IR 05000298/1989022

Insp Rept 50-298/89-22 on 890601-30.Violations Noted.Major Areas Inspected:Operational Safety Verification,Monthly Surveillance & Maint Observations & Onsite Followup of Events

ML20247L964
Person / Time
Site:	Cooper
Issue date:	07/20/1989
From:	Bennett W, Constable G, Greg Pick NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20247L955	List: IR 05000298/1989022 ML20247L950 ML20247L958
References
50-298-89-22, NUDOCS 8908010397
Download: ML20247L964 (12)

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3 O.S.. NUCLEAR. REGULATORY COMMISSION; 4

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REGION:IV

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- ..NRC ' Inspection Report: - . 50-298/89-22 ' ,

Operating' License: ;DPR-46 l

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' Docket: 50-298; d

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4 Licensee: Nebraska Public Power' District (NPPD) ' '

P.O.' Box 499i ,

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~ Columbus, Nebraska- .

68602-0499 ,

.faciitty Name

i Co'oper Nuclear' Station (CNS)

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Inspection At: CNS, Nemaha: County, Nebraska m; .

• LInspection' Conducted: ' June 1-30, 1989

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. Inspectors: 2 . '7 a 6'

~ gG. A" Pick, Resident -Inspector,. Project

. Date'

Section C, Division of Reactor. Projects j

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W. R.Menneii, Senior Resident Inspector, 1/w/99 Date; /

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Project Section C, Division of Reactor Projects ;1

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.j Contributing . U Personnel: M. E. - Murphy, Reactor Inspector, Test Program" .

e 'E Section, Division of Reactor Safety S. F. Kobylarz, Environmental,and Energy Services Company i j

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Approved: m _-- ' 7/2a[ft)

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JE'tT Constable, Chief Project-Section C, , D6t I a s Division.of Reactor Projects ,

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-2-Inspection Summary Inspection Conducted June 1-30, 1989 (Report 50-298/89-22)

Areas Inspected: Routine, unannounced inspection of followup of previously identified items, operational safety verification, monthly surveillance and maintenance observations, and onsite followup of event Results: Within the areas inspected, one apparent violation was identified (inadequate design control, paragraph 4).

Startup activities were conducted in a safe, conservative manner and good communication was evident among the operators. The diesel generator sequential loading test was completed successfully by knowledgeable and proficient personnel. The activities related to identifying and correcting the diesel generator petcock valves issue was comprehensive. The air compressor maintenance procedure was well written with excellent guidance. Licensee actions for correcting unqualified splices found in installed instrument racks were prompt and addressed the root cause. The licensee notified General Electric of the prc'alem who in turn notified other BWR licensees of the potential generic issu An inadvertent feedwater injection event occurred when a throttle valve was assumed to be closed when it was actually partially open. The licensee did not evaluate the reason the valve was partially open until prompted by the inspector l

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-3-DETAILS Persons Contacted Principal Licensee Employees

• G. R. Horn, Division Manager of Nuclear Operations

• R. L. Gardner, Maintenance Manager

• J. V. Sayer, Radiological Manager

• H. T. Hitch, Plant Services Manager

• R. Brungardt, Operations Manager

• J. R. Flaherty, Plant Engineering Supervisor

• G. R. Smith, Licensing Supervisor .

• L. E. Bray, Regulatory Compliance Specialist i

• Denotes those present during the exit interview conducted on July 6, 198 The inspectors also interviewed other licensee employees and contractors during the inspection perio . Plant Statqs The reactor achieved criticality at 2:37 p.m. on June 16, 1989, after a 10-week refueling outage. After minor adjustments to outage installed feedwater control system components, the plant reached 100 percent power operation on June 29, 198 . Followup On Previously Identified Inspection Findings (92701 and 92702) j (Closed)UnresolvedItem(298/8710-08): This item concerned the lack of a voltage study to demonstrate that critical 120 Vac electrical components would be provided adequate voltage during accident condition The inspectors reviewed the CNS 120 Vac Load Study, Applied Power i Associates (APA) Project 117.28, which was prepared in response to a j finding in the 1987 Safety Systems Functional Inspection (SSFI). The APA J study reanalyzed the worst case circuit operating loads and determined  !

