IR 05000219/1993011

Insp Rept 50-219/93-11 on 930629-0809.No Violations Noted. Major Areas Inspected:Day Shift & Back Shift Hours of Station Activities

ML20149D510
Person / Time
Site:	Oyster Creek
Issue date:	09/10/1993
From:	Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20149D494	List: IR 05000219/1993011 ML20149D490 ML20149D502
References
50-219-93-11, NUDOCS 9309210055
Download: ML20149D510 (23)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N i Docket N ;

License N DPR-16 )

Licensee: GPU Nuclear Corporation i

i Upper Pond Road Parsippany, New Jersey 07054 Facility Name: Oyster Creek Nuclear Generating Station

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Inspection Period: June 29,1993 - August 9,1993 ,

Inspectors: Steve Pindale, Resident Inspector

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Joe Schoppy, Resident Inspector, Salem / Hope Creek Dave Vito, Senior Resident Inspector Approved By: w W 76 I

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/6hriF. Rogge, Section Chieff_/ ' date ;

vReactor Projects Section 4B, DRP l Inspection Summary: This inspection report documents the safety inspections conducted ;

during day shift and backshift hours of station activities including: plant operations; maintenance and surveillance; engineering and technical support; and plant support. The Executive Summary delineates the inspection findings and conclusion .

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EXECUTIVE SUMMARY l Oyster Creek Nuclear Generating Station Report No. 93-11 e Plant Operations ,

The licensee operated the plant in a safe manner. The operations department effectively ,

planned and executed several activities in an attempt to minimize the potential adverse impact on overall plant operation due to elevated outside temperatures. Conversely, operations failed to implement corrective actions in response to previously specified concerns related to elevated temperatures in the 480 V and 4 kV vital switchgear rooms. This is a violation of NRC requirements. A detailed walkdown of the standby liquid control system found the

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system to be installed, aligned, and functioning as designed. Operators responded promptly and appropriately to an unexpected increase in reactor recirculation flo j Maintenance / Surveillance

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i The licensee appropriately implemented the safety objectives of the maintenance and  :

surveillance programs. Operability and inservice testing of the pumps and valves of _

containment spray / emergency service water systems 1 and 2 was completed satisfactorily and l was effectively coordinated by control room personne :

Engineering and Technical Suncort System engineering appropriately monitored the performance of the control rod drive systein 3 and identified degraded performance of one of the system pumps. However, the inspectors ,

identified the lack of formal guidance for control of troubwshooting conducted by system '

engineering or operations personnel. Licensee prioritization and evaluation for a finding developed by a licensee-initiated system functional evaluation was determined to be weak and untimely, and is an unresolved item. Engineering followup for a licensee identified design basis concern (reactor building peak pressure following a high energy line break) is continuing; the evaluations completed thus far were conducted appropriately and ,

conservativel Plant Support The management observation tour program was noted by the inspectors to be more ,

aggressive than in the past but still in need of improvement. The licensee has established  :

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adequate precautions to respond to abnormally high wind conditions at the Oyster Creek sit !

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TABLE OF CONTENTS  ;

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EX EC UTI VE S U M M A RY _ . . . . . . . . . . . . . . . . . . . . . . . ..............ii l

! OPERATIONS (71707, 71710, 93702, 40500) ..................... I Operations Summary . . . . . . . . . ....................... 1 l Inspection Activities . . . ............................. I  ! Potential Impact on Plant Operation Due to High Ambient Temperature . . 1 i Standby Liquid Control System Walkdown . . . . . . . . . . . . . . . . . . . . 2  : Unexpected Reactor Recirculation Flow Increase . . . . . . . . . . . . . . . . 3  ! Fire Drill ........................................ 3 l MAINTENANCE / SURVEILLANCE (62703, 61726) . . . . . . . . . . . . . . . . . . 4 , Maintenance Observation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 i Containment Spray / Emergency Service Water System Surveillance . . . . . 5 l, ENGINEERING AND TECHNICAL SUPPORT (71707,40500,37828) . . . . . . 6  ! Control Rod Drive Pump Performance Evaluation and Troubleshooting .. 6 l Engineering Review of Potcntial Safety Concerns IdentiDed During  ;

Licensee-Initiated System Evaluations (Unresolved Item  !

50-219/93-11-01) ................................... 7 , PLANT SUPPORT (71707, 92700, 92701) . . . . . . . . ............... 9 Radiological Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Security . . . . . . .................................. 9 ) Management Observation Teams .. . . . . . . . . . . . . . . . . . . . . . . . . .. 9 i Emergency Preparedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 l 4.4.1 Hurricane Readiness . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 In Office Review of Licensee Event Reports (LER) ............. 13 Review of Previously Opened Items (VIO 50-219/93-11-02) . . . . . . . . 14 EXIT MEETINGS (40500, 71707, 30702) ....................... 19 Preliminary inspection Findings ......................... 19 Attendance at Management Meetings ...................... 19 ATTACHMENT 1 - Core Spray System Minimum Flow Solenoid Valve Equipment

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ClassiGcation and Repair Chronology l

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DETAILS 1 O PERATIONS (71707, 71710, 93702, 40500) ,

l Operations Summary ]

Oyster Creek was operated at full power daring the entire inspection period, with the exception of several minor power reductions to maintain the main condenser circulating water system discharge maximum temperature below prescribed environmental limit .2 Inspection Activities The inspectors observed plant activities, interviewed station personnel, and conducted routine plant tours to assess equipment conditions, personnel safety hazards, procedural adherence and compliance with regulatory requirements. The inspectors independently verified the  ;

status of safety systems and compliance with Technical Specifications. Tours were conducted of the following areas:

• control room * intake area l e cable spreading room o reactor building

• diesel generator building * turbine building  ;

• new radwaste building * vital switchgear rooms J

• old radwaste building * access control points I

• transformer yard Control room activities were found to be well controlled and conducted in a professional l manner. The inspectors verified operator knowledge of ongoing plant activities, equipment i status, and existing fire watche i l Potential Impact on Plant Operation Due to IIigh Ambient Temperature  !

