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Insp Rept 50-261/91-05 on 910216-0330.Violations Noted.Major Areas Inspected:Operational Safety Verification,Surveillance Observation,Maint Observation,Engineered Safety Feature Sys Walkdown & Onsite Review Committee
	ML20138F796
Person / Time
Site:	Robinson
Issue date:	04/12/1991
From:	Christensen H, Garner L; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20138F783	List: IR 05000261/1991005; ML20138F776; ML20138F790;
References
	50-261-91-05, 50-261-91-5, NUDOCS 9610180068
	Download: ML20138F796 (27)
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appropriate : to ' the sci rcumstahcesVinvolvingstemp6sary4h'eatingiofJ thei reactor

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An operator's inattentiveness while drainin~g a steam generator resulted in a reactor trip while the unit was in cold shutdown (paragraph 2).

Containmenthousekeepingeffortsexhibitedimprovement(paragraph 2).

Emergent work resulted in the extention of refueling outage 13 from a scheduled 99 days to 183 days.

Internal components / system inspections revealed equipment degradation.

An overall strategy for addressing plant equipment degradation had not been developed by the licensee (paragraph 2).

Contract personnel have been employed to reduce the number of open Technical Support action items (approximately 1400) (paragraph 2).

Significant programmatic and organizational changes have been undertaken to improve self assessment capabilities and the corrective action program

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(paragraph 7).

Implementation of a new 10 CFR 50.59 procedure resulted in improvements in the safety review quality (paragraph 8).

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REPORT DETAILS

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1.

Persons Contacted l

R. Barnett, Manager, Outages and Modifications

C. Baucom, Senior Specialist, Regulatory Compliance D. Bauer, Regulatory Compliance Coordinator, Regulatory Compliance J. Benjamin, Shift Outage Manager, Outages and Modifications C. Bethea, Manager, Training W. Biggs, Manager, Nuclear Engineering Department Site Unit

S. Billings Technical Aide, Regulatory Compliance R. Chambers, Manager, Operations

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T. Cleary, Manager - Balance of ~ Plant Systems and Reactor Engineering, Technical Support l

D. Crook, Senior Specialist, Regulatory Compliance l

J. Curley, Manager, Special Projects - Nuclear Engineering Department

C. Dietz, Manager, Robinson Nuclear Project D. Dixon, Manager, Control and Administration

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W. Doorman, Acting Manager, Nuclear Assessment Department

'J. Eaddy, Manager, Environmental and Radiation Support S. Farmer, Manager Engineering Program, Technical Support R. Femal, Shift Supervisor, Operations

W. Gainey, Unit Manager, Plant Support B. Harward, Manager - Mechanical Systems, Technical Support

J. Huntley, Planning Supervisor, Maintenance

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J. Kloosterman, Manager. Regulatory Compliance D. Knight, Shift Supervisor, Operations D. Labelle, Project Engineer, Nuclear Assessment

E. Lee, Shift Outage Manager, Outages and Modifications A. McCauley, Manager - Electrical Systems, Technical Support R. Moore Shift Supervisor, Operations D. Nelson, Shift Outage Manager, Outages and Modifications A. Padgett, Manager, Environmental and Radiation Control M. Page,-Manager, Technical Support M. Scott, Manager - Support Systems, Technical Support D. Seagle, Shift Supervisor, Operations J. Sheppard, Plant General Manager R. Smith, Manager, Maintenance D. Stadler, Onsite Licensing Engineer, Nuclear Licensing R. Steele, Maneger - Maintenance Support, Maintenance G. Walters, Operating Event Followup Coordinator, Regulatory Compliance D. Winters, Shift Supervisor, Operations H. Young, Manager, Quality Control Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personnel.

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Attended exit interview on April 2, 1991.

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i Acronyms and initialisms used throughout this report are listed in the i

last paragraph.

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2.

Operational Safety Verification (71707, 71711)

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l The inspectors evaluated licensee activities to confinn that the facility was being operated safely and in conformance with regulatory requirements.

These activities were confirmed by direct observation.

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facility tours, interviews and discussions with licensee personnel and

management, verification of safety system status, and review of facility i.

records.

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To verify equipment operability and compliance with' TS, the inspectors reviewed shift logs, Operation's records, data sheets, instrument traces,

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and records of equipment malfunctions.

Through work observations and

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l discussions. with Operations Staff members, the inspectors verified the staff was knowledgeable of plant conditions. ' responded properly to alarms, adhered to procedures and applicable administrative controls,

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cogr.izant of in-progress surveillance and maintenance activities, and aware of inoperable equipment status.

The inspectors performed channel

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verifications and reviewed component status and safety-related parameters

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to verify conformance with TS.

Shif t changes were. routinely observed,

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verifying that system status continuity was maintained and that proper control room staffing existed.

Access to the control room was controlled i

and operations personnel carried out their assigned duties in an

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effective manner.

Control room demeanor and communications were

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I effective.

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h Plant tours and perimeter walkdowns Were conducted to verify equipment d.

operability, assess the general condition of plant equipment, and to

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verify that radiological mtrols,. fire protection controls, physical

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l protection controls, an/ equipment tagging procedures were properly implemented.

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j Fire In CV Reactor Vessel Head Storage Area On February 14,1991, at 9:46 p.m., a fire was discovered in the CV reactor vessel head storage area.

An HP notified an operator stationed

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on the CV third level that he smelled smoke.

Upon investigation, the

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operator observed an approximately ten-foot long and one foot high arch of flames at the reactor vessel head flange.

The control room was notified and the CV evacuation alarm was sounded. _ The operator, also a

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fire brigade member, was instructed to initiate fire fighting activities.

The operator, with the EP's assistance, extinguished the visible fire with a fire hose.

At 9:54 p.m., the operator nottfied the control room that the flames had been extinguished. ~ The fire brigade was mustered and

members dispatched at 9:58 p.m. for fire status assessment and personnel

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accountability verification.

The burned materials were verified to be smoldering, but flames were not visible. At 10:06 p.m., all personnel who had been in the CV were' accounted for and verified to be uninjured.

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this time, control room personnel (STA and SS) concluded that a NOUE was not warranted since the ten minute fire duration criteria was not exceeded.

During the next hour, the fire brigade utilized fire hoses and halon fire extinguishers to completely extinguish the smoldering materials.

At 11:27 p.m., the all clear fire alarm was stundedt however, access to the CV was restricted due to smoke.

During subsequent hours, the fire area was monitored and a video recording was made of.the fire damage.

Two teams were formed to investigate and evaluate'this event.

One team was chartered with root cause investigation and. evaluation of fire fighting / mitigation efforts.

They were also tasked with developing recommendations to preclude and/or enhance response to similar events.

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The second team was tasked with. determining what equipment was affected by the fire and/or smoke, as well as developing and implementing necessary

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l recovery actions.

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l The senior resident inspector observed activities in the control room

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from approximately 10:45 p.m. to 11:45 p.m..

The inspector verified that: personnel safety was being properly considered; event classifica-

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l tion was appropriate; communications between the fire brigade and control

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room, although sometimes technically difficult, was adequate; and steps were being taken to preserve information and the fire areas as-found condition.

