IR 05000219/1985023

Insp Rept 50-219/85-23 on 850701-0818.Violations Noted: Improper Closure of Containment Isolation Valve & Failure to Follow Procedures While Inerting Drywell

ML20133H402
Person / Time
Site:	Oyster Creek
Issue date:	10/07/1985
From:	Bateman W, Baunack W, Kister H, Reynolds S, Wechselberger NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20133H397	List: IR 05000219/1985023 IR 05000701/2008018 ML20133H393
References
50-219-85-23, NUDOCS 8510170153
Download: ML20133H402 (18)

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U. S. NUCLEAR REGULATORY COMMISSION  !

REGION I

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Report N /85-23 Docket N License N DPR-16 Priority Category _C Licensee: GEJ Nuclear Corporation 100 Interpace Parkway  ;

Parsippany. New Jersey 07054 l t

Facility Name: Oyster Creek Nuclear Generating Station r Inspection At: Forked River, New Jersey Inspection Conducted: July 1 - August 18. 1985

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Inspectors:

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W.'H. Batefan, Senior Resident Inspector l0/1 F te rr i

l sagn J. F. Wedihhrfberger, Resident Inspector w 'DJte (

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^ S. D. Reinoids, Lead Reactor Engineer ea-T te

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. W. H. Bauna

/5 Project Engineer Y 's

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. 6'. Kis'te4 Acting Chief, h50 ae Reactor Projects Section 1A Inspection Summaryl  ;

Routine and special onsite inspections were conducted by the resident inspectors and two region based inspectors (216 hours0.0025 days <br />0.06 hours <br />3.571429e-4 weeks <br />8.2188e-5 months <br />) of activities in  :

progress including plant operations, physical security, radiation control, housekeeping, chemistry, and hanger inspection The inspectors also followed up the events leading to two reactor trips, observed repair activities of the .

EfW piping, and routinely toured the control room and the power bloc '

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l Results:

l Two violations were ident!ffed. The first involved improper closure of a

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containment isolation valve (discussed in paragraph 1) and the second involved i

failure to follow procedures while inerting the drywell (discussed in l paragraph 2).

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O O DETAILS Licensee Event Report Review:

Licensee Event Report 85-002 which reported two inoperable containment isolation valves in a single penetration was reviewed in detai The LER identified a problem that occurred during a planned shutdown on February 2,1985, when a reactor water cleanup (RWCU) system containment isolation valve, V-16-1, was required to be unbackseated. Standing Order No. 33,

"Backwating/Unbackseating of Valves," and Station Procedure 700.2.014,

"Backseating and Unbackseating Valves V-14-36 V-14-37, and V-16-1 (Elec-trically)," provided the operators with the procedural directions. The control room operators, however, rather than using the prescribed unback-seating procedures, elected to unbackseat the valve by stationing an electrician at the motor control center supplying the valve and have him engage the closing contactor. To prevent full closure of the valve due to a seal-in closing signal, after two seconds of valve operation, the valve breaker was manually trippe This breaker trip resulted in an inadver-tent isolation of the RWCU system. A second isolation valve failed to fully close when the isolation signal was received, resulting in two inoperable containment isolation valves in the same line. The second isolation valve failed to close due to binding of the valve stem. The valve was subsequently repaired and tested, procedure 700.2.014 for unbackseating this valve was reviewed and it was determined that had this procedure been used, tne automatic containment isolation function of V-16-1 would not have been inoperable. (This is true for all backseating and unbackseating procedures.) This complies with the Technical Specification requirement that all automatic contain-

,' ment isolation valves be either operable or secured in the closed post-tion. The operators, in not following the prescribed procedure, made a containment isolation valve inoperable while in the open positio In summary, although this event was licensee identhtd and reported in accordance with 10 CFR 50.73, the inspector's review of the report noted that it did not fully address the fact that this event occurred as a result of using an incorrect method for unbackseating a valve. This is particu-larly bothersome since an approved procedure was available to perform the operation correctly. This is considered a serious matter and was not really dealt with as part of the licensee's documented corrective actio Also, it appears that the licensee's review process failed to note this condition and correct it. Since appropriate corrective action appears not to have been taken, this item has been classified as a violatio (219/85-23-01)

The LER will remain open pending review of a supplemental report which documents further corrective action regarding this matte _ _ _ _ _ .- . - . - - - - - - - . - .-_

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3 Containment Nitrogen Inertig l A special revi s was conducted of the circumstances associated with the containment inerting evolution which took place during the startup on August 4, 1985. The inspection was conducted to review licensee noncom-pliance with requirements to calibrate the drywell and torus oxygen analyzers when, during the inerting process, oxygen concentration decreases to less than 4%.

