IR 05000155/1988002

Insp Rept 50-155/88-02 on 871214-880216.No Violations or Deviations Noted.Major Areas Inspected:Operational Safety, Maint & Surveillance Operation,Regional Requests,Reactor Trips,Ie Bulletins,Ler Followup & Training

ML20150B103
Person / Time
Site:	Big Rock Point File:Consumers Energy icon.png
Issue date:	02/29/1988
From:	Jackiw I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20150B081	List: IR 05000155/1988002 ML20150B079
References
50-155-88-02, 50-155-88-2, IEB-87-002, IEB-87-2, NUDOCS 8803160165
Download: ML20150B103 (12)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-155/88002(ORP)

Docket No. 50-155 License No. OPR-6 Licensee: Consumers Power Company 212 West Michigan Avenue Jackson, MI 49201 Facility Name: Big Rock Point Nuclear Plant Inspection At: Charlevoix, MI 49720 Inspection Conducted: December 14, 1987 - February 16, 1988 Inspector: S. Guthrie C

u Approved By: . ac w, Chief d'd 7'-8[ ,

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P oject Section 20 Date Inspection Summary Inspection on December 14, 1987 through February 16, 1988 (Report No. 50-155/88002(ORP))

Areas Inspected: Routine, unannounced inspection conducted by the Senior Resident Inspector of Operational Safety, Maintenance Operation, Surveillance Operation, Regional Requests, Reactor Trips, IE Bulletins, Licensee Event Report Follow-up, and Trainin Results: Of the eight areas inspected, no violations or deviations were identified. No significant safety items were identified, g2TeiMTNP G

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DETAILS 1. Dersons Contacted

• T. Elward, Plant Se +

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• Petitjean, Pla inistrative Services Superintendent G. Withrow, Engine itanance Superintendent

• R. Alexander, Tec' sineer

• R. Abel, Product Plant Performance Superintendent

• L. Monshor, Quality .. surance Superintendent D. Staton, Shift Supervisor W. Trubilowicz, Operations Supervisor J. Beer, Chemistry / Health Physics Superintendent D. Kelly, Maintenance Supervisor D. Ball, Maintenance Supervisor W. Blosh, Maintenance Engineer M. Acker, Senior Engineer J. Toskey, General Engineer L. Darrah, Shift Supervisor J. Horan, Shift Supervisor R. Scheels, Shif t Supervisor R. Boss, Reactor Engineer

• D. Moeggenberg, Engineering Supervisor The inspector also contacted other licensee personnel in the Operations, Maintenance, Radiation Protection and Technical Department * Denotes those present at exit intervie . Operational Safety Verification The inspector observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the inspection period. The inspector verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of the containment sphere and turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance. The inspector by observation and direct interview verified that the physical security plan was being implemented in accordance with the station security pla The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. During the inspection period, the inspector walked down the accessible portions of the Liquid Poison, Emergency Condenser, Reactor Dapressurization, Post Incident, Core Spray and Containment Spray systems to verify operabilit The inspector also witnessed portions of the radioactive waste system controls associated with radwaste shipments and barrelin J