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During the week of July 5,1993, the outside ambient temperatures were expected to be  !

consistently in excess of 100 F. The forecasted high temperatures represented the potential !

for various operational challenges to the plant. Station personnel evaluated the condition of !

potentially affected plant equipment in an attempt to minimize any negative impact on plant l

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operatio The drywell cooling system consists of five recirculation fans, each of which is provided with a cooling unit. The reactor building closed cooling water (RBCCW) system cools the air that is circuhted in the drywell via the five fans. The RBCCW heat exchangers are, in turn, cooled by the service water (SW) system. Periodic cleaning of the heat exchangers is required to remove debris (sludge) and mussels on the SW side of the heat exchangers to

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ensure effective heat transfer. The two RBCCW heat exchanger tube sheets were cleaned ,

prior to reaching the extreme high temperatures, and periodically thereafter, in order to I maintain adequate drywell cooling. As a result of these actions, drywell temperature was satisfactorily maintained between approximately 140 F and 145 F while operating four of the ;

five drywell recirculation fan During the time when the ambient temperature was high, plant operators performed several load reductions to prevent New Jersey Pollutant Discharge Elimination System (NJPDES) !

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Permit violations. The permit limits the main condenser circulating water discharge temperature to a maximum of 106*F (while all four circu!ating water pumps are operating).

The operators attempted to maintain the discharge temperature less than 105.5 F. The load reductions were generally effective in maintaining the circulating water discharge temperature r within the prescribed limits. However, on two occasions, the 106 F limit was slightly exceeded (July 7; 106.3 F, and July 11; 106.1 F). On each occasion, the licensee properly ,

reported the NJPDES Permit violation to the state of New Jersey and the NR .

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Also during this period, the licensee frequently conducted main condenser backwash activities to control marine growth on the main condenser tubes, in order to prevent fouling and to maximize cooling. Backwashing involves directing water from the discharge of one condenser section (tube side) through the associated condenser section tubes via a cross :

connect valv The inspector monitored the licensce's activities associated with the RBCCW heat exchanger tube sheet cleaning, SW and drywell cooling system performance monitoring, and main i condenser and overall plant operations. The inspector concluded that the activities related to minimizing the potential adverse impact on overall plant operation were well planned and execute .4 Standby Liquid Control System Walkdown The inspector conducted a detailed review of the standby liquid control (SLC) system. The review included a system walkdown and lineup verification, a comparison of system alignment with the SLC operating procedure system lineup, a review of completed i surveillance tests, and a review of the FSAR commitments and Technical Specification (TS)

requirements. The intent of the detailed walkdown was to independently verify the status and operability of the SLC syste The inspector found that the valves in the SLC system were properly aligned for standby readiness. Likewise, the inspector verified that the electrical power supplies for the system components were properly aligned. During the walkdown, the inspector also verified that the electrical heat trace for the sy;.em piping and the SLC tank heater circuits were energized, and that the associated SLC system components and tank contents were being maintained at i the appropriate temperatures ,

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TS 3.2.C lists the required Boron-10 isotopic enrichment for the SLC solution, and specifies i the sodium pentaborate solution temperature and volume-concentration relationship l requirements. The inspector verified compliance with these requirements. TS 4. j specifies the surveillance requirements for the SLC system. The inspector reviewed selected :

surveillances and verified compliance with the associated specification The inspector determined that the SLC system was installed per the appropriate design and

installation specifications. Housekeeping in areas surrounding the SLC equipment was goo The overall material condition of the SLC system was also good. Based on the results of this ,

detailed system review, the inspector concluded that the SLC system could satisfactorily 3 perform its intended functio .5 Unexpected Reactor Recirculation Flow Increase

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On July 23,1993, while operating at 100% power (1929.1 MWt), the "C" reactor *

recirculation pump speed increased unexpectedly (without operator action) at 3:48 a.m.,

resulting in a corresponding reactor power increase. Control room operators responded immediately to an average power range monitoring system high alarm, and manually reduced total recirculation flow using the master recirculation flow controller. The operators '

followed Abnormal Operating Procedure 2000-ABN-3200.03, " Recirculation Flow '

Abnormality." During the transient, the operators noticed that the "C" recirculation indicated flow was " pegged high," and then placed the "C" recirculation pump speed ,

controller to manual, which successfully reduced flow in that reactor coolant loop. The safety parameter display system recorded a maximum core thermal power of 1963.8 MWt (about 101.8% of rated power) during the transient. There were no activities in progress at the time of the transient having the known potential to affect the "C" recirculation pump speed controlle .

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Later in the day, the licensee instrumented the "C" loop controller with a recorder so that a possible cause of the transient could be identified, isolated and repaired. The "C" i recirculation pump speed controller was subsequently placed in automatic. The licensee monitored three controller signals throughout the weekend; similar transients did not occur and no spikes were recorded. However, on July 26,1993, the inspector noted that the installed recorder had run out of paper, thereby preventing data collection in the event that a spike were to occur. The licensee subsequently removed the recorder. The "C" controller remained in automatic through the end of the inspection period and no additional operational problems were experience ;

The inspector reviewed the station's response to the transient and concluded that the operator response was timely and in accordance with station procedures. The inspector also interviewed the system engineer, who postulated that particulate debris from the control air system may have momentarily clogged the controller pilot valve, resulting in the "C" recirculation pump going to full speed. The licensee plans to inspect the associated speed controller during a power reduction planned for August 21,1993, in an attempt to identify a

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cause for the transient. The inspector concluded that the time during which the selected f

controller signals were recorded appeared to be short, and that such a short duration may have possibly resulted in failure to obtain useful information to determine the root cause of :

the event. The inspector will continue to review the licensce's actions and system performance during a subsequent inspectio !