,The following material associated with the event was reviewed. Also, P additional information was obtained during discussions with licensee personne .

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Station Procedures 201.2, Plant Heatup to Hot Standby; 312, Reactor

, Containment Integrity and Atmosphere Control; 312.7, Drywell/ Torus Oxygen Analyzer Operation; 604.3.019, Drywell and Torus Oxygen Analyzer Calibration; and 107, Procedure Control

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Control Room Log (August 4 to August 6,1985)

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Group Shift Supervisor Log (August 4 to August 6, 1985)

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Oxygen Analyzer Calibration Data for calibrations performed August 4 and August 6, 1985

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Nitrogen tank level records The findings from the above review show that the facility procedures associated with inerting the containment clearly specify the actions which are required to achieve Technical Spectfication requirements. The review

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also showed that Station Procedure 312 was,not fully adhered to during the l inerting evolutio Procedural requirements which were not fully implemented were:

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A prerequisite to containment inerting, which required the oxygen analyzers to be calibrated in accordance with a surveillance procedure, was not performed until inerting was in progres The requirement to use 150" of nitrogen from the nitrogen storage tank to achieve less than 4*.' oxygen concentration was not fully accomplished in that only 139" - 144" were adde The procedural step which states, " Ignore the oxygen analyzer reading

, until stopt 4.3.19 and 4.3.23 are completed," was not adhered t ! (Steps 4.3.19 and 4.3.23 required drywell and torus oxygen analyzers be calibrated at less than 4% containment oxygen concentration.)

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The required calibration of the drywell and torus oxygen analyzers was not performed when oxygen concentrations were less than 4%.

(This was not accomplished due to depletion of a necessary calibration gas.)

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The note in the precedure which requires inerting until both the torus and drywell are less than 3% oxygen concentration was not adhered t The requirement to reduce the containment atmosphere to less than 4%

oxygen was not achieved due to reliance on analyzers which had not been calibrated as required. A subsequent oxygen analyzer calibration performed on August 6, .1985, after calibration gas was obtained, showed a .4% nonconservative error existed in the drywell oxygen analyzer readout. As a result of this error, operation was being conducted at 4% drywell oxygen concentration as opposed to the Technical Specification requirement of less than 4%.

Analysis of findings show the required prerequisite oxygen analyzer calibrations were in fact performed during inerting with no procedure change request having been prepared. No reason could be determined for adding less than 150" of nitrogen from the storage tank. At the point in the procedure where the drywell and torus oxygen analyzer calibrations were required to be performed, it was determined no calibration gas, which was needed to perform the calibration, existed on site. At this point, a number of options were available to shift personnel; these included the use of PASS for drywell and torus oxygen analyses, use of the installed accident monitoring analyzer for drywell oxygen concentration, addition of a more significant amount of nitrogen which was available, expediting acquisition of calibration gas within the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed by the Technical Specifications, or not placing the Mode Switch into RUN and thereby avoiding having to reduce the oxygen concentration to less than 4%

within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. These options were apparently not considered. Instead, believing the calibration performed during startup was sufficient, operations personnel continued plant startup. When calibration gas was eventually received, the subsequent calibration showed a .4% error in the oxygen reading. This verified that operation at 4% oxygen versus the Technical Specification required less than 4% oxygen had occurred. The failure to adhere to Station Procedures is a violation. (219/85-23-02)

The failure of shift personnel (which included two SR0s and a STA on watch) to consider the use of other methods to draw oxygen samples is a matter that should be further evaluated. The entire event could have been avoided had an available option been selected and an appropriate procedure change prepare The licensee's procedure for the procurement of the calibration gas, which is required for the oxygen analyzer calibration, was briefly discussed with licensee personnel. Calibration gas has been maintained as a " stock item" since March 1984 with a maximum of 4 bottles and a minimum of 2

