IR 05000354/1998005
| ML20249A111 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 06/04/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20249A104 | List: |
| References | |
| 50-354-98-05, 50-354-98-5, NUDOCS 9806160070 | |
| Download: ML20249A111 (27) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No:
50-354
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License Nos:
NPF-57 l
Report No.
50-354/98-05 Licensee:
Public Service Electric and Gas Company i
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Facility:
Hope Creek Nuclear Generating Station I
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Location:
P.O. Box 236 I
Hancocks Bridge,14ew Jersey 08030
. Dates:
April 5,1998 - May 16,1998 Inspectors:
S. M. Pindale, Senior Resident inspector j
J. D. Orr, Resident inspector Approved by:
James C. Linville, Chief, Projects Branch 3 Division of Reactor Projects i
l l-i 99u6160070 990604 PDR ADOCK 05000354
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EXECUTIVE SUMMARY l
Hope Creek Generating Station NRC Inspection Report 50-354/98-05 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six week period of resident inspection; in addition, it includes the results of an in-office review of an unresolved item related to prior practices related full core offloads during refueling outages.
Operations Operations personnel conducted several high quality pre-activity briefs for various
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l activities, which focused on the potential consequences of planned activities and L
associated responses, and emphasized expectations regarding communications and self-and peer-check techniques. Control room operators responded quickly and effectively to a reactor core isolation cooling (RCIC) system battery charger failure. A non-licensed equipment operator demonstrated a good questioning attitude when he identified that a RCIC flow controller located on the Remote Shutdown Panel was in manual. (Section 01.1)
During tours of the torus and 'B' residual heat removal pump room, the inspectors identified
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some material condition and housekeeping deficiencies, such as a 'B' core spray system test line orifice installed backwards, unsecured ladders, and excessive scaffolding storage.
i The identified problems did not impact equipment operability. PSE&G initiated prompt and appropriate actions to address the deficiencies. (Section O2.1)
Control room operators were slow to declare safety-related equipment inoperable ('A'
Service Water Pump, 'B' torus-to-drywell vacuum breaker and the 'A' safety auxiliaries f
cooling system pump) when faced with unexpected results during surveillance testing on i.
three separate occasions. Although PSE&G later determined that each problem did not in f act render the equipment inoperable, the inspectors determined that the operators' delay in declaring safety-related equipment inoperable after the failed testing, demonstrated that operators did not always make conservative decisions. In response to these concerns, PSE&G appropriately aasessed the human performance issues and intended to incorporate the lessons learned into requalification training. (Section 04.1)
Maintenance Maintenance personnel safely performed on-line maintenance on 36 hydraulic control units.
. Strong supervisory oversight of the activities was evident. PSE&G provided critical assessments of the completed nine day work activity, including work coordination and performance, to develop lessons-learned for similar future activities. (Section M1.1)
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. Maintenance workers did not make effective use of self and peer checks during work j
activities, which was not consistent with maintenance management's expectations. This
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manifested itself in several errors that occurred during routine maintenance activities. First, an electrician manipulated a service water system valve on the wrong train during a 72 month surveillance. Second, a nuclear worker mis-operated a test switch while assisting instrument technicians performing a containment atmosphere control surveillance. The L
third error.was the improper connection of several lengths of. test equipment wires,
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resulting in a delay in restoring a safety system to service. (Section M4.1)
Encinaarina
' PSE&G failed to establish sufficient preservice and inservice testing requirements for a design modification installed during refueling outage RF07 to the safety related control area
- chillers, which was contrary to the requirements of 10 CFR 50, Appendix B (Test Control).
Lack of inservice testing requirements allowed both trains of the safety-related control room chillers to be outside of its design basis and not able to perform its intended safety f
function. In addition, PSE&G failed to correct a known deficiency associated with the minimum cooling water design temperature for the chillers since December 1997. (Section E2.1)
On two separate occasions, PSE&G did not adequately evaluate procedure changes that verified Filtration Recirculation and Ventilation System (FRVS) technical specification surveillance requirements, resulting in procedure non-compliances. The inadequate
- procedures in one case led to inoperable FRVS components and in the other case, inadequate test requirements. (Section E2.2)
Operations, maintenance and engineering personnel responded appropriately to degraded cell voltages in the CD447 safety related 125 Vdc battery. System engineering demonstrated a performance weakness in that a system manager was not assigned to the DC systems, and consequently, the degraded cells had not been monitored and trended.
Effective monitoring and trending may have predicted this degradation and prevented a challenge to plant staff. '(Section E2.3)
During refueling outage RF03 in 1990, contrary to procedures, the RHR system was not operated in parallel with the fuel pool cooling and cleanup (FPCC) system during the time the full core was offloaded into the fuel pool. More significantly, the RHR system was not maintained available to be placed in operation in the event that the FPCC system experienced a failure during RF03. Although alternative means to ensure the decay heat could be removed from the spent fuel pool during that period were evaluated, PSE&G did not perform such reviews as required by 10 CFR 50.59. (Section E8.1)
Plant Suonort
Chemistry and radwaste personnel non-conservatively attempted to increase the activity of -
a planned liquid release to raise the activity above the existing low level setpoint of the radiatien monitor. Although this release did not occur because a radiation technician rejected the release permit, the actions by chemistry and radwaste personnel demonstrated
. a poor safety perspective and a poor questioning attitude. (Section R4.1)
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- The site operations departments (Hope Creek and Salem) responded promptly and appropriately to a major loss of the telephone communications system. Following the restoration of the major loss, operators were slow to recognize a continuing minor
. degradation of the emergency notification system. (Section P2.1)
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TABLE OF CONTENTS EX EC UTIVE SU M M A RY.............................................. il TA BLE O F CO NTE NTS............................................... v l. Ope ra ti o n s..................................................... 1
Conduct of Operations.................................... 1 01.1 General Observations................................ 1 02.1 Material Condition and Housekeeping Weaknesses........... 1
Operator Knowledge and Performance......................... 2 04.1 Nonconservative S reillance Tests Evaluation.............. 2
. II. M ai nt e n a nc e................................................... 4 M1 Conduct of Maintenance................................... 4 M 1.1 Control Rod Drive Hydraulic Control Unit On-Line Maintenance... 4 M4 Maintenance Staff Knowledge and Performance.................. 5 M4.1 Performance Weaknesses by Maintenance Workers........... 5 M8 Miscellaneous Maintenance issues............................ 7 M8.1 (Closed) LER 50-354/97-034-01
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lll. Engine e ring.................................................... 8 E2 Engineering Support of Facilities and Equipment.................. 8 E2.1 Control Area Chilled Water Systems Design Change Package Review
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E2.2 Inadequate Filtration, Recirculation, and Ventilation System (FRVS)
l Surveillance Test.................................. 12 E2.3 Degraded Cells in 125 Vdc Safety Related Battery........... 14 E8 Miscellaneous Engineering issue............................ 15 E8.1 (Closed) Unresolved item 50-354/96-03-03: Fuel Pool Cooling and Cleanup System Operation Beyond Design Basis............ 15
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IV. Pl a nt S u pp o rt................................................. 17 R4 Staff Knowledge and Performance in Radiological Protection and Chemistry C c at rol s............................................. 1 7
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R4.1 Non-Conservative Actions While Preparing to Discharge Liquid Effluent
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P2 Status of Emergency Preparedness, Facilities, Equipment, and Resources.18 P2.1 Major Loss of Offsite Communications Capability........... 18 l-V. M anagement Meeting s........................................... 19 X1
. Exit M eeting Summary................................... 19 l
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Reoort Details
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l Summarv of Plant Status Hope Creek was operated at or near full power for the duration of the inspection period, with the exception of the period April 20 - 29,1998, when power was reduced to about 80% to perform on-line maintenance for control rod drive hydraulic control units.