! Fire Drill j On July 14, 1993, the inspectors observed a Gre drill. The drill consisted of a simulated electrical fire in the A-B battery room. The ignition source was unknown to the fire brigad ;

i The Orc brigade response was timely and appropriate. Members were correctly dressed, and i

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demonstrated proper use of self-contained breathing apparatus (SCBA). The fire brigade leader quickly assessed the fire situation and effectively managed the brigade respons ,

Three other quali0cd fire brigade members, in addition to the assigned five member brigade, !

initially responded to the fire scene. These initial responders were permitted by the drill !

observers to simulate activation of the battery room halon system and to report that simulated action to the control room. At Oyster Creek, qualified fire brigade personnel who are not specifically assigned to the Dre brigade for a given shift are encouraged to respond to the fire ;

scene to support the assigned Dre brigade. The inspectors did not object to this practice but l questioned the fire brigade training staff as to how the training and drill programs (

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accommodated evaluation of Gre brigade performance at the minimum (5 person) staffing level. The lead Grc protection instructor noted that practical training sessions are always conducted at the minimum fire brigade staffing level. The instructor also noted that a large _ ;

percentage of the off-hours drills involve only the assigned fire brigade complement due to limited overall onsite staffing at those times. The inspectors observed the post-drill critique with the drill participants and reviewed the subsequent drill report. The critique was appropriate and comments from the drill participants were encourage ' MAINTENANCE / SURVEILLANCE (62703,61726)

! Maintenance Observation l On July 28,1993, the inspector observed portions of a maintenance activity related to !

replacing the solenoid valves for the core spray system 11 minimum flow recirculation valve l The licensee properly implemented the applicable Technical Specification Limiting Condition :

for Operation. The inspector veriGed that the licensee conducted the activity in accordance l with approved procedures and drawings. The inspector concluded that the maintenance activity was conducted effectively. See Section 3.2 of this report for a discussion regarding l

the engineering basis and historical background for these solenoid valve !

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t Containment Spray / Emergency Service Water System Surveillance  ;

On August 4-5,1993, the inspectors observed the performance of the operability and inservice testing of the pumps and valves of containment spray and emergency service water

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systems (CS/ESW) I and 2. The inspectors observed both control room and field activities during the performance of the test including valve timing, acquisition of pump and heat exchanger performance data, and pump vibration monitorin The testing was completed satisfactorily and was effectively coordinated by control room personnel. Radio communications were effectively used to obtain simultaneous performance

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data readings since the containment spray pumps, containment spray heat exchangers, and the emergency service water pumps are in different locations. Current versions of the respective operability and inservice test procedures for CS/ESW systems 1 and 2 were used (Procedures 607.4.004, Revision 19, dated 5/16/93 and 607.4.005, Revision 15, dated 5/16/93). The ;

inspectors verified proper control room switch alignment for system operation. The inspectors veri 6ed that the installed monitoring instrumentation and portable monitoring instrumentation (vibration meters) used for the test were properly calibrate The licensee closely monitored the differential pressure (dp) on the emergency service water side of the containment spray heat exchangers during the tests. The licensee was concerne<1 that elevated intake water temperatures might cause heat exchanger fouling due to tube obstruction from increased intake of grass and/or marine life (mussels). The ESW heat !

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exchanger dp readings initially increased during the test run then settled out in the 20 psid range. The test criterion for declaring the heat exchangers inoperable is a dp of greater than ;

or equal to 40 psid. By the completion of the test runs for both CS/ESW systems, the heat exchanger dp had trended down to the 14-17 psid range, apparently due to auxiliary tube ,

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cleaning caused by continuous ESW pump operatio t Shortly after starting the test run for CS/ESW system 1 on the evening of August 4,1993, the licensee noted that the indicated ESW pump dp was abnormally low and not consistent ,

with the indicated ESW flow rate. The licensee immediately suspected fouling of the ESW

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system 1 flow sensing element (Annubar), a historic problem that has resulted in a false indication of degraded ESW pump performance. The Annubar was removed and the high and low pressure sensing ports were cleaned. The flow instrument was then reinstalled, calibrated, and returned to service. The operability and inservice test of CS/ESW system 1 j was then restarted and satisfactorily complete .

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. ENGINEERING AND TECIINICAL SUPPORT (71707,40500,37828) Control Rod Drive Pump Performance Evaluation and Troubleshooting Since June 1993, operations and system engineering personnel had been closely monitoring performance of the "A" control rod drive (CRD) pump. Surveillance Test Procedure 617.4.001, "CRD Pump Operability Test," contains acceptance criteria for the two CRD pumps, which includes the operability requirement that CRD charging water pressure is between 1390 psig and 1510 psig. The licensee initially provided increased attention to the

"A" CRD pump after its charging water pressure dropped toward the lower end of the operability range in early 1993. The typical charging water pressure values measured at that ,

time were between 1410 psig and 1430 psi The CRD pumps are not classified as components requiring testing prescribed by ASME ,

Section XI, " Rules for Inservice Inspection of Nuclear Power Plant Components." However, the Oyster Creek Technical Specifications (TS) require a monthly operability test for each CRD pump. System engineering review of the "A" CRD pump monthly operability test results identified about a six percent degradation in performance when compared to the associated pump curve. Due to the observed apparent pump degradation, the licensee initiated planning efforts in June 1993, to replace the rotating element of the "A" CRD pum On July 7,1993, system engineering and operations personnel operated the CRD system in an attempt to con 6rm that the observed degradation was an actual pump problem rather than a loss of system Cow through a leakage Howpath. One evolution that was conducted consisted of closing the minimum flow recirculation valve for the "A" CRD pump while that pump was operating to ensure that there was no leakage past the valve. A separate evolution consisted of closing the "B" CRD pump discharge valve while operating the "A" CRD pump to similarly eliminate a potential leakage flowpath. Neither evolution identified a leakage path, and the system engineer recommended that the "A" CRD pump rotating element be replaced. The pump was subsequently replaced and satisfactorily tested on July 15, 199 The licensee appropriately entered and satis 0ed the related TS Limiting Condition for Operation during the CRD pump maintenanc After the installed "A" CRD pump was removed, the licensee inspected the rotating elemen They found that the pump internals had degraded to the extent that the internal flowpath had allowed a portion of the higher pressure discharge flow to recirculate to the lower pressure suction side of the pump. There is no prescribed periodic CRD pump replacement schedul Rather, replacement is based upon recommendations from the system engineer, who monitors and trends pump performance. This pump had been installed for approximately seven year . . _ . .- _ . . ._ .