The inspector also discussed with the operator (who extinguished the flames) the fire's extent and potential damage.

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The inspectors reviewed a partial draft report by the fire investfrution

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team.

The fire a)parently resulted from the' overheating and combustion of temporary wir ng insulation.

Subsequently, other combustible

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materials in the area ignited.

The tempora'ry wiring was supplying power to light bulbs being used to warm. the reactor' vessel head flange.

The d-overheating was caused by either high resistance at an-electric socket connection, exceeding a 10 ampere wire rating, or a combination of these two conditions.

The investigation was sab' e to determine when or by whom the as-found wiring configuration was established.

The as-found wiring configuration involved a 15 ampere rated 6 outlet strip connected

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to a 10 ampere rated drop light. The drop light was connected to another 15 ampere rated extension cord which was p'ugged into an electric receptacle.

The 6 outlet strip supplied two~ fluorescent lamps, an air

sampler, a string of fif teen 100 watt incandescent lights, and a

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different drop light.

The first drop light and the 100 watt lights were installed in the reactor-vessel head flange stud holes.

Fire cloth and insulation had been placed over the stud holes and flange to retain heat.

The mechanical maintenance personnel who installed the tonporary heating configuration on February 11.-1991. indicated that both drop lights had been connected to the 6 outlet strip-which was connected to the extension

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cords, not the manner in which they were-found.

Subsequent work, such as l

adding insulation or light bulb replacement,;may have resulted in the l

wiring being switched to the as-found configuration.

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i Records. do not exist that specify the~ configuration that was to be s"

t installed or the. actual configuration installed.

The need to maintain

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the reactor vessel head flange within five degrees of the vessel flange and studs was identified during the previous reactor head stud tensioning evolution in January.

Procedure MRP-003. Reactor Vessel Stud Removal And

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Replacement, was revised on January 25, 1991, to reflect this temperature differential guideline.. However, no specific method or instructions were developed to accomplish this guideline.

On February 11,1991, the decision as to the methodology for keeping the reactor head flange warm

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was made through discussions among the Maintenance, Outages and Modifica-tions. Operations, and Technical Support organizations.

The work was accomplished under WR/J0s 91-ACER1 and 91-ACG01, which are generic work authorizations for capturing maintenance time associated with miscellaneous support activities to the refueling contractor. Detail.ed written instruc-tions were not provided and formal review of the methodology / configuration was not performed.

In addition, plant procedures had not been established for the use and control of items such as drop lights, extension cords, and outlet strips.

Failure to provide and implement documented instructions, '

procedures or drawings of a type appropriate to the circumstances is a

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violation:

Failure To Provide Appropriate Instructions for Activities

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Affecting Quality Resulted in a Fire Inside the CV, 91-05-01.

The licensee's draf t fire investigation report identified several additional problems and deficiencies which are to be addressed.

These include the following:

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Failure of the control board operator to immediately sound the

fire alarm when a fire was reported.

The fire brigade leader was not recognized by non-operations personnel

as being in charge of all support activities (e.g., radiological 4.

protection) in the fire area.

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Combustibles control inside the CV.

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Difficulty was experienced de-energizing involved wiring.

Communications between the control room and the CV via certain

radio channels were not possible.

The extent and possible impact of the fire was not communicated in a

timely manner to senior site management.

The Operations Manager's home telephone number was not correct in

emergency procedure, PEP-171, Emergency Communicator And Staff.

l The inspectors will review the final investigation report and associated

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recommendations to preclude repetition.

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The effects of the fire and smoke on equipment was evaluated in EE 91-039, Assessment Of Fire Under The Reactor. Vessel Head. The EE concluded that:

(1) the heat generated by the fire did not change the material properties j

of the reactor vessel head or damage other structures in the area and, (2)

removal of smoke deposits from the reactor head and other affected components was sufficient to attain an acceptable level. A hardness test was performed on the reactor vessel head to verify that no material. change had taken place.

Painted concrete surface visual inspection verified that the maximum temperature was not high enough to blister the paint and thus, could not have caused damage to concrete floors and walls.

Chemical analysis of smoke samples and deposits revealed the presence of halogens (i.e., chlorides and fluorides).

Other materials such as heavy metals were also detected; however, they were in such minute amounts that adverse effects are not anticipated.

Componr;nts.which may be sensitive to chloride stress corrosion were sampleC and cleaned as appropriate.

The reactor vessel head was cleaned using h:gh pressure water, mechanical, and chemical cleaning. The HVH-1 and 2 contlinment fan coolers' cooling coils

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were also cleaned.

Post-cleaning samples verified that the chloride deposits had been reduced tr en acceptable level'(i.e., within Westinghouse

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Process Specifications 292722, revision 9. for SS).

Other actions taken included: the reactor vessel head flange 0-ring was cleaned by the vendor; the HVH-1 and 2 prefilters were replaced; the radiation monitors ~were verified to be operable; charcoal filter La.-associated with HVE -1, 3, and 4, were verified by laboratory analysis to be greater than 90 percent

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efficient; and smears of B S/G snubber shafts indicted acceptable levels

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of chlorides.

The inspectors reviewed the report and have no further hardware concerns.

The reactor vessel head cleaning was performed without written instructionsa or directions.

The recovery team met as needed and detehnined what actions were necessary; however, these. were not documented.

The team included personnel representing Operations. Outages and Modifications, Maintenance, E & RC. Technical Support, and NED.

Video tapes of the head were used to describe areas to be cleaned and for Al. ARA considerations.

Although the cleaning was satisfactorily performed, the failure to use an established system, such as use of a special procedure with its associated controls and review ' processes, was identified as a weakness.

This was discussed with the Plant General Manager who agreed to review the plant's use of procedures for abnormal conditions.

Inadvertent Reactor Trip At 1:02 a.m. on February 28, 1991, a reactor trip occurred due to low-low

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level in A S/G.

The unit was in cold shutdown at the time; however, the reactor trip breakers were closed for performance of EST-048, Control Rod Drop Test.

Concurrent with this test, all three S/Gs were being drained to clear a S/G high level feedwater isolation signal to facili, tate MFRV testing.

Shutdown bank A RCCAs were being tested when the trip occurred.

Seven of eight RCCAs dropped into the core; the other RCCA had already been dropped per the EST.'. Path-1 of the E0Ps was entered and the reactor

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b trip was verified.

Draining of the 'A and B S/Gs was subsequently terminated.

The plant and associated equipment responded as expected to the event.

Evidently, the operator who was responsible for maintaining S/G 1evel was distracted by other evolutions which were being performed.

The S/G low level alarm was apparently acknowledged by' the operator; however, sufficient actio1 was not taken to prevent reaching the 16 percent low-low level trip set point as measured by the narrow range instrumenta-tion. The operator involved was counseled and ACR 91-120 was initiated to determir.e root cause and causal factors.

The inspectors are concerned that the individual was apparently allowed to become distracted by evolutions in which he was not involved.

However, the inspectors observed that the potential for unnecessary distractiens during the subsequent plant start-up were minimized.

Control room access was limited to necessary personnel and work evolutions were coordinated by startup managers.

The inspectors will monitor the ACR's corrective action effectiveness in precluding recurrence.