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a. On December 16 the licensee notified the inspector of an electrical fault in control rod drive (CRO) scram accumulator circuitry that resulted in activation of the control rod withdrawal interlock. The water over nitrogen scram accumulators provide hydraulic energy for rod insertion on a scram when reactor pressure is below 450 psi At the time of the circuit fault the reactor was at normal operating pressure of 1335 psig and approaching full power. Hydraulic force for a scram above 450 psig is supplied by reactor pressure and no reliance is placed on the accumulators. The control rod withdrawal permissive system inserts an interlock to prevent rod withdrawal when two of the thirty-two accumulators are at pressure below 700 psia, in accordance with Technical Specification 6.2.1(a). The licensee verified accumulator pressure to be above 700 psia and commenced diagnosis. The electrical '3uit was determined to be from two leads off two accumulator pressure switches shorting to the conduit which contained the Water leakage into the conduit may have contributed to the short. A "request for modification" has been submitted for replacement of suspect wiring within the syste The interlock on control rod withdrawal effectively prevented the licensee from performing the daily control rod drive exercise required by Technical Specification 5.2. This surveillance requires insertion of one notch of each withdrawn control rod and withdrawal to the original positio Performance of this surveillance would result in insertion of all withdrawn rods by one notch and force power reductions. The inspector concluded that the fault did not represent a threat to plant safety and that all safety systems would operate as designe The inspector noted that installation of a jumper solely to perform the daily surveillance introduced the potential for error that could impose a transient on the plant and that a jumper would interfere with diagnostic effort The inspector concluded that the safest alternative would be to forego the daily rod exercise and leave the plant in its present stable condition for the duration of the diagnosis and repai That recommendation was presented to Region III management and on December 16 the licensee was granted relief from Technical Specification 5.2.2.e until repairs were completed, at which time the exercise would immediately be performed. The licensee completed repairs on December 17 and immediately performed the daily withdrawal exerc;se successfull b. On December 22 the inspector observed compensatory measures implemented by the licensee in response to loss of the security compute Licensee response was in accordance with Security Plan requirement During the event the inspector determined through interviews with on shift operations and security personnel that while all security officers were aware of the method by which access could be gained to all vital areas of the plant necessary for response to operating events, several operators were not. The inspector related his concerns to the licensee that each operator should be aware of the location of keys and be familiar with the steps necessary to gain entry to all areas of the plant when the

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security computer is unavailable. The licensee provided instructions to all operators on the location of keys and methods of access and egress. Each shift was directed to try keys in all doors as a training exercis c. On January 19 the inspector observed licensee response to steam leakage from the high pressure feed heater's secondary side. Like a similar incident December 2 (detailed in Section 2.c of Report No. 155/87026 (DRP)), the licensee shut down the reactor fully at 6:08 AM and used the shutdown cooling system to keep plant pressure below 300 psig during heat exchanger repairs. Welding activities required breaking vacuum on the turbine and condense The mode switch remained in the "RUN" positio Following repairs to the heater plant start up was delayed because of high pH and conductivity believed to be the result of a crud burst during the shutdow The inspector observed plant start up commencing at midnight, January 19. The reactor reached criticality at 1:30 AM and the generator was on line at 4:30 A The inspector noted that the shutdown was not reported to NRC headquarters under the requirements of 10 CFR 50.72. That reporting requirement addressus only shutdowns required by a plant's Technical Specifications. Big Rock has no such Technical Specification requirement d. On January 21-22 the inspector observed the license's response to an apparent seal failure on No. 1 reactor recirculation pump. The seal represents a primary plant pressure boundary and is constructed in two segments, an inner and outer seal installed in line such that the outer seal is a backup for the inner seal. Operators became aware of possible seal leakage when control room alarms were rectived for seai cooling water high temperature, seal leakage pressure, ard seal cooling water high flow. The leakage resulted in a step increase in unidentified leak rate from approxim5.tely 0.350 gpm to approximately 0.7 gpm, very near the administra',1ve limit of 0.8 gpm at which power reduc +1on and corrective acticn is required. A power reduction was performed to permit verification of seal leakag Late on January 22 power was reduced to an analyzed rod configuration

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and the recirculating pump was tripped and isolated to prevent seal damage and reduce unidentified leak rat During the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, prior to pump trip, operators performed two hour leak rate calculations, which eventually reached 0.84 gpm and prompted the pump trip. After the pump trip, power fell from approximately 62 MWe to 46 MW Power was increased to the maximum permissible with single loop operation. Due to leakage past pump isolation valves, unidentified leak rate decreased only to approximately 0.55gpm. The plant operated -

in the single loop configuration until shutdown for seal replacement i

on February 2. The inspector on February 2 observed the reactor shutdown which terminated in a scram on an upscale /downstale indication from power range nuclear instrumentation. The scram is I described in detail in Section 6 of this report.