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bottles specified (each bottle provides gas for approximately three calibrations). A three week delivery is normal. The amount specified was based on 1984 usage. During 1984 the plant was shutdown and calibrations were not required or performed. The date could not be determined, but I&C technicians stated the storeroom was notified when the next to the last bottle was taken from the storeroom. A purchase requisition was prepared for additional gas on June 28, 1985 and no further action was taken until a purchase order (P0) was phoned to the supplier on July 30, 198 After running out, gas was picked up at the suppliers by the licensee on August 6, 1985. Steps have been taken to increase the specified amount of gas to be maintained on sit . Operational Safety Verification 3.1 Control Room Observation Routinely throughout the inspection period, the inspector independently verified plant parameters and engineered safeguard equipment availability. The following items were observed:

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Proper Control Room manning and access control;

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' Adherence to approved procedures for ongoing activities;

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Shift turnove duringareviewofcontrolroommanningrequirements,itwas identified that there is a conflict between the Regulations and the Technical Specification and Station Procedure 106, " Conduct of Operations," regarding the number of Senior Reactor Operators (SR0s) required per shift. Specifically, paragraph 50.54 of 10 CFR 50 requires two SR0s per shift,'whereas the Technical Specifications i and Station Procedure 106 require one SRO per shift. The licensee responded to this concsrn by stating they do require two SR0s per shift and will change the Technical Specifications and Procedure 106 to be consistent with the Regulations. Routine NRC inspections have confirmed two SR0s per shift staffing. The inconsistency between the Regulations and the Technical Specifications and Procedure 106 is an unresolved item pending revisions to the Technical Specifications and Procedure 106 to reflect the requirements of the Regulation (219/85-23-03)

3.2 Review of Logs and Operating Records The inspector reviewed, on a sampling basis, the following logs and instructions for the period July 1 to August 18, 1985:

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Control Room and Group Shift Supervisor's Logs;

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Control Room and Shift Supervisor's Turnover Check Lists;

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Reactor and Turbine Building Tour Sheets;

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Equipment Control Logs;

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Standing Orders; and

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Operational Memos and Directive The logs and instructions were reviewed to:

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Obtain information on plant problems and operations;

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Detect changes and trends in performance;

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Detect possible conflicts with Technical Specifications or regulatory requirements;

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Assess the effectiveness of the communications provided by the logs and instructions; and

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Determine that the reporting requirements of Technical Specifications are me The reviews indicated the logs and operating records were generally complete. No inspector concerns were identifie . Observation of Physical Security During daily entry and egress from the protected area, the inspectors verified that access controls were in accordance with the security plan and that security posts were properly manned. During facility tours, the inspectors verified that protected area gates were locked or guarded and that isolation zones were free of obstructions. The inspectors examined vital area access points to verify that they were properly locked or guarded and that access control was in accordance with the security pla A moderate loss of physical security was reported by the licensee. It involved loss of power to the security computer for approximately two hours during an early morning thunder and lightening storm. During the time the computer was disabled, vital area access was adequately controlled, however, all elements of the Security Plan were not implemented as regards a small portion of the protected area adjacent to the main security building. The actions taken to compensate for this section of the protected area did, however, offer reasonable assurance that the area was not trespassed. A subsequent search of the plant confirmed no unauthorized entries were made during the period of time the computer was disabled.

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i Plant Tours i

During the inspection period, the inspectors made frequent tours of plant areas to make an independent assessment of equipment conditions, safety,

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Turbine Building

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Reactor Building The following items were observed or verifie .1 Fire Protection

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Randomly selected fire extinguishers were accessible and inspected on schedule.

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Fire doors were unobstructed and in their proper positio Ignition sources and combustible materials were controlled in

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accordance with the licensee's approved procedures.

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Appropriate fire watches or fire patrols were stationed when

equipment was out of service.

5.2 Equipment Controls

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Specification requirements.

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Conditions requiring the use of jumpers received prompt licensee attention.

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Administrative controls for'the use of jumpers and equipment mark-ups were properly implemente .3 ' Vital Instrumentation

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Selected instruments appeared functional and demonstrated

' parameters within Technical Specification Limiting Conditions for Operation.