I. Operations
Conduct of Operations 01.1 General Observations (71707)
The inspectors conducted frequent reviews of ongoing plant operations throughout the report period. Several plant evolutions were observed, including testing and troubleshooting activities. The inspectors concluded that operations personnel properly conducted several high quality pre-activity briefs for various activities. The briefs focused on the potential consequences of the planned activities and
. associated responses, and emphasized expectations regarding communications and self-check techniques. During'several of the activities observed, the inspectors noted good use of peer-check verifications by operators, where second checks of planned activities verified proper component or system selection.
Control room operators responded quickly and effectively to a reactor core isolation cooling (RCIC) system battery charger failure after receiving an associated alarm in the control room.
A non-licensed equipment operator demonstrated a good questioning attitude when he identified that a RCIC flow controller located on the Remote Shutdown Panel was in manual. Operations personnel quickly evaluated the alignment and determined that the configuration did not compromise RCIC system operability nor did it affect the Hope Creek licensing basis.
02.1 Material Condition and Housekeeoina Weaknesses a.
insoection Scoce (71707)
The inspectors toured the 'B' residual heat removal (RHR) pump room and the torus room, which are radiologically contaminated areas and are not routinely accessed by operators.
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Observations and Findinos During a tour in the torus room, the inspectors questioned the orientation of a flow orifice in the 'B' core spray system. Followup review by operations and maintenance personnel confirmed that the orifice, located in the system test line (return to the torus), was installed backwards, in response, operations initiated an
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Action Request (980423153) for further evaluation. The associated review determined that the purpose of the orifice is for pressure reduction, and that the orifice is not beveled.. Therefore, orifice orientation has no operational impact.
PSE&G determined that there was no evidence indicating that the orifice was removed or. installed in the last 12 years, indicating that it was from original construction.
The inspectors also identified other minor deficiencies in the torus room, such as a large amount of stored scaffolding and unsecured ladders. The inspectors determined that an Action Request, initiated in March 1998, identified these and similar deficiencies. PSE&G management informed the inspectors that they were in the process of removing the scaffolding from the torus room.
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The inspectors found the components located in the 'B' RHR room to be in generally
. good material condition with minor exceptions. In addition, room lighting was
- degraded by several burnt out lights. These minor deficiencies were brought to the attention of the responsible PSE&G personnel, who initiated corrective actions.
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Conclusions During tours of the torus and 'B' residual heat removal pump room, the inspectors identified some minor material condition and housekeeping deficiencies, such as a B' core spray system test line orifice installed backwards, unsecured ladders, and i
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excessive scaffolding storage. The identified problems did not impact equipment operability. PSE&G initiated prompt and appropriate actions to address the deficiencies. '
Operator Knowledge and Performance 04.1 Nonconservative Surveillance Tests Evaluation
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- Insoection Scoon (61726. 71707)
The inspectors evaluated Hope Creek operators' responses to three separate surveillance tests for safety-related equipment that had failed its acceptance criteria.
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Observations and Findinas j
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On April 10,1998 at about 12:19 a.m., Hope Creek operators started an inservice
- surveillance test for the 'A' safety auxiliaries cooling system (SACS) pump. The
. surveillance test required that flow for the pump be established within an allowed i
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band around 11,000 gpm and then pump differential pressure (d/p) be measured L
after a two minute stabilization period. The operators, in accordance with the surveillance procedure, established the correct pump flow by throttling the pump
~ discharge valve. The Hope Creek operators noted that the pump did not achieve the required differential pressure (d/p). The results were not logged in the surveillance procedure but were recorded on a note pad. The operators suspected the flow
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instrument being used was the cause for not achieving the required d/p. The control -
room operators had noticed a disparity of about 600 gpm between two indicators
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4.that used the same flow measuring device. The operators adjusted pump flow within the allowed band and performed the surveillance again in an attempt to
- resolve the disparity between the control room flow indicators. The pump d/p was low and again failed the surveillance acceptance criteria. The surveillance test was
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run a few more times with unacceptable results.
Operators performed 'a shift relief at 7:00 a.m. The data that was collected in the -
. previous shift was recorded on a note pad and the notes were turned over to the encoming crew. The surveillance procedure had been used, but the operators recorded steps as being complete only up to the procedure steps that require recording test data.. The oncoming shift had a calibration check of the flow indicator performed.- The flow indicator was found to be within calibration. A
- different pump discharge pressure gauge was installed. The surveillance was run
. again a few more times with unacceptable results.
Operators the began to suspect the discharge pressure gauge that was being used L
as the cause for the unacceptable results. A cross check of pressure gauges was
performed and they were found to track to within 0.25 psig. A flow transmitter calibration was performed and it was found to be within calibration. Another
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surveillance test was performed and it failed with similar results. The control room operators declared the 'A' SACS pump inoperable at 3:37 p.m. on April 11,1998,
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and back-dated its entry time to the initial problem discovery at 12:19 a.m. on April i
10,1998. The 'A' SACS pump, although it may normally be in operation, was unnecessarily tested and over 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> had elapsed when the control room operators declared the pump inoperable and entered the appropriate technical specification action statement.
In retrospect, the control room operators independently recognized that they may not have conservatively evaluated the 'A' SACS pump test failure. An Operations Superintendent initiated an' Action Request to address the human performance issues.
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Troubleshooting was later performed and PSE&G determined that throttling the pump discharge valve, which is located very close to the pump outlet, has a dramatic effect on the pump discharge pressure. This method may provide false indications of pump performance. PSE&G revised the surveillance procedure and the new method adjusted SACS loads to achieve the desired pump flow. The new l
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. method was performed a few times to verify repeatability.
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- The inspectors determined that the operators may have justifiably suspected the initial flow indicators disparity, but no evidence existed to justify a delay in declaring
.,the 'A' SACS pump inoperable for a flow transmitter calibration and a pump j
discharge pressure gauge cross check. The inspectors also recalled two other similar testing problems where operators had either performed repeated tests or l
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continued with testing after recognizing unexpected results, and had delayed
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l declaring safety-related equipment inoperable. The 'A' Service Water Pump was not j
declared inoperable after a failed inservice test for about 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> on March 9, 1998..On March 30,1998, a torus-to-drywell vacuum breaker surveillance was l
allowed to continue and two more vacuum breakers were cycled after the operators had discovered a problem with the 'B' torus-to-dtywell vacuum breaker. There issues were discussed in NRC inspection Report 50-354/98-02.