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e. On February 6 the unit was returned to service following the scram on February 5. During the early morning hours of February 7 operators observed gradually increasing enclosure dirty sump levels and initiated a search for the source. Power was reduced to permit entry into the recirculation pump room, an area which is inaccessible due to high radiation during full power operatio Observation of piping entering the enclosure dirty sump identified overflow of the reactor cooling water (RCW) expansion tank, indicating a possible primary to secondary leak in a component served by RCW or a leak of service water into RCW at the heat exchanger interface of service water and RCW. Investigaticn determined leakage inside the heat exchanger used for pump seal i cooling on the No. 2 reactor recirculation pump. The licensee conducted an interim leak rate calculation and determined the unidentified leak rate had reached 1.18 gpm. The unit was shutdown in accordance with Technical Specificatian 4.1.2.(c) which requires that when unidentified leakage exceeds 1.0 gpm the reactor "shall be placed in hot shutdown condition within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cool down to a cold shutdown condition shall be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />." As required by the Site Emergency Plan, an unusual Event was declared and appropriate notifications were performed. The Unusual Event was terminated when the reactor reached cold shutdown conditions. The unit was returned to service February 1 f. Prior to startup on February 11 the inspector reviewed with the licensee the requirements of Technical Specification 4.1.5.B which j requires that depressurizing valves "shall be test-operated during each cold shutdown; however, in the case of frequent cold shutdowns,

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these valves need not be exercised more often than once every three months." During the inspection period the unit was taken to cold shutdown conditions on February 2 for recirculating pump seal repair and on February 7 for RCW heat exchange repai Startup on February 11 was 89 days into the three month interval referred in I

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Technical Specifications. The inspector reviewed with the licensee and with Regional Marement the wisdom of performing the depressurization valve surveillance even though not legally required.

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The licensee indicated a willingness to perform the surveillance to demonstrate valve operability and demonstrate conservative plant operation and concern for regulatory requirements. The inspector concluded that early performance of the surveillance was likely to ,

detract from plant safety for the following reasons: 1

The surveillance, which is performed during cold shutdown condition

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prior to startup has consistently resulted in valve leakage at no-mal operating pressure and temperatur The leakage is caused by a disruption in the seating surfaces and the lodging of corrosion products on seating surface ,

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Increased valve leakage contributes to plant unidentified leak rate

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totals and has been the cause of repeated forced outages. Given the i likelihood that the surveillance would result in a shutdown and -

startup, those evolutions were considered to be unnecessary and offered increased potential for transient ;

i The valves have never failed to perform satisfactorily during the  !

surveillance There is no evidence based on plant operating history  !

that the valves would fail to perform their safety function if ,

i called upon in an actual plant transient, '

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RDS system operation for the last three months indicates an effective -

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seating of disc to seat as reflected in the RDS tailpipe temperatures l and the absence of any indicated leakage through RO !

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! On February 11 Region III management concurred with the inspector's  ;

assessment that it was not in the best interests of plant safety i for the licensee to unnecessarily perform the surveillance earlier *

l than require j i

g, Reviewing the several operational events which occurred during the inspection period, the inspector noted that the licensee's i methodology for early identification and quantification of leakage  ;

] appears adequate. Using a combination of calculations, alarms, j t chart records, and alert operators the licensee was effective in  ;

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identifying early stages of leakage on the high pressure feed

! heater, recirculation pump seal, and recirculation pump seal cooling  :

heat exchange '

No violations or deviations were identit ud in this are t j 3. Monthly Maintenance Observation

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Station maintenance activities of safety related systems and components '

i listed below were observed / reviewed to ascertain that they were conducted i in accordance with approved procedures, regulatory guides and industry codes

or standards and in conformance with technical specification l

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l The following items were considered during this review: the limiting !

l conditions for operation were met while components or systems were removed (

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from service; approvals were obtained prior to initiating the work;  !

activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior >

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l to returning components or systems to service; quality control records were j maintained; activities were accomplished by qualified personnel; parts and '

materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemente :

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Work requests were reviewed to determine status of outstanding jobs and to l assure that priority is assigned to safety related equipment maintenance which may affect system performance, i