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The inspector monitored the licensee's actions related to the identification, monitoring, troubleshooting, and repair of the "A" CRD pump. System engineering and operations personnel appropriately identi6cd, trended and monitored the CRD pump performance problems. The inspector observed the troubleshooting activities that were conducted on July 7,1993, and found that, while the involved personnel adequately coordinated and executed the activities and no speci6c problems resulted, no formal guidance exists for the conduct of troubleshooting by system engineering and/or operations personnel. Procedure No. A100-ADM-3660.01, " Conduct of Installed Instrument Troubleshooting, Calibration and Maintenance," requires that maintenance technicians perform some level of risk assessment when troubleshooting critical components or systems, that a pre-work written plan be developed, and that some level of formal review and approval of the proposed troubleshooting activity be completed. The inspector expressed a concern that no such comparable formal process exists when system engineering and/or operations personnel

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manipulate systems for troubleshooting purposes to ensure that the proposed activities are properly assessed for potential adverse impacts. The licensee acknowledged the inspector's comments and stated that a review of a formal troubleshooting program for operators and system engineers would be evaluate .2 Engineering Review of Potential Safety Concerns identified During Licensee-Initiated System Evaluations (Unresolved item 50-219/93-11-01)

On July 28,1993, the inspector observed maintenance technicians replacing the solenoid valves associated with the air operated minimum flow recirculation valves (MFRVs) for core spray (CS) system II. Following additional review of the maintenance activity and component history, the inspector found that the solenoid valves were upgraded to new ASCO solenoid valves, rather than replaced by identical components. This was done as a result of a 1990 licensee-initiated (by an outside contractor) CS safety system functional inspection (SSFI). The inspector's subsequent review identified concerns related to the licensee's prior practices for identifying, prioritizing and correcting SSFI findings. A chronology of the following text is provided as Attachment I to this repor '

The licensee's SSFI identified in a report, dated September 20,1990, that the ASCO (Automatic Switch Company) solenoid valves that control air to the CS MFRVs were of an unknown model number and were commercial grade components; however, the report noted that the valves have a safety function. The CS system consists of two subsystems (I and II),

each of which is provided with two parallel MFRVs. The purpose of the MFRVs is to protect the CS pumps from overheating by providing a recirculation flowpath whenever the pumps are running. The MFRVs are of a fail safe design; the solenoid valves are normally energized to allow air pressure to the MFRV diaphragm to maintain the valve in the closed ,

position. Upon either a loss of 120 VAC power to the solenoid valve or a loss of air system pressure, the associated MFRV will fail to the open positio .

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In response to the concern identified by the SSFI, on November 8,1990, the licensee initiated a Technical Functions Assigned Action item Request (TFAAIR) No. AT6353. A TFAAIR is a mechanism by which technical problems requiring engineering support is initiated, tracked and closed. The TFAAIR was assigned the lowest of three priority levels

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(Routine), whose initial concurred completion date was listed as June 30,1991. Revised concurred completion dates were listed on the TFAAIR cover sheet as follows:

October 15,1991; April 15,1992; August 30,1992; and March 31,1993. The TFAAIR was officially closed on November 17, 199 The TFAAIR response, dated November 16, 1992, stated that the Quality Classification was changed from "Other" to " Nuclear Safety Related," and that the appropriate data base was ;

also revised accordingly. In addition, the response stated that a corrective change had been initiated to replace the subject valves, as needed. A corrective change is a minor physical configuration change on a component that does not change overall function or performance, i and does not fall outside of the established design envelope as determined by an engineering evaluation. The corrective change was not initiated until after a MFRV problem was ,

identified in February 1992, and it was completed on January 13, 199 ,

On February 16, 1992, plant operators noted that one of the CS system I MFRV solenoid valves (No. V-6-996) was " making a loud vibrating sound." A work request and job order were initiated on that date. It is after this date the corrective change was initiated. Then, on March 26,1992, the other system i solenoid valve experienced an operational problem; the MFRV associated with V-6-430 failed to meet is periodic timed stroke test. Since the corrective change was not completed and the upgraded valves were not in stock, V-6-430 was replaced with an identical (non-safety related) solenoid valve. After the corrective ;

change package was completed, both system I MFRV solenoid valves were replaced with the .>

upgraded safety related valves on June 1,199 On June 1 and 26,1993, plant deviation reports were written for CS system II, due to >

receiving keep fill trouble alarms in the control room. On each occasion, the CS system pressure was found to be around the alarm setpoir.t of 53 psig. CS system pressure is normally maintained between 65 psig and 70 psig by the keep fill pump in order to keep the system full of water and thereby prevent a water hammer condition following a CS system initiation. The licensee suspected that the reduced CS system pressure was the result of a combination of system leakage past one or both of the system II MFRVs and a degraded keep fill pump. Therefore, on July 28,1993, both system 11 MFRV solenoid valves were

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replaced per the January 13, 1993, corrective change, and the keep fill pump was replace Subsequent CS system pressure problems were not experienced through the end of the inspection perio The inspector became aware of the detailed history described above after observing the July 28,1993, maintenance on the system 11 solenoid valves. The inspector subsequently developed several concerns, as follows: 1) the SSFI identified a potentially significant issue; however, no immediate operability review was apparent or documented; 2) the TFAAIR that

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was assigned to resolve the SSFI Gnding was given a low priority, and the due date was allowed to be changed multiple times, resulting in closure more than two years after identification; 3) even after the TFAAIR was completed, the corrective action proposed (and accepted) in the TFAAIR allowed the continued reliance on the non-safety related solenoid -

valves in a safety related application for an indennite period of time (" replace the subject valves, as needed").

As a result of the concerns stated above, the inspector reviewed the current process for internally conducted SSFIs. The inspector found that the existing process is more formal than it was in 1990. Specifically, the preliminary safety signincance is evaluated and documented for each SSF1 finding. Each finding is then assigned and prioritized based upon its signiGcance. The inspector reviewed the preliminary determinations for an ongoing -

reactor protection system SSFI, and no specinc similar deficiencies were identifie However, the inspector was concerned that the untimely corrective action for the CS system :

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solenoid valves discussed above may not be an isolated occurrence. Pending a more comprehensive review of the prioritization and resolution of Gndings from previously completed GPUN SSFIs, this item is unresolved. (Unresolved Item 50-219/93-11-01)

. PLANT SUPPORT (71707,92700,92701) Radiological Controls i

During entry to and exit from the radiologically controlled area (RCA), the inspectors ;

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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 instruments were functional and in calibration. During periodic plant tours, the inspectors verified that posted extended Radiation Work Permits (RWPs) and survey status boards were current and accurate. The inspectors observed activities in the RCA and veriGed that personnel were complying with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the are , Security

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During routine tours, the inspectors verified that access controls were in accordance with the j Security Plan, security posts were properly manned, protected area gates were locked or i guarded, and isolation zones were free of obstructions. The inspectors examined vital area j access points and verified that they were properly locked or guarded and that access control j