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5.4 Radioactive Waste System Controls

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Gaseous releases were monitored and recorde i

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No unexpected gaseous releases occurre '

5.5 Housekeeping

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Plant housekeeping and cleanliness were in accordance with

approved licensee programs.

! Radiation Protection During entry to and exit from the radiologically controlled area (RCA),

the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive contamination, and monitoring 1 instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that ,

they were current and accurate. The inspector observed activities in the RCA to verify that personnel complied with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the are During this report period, ten individuals were slightly contaminated in the New Radwaste (NRW) Building when a damper in the building's HVAC system that isolates the building's HVAC-system from the main plant discharge stack inadvertently opened while undergoing repairs. When the damper opened, backflow from the plant stack into the NRW Building resulted in airborne contamination that contaminated the ten individual All individuals were decontaminated and whole body counted. No problems were identified.

4 Return of Spent Fuel From West Valley During this report period, the last shipments of spent fuel were received onsite from West Valley, New Yor The resident and region based inspectors observed final spent fuel receipt at Oyster Creek and the i handling and unloading of spent fuel from the TN-9 spent fuel shipping cask. Radiation Control personnel were observed to be knowledgeable and in control of radcon related activities. Once reaching the refueling

. floor, the TN-9 casks were moved and unloaded and spent fuel stored in the

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spent fuel pool in accordance with controlling procedures. The overall spent fuel shipping effort was conducted without a major inciden . Pipe Hanger Inspections During this report period, pipe and pipe support inspections continue Also, efforts were initiated to repair deficiencies that were determined by Technical Functions not to be acceptable as is. The overall scope of f

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the inspection continued to increase and stood at 504 at the end of this report period, 454 of which were inspected. Some of the more significant problems identified during this report period were with supports on the Core Spray System II full flow test line. The most significant of these problems involved a cracked pipe clamp and cracked attachment welds used to attach the pipe clamp to the pipe associated with snubber 411R1 Other supports en the test line also had deficiencies, although not as serious. Engineering evaluation of the problems determined the damage to have resulted from water hammer in the piping prior to incorporation of a

" keep full" system installed nearly five years ago. The " keep full" system eliminated the water hammer, but the damage to the supports was not

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identified until this inspection. Prompt repairs were made to affecte *

support . ContainmentSprayEmergencyServiceWaterSystem(CSESWSJ

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I During routine surveillance testing of the ESW pumps, problems involving differential pressure (DP) changes across the ESW side of the 1-3 Containment Spray heat exchanger (HX) were identified. Additionally, ESW

pump 52 C' was determined to have a loose impellor. As part of the investigation of the DP changes in 1-3 HX, the HX head was removed and an j inspection of the ESW side of the HX was performed. This inspection 4 revealed a meterial suspected to be "bitumastic" or a coal tar enamel coating applied to the inside of the ESW system piping for corrosion

! protection. A sample was sent out for analysis to confirm suspicion Meanwhile, additional flushing of ESW System II (2 pumps and 2

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heatexchangers are contained in ESW System I and ESW System II) was resumed. While this flushing was in progress, a routine surveillance of

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System I indicated inadequate pump performance thus requiring a plant shutdown as System II was still considered inoperable because of the 52 C' pump. At this point discussions ensued between licensee and NRC management as to whether or not at least one train of the ESW system could be considered operable. The licensee suggested that if they could verify, by use of other than normally used instrumentation, that the ESW pumps l were putting out equal to or greater than minimum flow, then ESW System I '

or II could be considered operable. The NRC' suggested that the operability of both loops was in question based on the presence of the coal tar enamel in the 1-3 HX and increasing DP's in the other HX's indicating a possible generic problem. The NRC and the licensee reached an agreement that if adequate flow could be demonstrated in ESW System I and a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run completed without encountering further problems, then

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System I could be considered operable. However, System II would not be considered operable until resolution of the problem of the foreign material blocking flow to the HX's and, thereby affecting the ability of the HX's to perform their design function. Less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the run of System I, the DP across the HX's increased to the allowable limit.

_ At this point, the licensee declared the ESW system inoperable, shut the t

plant down, and commenced a major effort to resolve the problem.