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a. On January 6 the inspector observed the trouble shooting and maintenance activities by operators and I & C technicians to diagnose and e.orrect problems with Reactor Depressurization System (RDS) sensor cabinet Performance of surveillance T-30-26, Electrical and Diesel Fire Pump L2 Module Test, had identified a fault on cabinet D when attempting to reset the cabinet at the conclusion of the surveillance. Inoperability of one of four RDS channels requires verification af o,nerability for the three remaining channels within four hours as required by Technical Specification 3. This verification was performed and diagnostic evaluation resulted in replacement of a fire pump start module in the cabinet. Operability was verified on sensor cabinet D and its associated actuation cabinet No. 4 by performance of Surveillance T30-31, RDS cabinet test. At 1258, approximately six hours after discovery of the fault, RDS was declared fully operabl On January 19 the inspecter observed portions of maintenance to repair Reactor Depressurization System (RDS) Sensor Cabinet A and Actuation Cabinet 1. Unlike the January 6 problem, the cause of the problem was identified before removing the channel from service. With an anticipated repair time well within the four hour limit of Technical Soecification 3.1.5, no verification of the remaining three channels was performe The channel was out of service for approximately one and one-half hour b. On January 13 the inspector observed portions of maintenance pe-formed on the area radiation monitor located in the hallway adjacent to the Technic.1 Support Center (TSC). The monitor's circuitry required calibration to compensate for normal setpoint drif The inspector observed the action of health physics technicians using a radiaactive source to assist I&C technicians in monitor calibration. Appropriate control over the source was observed to minimize exposure to persons in the area, including temporary relocation of all individuals working in the TSC are c. On January 19 the inspector observed licensee response to steam leakage discovered by a health physics technician in the area of the high pressure feed heater. Steam leakage from the low pressure shell side of the feed heater was previously identified in Section 2.c of report 155/87026(DRP). Repairs in December involved the welding of a

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preformed saddle style steel patch over an area where wall thickness was reduced due to steam impingement on the inside of the feed heate The January 19 observation appeared to be a pinhole defect in weld material used to install that patch. The defect was in a highly inaccessible area and was so small as to be undetectable by dye

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penetrant or magnaflux methods. The licensee used weld overlay to build up an area approximately 4 inch square covering the area of the

observed pinhole leak. Integrity of the repairs were verified by direct observation of zero leakage during start up and power escalatio ,

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The inspector questioned the effectiveness of the remote reading temperature and humidity indicating devices installed to monitor the integrity of the December repairs. The inspector concluded that the ,

very small size of the defect resulted in steam leakage that was contained under the insulation on the heat exchanger shell, causing it to condense and drip onto the pipe tunnel floor. Unlike the December incident, steam leakage during this event was insufficient to cause dew cell alarms in the control rcom. The remote indicating devices, installed because the pipe tunnel is not a normally accessible area due to radiation levels during plant operation, will remain in place until permanent feed heater repairs are performed during the upcoming outag On January 28 the inspector reviewed ultrasonic test results from tests conducted in December on the high pressure feed heater secondary side shell. The test results confirmed the adequacy of the saddle patch in covering the areas of greatest erosion, On February 1 the inspector observed rebuild activities for the selector valve on control rod drive E-2. The insert signal valve was observed by operators to be sticking during daily rod drive surveillance testing. The activity was conducted under procedural control and with appropriate tagged component isolation. The inspector expressed concern that the mildly contaminated rod drive water leaking past an isolation valve in a small stream could contaminate the area if it were allowed to continue dripping into the lower accumulator room area. Maintenance personnel contacted health physics technicians to assess the hazard and take appropriate actio On February 10-11 the inspector observed portions of rebuilding and

, testing of the leaking recirculation pump seal cooling heat exchanger that forced the shutdown of February 7. The original heat exchanger was repaired and hydrostatically tested to 2600 psi on the tube side and 125 psi on the shell sid Early arrival of a new unit from a vendor prompted the licensee to install the new unit after verifying its integrity using the same hydrostatic testing requirement No violations or deviations were identified in this this area.