them to be lower than originally assume J Based on the original APA voltage study a new feeder cable needed to be installed for certain loads. Field measurements determined that adequate operating voltage was present with the existing cable; therefore, a r.ew feeder cable will not be installed. The new operating load calculations have resolved the concern for minimum operating voltage. This item is  : '

considered close (Closed) Deviation 298/8818-01: Nuclear Performance Procedure (NPP) 10.9,

" Control Rod Scram Time Evaluation," Revision 14, did not include a

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~ requirement in the prerequisites section for performance by appropriately trained personne The licensee reviewed the qualifications of the personnel who performed NPP 10.9 during the 1988 refueling outage startup. These individuals were found to have been qualified station nuclear engineers, meeting the requirement for performance by appropriately trained personnel. The NRC inspector reviewed NPP 10.9, Revision 15, dated September 30, 1988. This revision incorporated a prerequisite identifying the qualifications required for performance. This item is considered close (Closed)OpenItem 298/8818-02: This item was open pending revision of NPP 10.16, " Shutdown Margin Evaluation," to clarify administrative items and to require the fuel vendor to submit a cycle management report which would be formatted to agree with CNS procedure The licensee has revised NPP 10.16 to clarify the specific criteria for shutdown margin demonstration as well as how it is satisfied. The fuel vendor has agreed with the licensee on a revised shutdown margin demonstration section for the Cooper Cycle Management Report. These revisions were in place for the 1989 refueling outage startup. This item is considered close . Operational Safety Verification (71707)

The inspectors observed operational activities throughout the inspection period. Proper control room staffing was maintained and control room activities and conduct were observed to be well controlled. The inspectors observed selected shift turnover meetings and noted that information concerning plant status was properly corraunicated to the oncoming operators. Control room access was controlled during the perio Discussions with operators determined that they were cognizant of plant status. Limiting Conditions for Operations were properly entered when equipment was declared inoperable for maintenance, and acceptance testing was properly performed and reviewed prior to declaring equipment operabl )

On June 4,1989, while opening reactor feedwater pump (RFP) suction valves, feedwater was inadvertently discharged into the reactor vesse The "A" RFP discharge throttle valve indicated closed; however, it was partially open which allowed flow to the reactor vessel. The refuel pool increased and an estimated 250 gallons of water flowed into ventilation ducts. The ducts are located vertically alongside the refueling pool in order to take suction off the pool surface to capture potentially escaping radioactive gases. Operators closed the discharge throttle valve upon noticing the refuel pool level increase.

i MaintenanceWorkRequest(MWR) 89-2720 was issued to investigate and J repair, as necessary, the discrepancy between the control room indication and the actual valve position. The packing gland follower appeared to be cocked. The electric shop stroked the valve and found the valve operation acceptable. No adjustment of the packing gland follower was needed. The l l

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-5-inspector expressed a concern that a nonconformance report (NCR) was not issued to' identify and correct the root cause of the discrepancy between

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the control room indicator and the actual valve position. In response to the inspector's concern, training will be provided to reemphasize the importance of assuring throttle valves are fully closed in accordance with procedure Since the valve handles for the RFP discharge valves are different from other thrcttle valve handles, the control room panel will be enhanced to clearly identify the feedwater discharge valves as throttle s valve The inspector observed the performance, in part, of:the reactor pressure boundary hydrostatic test. The test was performed on June 12, 1989, as

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required by ASME code. General Operating Procedure (GOP) 2.1.14, "ASME Class I-N System Leakage Test," Revision 21, dated June 10, 1989, was utilized to control the test' activities. The heatup and pressurization were maintained within pressure and temperature limits of the reactor vessel. The hydrostatic test revealed a' few minor leaks through valve packings which are allowed by the code. These leaks were subsequently repaire The inspector observed the plant startup on Juna'16, 1989, to approximately 100 psi. The startup activities _were conducted in accordance with GOP 2.1.1, " Cold Startup Procedure," Revision 54, dated November 9, 1988, NPP 10.13,'" Control Rod Sequence and Movement Control,"