In contrast, the inspectors judged on May 5,1998, that control room operators appropriately and promptly declared a torus level instrument line motor operated valve inoperable after they had noticed problems with the valve on its open stroke during surveillance testing. The inspectors determined through interviews with operations superintendents and the assistant operations manager, that operatcrs had been sensitized to the human performance issues learned with the 'A' SACS pump extended surveillance testing. The asristant operations manager planned to incorporate the corrective actions for this problem into operator requalification training.
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Conclusions Control room operators were slow to declare safety-related equipment inoperable ('A' Service Water Pump, 'B' torus-to-drywell vacuum breaker and the 'A' safety auxiliaries cooling system pump) when faced with unexpected results during surveillance testing on three separate occasions. Although PSE&G later determined that each problem did not in fact render the equipment inoperable, the inspectors determined that the operators' delay in declaring safety-related equipment inoperable
- after the failed testing, demonstrated that operators did not always make conservative decisions. In response to these concerns, PSE&G appropriately assessed the human performance issues and intended to incorporate the lessons learned into requalification training.
il. Maintenance M1 Conduct of Maintenance M1.1_ Control Rod Drive Hydraulic Control Unit On-Line Maintenance a.
Insoection Scone (62707. 71707)
The inspectors reviewed PSE&G's plans associated with performing on-line maintenance for several control rod drive hydraulic control units (HCU), including the work plan and the reactor engineering maneuver outline. The inspectors also j
observed portions of the on-line maintenance and testing activities.
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Observations and Findinas
_PSE&G planned an on-line maintenance activity for 60 HCUs in order to remove g
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some of the HCU maintenance from the refueling outage. The planned maintenance activities, to be conducted from April 20 - 29,1998, included replacing the scram solenoid pilot valves (SSPV) and the pneumatic diaphragms for the scram inlet and outlet valves. The existing SSPV assemblies have an environmental qualification
.(EO) in-service life of five years. For the SSPVs that were changed, PSE&G installed SSPVs containing an upgraded elastomer (Viton A-B replaced the BUNA-N material),
which has an EQ in-service life of 15 years. ' The pneumatic diaphragms (BUNA-N)
for the scram inlet and outlet valves have a;12 year EQ in-service life.
l The inspectors reviewed the maintenance plan associated 'with this planned nine-day q
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activity, including procedures, tagouts, and Technical Specificat on applicability.
i The maintenance 12-hour shift organization led the maintenance efforts. An HCU
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-. mockup was used in the maintenance shop to prepare the maintenance workers for the job. The inspectors found this to be an excellent initiative.
In accordance with the reactor engineering maneuver outline, the operators reduced power to 80% for the on-line maintenance. After the nine day activity, PSE&G completed 36 planned HUC tagouts and associated maintenance. The inspectors observed that the organization proceeded safely and deliberately during the maintenance. The inspectors also observed supervisors in the field, properly controlling and overseeing the work. Following the maintenance, the activity was critiqued to identify lessons learned for future similar activities.
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Conclusions Maintenance personnel safely performed on-line maintenance on 36 hydraulic control units. Strong supervisory oversight of the activities was evident. -PSE&G provided critical assessments of the completed nine-day work activity, including work coordination and performance, to deveiop lessons-learned for similar future activities.
M4 Maintenance Staff Knowledge and Performance l
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M4.1 Performance.Wsaknesses bv Maintenance Workers
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Insoection Scone (627071
- The inspectors reviewed the details surrounding three examples of personnel errors i
by 12-hour shift maintenance workers. In addition, the inspectors observed other
L maintenance activities to assess overall conduct of_ maintenance. The inspectors
' interviewed selected maintenance personnel, reviewed related documentation, and toured applicable plant or system areas.
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I b.
Observations and'Findinas Wrong Service Water Valve Operated On April 3,1998, a 12-hour shift electrician was performing a 72 month thermal overload surveillance for service water system valve 1EAHV-21980. He went to the service water intake structure to verify the valve was not on' the hard seat as directed by the control room supervisor. However, when he entered the area, he checked the similar valve on the adjacent service water system,1EAHV-21988.
After turning the handwheel for the wrong valve, the electrician recognized his error and immediately informed the control room. The B and D trains of service water are associated with the same loop (B). Therefore, the loop was declared inoperable during the short time period (several minutes) that both 'B' ar)d 'D' trains were technically inoperable. Operators responded immediately and verified the 'B' train to be operable. : PSE&G's investigation determined that the root cause of this event was inattention to detail and failure to use self-checking techniques.
. Wrong Test Switch Operated Dudng SurveWence On April 6,1998, during conduct of a surveillance calibration for a reactor building differential pressure channel (PD-5029), a maintenance 12-hour shift nuclear worker mis-operated a test switch located inside logic cabinet 1 A-C655. The nuclear
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- worker operated a switch adjacent to the switch he meant to operate. When the wrong switch was operated, the control room received several alarms, which cleared immediately.
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After the nuclear worker operated the wrong switch, he immediately recognized his error and repositioned it. He then operated the correct switch.' However, these
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actions were performed without informing the control room or his supervisor.
Operators questioned the reason for the control room alarms and subsequently
' determined that the nuclear worker had mispositioned a test switch.
Maintenance completed an evaluation of this incident and determined that in addition to his error; the nuclear worker failed to meet management's expectations after realizing the e.ror. Specifically, the nuclear worker should have stopped and notified his supervisor immediately and requested further direction. The evaluation determined that the nuclear worker was not aware of management's expectations regarding the expected response if an error occurs, and that the cause of this event j
was inattention to detail.
Maintenance supervision used the nuclear worker to perform a simplified task of l-operating a single toggle switch, and identified the switch by use of an information
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tag. In response to this event, PSE&G re-evaluated its use of nuclear workers I
regarding the work they can perform, particularly on safety-related equipment. In j
addition, the maintenance manager conducted shop meetings stressing the need to j
stay focused on work activities and to maintain a high level of attention to detail.
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The inspectors reviewed PSE&G's evaluation of this event and found it to be adequate, including corrective actions. Surveillance procedure HC.lC-SC.GS-0008(O), Sensor Calibration - Containment Atmosphere Control-Division 1 (Channe/ PD-50291, controlled the test activity. The inspectors determined that the nuclear worker failed to comply with procedure HC.lC-SC.GS-0008(O). This failure
constitutes a violation of minor significance and is not subject to formal enforcement action.