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was in accordance with the Security Pla .3 Management Observation Teams i

The inspectors reviewed the summary reports of management observation team tours .j conducted since September 1992, to assess whether the process had improved since the last resident inspector assessment of this area. In NRC Inspection Report 50-219/92-16, dated l

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September 9,1992, the inspectors concluded that the management observation team effort 1 had not been aggressive and that more participation from managers who could provide l informed assessment of work performance techniques was neede ;

The inspectors reviewed the summary reports of 84 management observation team tours  ;

conducted since September 1992. The inspectors noted that more supervisors were i participating in the program and that a larger percentage of the tours were being performed i I

by supervisors from departments other than radiological controls. While more assessment of work performance techniques and documentation of coaching was provided, the inspectors noted that the majority of the reports still tended to focus on radiological and industrial safety i practices, housekeeping, and general job descriptions. The inspectors also noted that the l reports occasionally described the observed activity in general terms without actually l reDecting how worker performance demonstrated the general assessment. For example, l

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several reports noted that workers were using proper techniques for self-checking without describing the actions that were observed that demonstrated those techniques. The licensee has acknowledged some of the program's shortcomings and has recently asked (in May 1993)

the participating supervisors for renewed commitment to the effor The inspectors concluded that the implementation of the management observation tour program has been more aggressive but that there is still room for improvement. More managers have gotten involved in the program and recent observation summaries have been ,

more focused on worker performance. However, many of the observation summaries l continue to be focused on physical plant status vice human performance and somewhat lacking in detail. Also, it was not apparent that the licensee has attempted to look at the i results of the management observation team efforts in the aggregate for common issues or i problems. The licensee has acknowledged that program improvements are still in order as !

noted in the May 7,1993, internal licensee memorandum to the members of the management i observation team. The licensee is also attempting to facilitate the documentation process by setting up an observation tour reporting and storage mechanism via electronic mai .4 Emergency Preparedness 4.4.1 Hurricane Readiness j

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The inspectors reviewed the licensee's readiness for and prescribed actions in response to a hurricane or other abnormally high wind condition. The inspectors reviewed licensee guidance available for actions in preparation for an approaching storm, communications system capabilities and susceptibility to a high wind condition, and the susceptibility of l protected area structures and equipment to failure or Hooding due to an abnormally high wind conditio l

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Oyster Creek prepares for and takes actions in response to approaching or imminent storm conditions through Plant Abnormal Procedure 2000-ABN-3200.31, "High Winds,"

Revision 11, dated 2/14/93. The procedure calls for actions to be taken in response to both abnormal wind and tidal conditions. For an anticipated high wind condition, Procedure 2000-ABN-3200.31 is entered when wind gusts greater than 30 mph are experienced. Initial actions include site walkdowns and securing of materials and equipment that could be adversely affected by the high wind condition. Additional actions are taken as anticipated wind speeds increase, including (1) evacuation of site personnel in certain areas (i.e.,

trailers), (2) actions in anticipation of possible station blackout problems, (3) control room operator review of reactor scram and loss of offsite power procedures, (4) planning for additional personnel on site if needed for longer term support, and (5) attempts to restore pertinent systems to operable status as soon as possible if they are currently down for maintenance purposes, if weather forecasts indicate that sustained winds greater than 74 mph may be experienced, power may be reduced to 40% in accordance with the High Winds procedure, at the option of the operations director. A National Weather Service forecast of sustained winds greater than 74 mph'within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> requires declaration of an Unusual Event. The High Winds procedure also directs that if weather forecasts indicate sustained winds of greater than or equal 85 mph, a controlled plant shutdown to hot standby should be commenced. The amount of advance notice for commencing a plant shutdown depends on when the forecasts are received. There is no specified shutdown completion time required before expected storm arrival. However, the rate of shutdown can be varied based on ;

anticipated storm arrival time. The plant could probably be placed in a hot standby condition within 4 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> depending upon how quickly power is reduced. Sustained winds of greater than 95 mph measured on the site wind speed recorder requires declaration of an Alert. A Site Area Emergency is to be declared if wind speeds on site are measured at greater than 100 mp No additional provisions have been made in the Oyster Creek emergency plan for providing external support since Hurricane Andrew in 1992. There is an emergency response organization position (Group Leader - Administrative Support) that is responsible for anticipating and taking care of whatever contingency provisions may be required, to the best of his/her ability. The licensee anticipates that they would have a minimum of 8-hours warning to make the necessary administrative arrangements. The TMI staff is expected to provide external support in these situation .

Communication systems in addition to the normal AT&T phone system include a company i dedicated microwave phone system, a company radio system with base stations in the control room and the emergency operations facility (EOF), and the capability of transmitting on the state emergency radio network (EMRAD) from the EOF. There are also a number of company vehicles both at the site and at Parsippany equipped with cellular phones. The microwave system and the cellular phones are probably just as susceptible to damage from a high wind condition as the normal phone system due to their exposed antenna networks. Use of the company radio provides communication with 5 vehicles, the EOF, and the onsite emergency response facilities. EMRAD provides for communication with the NJ State,

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Ocean County, and Lacey Township emergency operations centers. Primary power for the phone systems is provided by a 12.5 kV offsite line. A 19.5 kV offsite line provides backup capability and an 8-hour battery backup power supply is also provided. Onsite emergency circuits (emergency notification system (ENS), joint information center (JIC) line, other hot lines) have an additional 8-hour battery backup. The offsite emergency circuits are carried :

by both the AT&T lines and the GPU microwave. The GPU microwave has an 8-hour battery backup at each connecting node. The onsite battery backup systems are located in the Site Emergency Building in areas that are hardened and seismically qualifie .