Revhion 19, dated February 2, 1989, and other necessary system operating i proceduras (S0P). Approximately 4 weeks prior to the'startup, as work activities-in a system were completed, the systems were lined up, and shift supervisor (SS) initials on a checklist signified the lineup was ready for startup. This prevented a rush at the end of the outage and allowed for better control of system statu An onsite review committee meeting was held to implement GOP 2.1.1.1, " Plant Startup Review and Authorization," Revision 3, dated September 22, 1988. Implementation of the procedure assured that procedures, documents, commitments, and other required items were completed prior to startup. Completion of GOP 2.1.1.2, " Technical Specification Pre-Startup Checks," Revision 9, dated March 2, 1989, provided the SS with a means to assure all TS items were in place prior to startup. The inspector reviewed GOPs 2.1.1, 2.1.1.1, and 2.1.L 2 signatures and determined that required information was complet During the startup, the licensed operators communicated well and pertinent information exchange occurred. The control room supervisor kept

' distractions to a minimum. System operating procedures were available and were' utilized. The inspector verified that: the control rod withdraw sequence was utilized, surveillance tests required to be performed prior to startup were complete, procedures had been revised to reflect changes made to the facility, and Technical Specifications were followe On June 25, 1989, the feedwater control system (FWCS) experienced a feedwater control signal failure and the newly installed feedwater controllers went into Feedwater Hold, i.e., locked up at last speed

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tracked. The ' operations crew appeared to be surprised that the FWCS annunciator did not respond as expected. Discussions with an instrument and control (I&C) technician familiar with the new FWCS annunciator configuration provided the shift supervisor with sufficient understanding for corrective actions to be taken. The operators became concerned, since in the new configuration, corrective actions to clear the annunciator alarm condition could result in blowing a fuse, and automatically placing the feedwater pump in manual control. There was no longer a way to determine whether the control signal failure condition had cleared; consequently, when turning the feedwater pump lockout switch to reset the alarm condition a fuse would blow if the control signal failure had not cleare The above condition was created when the annunciator upgrade modification performed during the refueling outage could not be completed due to software / hardware incompatibility. An on-the-spot change (OSC) was written on April 20, 1989, to parallel the RFP Turbine Track and Hold Alarm to the Feedwater Control Signal Failure annunciator window. The OSC also required connection of the RFP Turbine Control Trouble Alarm to a spare annunciator windo The inspector verified that training on the feedwater control system had been conducted prior to the outage and that procedures had been changed to include operation of the modified FWCS. However, training had not been conducted to inform the operators of the new response of the feedwater annunciators and what the annunciators mean. Additionally, appropriate procedures had not been altered to reflect the OSC and no annunciator procedure was issued to describe Ntions regarding the RFP Turbine Control Trouble Alarm windo The CNS design change program has procedures which require that training be conducted and that procedures be modified to reflect the plant modifications. Specifically, Engineering Procedure 3.4, " Station Modifications," Revision 9, dated May 25, 1989, requires that Attar W .: B be completed ensuring that design change (DC) related items such as procedures and training be completed or determined to be "not applicable."

Engineering Procedure 3.4.11. " Status Reports," Revision 0, dated (

December 5,1988, requires that, after DC installation or prior to i required system operability (startup in this instance) whichever occurs first, that records be turned over to various departments so that

procedures and training can be conducted as necessary. Additionally, an OSC, as defined in Engineering Procedure 3.4.10. " Revision, Amendments, and On-the-Spot Changes," Revision 0, dated December 5, 1988, does not i

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require additional training nor changes to the necessary procedure CFR 50, Appendix B, Criterion III, requires that measures be established to assure that the design basis for structures, systems, and components l are correctly translated into specifications, drawings, procedures, and l l

instructions and that design changes, including field changes, shall be i subject to design control measures commensurate with those applied to the original design. The failure of the licensee's established programs to

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assure that required training was provided to licensed operators and to modify required procedures when a change was made to Design Change i Package 88-036,isanapparentviolation(298/8922-01).