Performance Error While Connecting Multiple Test Equipment Wires i
On May 8,1998, while performing response time testing of the high pressure coolant injection (HPCI) system following maintenance, an associated recorder failed to obtain the required data. The HPCI system was shutdown to determine why the data was not obtained. PSE&G subsequently determined that the polarity of the recorder leads was reversed. This occurred due to a performance error by a maintenance 12-hour shift worker, who apparently connected several lengths of leads together but had reversed the polarity. This error resulted in running the HPCI system an additional time and in a delay in restoring the safety-related system.
PSE&G initiated an Action Request to further evaluate this problem.
Maintenance Workers' Conduct of Routine Maintenance The inspectors found that the above routine maintenance activities had common performance deficiencies in that inattention to detail was a primary root cause contributor. During the inspection period, the inspectors noted a similar deficiency during maintenance in that technicians did not effectively use self-check and peer-check practices that are commonly used by operators. For example, during maintenance on safety related inverter DD482, where circuit cards were replaced, the electricians did not self-check per work standards (STAR concept; stop, think, act, review) while terminating connections for the new cards. In addition, operators typically use peer-checks by co-workers to verify steps / actions as they are being performed to obtain agreement with the planned action. This maintenance task did not use peer-checks during removal, installation, or connection of the circuit cards.
Although no errors resulted in this case, the inspectors observed that the workers were not implementing these important human performance improvement princip;cc.
The inspectors discussed this observation with the maintenance manager, who agreed that performance in this area, particularly during routine activities, needs further attention.
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Conclusions i
Maintenance workers did not make effective use of self and peer checks during work activities, which was not consistent with maintenance management's expectations. This manifested itself in several errors that occurred during routine maintenance activities. First, an electrician manipulated a service water system valve on the wrong trein during a 72 month surveillance. Second, a nuclear worker mis-operated a test switch while assisting instrument technicians performing a
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containment atmosphere control surveillance. The third error was the improper connection of several lengths of test equipment wires, resulting in a delay in restoring a safety system to service.
M8 Miscellaneous Maintenance issues M8.1 (Closed) LER 50-354/97-034-O'i: Operation in a tech'1ical specification (TS)
prohibited condition due to missed emergency diesel generator (EDG) surveillance.
This event involved overdue inservice testing of excess flow check valves in the 'D'
EDG air start system on December 26,1997. The details of this problem were described in NRC Inspection Report 50-354/98-01. PSE&G submitted this Supplement 01 to report a similar problem that had occurred on December 2,1997, involving the 'A' EDG. The inspectors reviewed LER 97-034-01 in office and determined that no new issues were revealed. The problem described in LER 97-034-01 is another example of the same TS 4.0.5 violation that was dispositioned in NRC Inspection Report 50-354/98-01. This licensee-identified and conected violation was treated as a Non-Cited Violation in NRC Inspection Report 50-354/98-01. Based on in-office review, the inspectors considered this LER closed.
Ill. Engineering E2 Engineering Support of Facilities and Equipment E2.1 Control Area Chilled Water Systems Desian Chanae Packsae Review a.
Insnection Scooe (37550. 37551)
The inspectors reviewed PSE&G's inservice test program and configuration controls that had been established for a design change on the control area chilled water systems (CACWS) during refuel outage number 7 (RF07).
b.
Observations and Findinas Backcround The CACWS consists of the control room chilled water system and the safety-related panel room chilled water system. Each subsystem maintains satisfactory ambient air temperatures for safety-related portions of the auxiliary building. The control room chilled water system supports the control room,1E switchgear rooms, diesel generator control rooms,1E battery and associated charger rooms, cable spreading rooms, control equipment room, ventilation equipment rooms, HPCI battery and associated charger rooms, and the RCIC battery and associated charger rooms. The control room chilled water system also provides cooling to the safety auxiliaries cooling system (SACS) room cooling units in the reactor building. The safety-related panel room chilled water system supports a non-1E control equipment
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room, some 1E inverter rooms, the non-1E inverter rooms, the technical support conter, and the remote shutdown panel room. The neat load on the safety related panel room chilled water system is about one-third the heat load on the control room chilled water system. There are four chillers, two in each subsystem. The control
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area chilled water system is designed to remain functional during a design basis.
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accident and to operate with a loss of offsite power.
The CACWS chillers are cooled by SACS. SACS is cooled by the service water system from the ultimate heat sink (the Delaware River). SACS heat exchanger
' outlet temperature is maintained by a air operated heat exchanger bypass
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temperature control. valve (TCV). When the heat exchanger TCV is full closed,.
maximum SACS flow is through the heat exchanger and maximum cooling from the Delaware River is being provided (See Figure 1).. The CACWS chiller condenser j
cooling flow, being provided from SACS, is throttled by an air operated PCV at the -
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chiller condenser outlet. The original desigr' for the air supply to both the SACS TCV and the chiller PCVs was from a non-safety-related air supply that is load shed during a loss of power event. During the loss of power event, the air supply to the
. valves would be lost, the TCV would fail closed and the PCV would fail open. With
' these conditions, maximum SACS cooling flow at the lowest possible temperature would be provided to the chiller condensers. PSE&G engineers have assumed that lowest possible chiller condenser cooling water temperature tc be equal to Delaware River water temperature.
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On August 28,1997, PSE&G engineers determined that the CACWS chillers would
- trip on evaporator refrigerant low pressure if maximum cooling flow below 55
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degrees Fahrenheit was established. PSE&G engineers concluded that this would
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exist during a loss of air supply, due to the loss of power event, concurrent with
Delaware River water temperature below 55 degrees Fahrenheit. PSE&G made a
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l four-hour report to the NRC on August 28,1997 when they determined that this
condition (Delaware River below 55 degrees Fahrenheit concurrent with a loss of
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power event) alone could have prevented the CACWS from fulfilling its safety
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function. At the time this discovery was made by the licensee, Delaware River temperature was 76 degrees Fahrenheit and it was not expected to drop below 55
, degrees Fahrenheit until November 1997. The initial discovery of this issue was
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described in detail in NRC Inspection Report 50-354/97-05. The associated
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Licensee Event Report (LER 50-354/97-020) was closed out in NRC Inspection Report 50-354/97-07.
l PSE&G engineers developed a design change package (DCP),4EC-3662-1,2,3,4&5 l
that provided a safety-related backup air supply to the each of the chiller condenser
. cooling water PCVs. The DCP ensured that the PCVs would continue to regulate cooling water flow to the chiller condensers even during's loss of power event.
l DCP 4EC-3662-1,2,3,4&5 was installed and successfully tested on all four CACWS
chillers prior to Delaware River temperature dropping below 55 degrees Fahrenheit.
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DCP 4EC-3662-1,2,3,4&5 was completed during Hope Creek refueling outage number 7 (RF07) and it was turned over to operations on November 24,1997, prior to restart from RF07,
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The DCP consisted of two nitrogen bottles that wow nrovide an air supply to each
- chiller condenser's PCV when the normal instrument air supply would be lost during a design basis accident. Each nitrogen bottle was supplied with a pressure g
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i regulator.' The backup nitrogen bottles pressure would remain in a reserve statur since the instrument air supply was nominally at a higher pressure (95 psig) than the bottle regulator settings (75 psig for one bottle and 50 psig for the other bottle).