I 4. Surveillance On February 15 the inspector observed licensee corrective action following unsuccessful performance of surveillance T-180-11, Reactor Depressurization System (RDS) Electrical Penetration Seal Pressure Tast. The test verifies the integrity of the inner seal on the RDS containment penetration by monitoring the nitrogen pressure of the area between the inner and outer seal. The valve that provides access to tha nitrogen pressurized area separated at the body to bonnet joint during the surveillance. To verify the integrity of the inner seal and eliminate doubts about loss of

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containment integrity through the inner seal, the licensee expects to perform surveillance TV-27. a one-half hour leak rate test that verified

! the integrity of the inner sea At the close of the period repair of the j salve was delayed due to parts availabilit I

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5. Regional Requests During the inspection period the inspector reviewed the . licensee's response to Generic Letter 86-07, Transmittal of NUREG-1190 Regarding the San Onofre Unite 1 loss of Power and Water Hammer Event. The Sun Onofre event involved the degradation of safety related feedwater check valves to the point of inoperability during a period of less than one year without detection, and that their failure jeopardized the integrity of safety related feedwater piping. At Big Rock Point all safety related check valves are included in the Pump and Valve Program and all check valves associated with maintenance of containment integrity are leak tested. The plant in 1985 identified corrosion and erosion of internal valve parts as a result of Inservice Inspection of feedwater check valve VFW-305. Presently the licensee is disassembling VFW-305 each refueling outage until engineering analysis can provide assurances that the soft seat materials can withstand corrosive and erosive effects beyond one year of operation. The Generic Letter was reviewed to determine that no additional corrective measures for VFW-305 were appropriate and the information was incorporated into the training cycle for control room operators. The response to the Generic Letter was reviewed by the Plant Review Committee. The licensee is considered to have satisfactorily addressed the concerns of the Generic lette During the inspection period the inspector reviewed the licensee's response to Generic Letter 87-06, Periodic Verification of Leak Tight Integrity of Pressure Isolation Valves. The licensee, in their response dated May 15, 1987, referred to SE.o topic V-5, "Reactor Coolant Pressure Boundary Leakage Detection" (NUREG-0828), which emphasi:ed intersystem leakac,e detection as the approach taken at Big Rock Point for verification of isolation valve integrit The response describes how for each system containing primary plant pressure isolation valves, including core spray, liquid poison, and shutdown cooling, a method exists to verify the leak tight integrity of the isolation valve and that integrity is verified routinely by plant operators. The licensee is considered to have satisfactorily responded to the Generic Lette On January 22 the inspector reviewed the licensee's equipment data base to verify that model GE AKF-2-25 generator field breakers are not installed in any application at the facilit .

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6. Reactor Trips . On February 2 during a normal shutdown to enter maintenance period for recirculation pump seal replacement the unit tripped from less than 14 power on a Reactor Protection System Signal from upscale /downscale indication from power range instrumentation. All control rods which ,

were still withdrawn inserted fully and all systems functioned normall The unit has a history of upscale /downscale trips at very low power that result from electrical noise in nuclear instrumentation. Unlike those trips, however, the February 2 scram had as a contributing factor the action of an operator trainee down ranging the nuclear instrumentation two ranges instead of the normal one range. This inserted an upscale signal from one of three power range channel The downscale signal necessary to complete the trip signal had its origin in the electrical noise "crosstalk" between channels. Without

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the spurious downscale signal no trip would have occurred as a result of the operator error. The trainee was performing under the supervision and in the presence of several licensed operators. The SRI was present in the control room during the scram and recover On February 5 the reactor was manually scrammed following an unsuccessful attempt to synchronize the unit generator with the gri Operators using a synchroscope for verification that the grid and generator were matched phase for phase closed the generator output breaker slightly early, resulting in a current surge when the two .

electrical sources were joined slightly out of phase. Relays sensing l the generator was slightly out of phase interpreted the current surge as a circuit fault and opened the generator output breaker, t Station power is normally provided by the unit generator 13.8 KV output

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via the station p. wer transformer number on Station power normally feeds the 2400 voet station power bus from which recirculation pumps i

are supplied. Backup power for the 2400 volt bus is the 46 KV line via

a transformar. Loss of generator output resulting from the generator output breaker automatic trip caused the automatic transfer to the t 46 KV supply af ter the required three second delay. During the time delayed transfer, recirculation pumps tripped but Reactor Protection System (RPS) motor generator sets continued to supply RPS load as designed because of the inertia of their flywheel Recirculation pumps do not restart automatically on 2400 volt power restoration

because of cold water accident considerations. With the loss of both l reactor recirculation pumps the reactor was manually scrammed in accordance with Off Normal Procedure 2.27. All control rods inserted

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No violations or deviations were identified in this area.