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) Resident and region based inspectors reviewed the licensee's activities in investigating the cause of the loss of bonding of the internal coating on the ESW piping. The pipe lines affected were the redundant System I and System II Emergency Service Water Inlets to Containment Spray Heat 4 Exchangers 1-1, 1-2, 1-3, and.1-4. These lines appear on special GPUN isometric sketches SK-1, SK-2, and SK-3 which reference the original

! construction piping drawings. System I connects ESW pumps #1 and #2 to a common line which supplies CSHX 1-1 and 1-2. System II connects ESW pumps

1. 3 and #4 to a common line which supplies CSHX 1-3 and 1-4. The piping from the pump to the common line is 10" in diameter and the common line pipe itself is 14". At approximately 102. feet from the pumps on System I and 73 feet from the pumps on System II the cooling water is chlorinate '

The total pipe length from pump to HX is approximately 780 feet in System I and approximately 40 feet less than this for System II (estimated by inspector). Investigation of the pipe by the licensee (utilizing a TV '

optics system) of roughly 215 feet of System I and 280 feet of System II, showed the coating problem to be limited to that portion of pipe between the pumps' discharge and the point of chlorinatio The ESW piping system from the pumps to the CSHX consists of flanged pipe

and elbows of carbon steel which were purchased as spool pieces then sent to a coating application vendor. The licensee indicated they have not been able to retrieve the purchasing information indicating the pipe procurement and coating, however, licensee specifications called for the coatings to meet American Water Works Association (AWWA) C 203-73 Type II internal pipe coating system requirements. This coating system consists l

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of cleaning and blasting the pipe ID followed by application of a cold primer coat of a coal tar pitch cut with a coal tar oil to a liquid consistency which can be applied by brush or spray. Upon completion of the primer coat, a hot coal tar enamel (pitch) containing inert mineral fillers is cast in the pipe and a " pig" is drawn through the pipe to

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produce a thick pliable coating in the order of 1/8-1/4" thick on the pipe wall. The hot coal tar pitch coating is similar to a hot pitch roof, however, the roof pitch does not contain the mineral fillers. The coating 1 does not extend around the radius of the flange attachment to the flange face, but is given a guillotine cut in the same plane as the flange face to produce an abutting (square butt) joint with adjacent spool piece The coating continuity is, therefore, a function of the tightness of the

, square butt joint. Disassembly of the spool pieces near the pumps

! indicated that the worst area of coating de-bonding was in the first few spool piece The piping system immediately adjacent to the pumps consists of a short

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horizontal straight pump extension piece (A), elbow (B), flow restrictor (C), horizontal straight spool piece (D), elbow (E), vertical straight spool piece (F), elbow (G), and a tee to the 14" common flow lin Disassembly of the spool pieces near the pump indicated the worst de-bonding of the coating was in the four horizontal straight spool pieces

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(D). These pieces and two elbows (E) were removed and replaced. One of

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these was cut up for evaluation by GPUN Reading Material Engineering Laboratory and one left intact for visual examination. The inspector

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visually inspected one section from the cut-up elbow and also inspected

the other intact elbow. Marine life (barnacles, etc.) was attached to the

! coating. The coating thickness varied from approximately 1/8 to 1/4 " or

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greater. There were " mud cracks" on the surface, but these cracks didn't i

! appear to go through the coating. On the elbow which was intact, the

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coating was not present on portions of the elbow adjacent to the flange face at the exposed edge (abutting edge area). On the elbow which was '

I sectioned, the coating attachment was good except for the apex of the

" pie" cut section (introdos of elbow) where the cutting may have

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l mechanically loosened the coating (even though efforts were made to keep i the saw cut cold).

Discussions with a representative of the GPUN Materials Engineering  !

1 Laboratory indicated the following results of examination of the sectioned ,

j elbow:

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" Mud cracking" pattern observed on surface -

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Undercutting at exposed coating edges observed (substrate corrosion i causing loosening of coating).