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CCW Pump Isolation

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During R0-13, it was identified that the B CCW pump could not be isolated for maintenance due to seat leakage on both the pump's supply and

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diLcharge valves, CC-701B and CC-703B, respectively.

Since each CCW pump's supply and discharge valves are in parallel with the other pumps'

valves, a CCW pump cannot be isolated for repair without shutdown of the CCW system.

During normal operation, pump operability is not affected as all three pumps' discharge and supply valves are open.

However, the

inability to isolate a pump with seal leakage resulted in a system vulnerability which the licensee analyzed.

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It was determined that if a pump seal fails, system operability is not affected even if the leak cannot be isolated.

The system makeup capability exceeds the maximum credible mechanical seal failure leakage rate.

However, as a result of operational and personnel safety-(due to chromated water) considerations, the licensee was developing a TM to mitigate the effects of a pump seal leak.- Additionally, Operations personnel have been instructed to minimize B CCW pump operation due to the isolation concerns previously discussed.

The proposed TM (91-701) delineates the methodology and material necessary to control a leaking shaft seal should pump isolation be impossible.

Chesterton Corporation is developing a " split auxiliary back-up housing" for the pumps which can be installed without pump isolation.

The licensee had previously changed 'the current seal type in A CCW pump to a cartridge seal, which minimizes potential installation errors and as such, leak probability.

Cartridge seals have. been procurred for the other two pumps and will be installed on an as-needed basis.

The issuance of TM 91-701 and the cartridge seals' availability, should be sufficient to minimize the potential for and mitigate the

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consequences of a CCW seal leak / failure.

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CV Closeout Inspection

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On March 2,1991, the inspectors, accompanied by the Operations and Regulatory Compliance Managers, verified that safety-related equipment located inside the CV appeared to be functional and properly placed in j

service or in standby as required.

The inspectors observed that in l

contrast to the housekeeping conditions reported'in IR 91-01, housekeeping had improved considerably.

The inspectors noted that general cleanliness

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of the CV was better than previously observed in the last three years.

Minor deficiencies which did not affect operability were noted.

Examples of these conditions included: pressure instrumentation used for monitoring inlet and outlet SW pressures of the containment fan coolers had been over-ranged; B S/G wide range level instrument, LT-487, had an instrument tube fitting leak; and letdown orifice isolation valve CVC-200B had a packing leak. The observed items were evaluated and repaired as necessary.

Plant Restart

On March 7, 1991, at 6:35 a.m., the reactor was made critical in accordance with EST-050, Refueling Startup Procedure.

On March 9, 1991, R0-13 ended at 12:20 p.m. when the main generator output breaker was closed.

The inspectors observed portions of-EST-050 and GP-005, Power Operations.

The inspectors observed that procedures were properly

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implemented, distractions to the operators were minimized, and communications were formal and effective.

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Identification of RG-1.97 Control Room Instrumentation d-On March 16, 1991, the inspectors observed that RTGB PI-402 RCS pressure indicators and PI-501 were not identified with blue bezels.

Prior to R0-13 these indicators had been marked with blue bezels to identify them as meeting).RG-1.97 category A' criteria (i.e., reliable under accident conditions During the outage, these instruments were relocated and new indicators were installed per M-1011, Instrumentation for Mid-Loop Operation.

Apparently, the blue bezels were inadvertently deleted during this evolution.

During subsequent discussions with the cognizant engineer, he indicated that this condition Will be corrected.

A control room instrumentation review identified no other similar discrepancies.

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AFW Valve Bonnet To Body Leaks During plant heatup and pressurization, bonnet to body leaks were detected on AFW-68, 69, and 70, MDAFW pump discharge check valves to S/Gs A, B, and C, respectively.

These valves had been disassembled during the RO for visual inspection.

The valves are located inside containment adjacent to the AFW to main feedwater header connections.

Bonnet stud tightening was successful in stopping the leak on APJ-70.

Permanent repair (pressure L

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seal replacement) of the other two valves requires the valves to be

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disassembled and reassembled.As a result, the licensee elected to implement TM in cold shutdown.91-703, Installation Of Furmanite Check Valve Bonnet Sealing Enclosures on

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AFW-68 and AFW-69, to allow operation until the next refueling outage or The inspectors.

outage of sufficient length to allow permanent repairs. review concerns at this time.

Inoperable Control Rod Group 19,1991, at 7:41 a.m., a rod control system urgent failure alarm Maintenance personnel confirmed that the alarm was valid, On March was received.

due to a failure in the A shutdown bank group 2 control rod drive circuitry.

Since a power cabinet urgent failure alarm results in all moveable and stationary coils associated with'the cabinet being energized to hold the rods in place, a total of twelve control rods could not be moved by their-Although these rods could not'be inserted or withdrawn, drive mechanisms.

they were still capable of responding normally to a reactor trip signal.

'

At approximately 9:00 a.m., these twelve control rods were determ be inoperable per TS 3.10.6.1.

TS 3.0 requires the unit as allowed by TS 3.10.6.2, TS 3.0 was entered.

,

to be in hot shutdown within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and in cold shutdown in the following

The starting time for the above: referenced time intervals was 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

established at 7:41 a.m. (i.e., the time the alarm was received).

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Maintenance personnel, assisted by Technical Support and Westinghouse personnel (the latter via telephone), determined the failure to be inT a*

either one of two circuit boards.

The alarm was phase and firing printed circuit boards) were replaced. rese inserting and withdrawing them in accordance~ with OST-Oll, Rod Cluster

' Subsequently, the control Control Exercise & Rod Position Indication.

rods were declared to be operable and TS:3.0 was exited at 12:00 noon.

The inspectors observed both the repair efforts and subsequent testing.

The inspectors verified that plans were'in" place to initiate a shutdown at approximately 12:30 p.m. if the condition Was.not corrected by that time.

The shutdown would have consisted of driving the unaffected D contol bank At control rods into the core until the C control bank had to be moved that point, approximately 1200 gallons' of boric ~ acid would have been use to bring the' unit to hot shutdown.

Initiating a shutdown at 12:30 p.m.

would have allowed ample time (3. hours) to perform this non-standard shutdown in a controlled manner.

Visual examination of the firing card revealed a potential area of The overheating which may have contributed. to component failure.

licensee plans to perform a failure analysis to determine th failure mechanism.

"_

to perform preventive maintenance on similar circuits in the control rod drive power cabinets.

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R0-13 Refueling outage 13 which commenced on September 8, 1990, was completed on March 9, 1991.

The 99 day scheduled outage was completed in 183 days.

Emergent issues were the major contributors to outage extension.

Examples of these issues and associated time' on critical path were: split pin replacement (14 days), an RCP seal runner repair (9 days), unlatched

!

control rod recovery (17 days), and.CV fire recovery (7 days).

In addition to these items the licensee successfully addressed a number of safety-related issues including:

SI accumulator nozzle crackingt S/G girth weld UT indications; degradation of underground SW header piping; CCW Hx tube cracking; MIC growth in'HVH-4 SW piping and in HVH 1-4 SW

containment penetrations; and, degradation of MCC wiring.

Inspections

,

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performed on 18 check valves under the guidelines of the check valve detected 8 valves which required repair.