Check valves would isolate the depressurized non-safety-related instrument air supply from the safety-related backup pneumatic supply during a loss of power event. The relatively leak tight boundary provided by the check valves and the pneumatic supply maintained in the nitrogen bottles would ensure the continued operability of the chiller condenser PCVs for four hours during a loss of power event. PSE&G engineers had determined that four hours would provide sufficient time for equipment operators to replace the nitrogen bottles. PSE&G engineers determined that pressure above 35 psig was necessary for proper PCV operation.
Becent insnection observations and findinas inservice Testing Requirements Not Established
,
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During the week of March 8,1998, NRC inspectors questioned PSE&G engineers to determine if preservice testing had been accomplished and if periodic inservice testing (IST) surveillance requirements were established for check valves 1KBV-1243, -1244, -1245, -1246, -1246, -1247, -1248, -1249, and -1250. On April 7, 1998 Hope Creek engineers verified that no preservice check valve seat leakage tests had been performed nor had they been included in an inservice test program.
A system exte nal leak test and a function test had been performed for the DCP during post-insta!!ation testing.10 CFR Appendix B Criterion XI requires in part that safety-related structures, systems, anri components will be included in a test
. program and tested in service to ensure that design requirements are satisfied.
Failure to establish inservice testing requirements for these eight' check valves and to perform periodically, those inservbe tests, is a violation of 10 CFR Appendix B Criterion XI. -(*/10 50-354/98-05-01)
- Safety-Related Pneumatic Supply Regulator Pressure Not Maintained On April 8,1998, in response to the problem identified by the NRC inspectors, Hope Creek IST engineers started a valve leak rate test for the 'B' control room chiller DCP check vales. Valve leak rate tests were intended for all the DCP check valves on all the CACWS chillers, but the 'B' control room chiller was selected first.
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The IST engineers first isolated the normal non-safety related instrument air to the
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'B' control room chiller condenser PCV in accordance with Hope Creek leak rate test
!
procedure, Leakage Test of Air Supply in-Line Check Valves for SACS Flow Control Valves to the Control Room and 1E Panel Room Chillers, HC.RA-IS.KB-0001(Q) -
REV. O, to st6rt the check valve leak rate tests. The equipment operators assisting the engineers audibly noticed a load change on the 'B' control room chiller and discovered that the condenser PCV had gone full open. The equipment operators
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_ further noticed that both 'B' control room chiller condenser PCV backup nitrogen bottle pressure regulators had been fully backed off and the regulators were set at
~ about zero psig. The equipmsnt operators were not previously able to verify the.
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bottle regulator pressure settings since they were normally set below the instrument air pressure at 95 psig compared to 75 psig and 50 psig. The outboard pressure indicator on the nitrogen bottle manifold reads line pressure and not necessarily regulator setpoint pressure.
Once the equipment operators discovered the problem with the configuration control ca the 'B'. control room chiller nitrogen bottle regulators, PSE&G promptly developed a troubleshooting plan for all the CACWS chillers to: (1) complete all the check
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valve leak rate tests, (2) investigate the setting and properly set all the nitrogen bottle regulators, and (3) determine an apparent cause for the improperly adjusted regulator settings..The 'A' safety-related panel room chiller was already in a schedried maintenance outage and was considered inoperable.
IST engineers completed the valve leak rate tests and determined the check valve leak' rate results to all be acceptable. Equipment operators discovered that all but the.'B' safety-related panel room chiller nitrogen bottle regulators were not set at
.the nominal values of 50 p=ig and 75 psig. Each chiller has two associated nitrogen bottle regulators (one regulator for each nitrogen bottle), with one regulator to be set at 50 psig and the other regulator to be set at 75 psig. The regulator as-found
' settings were:
'A' Control Room Chiller:
29 psig/44 psig
'B' Control Room Chiller:
O psig / 0 psig
- A' SR Panel Room Chiller:.40 psig/70 psig
'
'B' SR Panel Room Chiller: 50 psig/75 psig The control room operators considered the as found regulator settings and determined that both control room chillers would have been inoperable during periods when Delaware River water temperature was below 55 degrees Fahrenheit.
Delaware River water temperature was.55.5 degrees Fahrenheit and slowly trending up (due to seasonal changes) when PSE&G discovered that all control room chiller nitrogen bottle regulator settings were improperly adjusted and set below 35 psig, the pressure required for satisfactory PCV operation. Hope Creek made a four-hour
. report to the NRC on April 9,1998, similar to the four-hour report made by Hope-Creek on August 28,1997.
PSE&G could not exactly determine any single equipment operation that would have improperly adjusted the CACWS nitrogen bottle pressure regulators. All but the 'B
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safety-releted panel room chiller regulators were improperly adjusted. On Apri! 10, 1998, PSE&G properly readjusted all tiie chiller nitrogen bottle pressure regulators.
PSE&G determined that the DCP post-modifiestion testing had properly set the regulators (while instrument air was isolated from the bottles) before Hope Creek started up from RF07 in November 1997.10 CFR 50 Appendix B Criterion XI requires in part that testing be performed to demonstrate that structures, systems, l
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or components will perform satisfactorily in service. The NRC inspectors concluded that PSE&G had not established any measures to ensure that the CACWS nitrogen bottle pressure regulators remained above the minimum pressure for satisfactory chiller condenser PCV operation. Failure to properly maintain CACWS nitrogen bottle pressure regulators at the proper setpoint is a violation of 10 CFR Appendix B Criterion XI. (VIO 50-354/98-05-02)
Design Basis Change Not identified to Station Management
,
On April 9,1998, a PSE&G engineer recalled that the minimum Delaware River water temperature should have been 70 degrees Fahrenheit, instead of the 55 degrees, that was used in the CACWS chiller DCP basis. PSE&G determined that information had been received from an engineering consultant on December 10, 1997,' that suggested that 70 degrees Fahrenheit cooling water temperature was more appropriate for design considerations. The engineering consultant had identified that 55 degrees Fahrenheit cooling water temperature was appropriate for
,
chiller operation at about 100% load, but that 70 degrees Fahrenheit was more appropriate for chiller operation at about 10% load. PSE&G determined that they should have been considering 70 degrees Fahrenheit as the minimum cooling water temperature that should be allowed with the CACWS chiller backup air supply not available. On April 8,1998, control room operators were not familiar that CACWS chiller minimum cooling water temperature design basis was 70 degrees Fahrenheit.
j The NRC inspectors verified that Hope Creek abnormal operating procedure, Loss of Instrument Air and/or Service Air, HC.OP-AB.ZZ-0131(O) - Rev.14, also incorrectly stated 55 degrees Fahrenheit minimum temperature. The NRC inspectors concluded that the control room operators incorrectly determined, and the abnormal operating procedure did not contain, the correct minimum cooling water temperature that should be allowed with the CACWS chiller backup air supply not available.