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e Licensee Action on IE Bulletins On January 15 the inspector reviewed initial results of licensee laboratory testing of quality and non quality listed fasteners required by Bulletin 87-0 From a sample of 44 fasteners, nine failed to meet their respective specifications for hardness and/or chemical requirements. Typical of the deficiencies identified were carbon content and hardness. The deficiencies are detailed in a licensee Deviation Report that attributed the problem to normal variations in' manufacturing. The Corrective Action Review Board (CARB) concluded no corrective actions to prevent recurrence were deemed necessa r The inspector discussed with a Region III specialist the laboratory results and conclusions of the CARB to assess the safet implications of the findings and their potential immediate impact on safe facility operations. Because the deficiencies in and/or chemical properties did not deviate significantly from the standard, and because the deficiencies did not involve the physical properties of the fa, tener, such as tensile strength, that would detract from the fastener's integrity, r.: immediate actions were recommende The deficiencies will be evaluated during NRR's assessment of survey results from plants across the natio i No violations or deviations were identified in this are . Training On January 29 the inspector observed a plant wide accountability exercise intended to verify the licensee's ability to account for each individual on sit The drill was generally satisfactory in locating all personnel in approximately 15 minutes, including those working in office areas outside the protected areas. The licensee's critique identified several opportunities for minor improvement and intends to emphasiee the role of the site accountability director by centralizing

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responsibility for accountability with that individual as opposed to distributing responsibility among three assembly area directors, On February 2 the inspector observed portions of training conducted for maintenance personnel and health physics technicians involved in the recirculation pump seal replacement scheduled to commence the following day. The training was technical in nature and addressed

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seal construction and operatio Radiological pre-job briefings were conducted in a separate session February . Licensee E"ent Reports Followup Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was arcomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specifications.

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By letter dated September 29, 1987, the licensee submitted LER 87-010,

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Reactot Trip on Spurious Short Period. This RDS actuation occurred during

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a maintenance outage while testing control rod drives. The one control rod l

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withdrawn for testing successfully inserted. Power level at the time of the spurious RDS actuation was less than .0001 percent. Spurious actuations at low power levels resulting from electrical noise are a known operating characteristic of the facility. This LER is considered close By letter dated November 24, 1987, the licensee submitted LER 87003, Revision 3, Inoperable Primary System Safety Valves. The submittal provided a summary update of recent licensee repair activities and testing of primary safety valves. Primary System safety valves were observed to be sticking during tests conducted in January,1987, 'nd the Revision 3 submittal provided documentation of acceptability ( corrective action The subject testing was discussed at length in Report No. 155/87026 (DRP).

This LER revision is considered close By letter dated December 10 the licensee submitted LER 87012, Reactor Trip Caused by Failure of Intermediate Range Neutron Monitoring Channel. The 4 reactor trip occurred on November 23, 1987, and is discussed in detail in Report No. 155/87026 (DRP) All withdrawn control rods successfully inserted on an RPS actuation occurring at less than 10-6 percent power during startup from a planned maintenance outage. The cause was failure of one of two intermediate range logarithmic amplifiers, resulting in an upscale failure and short period tri This LER is considered close By letter dated December 22 the licensee LER 87013, Technical Specification Violation - Limit for control rod drive withdrawal time. The event involved the double notchir.g of control rod drives during startup November 22, 1987, resulting from effects of recirculation pumpflow on rod drive timin The ,

incident is discussed in detail in Section 2.b of inspection report 155/87026 L (DRP). This LER is considered close . Exit Interview

The inspector met with licensee representatives (denoted in Paragraph 1)

throughout the month and at the conclusion of the inspection period and summarized the scope and findings of the inspection activities. The licensee acknowledged these findings. The inspector also discussed the likely informational content of the inspection report with regard to documents or

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processes reviewed by the inspector during the inspection. The licensee did 4 not identify any such documents or processes as proprietary.

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