Repair part j

program unavailability resulted in two valves, CVC-312 A 'and B, being replaced

,

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with new valves.

significant number of these items / issues involved material condition of plant equipment.

The1 external condition, i.e.,

'

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appearance, leaks, etc., of components was good; however, internal inspections have revealed significant degradations.

The licensee has not developed an overall strategy for addressing plant aging.

This concern was discussed with the Site Manager.

Technical Support Work Items

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The Technical Support Improvements - February 1991 Status Report identified approximately 1400 action items. Of these items, approximately 700 items were greater than 90 days old and approximately 800 items had

[

not been prioritized.

Three contractors have been employed to assist

with emergent and backlog work.

Additiona1' contractors are to be added as necessary to reduce the action items backlog by December 1992, to l

a level manageable by the plant staff.

By the end of 1991, the manhour effort to address each open item is to be determined and incorporated into the work management system.

The inspectors plan to periodically review

.

backlog status.

l One violation was identified.

.

3.

MonthlySurveillanceObservation(61726,71711)

The inspectors observed certain safety-related surveillance act1vities on

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systems' and components to ascertain that these activities were conducted in accordance with license requirements.-

For the surveillance test procedures listed below, the inspectors? determined that. precautions and LCOs were adhered to, the required administrative approvals and tagouts

.

was accomplished by were obtain'ed prior to test initiation, testing d test procedure, test f

qualified personnel in accordance with an approve

i instrumentation was properly calibrated, the tests were completed at the

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required frequency, and that the tests' conformed to TS requirements.

l Upon test completion, the inspectors verified the recorded test data was

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complete, accurate, and met TS requirements ' test discrepancies were -

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properly _ documented and rectified, and 'that the systems were properly returned to service.

Specifically, the inspectors witnessed / reviewed portions of the following test activities:

~

l EST-028 Main Steam Safety Valve Testing EST-050 Refueling Startup P'rocedure EST-052 Operational Alignment Of Process Temperature

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Instrumentation OST-011 Rod Cluster Control' Exercise & Rod Position t

l Indication

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OST-051 Reactor Coolant System Leakage Evaluation

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Snubber Concerns

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i During an RHR system snubber inspection in October 1990, QC inspectors identified and documented on NCRs 90-033 and. 034: snubber defects; i

v snubber installation procedure concerns; and apparent deficiencies with inspections previously performed on the snubbers in question.

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. subsequent QC inspection of other safety-related snubbers identified similar hardware and procedural concerns.

The procedures of concern were: CM-401, Removal and Reinstallation. of' Hydraulic and Mechanical d'

Shock Suppressors; CM-402, Figure 200 '& 201 ITT Shock and Sway

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Suppressors Maintenance; and EST-032, Visual 1 Inspection of Hydraulic and j,

Mechanical Shock Suppressors.

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l Corrective actions were initiated by Technical Support and Maintenance to

'

l address the hardware and procedural concerns.' The NCRs indicated that l

individual snubber " defects" were subsequently corrected by WR/J0s and temporary changes to CM-401 and 402.- A temporary change was issued to EST-032 to provide clarification and additional information prior to snubber reinspection.

The NCRs, which were closed on January 30, 1991,

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l stated in part. "...the hardware problems identified have been addressed and corrections / repairs made to ensure component configuration and integrity.".

According to the Manager, Technical ~ Support Programs, all safety-related snubbers were either ' replaced 'or satisfactorily bench tested with reinstallation and inspection' performed under the temporarily changed procedures.

The inspectors subsequently reviewed snubber construction drawings and visually ' items which would affect snubber inspected various safety-related snubbers throughout the plant.

No operability were identified.

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b On January 11,1991 ACR 91-021.was ' initiated to document and evaluate the lack of. snubber inspection guidance' and procedure coordination between the CM and EST procedures.

Iniaddition to the above discussed items, the ACR addressed deficiencies identified by FR 90-346 with procedures CH-408, Bergen-Patterson HSSA-20' And.HSSA-30 Hydraulic Shock Sup)ressor Maintenance, and EST-033. Functional Testing Of Hydraulic and Mec1anical Shock Suppressors.

The ACR'also identified that the snubber program had failed to be proactive in problem resolution.

The A'CR is scheduled for resolution / root caused. assessment by July 1991, at which time the inspectors will review the. associated corrective actions.

Failure to have adequately established procedures for safety-relate snubber installation and inspection ~ is a violation.

However, this -

licensee-identified violation will not' be. cited because the criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied, NCV: Procedures for Snubber Installation and Inspections Were Inadequately,

Established.- 91-05-02.

.

IVSW Manual Header Utilization The IVSW system is designed to provide water at slightly greater than accident pressure (42 psig) to seal fluid lines which penetrate the CV.

This. is accomplished by injecting pressurized water between closed globe and diaphragm isolation valves or between the seats and stem packing of

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double-disc isolation valves.

Three of the IVSW headers are automatic

'

(i.e., a SI or containment phase A isolation signal will open the two supply valves to these headers, as well as closing the associated

isolation valves).

One manual header requires the supply valves to the lines penetrating the CV be opened locally, as well as manual closure of 6 MOVs and non-MOVs on these lines.

The manual header can seal the following lines: charging, RCP seal water supply. SI to the hot and cold legs, train A and train B supplies containment. spray.

During performance of EST-004, Isolation Valve Seal Water, several valves '

'

cn the manual IVSW header were determined to be leaking in excess of the EST's acceptance criteria.

The excessive. leakage was satisfactorily corrected.

However, during the review of' the basis for the leakage criteria associated with the IVSW manual header the licensee determined

,

that no procedure guidance existed ~ for" placing the manual header in service after an accident.

Of the six lines associated with the manual IVSW header, four of the lines are considered essential to mitigating the consequences of an accident and must remain in. service.

The remaining two lines, charging and RCP seal water supply, are not required for accident mitigation.

These two lines may be sealed by the IVSW system to prevent leakage from the CV.

Procedure EPP-9. Transfer To Cold. Leg Recirculation, was revised on March 1,1991, to provide steps to manually seal the charging and RCP seal water supply. lines.

.

One NCY was identified.

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MonthlyMaintenanceObservation(62703).

! i The inspectors observed safety-related maintenance activities on systems and components to ascertain that these activities were conducted in

accordance with TS, approved procedures, and appropriate industry codes and standards.

The inspectors determined that these activities did not -

i violate LCOs and that required redundant components were operable. The

,

inspectors verified that required administrative, testing, and fire

,

prevention controls were adhered to.

In particular, the inspectors i

observed / reviewed the following maintenance' activities:

WR/00 90-BKL435 Perform LP-551, Rod Position Indication System

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WR/JO 91-ADWN1 B MDAFW Lube Oil Leak Repair

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WR/JO 91-AESS1 Repair Of Control Rod Power Cabinet

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Maintenance Improvement Plan

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On October 14, 1990, a Maintenance Improvement Plan was established. The plan is a compilation of the major-corrective actions and enhancements

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being implemented to support maintenance activities.

The plan has been i

updated approximately every month to' provide an overall status perspective of maintenance issues.