]
On December 10,.1997, when PSE&G engineers had determined to change the CACWS chiller minimum cooling water design temperature, a new Action Request (AR) was not initiated. Rather than initiate a new AR, a corrective action item was assigned from one PSE&G engineer to another PSE&G engineer to incorporate the revised minimum cooling water temperature into applicable operating procedures, which included, Loss ofinstrument Air and/or Service Air, HC.OP-AB.ZZ-0131(Q) -
Bev.14. PSE&G nuclear station procedure, Corrective Action Program, NC.NA-AP.ZZ-OOO6(O)- Rev.15, requires in part that a new Action Request should be initiated if new information indicates that the condition has changed and there is greater impact on operability / deportability than originally determined. The NRC inspectors determined that on December 10,1997, PSE&G engineers were aware of a change to the design basis for the CACWS chiller operntbn, but the engineers failed to report this problem to PSE&G management by initiating a new AR, resulting in not correcting the known deficiency. This is a violation of 10 CFR Appendix B, Criterion XVI (Corrective Action). (VIO 50-354/98-05-03)
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c.
Conclusions
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. NRC inspectors identified that PSE&G failed to establish sufficient preservice and inservice testing requirements for a design modification installed during refueling outage RF07 to the safety related chillers, which was contrary to the requirements
. of 10 CFR 50, Appendix B (Test Control). Lack of inservice testing requirements allowed both trains of the safety-related control room chillers to be outside of its design basis and not able to perform its intended safety function. In addition, PSE&G failed to correct a known deficiency associated with the minimum cooling water design temperature for the chillers since December 1997.
)
E2.2 Irmdannate Filtration. Recirculation. and Ventilation Svstem (FRVS) Surv9%ca Test I
a.
Inanaction Scone (37551. 92700)
The inspectors conducted onsite inspection for an issue identified in Licensee Event Report 98-02, entitled " Technical Specification Prohibited Condition - Inadequate Filtration, Recirculation, and Ventilation System Surveillance Test."
b.
Observations and Findings Hope Creek technical specification required that FRVS heaters be verified on during the performance of a 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> test run once per 31 days. On March 15,1998, control room operators questioned the validity of a recent change in FRVS heater testing that was implemented by the FRVS monthly surveillance test, FRVS Operability Test - Monthly, HC.OP-ST.GU-0001(Q) - Rev.24. The change in test methodology was approved for use on November 21,1997. A light indication on the FRVS heater humidistat was used to verify that the heaters wm on when a full
!
on demand signal was applied to the heaters. Previous surveillance testing of the
,
FRVS heaters was performed on each heater phase using a clamp on ammeter and voltmeter. The control room operators considered that the new test method, checking light indication, may not positively indicate that the heaters were on. The control room operators initiated an action request for engineering to evaluate the new methodology for FRVS heater testing. In addition to challenging the new test methodology, control room operators also tested all FRVS recirculation and ventilation heaters using the previous method whereby amps and volts are measured to each heater phase on March 15,1998. The control room operators appropriately used a troubleshooting procedure to accomplish this task. The FRVS heaters passed the previous surveillance test method.
O'n March 20,1998, PSE&G engineers determined that the new FRVS heater test methodology was inadequate. The engineers identified a potential problem whereby the humidistat light indication could be lit, but the heaters could be not energized.
PSE&G had not adequately verified that FRVS heaters were on during FRVS operations since November 21,1997. Failure to verify that the heaters are on at least once per 31 days when FRVS is opeoting is a violation of Hope Creek technical specification 4.6.5.3.1.b. and 4.6.5.3.2.b.
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l The inspectors also reviewed LER 97-026-00 which may have identified similarities.
j
' LER 97-026-00 was described in NRC inspection Report 50-354/97-09 Section
. _ M8.3.. LER 97-026-00 described a licensee identified issue on October 20,1997, in which the same FRVS surveillance procedure, FRVS Operability Test - Monthly, NC.OP-ST.GU-DOOUO), was revised and the test methodology was changed that ultimately led to the inoperability of some FRVS trains. The problem described in i
LER 97-026-00 was treated as a non-cited violation. The NRC inspectors determined that although the problem described in LER 98-002-00 was also due to a
faulted procedure revision, the previous corrective actions that were taken for the i
particular problem were adequate.. The inspectors verified that PSE&G had completed another surveillance procedure revision to correctly verify FRVS heaters
on._ This non-repetitive, licensee identified and corrected violation is being treated l
as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Pohey. (NCV 50-354/98-05-04)
. c.
Conclusions
- On two separate occasions, PSE&G did not adequately evaluate procedure chnges
' that verified Filtration Recirculation and Ventilation System (FRVS) technical specification surveillance requirements, resulting in procedure non-compliances. The inadequate procedures in one case led to inoperable FRVS components and in the other case, inadequate test requirements. The inspectors considered LER 98-02 closed.
E2.3 Daaraded Calls in 125 Vdc Safety Related Batterv a.
- Inanection Scone (37551. 62707. 71707)
The inspectors reviewed PSE&G response to degraded voltage conditions on two
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cells of a safety related 125 Vdc battery. The inspectors interviewed operations, maintenance and engineering personnel, observed in-field activities and reviewed documentation.
b.
Observations and Findinas On May.14,1998, during the performance of a quarterly battery surveillance, L
operators declared the CD447 battery inoperable due to low cell voltages on one of
.the 60 cells. Specifically, cell No. 3 failed to meet the Category C minimum limit of l
.-2.07 volts as specified in Technical Specification Table 4.8.2.1-1. The cell reading
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i was 2.06 volts. In addition, another cell (No. 50) was below the Category A/B minimum limit of.?.13. volts but was greater than the Category C limit. Due to the inoperable battery, operators entered Technical Specification 3.8.2.1, which j.
required operators to restore the battery to an operable status within two hours or
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be in at least Hot Shutdown within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Operations, maintenance and engineering personnel evaluated the condition and j
postulated that the low voltage may be due to sediment buildup inside the cell, i
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which creates bridges across the plates. PSE&G developed an action plan to
- mechanically agitate the cell in an attempt to remove the sediment from the plates.
.,This action appeared successful in that, as the sediment fell to the bottom of the cell, the cell voltcce began to rise. Operators also placed the entire CD447 battery on an equalize charge, and began checking cell voltages for cells No. 3 and No. 50 every 15 minutes.
Within the next several hours, the cell voltages stabilized at 2.10 volts for cell No. 3 and 2.08 volts for cell No. 50. Accordingly, operators exited the shutdown requirement of Technical Specification 3.8.2.1. However, since both cells remained below the Category A/B limit of 2.13 volts, operators entered the applicable 31 day action requirement specified in Table 4.8.2.1-1. At the end of this inspection, this action requirement remained in effect.