GPU maintains the phones and cellular units. JCP&L maintains the radios and the microwave system. Because the communications systems are for the most part, routinely used, there is no routine testing. The EOF EMRAD connection is periodically checked by JCP&L. The licensee has been consistently pursuing changes to improve the reliability of ,

the communications systems. The microwave was recently converted from an analog to a

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digital system. Efforts are continuing to convert portions of system connections to fiber optics and to replace land lines with buried cable when possible. Emergency response organization personnel who are designated as communicators, including the control room operators, are trained in the use of the radio equipmen '

The inspectors performed several site walkdowns and interviewed cognizant licensee engineering personnel with regard to the susceptibility to damage of site equipment and structures external to the turbine building and the reactor building. The inspectors concluded that most of the non-safety structures could withstand sustained winds up to 74 mph. Many structures external to the turbine building and reactor building were built to the BOCA cod and are expected to withstand sustained winds up to 85 mph (new radwaste building, augmented offgas building, reduridant fire water pump house, combustion turbines). The main stack is designed to withstand sustained winds up to 185 mph and the site transformers are designed to withstand sustained winds up to 200 mph. The licensee acknowledged that the stability of personnel trailers was questionable with winds of 50 mph or greater. As such, the High Winds procedure directs personnel trailer evacuation at this wind speed. The !

personnel trailers next to the new station blackout stepdown transformer have already been tied down to keep them from adversely affecting the station blackout transformer in a high !

wind condition. The main fire diesel building at the fire pond is not designed to withstand r hurricane force winds and would probably be destroyed in this condition. The fire diesels themselves may remain intact but the destruction of the building would probably sever the diesel fuel supply line that comes through the building wall. At sustained wind speeds beyond 85 mph, it is difficult to predict exactly when and how the non-safety structures and equipment would fail. The licensee anticipated that the onsite tanks (condensate storage tank '

(CST), torus water storage tank, redundant fire water storage tank, sodium hypochlorite, nitrogen) could withstand hurricane force winds but that none could withstand tornado force winds. For this reason, a procedure was (eveloped for providing isolation condenser i

makeup via the torus if the CST is unavailable. The licensee stated that attempts would probably be made to tie down the tanks if exceptionally high wind speeds were expecte ,

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All of the equipment at the intake structure is susceptible to damage or inoperability due to t

high wind and/or water level problems. Specific actions in response to high water levels at the intake structure are noted in the High Winds procedure and include (1) intake level monitoring (3.0 ft above mean sea level (MSL)), (2) controlled plant shutdown and Unusual Event declaration (+4.5 ft MSL), (3) manual scram and Alert declaration (+6.0 ft MSL),

circulating water pump isolation (+6.5 ft MSL), and service water pump isolation and Site i Area Emergency declaration (+8.0 ft MSL). Both the main fire diesel pump house and redundant fire water pump house are also susceptible to damage. The standby gas treatment system fans are also located outside next to the main stack. These fans would also be -

subjected to high winds but they are located in a reasonably sheltered are .

Areas of " historic" flooding at Oyster Creek subsequent to severe storm conditions have been -

the northwest corner room of the reactor building (RB) and the northeast RB access door The licensee is currently working on resolving the groundwater intrusion problem in the ,

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northwest corner room that contains one train of main core spray pumps (2 pumps). The core spray pumps and pump motors are mounted on pedestals that are about 6 inches hig ,

The Door drains in the corner room have effectively controlled the amount of water that collects on the Door. In a heavy rainfall, water will occasionally run under the northeast RB ,

't access doors and onto the floor of the RB 23 ft elevation, around a floor hatch and down into the northeast corner room. This corner room contains one train of containment spray pumps (2 pumps). This means of water intrusion has been rare and that amount of water not removed by the licensee actions at the northeast RB access door area is effectively removed by the corner room drai Overall, the inspectors concluded that the licensee has established adequate precautions to ,

respond to abnormally high wind conditions at the Oyster Creek site. While it is difGcult to predict how and when non-safety structures and equipment would fail at sustained wind speeds beyond 85 mph, the licensee appears to be aware of the potential site vulnerabilities to !

this conditio t In-Office Review of Licensee Event Reports (LER)

NRC inspectors reviewed the following LER and verified appropriate reporting, timeliness, ,

complete event description, cause identification, and complete information. In addition, the need for on site review was assesse LER N DESCRIPTION 93-004 External Torus Pressure Outside Design Basis Due to Inadequate !

Design information (Lack of Blowout Panels)  :

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This LER was written to document a design basis reconstitution program review Onding relating the inability to validate the physical existence of blowout panels in the reactor building wall. NRC review of this plant condition was documented in NRC Inspection

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Report 50-219/93-09, dated July 18, 1993. Further NRC assessment of this issue is provided

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in Section 4.5 of this report. The LER adequately summarized the issue, identified the apparent cause, and was issued in a timely manner. The completion of corrective actions stated in the LER will be tracked through inspector followup of Unresolved Item 50-219/93-09-0 .6 Review of Previously Opened Items (VIO 50-219/93-11-02)

(Closed) Unresolved Item 50-219/92-80-07. This item dealt with vital switchgear room temperature controls, as related to the licensee's ability to identify, monitor, and respond to high ambient temperature effects on installed electrical equipment in the 480 V and 4 kV vital switchgear rooms. During this inspection, the inspector determined that the licensee-had not implemented corrective actions to ensure that the assumed design basis temperature for the vital switchgear rooms is not exceeded. Therefore, this unresolved item is being upgraded to a violatio Each of the two switchgear rooms are provided with an installed temperature detectc However, the NRC identined that the alarm setpoint of 105 F was above the 104 F design basis value. In addition, the associated high temperature alarm response Procedure 2000-RAP-3024.02 (aununciator window U-7-a),' instructed the operators to evaluate the need -

for temporary ventilation, but gave no guidance as to what temperatures were acceptable or what speci6c actions should be take In response to the identified concern, the licensee's engineering organization completed an evaluation and issued recommendations to the station via a memorandum', dated i February 2,1993. Those recommended actions included resetting the high temperature ,

alarm setpoint to 104*F, opening electrical cabinet doors and instituting hourly temperature readings if the high temperature alarm is received, and taking additional specine actions if the temperature subsequently continues to increase above 104 ,

During the period of July 7-9,1993, when outside temperatures were consistently in excess of 100 F, the impector toured the 480 V vital switchgear room. A portable, non-calibrated temperature instrument was located inside the roem, near the ventilation inlet damper. The indicator displayed a 90 room temperature. However, when the inspector moved the detector away from the ventilation flow, toward the rear of the room, the indicator displayed a temperature value in excess of 95 F. The inspector also found that the high temperature alarm for the installed detector was not changed from 105 F to 104 F, no specinc guidance was communicated to the appropriate operations personnel to monitor the 480 V room temperature, and none of the proposed contingency actions were presented to the appropriate