The issue initiation mechanism was used to v

subdivide the plan into the following 6 parts: mechanical maintenance

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I technician interviews;: planner analyst = interviews; I & C technician

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interviews - electrical technician interviews;' maintenance unit performance

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enhancements; maintenance inspection team J report (USNRC) - corrective

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actions for weaknesses identified;.and emergent issues - maintenance. Thi plan was intended to be a "living document"-as' implied by the last part's

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title.

The plan includes work items involving. site organizations other

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than the Maintenance Unit.

By the end of 1991, the licensee expects to

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have all the short term items addressed.. Examples of long term issues and their expected completion dates are:

the maintenance procedure upgrade

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December 1992, check' valve program - December 1992,

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project

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safety-related equipment PM development

December 1993, and EDBS development - December 1995. Examples of areas.which have shown improvement were post-maintenance testing specifications, torquing, supervisory

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oversight, communications with Operations, and procedure utilization.

The latter has been attributed to in part, the procedure usage cover sheet which was issued with each procedure to clearly define the supervisors expectations (e.g., step by step adherence, performance of a group of steps, or skill of the craft).

Communications with Technical Support

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i required' additional management attention.

An example of this was manage-

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ment prompting maintenance technicians to contact engineering for which involved a shutdown LCO (see paragraph'2) power cabinet urgent alarm assistance, when troubleshooting a control' rod

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The Maintenance Manager indicated that certain performance indicators reflected favorably on maintenance performance.

Examples were no reactor trips or turbine runbacks due to maintenance personnel errors, and a 98.6 percent safety system availability factor during '1990.

The amount of rework, previously identified by the ' inspectors as a concern, was 2.8 percent for 1990. Rework was deemed to have occurred if any specific work activity on a component had to be-re-performed in~an 18 month period.

Based upon this information, the total rework quantity was not considered to be a problem; however.1 occasionally rework on specific components or types of activities' did require corrective actions.

Other positive indicators were completion of all but three-of the 4130 PM activities scheduled for "1990; 55 person-rem maintenance unit exposure for 1990; and implementation of a six month pilot program to provide around the clock maintenance coverage.

This latter item, initiated at the end of R0-13, provided 5 shifts of 2 mechanics and 2 I&C/ electricians to rotate on the same shift schedule

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appears ' to have been well as Operations.

This shift coverage. inspectors periodically review the The received by Operations personnel.

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maintenance improvement plan updates and. implementation results.

No violations or deviations were identified.

5.

ESFSystemWalkdown(71710)

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The inspectors performed a walkdown ' of the ?SI' and containment spray

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subsystems of the SI system to verify that'the subsystems were operational.

The inspection included visual examination of the valving, pumps,-piping, instrumentation,- and associated supports.- Specifically, valve. alignment andpiping(bothinsideandoutsidetheCV)-associatedwiththeinjection6 pathways was inspected.

The subsystems were verified to be properl aligned.

The C SI pump remained out of service;(off-site since 1989)y for casing crack repairs.

Initiation.and monitoring instrumentation was

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observed to be operating nonna11yi ~ Support: systems such as component cooling water, SW, heating and ventilationfand-electrical power were

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verified to be capable of providing their necessary support functions.

Conditions which could potentially render the system inoperable were not identified during a review of outstanding WR/J0s. Minor' leakage from the system was reported to the licensee for corrective action.-

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No violations or deviations were identified.

6.

OnsiteReviewCommittee(40500)

The inspectors evaluated certain activities of the PNSC to determine whether the onsite review functions'were conducted in acccedance with TS j

and other regulatory requirements.

In - particular, the inspectors attended the pre-restart PNSC meeting.on February >27,1991.. It was ascertained that provisions of the TS dealing With membership, review process, frequency, and qualifications were satisfied.

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SelfAssessmentCapability(40500)

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The inspectors have evaluated the licensee's self-assessment capability on

'

a continuing basis.

This evaluation is performed through routinely

"

attending' management and PNSC meetings -(both'special and regular), and review of performance indicators.(LERs, ONS'and PNSC findings / recommendations and action items.

In addition toithis continuous evaluation, the o

inspectors reviewed the activities of various oversight groups including t

CNS, ONS, PNSC, and the newly formed NAD (CNS,c0NS, and QA organizations

,

were disbanded effective January 1,.1991). ' On-site oversight was primarily performed by the PNSC and ONS.

Technical Specification required i

independent reviews and audits were performed by the CNS and corporate QA

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departments, respectively.

Technical Specification Section 6.5.1.6 delineates PNSC responsibilities,

'

composition, and meeting frequency. - The PNSC serves as the principal

'

s management overview. group for reviewing, evaluating, and resolving plant nuclear safety issues.

The inspectors attended the majority of special

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PNSC meetings held in the past year and approximately 25 percent of the monthly meetings.

The PNSC' routinely performed the TS responsibilities they are charged with; safety issues were nonna11y dispositioned in a

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technically sound, conservative : manner.

The PNSC routinely invited technical experts to present issues and ' answer questions, which has

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enabled the members to make technically sound decisions.

Differences of v

opinion were freely voiced, resulting"in : issues being thoroughly

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evaluated.

The PNSC quorum requirements'were consistently met and action

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c items tracked to resolution..As'of March 21, 1991, there were five open

PNSC action items (1-1989, 2-1990, 1-1991), none of which is open due to a lack of PNSC follow-up.

During the recent R0, the inspectors perceived 6 some schedular-driven concerns were raised, on an issue rather than limiting discussions to the issue's safety: aspect.

This concern was

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brought to plant management's ~ attention;.further instances of this concern were not noted by the inspectors.

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The ONS unit provided the primary site activity overview that had been i

charged to CNS.

Prior to this unit being dissolved they provided three main functions.

These were speciali project ' performance, OEF

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review / evaluation, and procedure review to complement the PNSC overview

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li of procedures and procedure changet.

The OEF review / evaluation included, but was not limited to: NRCBs, ins, INP0 50ERs and SERs, and 10 CFR part 21 notices.

This function is now performed by Regulatory Compliance.

however, their effectiveness was not evaluated.during the inspection.

i

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There were twenty-two special investigations / projects conducted by ONS in

1990.

These included:

Number Special Project Description,

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90-06 Containment Isolation Capability of Check Valves

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SI-890A & B

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90-10 ONS Assessment of Transformer Outage Activities 90-11 Root Cause Assessment of Torquing Concerns 90-19 Review and Analysis of the HVA-2 Freon Line Cutting 90-20 Trend of Lighted Annunciators and Equipment Blue Stickers in the Control Room.

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90-21 Nuclear Instrumentation System Assessment These special investigations / projects were perfomed at the request of the plant, in response to events, or at the discretion of ONS/CNS

management.

Recommendations and action items 'were' routinely identified

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and tracked to resolution.

The~ inspectors reviewed the majority of the

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1990 special investigations.' The reports often' identified concerns which s

required resolution or further evaluation.

For example, Special Report 90-06 recomended that a containment'.DBD be ' generated to enhance the

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definition and understanding of what! constitutes containment isolation boundaries.

,

Prior to the May 1990 transformer. outage. ONS developed and conducted a

" Focus on Nuclear Safety" meeting.

This effort "which resulted partly

>

from the March 1990 Vogtle LOOP event.- was iinitiated. to improve the

>

outage's planning, communications. and execution.