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j The laboratory had technical discussions with three people (representing i field, laboratory, and technical area) of the Koppers Company on service

experience problems with AWA C203 coal tar enamel Koppers indicated that if the-coating is permitted to dry out and concurrently subjected to ambient thermal cycles, it will produce " mud cracks." They also indicated f that if the coating is dry and subject to. low temperatures in the order of

! O F, it will crack. A portion of the sectioned elbow was sent to Koppers  ;

j for their analysis. The inspector requested copies of the GPUN Material

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j Laboratory Report and the Koppers Co. report when available. The portion

} of pipe with the worst coating de-bonding was the horizontal run above the i concrete mat which could have seen either of the two conditions described i above. In addition this portion of the pipe line had severe barnacle

! attachment and is subject to mechanical loading forces due to pump j starting and pump shut of ! The licensee hydrolased the coating off the pipe in System I for  !

i approximately 60 feet from the pump and 75 feet from the pump (toward the

chlorination point) in System II. Subsequent flushing was performed to i- ensure removal of loose material.

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The inspector reviewed the following documents:

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AWA C203-73 " Coal Tar Protective Coatings and Linings for Steel Water Pipelines - Enamel and Tape - Hot Applied" (specified by the j A . E ._ )

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GPU Nuclear OCNGSP No. 607.4.001 Rev. IB (DP acceptance criteria -

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GPU Nuclear 0CNGSP No. 607.4.003 Rev. 7 (requires check of CSHX tube side pressures at various HX stages - Data Sheet 6.9)

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LER 50-219/82-64/032 (HX DP problem caused by marine fouling)

I Discussions with the licensee indicated the following additional information on subject piping system:

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In the area where there was coating de-bonding, the insulation had been removed from the pipe for a long period of tim The nominal cooling water conditions during operation are 4000 GPM flow at ambient temperature with a pressure of 65 psig at the H There has been no previous history of coating de-bonding. LER 064 in

1982 concerning marine biofouling was solved by chlorination.

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Frequent periodic examination and cleaning of the water boxes on the reactor building closed cooling water HXs required by biofouling l problems has indicated the coal tar enamel coating in the plant

, Service Water system is intact. (The lined piping used in this

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system is similar to that used in the ESW System.)

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GPUN Engineering estimates a corrosion rate of 14 - 15 mils per year (including pitting reactions) on the bare carbon steel pipin TV optics examination of other portions of ESW system I and II where ,

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coating was not removed from the pump to the chlorination point,

indicates coating to be intact with no significant surface defect The nominal pipe wall thickness is 1/2" with a minimum design wall (including 0.088" corrosion allowance) of 0.150".

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Monthly ESW pump operability tests to 607.4.001 and 607.4.003 will provide sufficient information on any tube blockage by DP reading The Perfex four pass Containment Spray HXs were originally tubed with aluminum brass which had reasonable service, then retubed with 90-10 CU-NI, which failed in a relatively short time apparently due to wet

layup (static) pitting beneath surface films, and finally retubed with unalloyed titanium tubes. The current tubes have great

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resistance to partially blocked tube erosion problems. The water 1 boxes and tube sheets are CU-NI, but there is no evidence of galvanic

attack of the tube sheet.

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No final engineering decision has been made by the licensee on the long term plans regarding the uncoated ESW piping. Base line UT

! readings have been taken for monitoring purposes in the event it is

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later determined that monitoring is necessary. The next refueling outage is April 1986. The pipe line will.be run with no coating in

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the pipe upstream of the chlorination point at least until April 1986. Replacement or recoating of the piping is being considere Estimated corrosion rates, if correct, would give long term (multiple refueling cycle) satisfactory service with bare pip The exact initiating mechanism of the coating de-bonding is not known. The final reports from the GPUN Reading Lab and Koppers will be supplied to the NRC when availabl No special surveillance requirements of the pipe corrosion rates (and coating in the remainder of the pipe) are contemplated at this tim The NRC considers the issues discussed above as unresolved pending the licensee providing the following information for NRC review:

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Koppers Company failure analysis repor GPUN R(ading Materials Laborato y failure analysis repor Final engineering decision and the long term solution to the coating de-bonding proble Engineering justification for changes in pump operability tests which will increase DP limits and possibly change testing time to ensure sufficient transport time for loose coating to collect on HX tube sheets. (219/85-23-04)

No violations were identifie . Followup of Operational Events 10.1 In NRC Inspection Report 85-19, a problem concerning drywell bulk temperature was discussed. During this report period, the calculation to arrive at drywell bulk temperature was revised to factor in the gas contained in the large spherical volume at the bottom of the drywell. This dropped the calculated bulk temperature by several degrees from that value arrived at by the orevious calculatio As regards the concern of the deviation between the FSAR and plant procedures as to the assumed drywell bulk temperature at the start of a design basis accident and the failure of the licensee to notify NRC licensing of this change, the licensee submitted LER 85-017. This LER described the problem and stated their plans for corrective action. The corrective action stated in the LER addresses the NRC concerns regarding this issue, therefore, final resolution will be tracked as part of closeout of LER 85-017.