The inspector reviewed PSE&G's response to this issue and concluded that the respnse was quick and appropriate. However, the inspectors discovered that an engineering system manager was not assigned to.the DC systems, in addition, there have been prior battery problems at both the Hope Creek and Salem stations.
The inspectors determined that PSE&G did not effectively trend battery cell performance, which may have predicted this problem based upon degrading cell performance. This is a weakness in monitoring system performance.
At the end of the inspection period, PSE&G was pursuing several options to fully restore the battery to an operable status, including single cell charges for the two degraded cells, replacing the two cells, or jumpering a single cell out of service via a j
c.
Conclusions Operations, maintenance and engineering personnel responded appropriately to degraded cell voltages in the CD447 safety related 125 Vdc battery. System engineering demonstrated a performance weakness in that a system manager was not assigned to the DC systems, and consequently, the degraded cells ' lad not been monitored and trended. Effective monitoring and trending may have predicted this
{
degradation and prevented a challenge to plant staff.
E8 Miscellaneous Engineering issue
. E8.1 (Closed) Unresolved item 50-354/98-03-03: Fuel Pool Coolina and Cleanuo Svstem Operation Beyond Design Basis a.
Innosction Scone (92901. 92903)
-The inspectors previously reviewed records and laterviewed personnel related to the i
fuel pool cooling and cleanup (FPCC) system operation during prior refueling outages, and opened unresolved item 50-354/96-03-03. Technical reviewers from j
the Office of Nuclear Reactor Regulation reviewed and further evaluated this item.
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Specifically, Hope Creek's conformance with design basis assumptions regarding
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spent fuel pool decay heat loads was reviewed.-
b.
Observations and FindiDER Section 9.1.3.1, Design Beses, of the Hope Creek Final Safety Analysis Report (FSAR) (Revision O) states that the FPCC system is designed to:
handle the decay heat released by all combinations of spent fuel that could be stored in the fuel pool. The pool water temperature is maintained at a maximum of 135' F under the design load of 16.1 x 108, Btu /h. This heat load is based on 16 consecutive refuelings with cne-third of the core removed during each refueling, and on a refueling frequency of 18 months.
. The FPCC is de*igned to permit the residual heat removal (RHR) system to be operated in pr..llel with the FPCC through a crosstie, to remove the maximum heaj :oad and to maintain the bulk water temperature in the spent fuel pool at or below 150' F, with a maximum anticipated heat load of 34.2 x 108 Btu /h. This is based on one full core load of fuel at the end of a fuel cycle, plus the decay heat of the spent fuel discharged at the thirteen previous refuelings. If required, one RHR pump and one RHR heat exchanger
. can be aligned to augment the FPCC system through the system crosstle.
Further, Section 9.1.3.2.2, System Operation, states:
"The FPCC system design heat load is 16.1 x 10 ' Btu /h. This is the decay heat expected from 16 consecutive refuelings. The FPCC system's maximum hest load is 34.2 x 10' Btu /h. This is the decay heat expected if it becomes necessary to unload the entire core from the reactor and store it
.in the pool, which already contains fuel from thirteen' previous refuelings. For this core unload design condition, an RHR heat exchanger is operated in parallel with the FPCC system."
' The inspectors reviewed records from past refueling outages and determined that PSE&G had performed full core unloads during refueling outages RF03 in December 1990 and RF04 in September 1992. The inspectors reviewed records and i <
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, evaluations from those outages and determined that PSE&G did not operate the RHR l
system in parallel with the FPCC system as described in FSAR Section 9.1.3.2.2 during either RF03 or RF04.
With regard to RF03, the inspectors determined that the RHR system was not operated in parallel with the FPCC system during the time the full core was offloaded into the fuel pool. More significantly, the RHR system was not maintained available to be placed in operation in the event that the FPCC system experienced a failure during RF03. Although alternative means to ensure the decay heat could be removed from the spent fuel pool during that period were evaluated, PSE&G did not
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perform such reviews pursuant to 10 CFR 50.59. This is a violation. (VIO 50-354/98 05-05)
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With regard to RF04, the inspectors determined that PSE&G identified a need to maintain the RHR system available for augmenting the FPCC system as part of the outage planning and review process prior to the start of the outage. In response, records indicate that PSE&G modified system outage windows to ensure an RHR train was available to augment the FPCC system. The inspectors concluded that by maintaining the RHR system available, PSE&G operation was consistent with the FSAR description of the system operation.
The inspectors observed that Section 9.1.3.2.2, with use of the phrase "if it becomes necessary to unloaa the entire core..." suggests that it would not always be necessary to offload the full core during a refueling outage and thus, that partial core offloads were to be the more routine practice. The inspectors were unable to conclude, however, that Section 9.1.3.2.2 represents a specific commitment to limit the frequency with which full core offloads are conducted, importantly, nothing in the FSAR description of the spent fuel pool cooling design basis ii. sensitive to the frequency with which full core offloads are conducted. Therefore, the inspectors concluded that, by itself, the practice of offloading the full core during refueling outages RF03 and RF04 did not represent r, change to the facility or a change to the procedure described in the FSAR and thus did not require a review pursuant to 10 CFR 50.59. This inspection completes the review of NRC unresolved item 50-354/96-03-03, which is considered closed.
c.
Conclusions During refueling outage RF03 in 1990, contrary to procedures, the RHR system was not operated in parallel with the FPCC system during the time the full core was offloaded into the fuel pool. More significantly, the RHR system was not maintained available to be placed in operation in the event that the FPCC system experienced a failure during RF03. Although alternative means to ensure the decay heat could be removed from the spent fuel pool during that period were evaluated, PSE&G did not perform such reviews as required by 10 CFR 50.59.
IV. Plant Suonort R4 Staff Knowledge and Performance in Radiological Protection and Chemistry Controls R4.1 Non-Conservative Actions While Precarino to Discharoe Liould Effluent a.
Insoection Scone (71707. 71750)
The inspectors reviewed the details associated with an activity were chemistry personnel initiated inappropriate actions while preparing for a radioactive liquid
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effluent discharge. The inspectors reviewed applicable w cementation and interviewed chemistry and radiation protection (RP) personnel.
b.
Observations and Findinas On April 15,1998, RP personnel rejected a liquid release permit for the 'A'
detergent drain tank (DDT) because the calculated setpoint for the associated radiation monitor (RE8817) was below the default value specified in procedures.
After RP initially rejected the release, chemistry personnel discussed adding liquid with higher activity to raise the 'A' DDT activity above the setpoint as a means to resolve the condition. A chemistry technician and a chemistry supervisor determined that the proposed action was not forbidden by procedures, so they proceeded to transfer the 'A' DDT to the 'B' DDT, which had a higher activity. A radwaste operator questioned the proposed process, but was informed that the evolution was approved by the chemistry supervisor. After the liquid transfer, the
'B' DDT activity decreased an insignificant amount, which indicated a corresponding insignificant increase in the "A" DDT. RP and chemistry management became aware of these actions before any release was initiated and promptly stopped all related activities and initiated an Action Request (980415270) to evaluate the event.