The inspectors verified that selected activities of the licensee's l radiological . protection program were implemented in confonnance with {

facility policies, procedures, and regalatory requirements. Radiation {

and/or contaminated areas were properly posted and controlled. Health ]

physics personnel were prompt in reposting radiation areas affected by the '

startup. Radiation work permits contained appropriate information to ensure that work could be performed in a safe and controlled manne Health physics personnel were observed to be touring work areas, ensuring proper implementation of ALARA and radiological control requirement Radiation monitors were properly utilized to check for contaminatio The inspectors observed security prsonnel performing. vehicle, personnel, and package searches. Vehicles were properly authorized and controlled or escorted within the protected area. The inspectors conducted site tours to. ensure that compensatory measures were properly implemented as require The licensee continued implementatf on of the security equipment upgrad Personnel access was observed to be controlled in accordance with established procedures. Interviews with security personnel demonstrated J that they were cognizant of their responsibilities. The PA barrier had adequate illumination and the isolation zones were free of transient material A violation for inadequate design control was identified in this area. In I addition, the inspector expressed a concern for an apparent failure to I

take corrective actions to address the root cause related to an inadvertent injection of feedwater into the reactor vessel. Startup activities were conducted well with good communications among the ,

operations staf No other violations or deviations were identifie . Monthly Surveillance Observations (61726)

The inspectors observed the performance of and/or reviewed the following surveillance procedures (SPs): j SP 6.3.4.3, " Sequent * 1 Loading of Emergency Diesel Generators," ,

Revision 27, dated June 8, 1989. This surveillance functionally tests the emergency start ant, loading sequence for the emergency diesel generators .

(EDG). Also, the residual heat removal pumps and core spray pumps I emergency start features were tested. This is a complex surveillance which involved approximately 20 individuals and had data taken and verified at a minimum of 5 locations. All equipment performed as designed and the accepter.ce criteria were met. The June 12, 1989, test of EDG No. 2 wr, observed and the procedure reviewed. The procedure and data ,

for the EDG No. I testing was reviewed. The operators involved with the j EDG No. 2 test were knowledgeable and familiar with the surveillance purposes, steps, and requirement l

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SP 6.3.10.2, " Instrument Line Flow Check Valve Test," Revision 16, dated September 1, 1988. The inspector observed the performance of this procedure, in part, on June 12, 1989. This procedure tests the Marotta excess flow check valves once per operating cycle to ensure that upon a postulated instrument line break, the leakage would be maintained between 0.2 and 0.7 gallons per minute (gpm), thereby, not exceeding ASME Section XI requirements. Sixty-eight valves were tested with four with leakage greater than 0.7 gpm. Corrective actions were taken to bring the four valves within specification. Two crews tested the valves with each crew consisting of I&C technicians and operations staff personnel. This work was conducted in contaminated 'reas with spills expected to occur due to the testing. ALARA principles were followed and all spills were promptly cleaned up. This test is conducted each outage prior to startup in conjunction with the reactor pressure boundary hydrostatic test. The test was well coordinated 4nd execute SP 6.2.3.L1, "Drywell Floor Drain Sump 1F Flow Loop Calibration Test,"

Revision 1, dated November 9, 1988. This procedure was performed on June 26, 1989, to comply with TS Protective Instrument surveillance requirements. The inspector reviewed the completed procedure. All signoffs were completed. One discrepancy was annotated, then deleted without a stated reason for deletion of the comment. Discussions with the I&C technician revealed that he had inadvertently placed test leads into the incorrect test jacks. This action resulted in erroneous data. After utilizing the correct test jacks, the data was within toleranc SP 6.2.3.2.1, "Drywell Equipment Drain Sump IG Flow Loop Calibration Test," Revision 1, dated November 9, 1988. The inspector observed the performance of this test conducted on June 26, 1989. All required signatures had been obtained on this TS required surveillance. Good communication between technicians was evident. Measuring and test instruments utilized were calibrate NPP 10.9, " Control Rod Scram Time Evaluation," Revision 17, dated April 27,1989. The inspector observed, in part, the performance of this procedure on June 19, 1989. This test was performed to meet TS requirements and ASME,Section XI, inservice Testing requirements. The scram times were obtained by utilizing the process computer. Discussions with the licensed operators performing the test and the reactor engineers indicated that they had a thorough understanding of the. limitations, precautions, and prerequisites associated with the testing. No discrepancies were identified during the testing. All data were within specification No violations or deviations were identifie . Monthly Maintenance Observation (62703)