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10.2 A scram from full power operation due to low condenser vacuum occurred on July 8, 1985. The inspectors responded immediately and particulary noted that no problems with the scram discharge volume drain valves recurred. The scram resulted when the steam jet air ejector drain pumps malfunctioned and ultimately affected the steam jet air ejectors (SJAEs). With erratic SJAE operation, condenser vacuum dropped to the setpoint of the low condenser vacuum scra Plant response and recovery was considered normal. However, operator action to restore reactor vessel water level resulted in a high level condition which has been a problem in previous recoveries from various events. The licensee intends to address this issue in future training activitie .3 In NRC Inspection Report 85-19, the MSIV closure scram from full power was discussed. In this discussion, some abnormal and normal equipment responses that raised concerns were presented. These included two series scram discharge volume drain valves leaking, inability to reset the scram until reactor pressure decreased to less than 600 psig, and potentially inoperable safety-related equipment due to initiation of a plant deluge system. Further discussion of these concerns follows:

10. The licensee conducted an investigation into the cause of the leaky scram discharge volume (SDV) drain valves. The investigation disclosed that, on one of the valves (V-15-121), the stroke was improperly adjusted such that the valve did not fully close and, on the other valve (V-15-134), the closing springs were undersized thus failing to hold the valve closed against reactor coolant system pressure. The stroke on V-15-121 was properly adjusted and the proper size closing springs were installed

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in V-15-134. A licensee self-critique of the undersized sorings identified a multitude of problems and situations tnat contributed to the installation of V-15-134 during the ,

last outage. Action has been taken to address the '

identified concerns. A concern remaining, however, that did not appear to be addressed was that V-15-134 was installed such that reactor pressure tended to open the valve rather than to help seat it. A second concern was raised in NRC Inspection Report 84-09. In particular, Unresolved Item 219/84-09-08 questioned why the SDV vent

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and drain valves were not included as part of the containment pressure boundary and, therefore, tested in accordance with the requirements of 10 CFR 50 Appendix These two concerns are unresolved pending licensee justification for the installed position of V-15-134 (219/85-23-05) and a response to address why the SDV vent and drain valves are not considered containment isolation valves and, therefore, tested in accordance with the

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requirements of 10 CFR 50 Appendix (219/85-23-06)

(Note: Urresolved Item 219/84-09-08 is closed as it will now be tracked as Unresolved Item 219/85-23-06.)

10. Another concern raised as result of the MSIV closure scram on June 12, 1985 was the inability to reset the scram until the reactor was depressurized to 600 psig. This became significant as a result of the failure of the Scram Discharge Volume drain valves to seat properl A Technical Specification amendment changed the MSIV closure and low condenser vacuum scram bypass from 600 psig to 800 psia. The actual plant setpoint, however, remains at 600 psig as a result of some concerns the licensee developed as a result of the Intermediate Range Monitoring (IRM) nuclear instrumentation system Range 10 modificatio The particular concern involved a reactivity addition accident (excessive feedwater addition; idle recirculation loop startup) and subsequent power excursion event from IRM range 9. The hypothesized event would have the operator erroneously responding to resulting power excursion by upranging from IRM range 9 to 10. This would replace the IRM range 9 scram setpoint of 12% with the IRM range 10 scram setpoint of 38.4%. If the resultant reactor scram occurred due to the 38.4% trip point, the 25% safety limit associated with the GEXL correlation would be violate The 25% safety limit associated with GEXL correlation is provided to limit core power when reactor pressure is less than 800 psia and core flow is less than 10*. to protect the fuel cladding integrity safety limit. This event theorizes that the neutronic trip of 38.4". would be reached prior to the MSIV closure and low condenser vacuum scram being unbypassed as pressure increases to the bypass setpoin Based on this and similar hypothesized accident scenarios, the licensee elected to leave the MSIV closure and low condenser vacuum scram bypass setpoint at 600 psig instead of increasing the setpoint to the amended 800 psia poin This provides additional margin, possibly to insure the 25%

core thermal power limit is not exceeded. The licensee is contemplating hardware and software modification (s) to eliminate the reliance on the 600 psig setpoint for core