PSE&G evaluated this event and found that the reason the initial sample of the 'A'
DDT was low was due to a clogged sample processing filter and differential pressure gauge. Chemistry determined that the initial sample was not representative of the
~ full contents of the 'A' DDT. More significantly, chemistry's investigation concluded that lack of supervision and poor communications between the chemistry techaician and chemistry supervisor were the apparent causes of the event, and the approach taken by personnel involved was non-conservative.
The 'A' and 'B' DDTs were subsequently processed, and the.'A' DDT was released with a new release permit.
The inspectors reviewed PSE&G's evaluation and determined that it was acceptable and developed appropriate corrective actions. The chemistry superintendent reinforced supervisory expectations to all chemistry department supervisors and discussed conservative decision making and open communications with chemistry and radwaste personnel.
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. c.
Conclusions Chemistry and radwaste personnel non conservatively attempted to ir. crease the activity of a planned liquid release to raise the activity above the existing low level setpoint of the radiation monitor. Although this _ release did not occur because a
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radiation technician rejected the release permit, the actions by chemistry and radwaste personnel demonstrated a poor safety perspective and a poor questioning attitude, a
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P2
. Status of Emergency Preparedness, Facilities, Equipment, and Resources P2.1 Maior Loss of Offsite Communications Canability a.
Insoection Scone (71707, 93702)
The inspectors reviewed PSE&G's response and follow-up to a major loss of the telephone communications system, b.
Observations and Findinas On May 14,1998, at 2:15 a.m., PSE&G reported tc the NRC that a major portion of I
the telecommunications system was inoperable, t.icluding the emergency notification system (ENS). All of the common carrier digital lines and most of the nuclear emergency telecommunication system (NETS) lines were inoperable. The Hope Creek and Salem control rooms each had at least three operable NETS lines.
In addition, each control room had at least one operable microwave tie line from Newark, NJ, and control room personnel had several cellular phones available for use.
PSE&G identified that the telecommunications system was inoperable at 1:40 a.m.
on May 14,1998. The subsequent investigation identified that a disconnect switch to a telecommunications inverter was open, and that the standby telecommunications system battery was discharged. Upon discovery of the open disconnect switch, PSE&G entered the potential tampering procedure.
Telecommunications technicians respraded to the site and restored the system at I
4:40 a.m. At 4:45 a.m., operations personnel notified the NRC via ENS that the phones had been restored.
PSE&G subsequently determined that a Salem equipment operator (EO) had entered the normally locked onsite telecommunications building shortly after midnight on May 14 in response to a high room temperature alarm that had annunciated in the
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Salem control room. The EO found that the ventilation system had tripped and caused the high room temperature condition. PSE&G concluded that the EO must have inadvertently and unknowingly bumped the breaker knife switch, resulting in tripping the breaker op~a At the same time, PSE&G concluded that the one hour telecommunications system battery unit had begun to power the telecommunications system until around 1:40 a.m., when the battery depleted and the telecommunications system failed.
The NRC Operations Center conducts daily checks of the ENS by calling each control room ENS telephone. According to the Salem senior reactor operator log on May 15, at 5:00 a.m_., it was recognized that the ENS riagdown was inoperable.
l That is, the phone functioned, but did not ring for incoming calls. That same day, l'
the NRC Operations Center initiated a trouble ticket to repair the inoperable ringdown feature of the ENS at 10:52 a.m. Later on May 15, around 1:"i p.m., the inspectors requested that the Hope Creek operators perform a check of the ENS by E_-_--________
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calling the NRC Operations Center and requested that the Operations Center call them back. The operators reported that the Hope Creek ENS line did not ring. The ENS circuit was otherwise operational. At 7:30 p.m. on May 15, PSE&G verified
- that the ENS line was fully functional after it was repaired by contractor telephone
' repair personnel. The ringdown problem was apperently due to a combination of a
' degraded multi-pin connector and re-powering the telecommunications system.
The inspector concluded that PSE&G properly responded to the loss of the telecommunications system and identified those telephones capable of establishing and maintaining communications. However, the operators' test of the ENS did not fully test the system, and consequently, the identification of its continued minor degradation was delayed by about one day. PSE&G's initial investigation into the root cause of the problem was acceptable, and a follow-up investigation was continuing at the end of this inspection. Follow-up system testing was planned to confirm the results of PSE&G's investigation conclusions.
c.
Conclusions The site operations departments (Hope Creek and Salem) responded promptly and appropriately to a major loss of the telephone communications system. Following the rest' oration of the major loss, operators were slow to recognize continuing minor degradation of the emergency notification system.
V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 28,1998. The licensee acknowledged the findings presented.
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. INSPECTION PROCEDURES USED IP. 37551:
Onsite Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 92901:
Folicruup - Plant Operations IP 92903:
Followup - Engineering IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED AND CLOSED Opened 50-354/98-05-01 VIO Failure to establish IST requirements. (E2.1)
50-354/98-05-02 VIO Failure to properly maintain CACWS nitrogen bottle
pressure regulators at the proper setpoint. (E2.1)
50-354/98-05-03 VIO Ineffective corrective action for a change of design basis for the CACWS chiller operation. (E2.1)
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50 354/98-05-05 VIO RHR system not operated in parallel with the FPCC
system during the time the full core was offloaded into the fuel pool. (E8.1)
Opened / Closed R
l 50-354/98-05-04 NCV Inadequate FRVS surveillance test. (E2.2)
Closed 50-354/97-034-01 LER Operation in a TS prohibited condition due to missed EDG surveillance. (M8.1)
50-354/98-02-00 LER Operation in a TS prohibited condition due to inadequate
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FRVS surveillance. (E2.2)
50-354/96-03-03 URI Rr1R system not operated in parallel with the FPCC system during the time the full core was offloaded into the fuel pool. (E8.1)
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i LIST OF ACRONYMS USED
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AR Action Request l
CACWS Control Area Chilled Water System d/p Differential Pressure DCP Design Change Package DDT Detergent Drain Tank
.EDG Emergency Diesel Generator ENS Emergency Notification System EO Equipment Operator EQ-Environmental Qualification FPCL
. Fuel Pool Cooling and Cleanup FRVS Filtration, Recirculation, and Ventilation System FSAR Final Safety Analysis Report i
_ Hydraulic Control Units HPCI High Pressure Coolant injection IST Inservice Testing
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NETS Nuclear Emergency Telecommunication System NRC Nuclear Regulatory Commission PDR Public Document Room j
PSE&G Public Service Electric and Gas RCIC Reactor Core isolation Cooling
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RP-Radiation Personnel
SACS Safety Auxiliaries Cooling System SSPV Scram Solenoid Pilot Valves TCV Temperature Control Valve
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'TS Technical Specification USQ Unreviewed Safety Question
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