On June 27-28, 1989, the inspector observed the performance of Preventative Maintenance Activity (PM) 03873. The annual PM involved the disassembly, inspection, and replacement, as needed, of parts on the "B" Air j f

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Compressor. Maintenance Procedure (MP) 7.2.27, " Air Compressor Maintenance," Revision 3, dated February 6,1986, was used in the performance of the PM. The procedure was adequate and was sectioned L in a logical manner. For example, sections existed for: piston removal T

'and replacement; water cleaning jackets; removal of the intercooler and installation and Acleaning of the Type (of the cylinder NL nonlubricated)

channel valves; and disassembly, repair, and assembly of the Type A NL

. valves. The mechanics were experienced and.followed proper safety practice During a maintenance run of one of the EDGs, a petcock valve in an individual cylinder exhaust pipe sheared. .The inspector reviewed corrective actions identified by the license Investigation by the licensee determined that a'. hairline crack must have existed since original installation. .The failure was thought to have occurred due to stress by additional forces placed on the valve over time by the mechanics conducting engine analysis. The failure of the petcock valves would not render the EDGs inoperable. All adapter plates and petcock valves were replaced on both EDGs. Two additional petcock valves were broken during removal. Radiographic examinations were performed on the remaining 29 valves. Indications were found on one other valve. The 28 valves without indications were returned to spare The manner in which the air compressor maintenance procedure was written combined with the skills, knowledge, and abilities possessed by the technicians allowed for a well conducted maintenance activity. The ,

activities related to identifying and correcting the EDG petcock valves issue ~was comprehensiv No violations or deviations were identifie . Onsite Followup of Events (Unqualified Wire and Splices Found in EQ Equipment) (93702)

- While working.to complete DC 87-190, to update the limit switches of air operated valves (A0V) to seismic requirements as required in Regulatory

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! Guide 1.97, " Instrumentation for Light-Water-Cooled Nuclear Power Plants

'to Assess Plant and Environs Conditions During and following an Accident,"

- the licensee discovered four switches with unqualified wire. These wires were replaced with environmentally qualified (EQ) wire in accordance with DC 87-190 installation instructions. The licensee conducted a walkdown of all- A0Vs required to be environmentally qualified and identified five-additional limit. switches with unqualified wire. Replacement of the wire wasaccomplishedunderEquipmentSpecificationChange(ESC)89-18 To determine if the problem was isolated to the indication circuits of A0Vs, the licensee initiated a random sampling inspection of local terminal boxes. This resulted in the finding of questionable wire, which was later identified as instrument pigtails. This discovery led to the evaluation of additional EQ equipnent. The list of actual iteme to be walked down was developed by using the following elimination criteria:

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All cabling to the component has already been walked down Component uses a conduit seal spliced directly to known field cable l Component does not require cable for the performance of its safety function

Component is located within a qualified assembly _

i Equipment is a generic support item which is required only to support the operation of other components

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Component or cable has been recently installed and cable information is available from the design package Component was purchased / supplied with qualified interconnecting cables

No local terminal boxes are used

Jumpers are not used, field cables were connected directly to equipment terminals (These criteria were extracted from the licensee's document titled,

"Walkdown of EQ Jumper Cables")

Eliminating the items that met any of the preceding criteria resulted in a list of 150 items to be inspected. These items, uniquely, had a locally mounted terminal box requiring a jumper to interface the component to the field wire. The items were: ASCO - solenoid operated valves (S0Vs),

Barton pressure switches, Yarway switches, various small motors (e.g.,

valve operators), Target Rock - S0Vs, PCI pres:;ure switches, Woodward Governor controls, and other miscellaneous items (e.g., ball flow switches).