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operations personnel. In summary, neither the corrective actions proposed by the February 2,1993, engineering memorandum nor alternate actions were implemented to resolve the identified temperature concerns for the 480 V vital switchgear roo __ _ _ . ,

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The inspector identified similar concerns for the 4 kV vital switchgear rooms. An April 27,1993, engineering memorandum provided an evaluation and associated recommendations to the station for the temperature concerns for the 4 kV vital switchgear rooms. The recommendations included providing a temperature detector in each of the two 4 kV vital switchgear rooms and monitoring the room ambient temperatures twice per shif The memorandum also provided contingency actions, such as opening the switchgear room roll-up doors and connecting temporary ventilation if 104 F is exceeded. The inspector found that the licensee did not implement any of these action The inspector noted that the GPUN memoranda stated that the design basis room temperature for the vital switchgear rooms of 104 F is based upon an outside temperature of 89'F. The inspector concluded that, as a minimum, periodic room temperature readings should have been taken when 89 F was exceeded to ensure that the assumed 104 F design basis value was not exceede The inspector identified the above concerns to GPUN management on July 9,1993. The outside temperature on that day exceeded 100 F. The licensee subsequently implemented several actions, which included 1) instituting temperature readings, using calibrated ,

temperature instruments, for both the 480 V and 4 kV vital switchgear rooms on a twice per shift frequency; 2) initiating procedure changes to delineate specific operator actions when pre-determined temperature values are exceeded; 3) installing temporary temperature instruments in the 4 kV vital switchgear rooms; and 4) opening the roll-up doors for the 4 kV vital switchgear rooms to enhance area ventilation. During that period, the licensee's

periodic temperature readings reached a maximum of 100 F. Other licensee actions, planned to be completed by the end of August 1993, include revising the reactor and turbine building summer tour sheets to include recording ambient temperatures in the 480 V and 4 kV switchgear rooms, and investigating the use of portable fans and flexible ductwork to enhance cooling the vital switchgear room ,

The inspector concluded that the licensee had not implemented the corrective actions in response to the previously identified adverse condition. The fact that the outside ambient temperature had exceeded the maximum value (89 F) assumed in the design basis for the vital switchgear heightens the safety concern for this issue. Title 10 CFR 50, Appendix B, ,

Criterion XVI, " Corrective Action," states that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. The failure to implement corrective actions for vital switchgear room temperature control deficiencies, to the extent that extreme high ambient temperatures were reached and no remedial actions were taken, is a violation. (Violation 50-219/93-11-02)

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(Uodated) Unresolved Item 50-219/93-09-01. This item dealt with an issue identified by the licensee during the design basis document (DBD) review of the standby gas treatment

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system. The licensee had found that there was no clear documentation of either the existence of blowout panels on the reactor building wall or verification of reactor building pressure relief at 0.25 psig internal pressure as stated in Section 6.2.3.2 of the updated FSAR. The original high energy line break (HELB) analyses and equipment quali0 cation (EQ) pressure and temperature profiles had been developed using the 0.25 psig value with certain l conservatism applied. In response to this design discrepancy, the licensee performed an l amended HELB analysis and several subsequent calculations to assess the effects of the higher post-HELB pressures and temperatures on reactor building structures and equipment,-

including EQ equipment. One of the calculations determined an external pressure on the torus shell (1.37 psig) greater than the torus external design pressure noted in the UFSAR :

(1.0 psig) for a few seconds after an isolation condenser line break. This Onding prompted a J

10 CFR .50.72 notification on June 2,1993, and subsequent licensee reevaluation of torus integrity based on external pressure. This issue was identified as an unresolved item in NRC Inspection Report 50-219/93-09 pending further review of the licensee's documentation supporting continued plant operation and the subsequent LE The inspectors reviewed the following documentation:  ;

! GPUN Calculation C-1302-822-5450-052, Reactor Building Response to HELBs j Without Blowout Panels l i GPUN Calculation C-1302-187-5320-027, Oyster Creek Torus External Pressure Calculation Design Change Notice (DCN) C091024 - effects of increased post-HELB reactor building temperatures and pressures on EQ qualified equipment GPUN Calculation C-1302-153-5320-071, Reactor Building Siding Blowout GPUN Calculation C-1302-153-5320-071, Reactor Building Masonry Walls Structural Adequacy to Overpressure The GOTHIC computer code (Version 3.4., April 1991) was used to evaluate reactor building l response to three HELBs including a main steam line break, an isolation condenser line break, and a reactor water cleanup system line break. The analyses assumed reactor building pressure relief at 0.95 psig based on a Oyster Creek architect-engineer (Burns and Roe)

document that described the failure mechanism for the reactor building refueling floor wall panels. The limiting case results came from the isolation condenser line break analysis. The results of this modified HELB analysis prompted the other calculations performed to assess plant response.

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The torus external pressure calculation was performed using ASME Section IH, Subsection NE-3000 and ASME Code Case N-284. The calculation determined that the torus had sufficient design margin to withstand greater than 1.37 psig external pressure in combination with the dead weight of the torus. The inspectors reviewed the calculation and found that it had been performed in accordance with the referenced ASME guidance. The inspectors verified that the use of the August 25,1980, version of ASME Code Case N-284 was acceptable per Revision 29 of NRC Regulatory Guide 1.84, " Design and Fabrication Code Case Acceptability, ASME Section III, Division I," dated July 1993. The inspectors noted ;

that GPUN used several conservative assumptions in this calculation including taking no credit for the counteracting force of the water volume inside the toru The reactor building (refueling floor) siding blowout calculation was performed by the licensee in an attempt to validate the 0.95 psig reactor building pressure relief value noted in the 1968 Burns and Roe letter. This calculation was prudent because the Burns and Roe letter was not signed and provided minimal detail of the calculations performed or subsequent design veri 6 cation. The licensee's calculation showed that the screws connecting the refueling floor metal siding to the metal framing would fail at 0.9 psig. Since this value was less conservative than the value in the Burns and Roe letter, the 0.95 psig pressure relief value was used in the amended HELB calculation. This calculation did not assess potential failure mechanisms of other structural components that make up the reactor building wall structure above the refueling Door. The licensee also did not assess the failure of the reactor building roof decking because of the uncertainty of additional live loading that would be imparted by a signincant amount of snow or ice. A detailed assessment of potential failure mechanisms for other structural components above the refueling floor is currently in i progres '

The differential pressures across compartment walls in the reactor building were evaluated to determine the effects on structural components within the building. Licensee analysis of masonry walls in accordance with the NRC Bulletin 80-11 program found that some masonry walls would be exposed to excessive stresses and would collapse. Since the masonry walls ;

are not load bearing, the postulated wall failures were assessed for loss of support for safety-related equipment and for wall collapse onto safety related equipment. The licensee actions in response to the postulated wall failures were appropriate (see NRC Inspection Report 50-219/93-09, Section 4.1).