As a result of the

'

meeting's success, ONS implemented distribution of OEF Reminders.

Each

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OEF Reminder discussed industry events which had potential to occur during future plant evolutions or activities, 'ii e.,

shared " lessons learned" (previously discussed in~. irs 90-11 and 90-22).

In. addition ONS 6

'

conducted a Focus on Nuclear Safety meeting prior to the unit's recent

.

startup from R0-13.

The Special Investigations / Reports, Focus on Nuclear Safety meetings, and OEF Reminders were examples of proactive involvement

,

by an independent assessment organization 4

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i The CNS section's independent reviw responsibilities are delineated in TS section 6.5.2, Inspection Report' 89-25 described concerns with CNS's

<

effectiveness in performing independent reviews 'and providing oversight functions.

During 1990, the number of individuals performing independent

.

reviews and the time dedicated to perform the function was increased. * As

of March 22, 1991, there were 24 items which had not received independent

,

review as compared to approximately 180 ~a year earlier.

Current items i

requiring review were being evaluated.as well as, those items contained in the backlog. Some reviews resulted in identification of items requiring plant evaluation and/or aciton. 'These items included: steam dump system summator circuit response concernst 50.59 adequacy regarding lifting of heavy loads'and single failure concerns associated with 51-869, SI hot leg

injection isolation valve; and, vendor recommeetion incorporation into i

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vendor manuals and procedures.

The backlog reduction should enable the independent review results to be more timely, thus increasing the effectiveness of the resultant recommendations.

In addition,.CNS performed a special investigation at the plant's request to. investigate the scope of missed / inadequate TS surveillance tests.

l The NAD is responsible to " independently evaluate those company functions which have potential nuclear safety, reliability, or quality l

implications".

The NAD will perform the' independent oversight and

,

internal nuclear assessment activities'which were previously provided by the conglomeration of CNS, ONS, and QA.

The TS: responsibilities these organizations were charted with are ' being '-assumed by the NAD and Regulatory Compliance.

The NAD assessment process consists of corporate, site / department, and functional area assessments, as well as, onsite assessment activities.

The broad goal of these assessments is timely issue recognition with timely management action.

These asessments,

,

results and supporting observations are to be entered into a data base for intrasite and intersite utilization.

.

There is a NAD unit on each site and in the corporate office. Within the site units there are personnel assigned to specific areas of " focus". These i

areas include: E & RC, Operations, Maintenance, Engineering / Technical Support, and Management.

The Engineering / Technical Support and

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Maintenance areas have an additional level of oversight with a responsible manager reporting to the site unit manager. rThe corporate office has

leads for functional evaluations in the first four areas named above, as well as, Planning and Support and a Manager - Nuclear Safety Review.

The NAD Nuclear Safety Review unit now performs all TS required independent reviews.

In addition to formation of ~ the NAD, CP&l. initiated a new CAP.

This program was initiated simultaneously with NAD implementation.

The

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CAP program was developed to provide a centralized and singular, site-wide

'

corrective action system.

This program is' based on self-identification

, and resolution and trending of identified adverse conditions.

Due to the relatively short time these efforts have' been in effect, the inspectors are unable to evaluate the NAD's and the CAP's? effectiveness.

i The NSD has been challenged with providing the second level of self assessment.

The NSD's stated mission "is to provide proactive support to

,

nuclear plant operations, be the catalyst stimulating the Nuclear Generation Group to higher levels of excelhnce, and monitor / review nuclear plant activities.

Indicated as & significant part of NSD's monitoring / review function is the enrocrate =ande plant peer management interaction in the areas of operations,xmaintenance, environmental and radiological controls, technical support, security, emergency

.

preparedness, and outages / modifications."

Accordingly, the results of this monitoring / review function are to be presented quarterly to the

'

i Senior Vice President - Nuclear Operations."

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There have been additional self assessment efforts undertaken on both a s

micro and macro level.

The micro-level. assessment efforts include semi-regular adverse trend assessments.

These assessments are not proceduralized nor documented.

They were initiated at the request of the Site Manager and participation has -included ;the'! Plant General Manager,

QA/QC Manager, Regulatory Compliance ~ Manager, and '0NS Director.

Recent

,

participation has also included atCAP humantfactors representative and

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l the CAP lead.

These assessments ' are - performedt to detect and correct

)

identified trends.

It included a sumary'levelc review of LERs, NRC irs, j

SCRs, NCRs, FRs, and now, ACRs. Some adverse trends have been identified

' Examples of trends and corrective actions taken as necessaryd

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j identified include: inadequats radiological' postings, ineffectiveness of i

the site's torquing control program, and construction work practice control regarding repetitive concerns such' as' nicking rebar. The new CAP and ACR process, coupled with future ACR trending,'should effectively replace and improve upon the process and results_ of these assessments.

,

In August 1990, a Robinson Summary-level' Evaluation was performed.

This

.

evaluation resulted from a recommendation by the Nuclear Assessment Project Quality Team.

The team recognized. the need. for an independent assessment function focused on broad-scope issues potentially impacting important elements of site. performance, ;This evaluation was performed to provide senior management with a cleardidentification, analysis, and recommended corrective actions for any ; major ebarriers to desired r

'

performance.

This evaluation also, served asuthe pilot effort for future s,-

similar broad-scope evaluations to be: performed ^at the plant sites and at

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the Nuclear Generation Group level.v This; evaluation identified several key barrier issues and potential correctiveiactions.

Corrective actions have been implemented; however. the effects.of these actions could not be 6

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concretely evaluated.

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The inspectors believe that these processes * constitute an improved effort in self assessment.

Weak areas have exhibited improvement and additional self assessment programs and resources 'haveibeen developed.

Effective

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implementation should improve the site's-self' assessment ability, as well as overall performance.

.

No violations or deviations were identified.:

,

8.

10CFR50.59SafetyReview(37702)

On March 5 and 6, 1991, a review was~ performed of-the licensee's safety

-

reviews for plant modifications.. This review was performed as a followup of a review performed during the week of~ August 27, 1990.

As reported in IR 90-20, the latter review concluded that.the' licensee's new procedure (PLP-032,10 CFR 50.59 Reviews -Of Changes, ~ Tests,- And Experiments) for performing safety reviews represented * a substantial improvement in providing guidance for safety review performance and~ has addressed the inadequacies of the previous program. LHowever. since the new procedure

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was only implemented in July,1990, the sample of modification safety reviews was not sufficient at that time ~to~ determine if the improvements were being consistently implemented.

During R0-13 the licensee performed a sagnificant number of plant modifications.1 The followup review provided an indication on the licensee's"perfomance in the implementation of the new safety review process.'.

-

The following modification safety evaluations were selected for review:

M-993. Control Room Habitability - Pre-Outage Mod; M-1004, DB50/DB75 Air

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Circuit Breaker Upgrade; M-1049, Radiation Monitoring System By System

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Team; M-1050. Condensate Storage Tank Level Alarm Setpoints; and M-1056,

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y MCC-5 and MC'-6 Load Shedding. The review found that these Safety Reviews

'

were perfort, ed according to the' guidelines of PLP-032.