, protection. The inspector will review the licensee's analysis to support these modifications and the Technical Specification basis change to 800 psia in a future inspection report. (219/85-23-07)

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10. An Unusual Event was declared when a fire protection

deluge system initiated and wetted down safety-related equipment thereby rendering operability status questionable. The fire protection system performed as

, designed but did have a potential impact on the operability i

of safety-related equipment. This conflict in safety i

! system objectives, that apparently was only partially 1 addressed when spray shields were installed, is unresolved

! pending licensee corrective action to address the conflic i

(219/85-23-08)

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11. 480 Volt Unit Substation Transformers-Low 011 Level i

The licensee shutdown the plant to perform an oil filling operation on vital transformers 1A2 and 182 on August 9, 1985. The shutdown resulted when the licensee determined, using a thermographic process, that the

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vital transformers might not be able to perform their design functio Using a thermographic photography process, the oil (ASKAREL) in the IA2 1 and 182 transformers was determined to be low and not flowing in some of j the cooling fins. This situation could be significant during a LOCA

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coupled with a single-failure of one of the transformers. A single

transformer failure would result in both transformer LOCA loads being

! supplied through one vital transformer. (LER 85-009 provides further discussion of this area.) Under these conditions the vital transformer may not be able to perform its design function with a degraded cooling capabilit .

] The licensee's investigation into the low level concern determined that '

approximately five quarts of oil samples could have been taken since the i

i transformer installation. It could not be determined if any routine

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sampling of these transformers was conducted or spectfied on any l preventative maintenance schedule. As a result of the filling operation

and load / cooling tests performed on the vital transformers, the licensee ,

determined that the oil level in the transformer cooling header was not sufficient to fill all the cooling fins protruding into the header During the filling operation the licensee established a new oil level i approximately l" higher than the specified nameplate data required. This

i was done to insure all the cooling fins would be filled with oil and thus restore full cooling capability to the transformers. The 1A2 and 182

transformers required 16 and 12 gallons, respectively, to establish this

new oil level. The IA2 transformer may have required more oil to

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establish the new level as a result of the transformer being slightly out

' of level. The licensee calculated the cold (25 C) as found oil level to be slightly less than specified by the nameplate data. A General Electric representative was present during the filling operation. Upon completion of the filling operation, the licensee verified that all cooling fins had proper oil flow using thermographic photography, i

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Some problems with instrumentation were discovered during the licensee's investigation. The liquid temperature indicator did not give an accurate reading of the oil temperature. The temperature indicator is installed in a cooling fin and to display an accurate liquid temperature reading its sensor must be submerged in the transformer oil. This particular cooling fin was one of the cooling fins that did not receive any oil flow as a result of the low oil level. During licensee testing of the vital transformer, a portable pyrometer was used to measure the oil temperatur Once oil flow in the cooling fin with the installed temperature device was established, the pyrometer and installed temperature sensor compared favorably. Another instrument problem was the liquid-level gage. The accuracy of the level gage required to sense small level changes in the transformer cooling headers is critical. The present level gage may not have the required accuracy to indicate these small level changes in the cooling header to the extent that an operator could determine the onset of cooling degradatio The licensee's immediate corrective action was to shut down and fill the transformers to the newly established oil level which is higher than the manufacturer's (GE) recommended level stated on the transformer The long term corrective action has not been finalized. A number of action items are being considered including:

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A thermographic testing program

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Transformer replacement

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Issue filling and sampling procedures and requirements

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Instrumentation upgrading In addition the licensee is planning to request General Electric to review the vital transformer cooling problem. The cooling capability of the vital transformers in regard to the oil level in the transformers has the potential to be a generic issue. This will remain an Inspector Followup Item pending final resolution of long term corrective action and analysi (219/85-23-09)

12. Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss the inspection scope and findings. A summary of findings was presented to the licensee at the end of this inspection. The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was included.