The evaluation of EQ components in the reactor building appropriately used the most severe pressure / temperature profile of the three HELB scenarios calculated for each affected area in the reactor building. These profiles were compared to the existing pressure / temperature profiles in the EQ component files. If the existing profiles were exceeded, the new profiles were compared to the existing test profiles. If the equipment test pro 61es were exceeded, l further component evaluations were performed. These component evaluations were included in the referenced DCN (C091024). Overall, the licensee concluded that all affected EQ

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components remained qualified. The inspectors reviewed the DCN and found that, for the most part, the licensee assessments of the effects on component operability and qualification !

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were reasonable based on the small magnitude of the differences between the existing and the new pressure / temperature profiles and the short duration of the pressure / temperature spike in the new profiles resulting from reactor building relief at a higher internal pressure. The

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inspectors questioned the licensee on the assessment of one component (EGS/Patel Temperature Switch) due to the difference in peak pressure at the switch location (main ,

steam isolation valve (MSIV) area) compared to the original HELB calculated value and the peak test pressure. The peak pressure at the switches based on the amended HELB ,

calculation was 48.28 psia. The peak pressure for the original HELB calculation was 21.43 psia and the peak test pressure was 40.70 psia. The licensee noted in the DCN for EQ File No. OC-318 for the switches that "the equipment was isostatic and would not be affected by the noted increase in pressure for a short period of time." The inspectors requested additional information related to the temperature switch to assess the validity of the licensee's conclusion. The temperature switches are strut-and-tube type thermoswitches with an outer shell made of a high-expanding metal and a strut assembly made of a low-expanding meta A pair of electrical contacts are mounted on the strut assembly and installed in the shel Each end of the strut assembly is connected to the ends of the shell. A change in force is produced on the strut assembly as the shell expands or contracts with changing temperatur '

The contact make-or-break temperature is varied by an adjusting screw. The electronic components are in a stainless steel hermetically-scaled housing. The switches sense high temperature in the main steam tunnel and isolate the MSIVs when the switch reaches its setpoint. Once initiated, the circuit locks in and prevents opening the MSIVs until the circuit is reset. Based on the physical characteristics of the temperature switch and the short period of time that the amended HELB pressure / temperature profile is above the stated test pressure (about 0.4 seconds), the inspectors concluded that the licensee's assessment was reasonable and that the switch would function as designe ,

The inspectors concluded that the calculations and evaluations performed thus far by the licensee to assess the effects of higher post-HELB pressures and temperatures on reactor building structures and equipment were done in accordance with established guidance and applied appropriate levels of conservatism. The results of the licensee's initial efforts have demonstrated that the plant could be placed in a safe condition in the event of a worst case HELB with reactor building pressure relief at a value higher than the previously stated value (0.95 psig vs. 0.25 psig). The licensee is currently performing a detailed analysis on the reactor building structure above the refueling floor to determine its overall integrity if a reactor building intemal pressure transient up to 0.95 psig were to actually occur. The intent ,

of this analysis is to determine whether the reactor building structure above the refueling floor could be degraded to the point where it could adversely affect refueling floor equipment. Another purpose of the analysis is to determine whether reactor building ,

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pressure relief could occur at a lower value than 0.95 psig due to the failure of other structural components, e.g., trusses or other framing members, that make up the building .

structure above the refueling floor. The licensee intends to submit a supplemental LER based on the results of this analysis. This unresolved item will remain open pending licensee completion of this analysis and implementation of appropriate corrective actions, if necessar !

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19 EXIT MEETINGS (40500,71707,30702) Preliminary Inspection Findings A verbal summary of preliminary Endings was provided to the onsite senior licensee management on August 11, 1993. During the inspection, licensee management was ,

periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspection. No proprietary information is included in this repor The inspection consisted of normal, backshift and deep backshift inspection; 38 of the direct inspection hours were performed during backshift periods, and 14 of the hours were deep backshift hour l Attendance at Management Meetings The resident inspectors attended exit meetings for other inspections / evaluations conducted as follows:

Date Lead Inspector Subiect Report N l July 10,1993 Paolino Environmental 50-219/93-12 :

Qualification July 15,1993 Orrik Operational Safeguards N/A Response Evaluation ,

July 30,1993 McBrearty Erosion / Corrosion 50-219/93-16 August 5,1993 Laughlin Emergency Preparedness 50-219/93-14 ;

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At these meetings, the lead inspector discussed preliminary findings with senior GPUN managemen l

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i ATTACIIMENT 1 CORE SPRAY SYSTEM MINIMUM FLOW SOLENOID VALVE EQUIPMENT CLASSIFICATION AND REPAIR CIIRONOLOGY Date Description ,

9/20/90 SSFI finding documented 11/8/90 TFAAIR assigned (Routine priority)

2/16/92 Loud vibrating sound heard from V-6-996 (CS system I). Subsequent to this date, a corrective i change package was initiated 3/26/92 V-6-430 (CS system I) failed stroke time surveillance test 3/31/92 Repaired V-6-430 with identical (non-safety related) component because corrective change package not complete and upgraded valves not in stock 11/16/92 TFAAIR response complete (replace as-needed) '

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11/17/92 TFAAIR administratively closed ,

1/13/93 Solenoid valve upgrade corrective change package completed 6/1/93 Replaced V-6-996 and V-6-430 with upgraded safety related components per corrective change 6/1/93 CS system II keep fill trouble alarm - deviation report documented. Suspected a problem with one or both MFRV solenoid valves and/or keep fill pump 6/26/93 CS system II keep fill trouble alarm - deviation report documented 7/28/93 Replaced both CS system 11 solenoid valves with upgraded components per corrective change (and replaced keep fill pump)

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