LER 96-011-00 LER 96-014-00 LER 96-015-00 LER 96-017-00 LER 96-022-00 96-106/03022 LER 96-018-00 LER 96-019-00 LER 96-020-00 LER 96-024-00 )

LER 96-025-00 LER 96-026-00 LER 96-027-00 LER 96-030-00 LER 96-031-00 96-197/01202 96-197/02012 96-197/03032 96-197/05024 LER 96-032-00 LER 96-036-00 LER 96-037-00 LER 96-010-00 LER 96-039 00 LER 96-038-00 LER 96-029-00 LER 96-011-01 LER 96-003-01 96 350/04103 96 351/03042 96-352/03012 LER 96-030-01 LER 96-045-00 LER 96-046-00 LER 96-048-00

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LER 96-027-01 LER 96-039-01 LER 96-049-00 LER 96-050-00 LER 96-051-00 LER 96-052-00 LER 96-054-00 LER 96-046-01 LER 96-037-01 LER 96-055-00 LER 96-051-01 LER 96-056-00 LER 96-057-00 LER 96-058-00 URI 97-001-02 VIO 95-042-01 URI 97-001-04 URI 97-001-05 URI 97-002-03 URI 97-002-04

eel 97-002-05 eel 97-002-06 VIO 97-002-07 eel 97-002-08 eel 97-002-09

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eel 97-002-10 eel 97-002-11 LER 96-020-01 LER 96-026-01 LER 96-031-01 LER 96-046-02 LER 96-054-01 LER 96-059-00 LER 96-060-00 LER 96-061-00 LER 96-062-00 LER 96-003-02 LER 96-040-01 LER 96-064-00 IFl 97-080-02 Enclosure 3 - Page 3 l

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LER 98-004-00 LER 98-005-00 LER 97-001-00 97-104/01011 LER 97-002-00 LER 97-005-00 LER 95-033-00 97-141/01192 97-141/02022 97-141/02182 LER 97-004-00 LER 97-006-00 LER 97-007-00 LER 97-008-00 LER 96-046-03 LER 96-037-02 LER 96-020-02 LER 97-010-00 LER 97-011-00 LER 97-012-00 LER 97-014-00 LER 97-017-00 URI 97-202-01 eel 97-202-06 VIO 97-203-02 URI 97-203-03 LER 97-022-00 LER 97-021-00 LER 97-018-00 LER 97-015-00 LER 97-014-01 LER 97-009-00 LER 97-003-00 LER 97-007-01 LER 97-016-00 LER 97-005-01 LER 97-004-01 LER 97-009-01 LER 97-023-00 LER 97-024-00 LER 97-026-00 LER 97-027-00 LER 97-028-00 LER 97-025-00 LER 96-066-00 LER 97-029-00 LER 96-037-03 LER 96-039-02 LER 97-032-00 LER 97-031-00 LER 97-014-02 LER 95-033-03 LER 97-035-00 LER 97-036-00 LER 97-022-01 LER 97-038-00 LER 97-039-00 LER 97-034-00 LER 97-040-00 LER 98-001-00 LER 98-002-00 VIO 98-206-01 URI 98-207-01 VIO 98-207-02 URI 98-208-01 i

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Enclosure 3 - Page 4