The review identified ai overall improvement in the program and the quality of the safety reviews as compared to those previously performed. A noted feature of PLP-032 program was the thorough incorporation of Design Basis. As the

.

Design Basis Documentation effort progresses, evaluations of design basis issues are especially important.

Another noted improvement was the

.

recognition of the need to update the FSAR as a line item.

No violations or deviations were identified.

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I 9.

Modifications (37828)

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During R0-13, the inspectors observed part of the installation and testing

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activities associated with:

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M-994 Control Room Habitability 4.

M-1001 Service Water Pipe Replacement-Containment Penetration To

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SW Booster Pumps.

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M-1004 DB50/DB75 Air Circuit Breaker Upgrade

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M-1014 Resupply Of SWBP M-1056 MCC-5 and MCC-6 Load Shedding j

The inspectors verified that selected activities. were successfully performed in accordance with approved drawings and procedures.

Activities inspected included: verification that the installation was in accordance with as-built drawings, cleaning and flushir.g was performed as necessary, hydrostatic test were properly performed, breakers were appropriately cycled, and acceptance test were appropriate and completed satisfactorily.

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No violations or deviations were identified.

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Followup (92700,92701,92702)

(Closed) LER 88-18 Inoperable Cable Tray Penetration Seals Due To Inadequate Installation Procedure. :The~ root'cause of the subject event was an inadequate procedure (i.e.', the - procedure did not specifically address how to seal cable trays with: covers)r ~The inspectors verified that CM-621, Structural, Mechanical ' and Electrical Penetration Fire Barriers, rev.11, requires verification that silicone foam was installed under the cover for penetrations when it is not possible to remove the tray covers prior to sealing.- As ' discussed in the LER, 38 of'101 cable tray penetrations required repair.

Of these,'3 could not be repaired to a 3 hour3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months fire rating and were evaluated by' engineering evaluations to be acceptable for the fire hazard' present.

The adequacy of engineering

. evaluations involved with this type of rondition was identified as an IFI in IR 88-31.

Thus, this aspect of LER 88-18 is considered to be part of the followup on IFI 88-31-01.

This LER is considered closed.

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(Closed) LER 90-03, Inoperable Fire Barrier Penetration Seals Due To

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Installation Deficiency.

The specific deficiency discussed in the LER was addressed in IR 90-15.

The IR identified that other fire barrier inspections for similar deficiencies will be-performed during the 1990 Fire Barrier Penetration Inspection ~ Project.

Review of the project and its associated results are to be performed as part of the followup inspection on IFI 88-31-01. The LER is considered closed.

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(Closed) LER 90-08 Inoperable Fire ~ Barrier' Penetration Seal.

The subject item was identified as part of the: corrective action committed to in LER 90-03.

(See LER 90-03 item above for-additional information.) The inspectors verified via procedure CM-621, completed on May 5, 1990, that 6 the condition identified in LER 90-08 had been repaired as stated in the LER. This LER is considered closed.

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(0 pen) UNR 88-16-01, Resolution Of EQ Issues Associated With SI And RHR

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Pump Rooms.

On June 23. 1988, the licenseesfound that equipment in the

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SI pump room was not environmentally' qualified,9with the exception of the Regulatory Guide 1.97 instrumentation.

Major components affected were the three SI pump motors and the two CV ' spray pump motors.

Based on these concerns, the licensee has ' qualified"tha SI and CV spray pump

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motors.

The inspectors reviewed this documentation (EQDP 8.1 revision 1, for the SI pump motors, and EQDP 8.2 revision 0 for the CV spray pump

motors) and found that the analyses-were satisfactory.

In the qualification documentation, the licensee indicated that the CV spray pump motors did not need to be ~ qualified 7for a radiation harsh environment because the CV spray pumps operate prior to the recirculation phase of an. accident.

The SI pump motors were qualified to withstand a radiation harsh environment.

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The SI and RHR room coolers are not qualified for a radiation harsh

environment.

In December 1988, the;11censee also identified that a single failure of instrument bus 1 circuit 17 would prevent the S1 and i-

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RHR pump room coolers from startingc ~ Hence.The EQDPs also addressed the l

lifetimes 'of the CV spray, SI, and RHR' pump? motors due to possible

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elevated ambient room temperatures resulting1from an unavailability of.

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- the room coolers.

The lifetimes ofithe* CV1and SI - pump motors were

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evaluated to be 25 days (required ~ 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months post-accident) and 52 days l

l (required 30 days, post-accident), respectively. = However, for the-RHR pump motors, the inspectors determined that'an-assumptions used in EQDP

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8.1 was invalid.

The EQOP'had assumed the-RHR pump motors would operate i

5 percent of the time for 40 years.

This 7resulted in an assumed operating time of 17.520 hours0.00602 days 0.144 hours 8.597884e-4 weeks 1.9786e-4 months .' At the present time, the RHR operating

timers on the emergency busses indicate that'the.A and B RHR pump motors have run 20,499 and 15,935 hours0.0108 days 0.26 hours 0.00155 weeks 3.557675e-4 months respectively.' However, the RHR pumps

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are considered to be operable based upon EEt 89-018 rev. 2.

This EE

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j demonstrated that, at least through the end of:1992, the RHR pump motors could operate for at least 32 days (required 30' days, post-accident) with

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The cognizant engineering supervisor indicated j

that EQDP 8.1 would be revised to reflect a more appropriate RHR pump motor or isting time.

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Even5th agh the EQDP 8.1 SI motor lifetime evaluation is conservative,

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without the room coolers available, the potential unavailability of the-

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room coolers is undesirable.

For example, the evaluations indicated that '

j without the SI room coolers available, the maximum peak temperature in

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the 31 - pump room would be 213.4 degrees F; conversely, with the room coolers available, maximum peak temperature would be 104 degrees F.

6 Prolonged operation of the SI pump motors 'at the ~ elevated temperatures

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has not been demonstrated.

The licensee is presently reviewing the room

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cooler question.

On August'24, 1990 RET RNP'90-121 was issued to study

whether or not the.SI and RHR pump > room coolers art needed during

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accident conditions.

If so, the' seismic, EQ'and single failure of the

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f an coolers are to be evaluated and addressed.

On September 17, 1990,

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RET RNP 90-121 was incorporated in PCN 90-151 which was issued.on July

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l 12, 1990, to address replacement of the fan' cooler coils (See IR 89-13).

In R0-14 (Spring 1992), the licensee plans to replace the room cooler

coils with AL6XN, a material-less susceptible"to' erosion.

The room

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coolers are to be upgraded as necessary to address the single failure ~ and j

EQ question by R0-15 (Fall 1993).

This item remains open, pending

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licensee action to resolve the SI and RHR pump room cooler single failure

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'and RHR pump motor lifetime issues.;

f (Closed) IFI 88-38-01, Review Battery A and B SiYear Performance Capacity Test Evaluation.

The results of'the performance tests were submitted to i

NRR for review.

This review concluded, as had the licensee's evaluation,

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that the test had satisfactorily demonstrated the battery's capacities to

j be acceptable.