The walkdown of the 150 items was performed and document? under MWR 89-2495. This inspection resulted in two findings: (1) PVC wire in high pressure coolant injection (HPCI)-LS-91A and -B, did not have qualification documentation in place, and (2) one type of wire leading from a terminal box with a different type wire termit; ting at the Barton pressure switche The HPCI PVC wire, even though it was judged to be qualified based on partial testing and analysis, was replaced by an amendment to ESC 89-18 Further investigation of the difference in wires associated with the Barton switches revealed the presence of unqualified splices. These were found in conduit LBs between the local terminal box and the instrumen This discovery prompted the licensee to perform another walkdown of the original 150 items to lc,ok specifically for unqualified splices. The reinspection established that all unqualified splices were isolated to

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-11-Barton instruments. To provide further assurance that all unqualified local splices had been identified, the licensee performed another walkdown utilizing a random sample of the previously exempted items. This walkdown did not reveal any other unqualified configuration The licensee investigated the possible sources of the splices and why they had not been identified during previous EQ qualification inspections. It was verified that during prior walkdowns, cable qualification was verified only to the rack-mounted terminal boxes. Because of the short run of conduit to the instruments and the fact that the integrity of the q instrument would have to be broken to inspect the instrument terminal a board, it was assumed that qualified cable existed from the terminal box  !

to the instrument terminal boar The unqualified splices do not appear on the drawings for the instruments j or for the racks. The drawings reference General Electric (GE) Design Specification 209A4351. This specification states, " Connections to external devices are to be on terminal blocks located in NEMA Type 12 enclosed steel terminal cabinets." The specification does not address splices, and splicing in general was not addressed by any original  ;

construction practices except for the specific prohibition of splici power cable The instrument racks were originally provided to the site by GE under the blanket " Nuclear Steam Supply System" Contract E66-31. A review, by the licensee, of the receiving documentation for this contract verified '

traceability to the original rack manufacturer, HUIC0 Incorporated of Pasco, Washington. Rack construction and instrument installation was based on GE Specification 209A4351 and they were delivered to GE under Purchase Order 282-Y-7044. The racks were installed under Contract E70-3, which made connections to the field side of the terminal box. No records were found to indicate the rack wiring was modified during original installatio It was identified by the licensee, during a maintenance history review, that four switches had been replaced since original instrument rack installation. These switch changes were made by lead lifting and landing at the instrument terminal board, leaving the spliced lead between the terminal box and instrument undisturbe The licensee concluded that the original contractor spliced the pigtails to the GE wire to avoid disassembling the switch. The splices, therefore, existed in the conduit when the instrument racks were received at CN NPPD Letter NLS8900225, dated June 8, 1989, advised GE that a potential generic manufacturing problem existed. It further advised GE that there i was a possible need to report this in accordance with the requirements of )

10 CFR Part 21. In a letter dated June 30, 1989, GE responded stating,

"Because each plant has unique individual plant EQ requirements, ano GF

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does not have information on the compliance to these requirements, GE is unable to complete a safety hazard evaluatio I L -----------_o

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-12-Therefore, GE cannot make a conclusion to 10 CFR 21 deportability."

Additionally, GE was to notify all BWR owners of this Potentially ReportableCondition(PRC). The information in the PRC summarized what was found at CNS and stated that single conditions may exist at other utilities which have GE supplied instrument rack During field observations of the spliced cable replacement by the inspectors, it was noted that numerous similar splices in non-EQ instrument leads existed. The licensee was asked if this condition had been evaluated for effects on safety-related functions. The licensee's representatives informed the inrpectors that if a non-EQ instrument could affect safety-related functions then the instrument would have been classified as EQ and designated as such on the Master Equipment Lis This was the policy adopted during the development of the original EQ classificatio Replacement of all EQ instrument cables with nonqualified splices was completed prior to startup on June 16, 1989. The licensee was finalizing a justification for continued operation (JCO) while shut down. A JC0 was not needed for startup, since the pressure switches were made operable by changing out the unqualified wire prior to startup. An operability evaluation for Nonconformance Report 89-111 was also being processe The licensee took decisive and prompt action to identify the extent of the nonqualified spices. . The licensee also provided information to GE so that other license holders with similar configurations could be notified. No violations or deviotions were identifie . Exit Interviews (30703)

An exit interview was conducted on July 6, 1989, with licensee representatives identified in paragraph 1. During the interview, the inspectors reviewed the scope and findings of the inspection. Other meetings between the inspectors and licensee management were held periodically during the inspection period to discuss identified concern The licensee did not identify as proprietary any information provided to, or reviewed by, the inspector ;

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