Inspection Report 88-38 also discussed that the licensee

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1V would consider routinely cycling a replacement battery cell prior to Af ter reviewing this with the vendor, the licensee determined that this was not necessary..However, during this review, the installation.

licensee determined that MST-903,' Station Battery Charge - Monthly, did In addition, no not contain acceptance criteria for the spare batteries.

i procedure currently exists to require a 5 year performance test of spare The licensee plans to revise MST-903-to provide an acceptance criteria and develop a new procedure to address the performance testing cells.

The inspectors have no further questions at this of spare battery cells.

time. This item is closed.

j Determine If One SI Pump Injection Into Three Cold o

(Closed) URI 89-09-02, During R0-13, the licensee agreed to l

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Legs Should Be Demonstrated.that one SI pump could simultaneously inject w

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demonstrate On September 25, 1990, a l-experiencing runout into all three cold legs.

The special test was performed in the above described conf

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discharge pressure than previously documented (see IR 90-22).Due to

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the lack of technical information to resolve the concern, the SI pu were considered to be inoperable.

On the time (i.e., the Si pumps were not required by TS to be operable).

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another special test, SP-986, Safety Injection System November 24, 1990, Flow Test, was performed to provide additional data to resolve this Analysis of the data, documented in-a memo from Turner to Page,

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issue.

dated January 14, 1991, indicted that S1' pump runout would not occur

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under postulated accident conditions.. The inspectors reviewed this memo A' discrepancy was noted in the and associated backup information.

analysis; the suction line pressure drop did not account for simultaneous6 operation of a CV spray. pump, the configuration required by EPP The inspectors concluded that' available information

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procedures. indicated that the SI pump could perform'its safety function'.

In LER Based upon their analysis, the licensee declared the SI6 pumps operable.

90-12 the licensee comitted to issue a supplement when their

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investigation had been validated.

The inspectors will review the supplement when issued to verify that the above discussed discrepancy was satisfactorily addressed.

The subject URI is considered closed; however,

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LER 90-12 remains open.

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89-12-01, Ensure Adequacy Of Upgraded Maintenance Procedures.

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(0 pen) UNR In early 1990, the licensee, based upon an INP0 finding, determined that the quality of the upgraded maintenance procedures required review.

However, since the upgrade procedures were an improvement over existing the rewrite procedures, and new procedures were ' required for R0-13,A total of 247 proce process with some adjustments, continued.

A new rewrite processed before this effort was phased out in early 1991.

program staffed with a mixture of contractors and licensee personnel was The first procedure being implemented at end of the report period..

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revision under the new program, should be issued in early April 1991.

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The program scope included approximately 500 procedures, including the

247 procedures revised under the discontinued upgrade project.

The new effort is scheduled to be completed by' December 1992.

This will be a

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challenge in that several efforts which impact the rewrite project are just being initiated at this time.

These efforts are the Technical

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Support PM development project and the Operations equipment

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identification / tagging project.

This subject was discussed with the j

manager of the rewrite project.

Coordination: plans, though not yet defined, were being developed.

The inspectors plan to review a sampling

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j of the revised procedures when available.

j (Closed) IFI 89-32-01, Review M-1025 and M-1018 Acceptance Tests.

The

ispectors reviewed the acceptance tests resths and associated analysis.

The M-1018 tests and analysis confirmed that sufficient NPSH exists to allow all three AFW pumps to simultaneously deliver maximum flow to the

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S/Gs at low CST levels without experiencing cavitation.

The M-1025

acceptance test verified that with FCV-6416, the SDAFW pump-discharge

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flow control valve, limited to a less than? maximum open position.

sufficient flow is available to the S/Gs 'for LOCA conditions while also

restricting pump flow to less than the maximum flow rate assumed in the steam line break analysis. This item is closed.

v (0 pen) IFI 90-05-01, Review SW MIC Monitoring Program Changes Required By

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Accelerated MIC Growth Rates.

During R0-13,'the SS SW pipe outside the

CV which was susceptible to MIC growth was replaced with AL6XN material.

Thus excluding the HVH-4 SW piping inside..the LCV and the eight SW CV

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penetrations associated with HVH 1-4, all the'SS SW piping has been

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replaced with AL6XN material.

During R0-13 the'HVH-4 SW piping and 4 CV

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penetrations were found to have small amount'of MIC (see IR 91-01).

The

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HVH-4 SW piping and 4 CV penetrations'were sleeved.

The licensee plans

to replace the HVH-4 SS SW piping with AL6XN' material during R0-14.

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plan for replacement of the 8 ' CV SW HVH ;1-4 penetrations is to be

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developed and submitted to the NRC by September 1991. Due to the present condition of the SS SW piping, an accelerated MIC growth rate is not an issue unless the remaining sections of SS SW piping are not replaced with

AL6XN material during R0-14.

This item remains-open pending replacement

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i of these piping sections.

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No violations or deviations were identified.

11.

ExitInterview(30703)

The inspection scope and findings were summarized on April 2,1991, with those persons indicated in paragraph-1.

The inspectors described the

areas inspected and discussed in detail the inspection findings listed

below and in the sumary.

Dissenting comments were not received from the

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licensee.

The licensee did not identify as proprietary any of the materials provided to or reviewed) byf the. inspectors during this

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Item Number Description / Reference Paragraph (

91-05-01 VIO - Failure To Provide Appropriate.

Instructions for Activities Affecting Quality Resulted."In A Fire Inside The CV

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(paragraph 2).-

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91-05-02 NCV - Procedures For The Installation And

Inspections Of Snubbers Were Inadequately i

Established (paragraph 3).

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12. List of Acronyms and Initialisms

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h Ante' Meridiem

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ACR Adverse Condition Report AFW Auxiliary Feedwater.

ALARA As Low As Reasonably Achievable-

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CAP Corrective Action-Program

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Component Cooling

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CCW Component Cooling Water

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-CE Combustion Engineering

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CFR Code of Federal Regulations

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CM Corrective Maintenance CNS Corporate Nuclear' Safety

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CP&L Carolina Power & Light d.

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, Condensate Storage Tank

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CV Containment Vessel

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P CVC Chemical Volume Control DBD Design Basis Documentation-3-

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E & RC Environmental and Radiation Control

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For Example EDBS Equipment Date Base System l

EE Engineering Evaluation j

E0P Emergency Operation Procedures

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EPP End Path Procedures'

EQ Environmental Qualifications

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EQDP Environmental Qaulif4ctiner Documentation Package i

ESF Engineered Safety Feature

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EST Engineering Surveillance Tast j

F Fahrenheit

$ FCV Flow Control Valve

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a FR Field Report i

FSAR Final Safety Analysis. Report..

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GP General Procedure HP Health Physics

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-HVA Heating Ventilation Air'

HVH Heating Ventilation Handling pHVE Heating Ventilation Exhaust.-

j Hx Heat Exchanger

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I&C Instrument and Control i.e.

That is IFI Inspector Followup Item IR

Inspection Report

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Information Notice

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v t e Inspection Report - Robinson - 1991005
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \| 25 \|
1991 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 10(0) 11(0) 12(0) 13(0) 14(0) 15(0) 16(0) 17(0) 18(0) 19(0) 20(0) 21(0) 22(0) 23(0) 24(0) 25(0) 26(0) 27(0) 28(0) Security Operator Exams 300(0) Emergency Planning Other

IR 05000261/1991005

Text

Inspection Report

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