IR 05000272/1994019

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Insp Repts 50-272/94-19 & 50-311/94-19 on 940807-0917.No Violations Noted.Major Areas Inspected:Operations, Radiological Controls,Maintenance & Surveillance Testing,Ep, Security,Engineering/Technical Support & Safety Assessment
ML18101A284
Person / Time
Site: Salem  PSEG icon.png
Issue date: 10/12/1994
From: Jason White
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18101A283 List:
References
50-272-94-19, 50-311-94-19, NUDOCS 9410180073
Download: ML18101A284 (82)
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Report No License No Licensee:

Facilities:

Dates:

Inspectors:

Approved:

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

50-272/94-19 50-3II/94~19 DPR-70 DPR-75 Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station August 7, 1994 - September 17, 1994 C. S. Marschall, Senior Resident Inspector J. G. Schoppy, Resident Inspector T. H. Fish, Resident Inspector J. C. Stone, Project Manager, NRR D. H. Moran Projec Man r, N 2A Insoection Summary:

/~y Da e This inspection report documents inspections to assure public health and safety during day and backshift hours of station activities, including:

operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification. The Executive Summary delineates the inspection findings and conclusion PDR ADDCK 05000272 G

PDR

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SALEM EXECUTIVE SUMMARY Salem Inspection Reports 50-272/94-19; 50-311/94-19 Hope Creek Inspection Report 50-354/94-19 August 7, 1994 - September 17, 1994 OPERATIONS (Modules 60705, 71707)

Salem:

The inspectors noted that, during the five week inspection period, Salem Unit 1 reduced power twice, and Salem Unit 2 reduced power six time Balance of plant equipment problems cause all eight power reduction The inspectors concluded that the licensee demonstrated appropriate plant operation in reducing power in cases for which regulatory requirements did not mandate a power reductio The inspectors also concluded that an inordinately high number of non-safety related equipment failures presented an unacceptably high potential for challenges to safe plant operation. Operator response to a reduction in turbine auxiliary cooling flow was prompt and appropriat During the shutdown in response to damage to the condensate header, the inspector noted appropriate command and control by the Nuclear Shift Supervisor. The reactor operators closely observed appropriate key plant parameters during the power reduction, and coordinated well with equipment operators in directing the shutdown of secondary plant system The inspector noted that operators performed a safe, deliberate shutdown controlled by procedures. The licensee's initial response and subsequent corrective actions following a circulating water manway failure were prompt and appropriat Maintenance activities were well-controlled and the root cause investigation was thoroug In response to emergency diesel generator power oscillations during a surveillance, the inspector determined that plant staff dealt

adequately with the degraded EOG performance, but noted that operations personnel did not initially have sufficient basis for their determination of EOG operabilit MAINTENANCE AND SURVEILLANCE (Modules 61726, 62703, 92902)

Salem:

The licensee appropriately evaluated and repaired damaged portions of the condensate heade Instrumentations and controls staff demonstrated trouble shooting competence and detailed knowledge of circuit design in investigating the cause of inadvertent rod steppin ENGINEERING AND TECHNICAL SUPPORT (Modules 37551, 71707, 92903)

Salem:

The inspector closed an open item involving accumulator level alarm setpoint discrepancies. A control oil power unit filter maintenance activity was well conducted and controlled; however, control oil power unit.system performance continues to be an engineering problem that affects plant *

operations. The licensee continues to rely on short-term corrective measures to address long-standing problems with the diesel air start system, although they are considering upgrading carbon steel components to stainless steel to ii

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reduce corrosion induced failures. Marginal control air system performance continues to pose a challenge to uneventful operatio Inspectors closed an Unresolved Item concerning Safety Injection Accumulator level alarm setpoint discrepancies. Based on the inspector questions concerning the adequacy of Technical Specification definition of controlled leakage, the licensee requested that Westinghouse determine the correct definition of controlled leakag This item will remain open pending review of the determination by Westinghouse and the licensee. The licensee took appropriate action to address feedwater nozzle weld problems and thermal sleeve erosio PLANT SUPPORT (Modules 71707, 71750, 92700, 92904)

Salem:

The licensee responded promptly and. in accordance with prescribed procedures in response to elevated containment radiation readings. Radiation levels did not impose increased radiological risk to plant workers or the general public and the increased levels did not exceed regulatory limit INSPECTION COMMON TO SALEM AND HOPE CREEK:

ENGINEERING AND TECHNICAL SUPPORT:

The project managers considered the program to meet the requirements of 10 CFR 50.59 adequat They identified that during the development of safety evaluations, the review process may not address completed modifications not yet entered in the FSA The project managers left this as an item for further inspectio iii

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SUMMARY OF SALEM OPERATIONS Salem Units 1 and 2 Unit 1 began the report period at full power and operated continuously until August 24, when operators reduced power to 1% (Mode 2, Startup) to repair the condensate system suction heade Following repairs, operators synchronized the generator to the grid on September On September 2, they reduced power to 45% to replace an 0-ring in the test solenoid for one of the main turbine intercept valves. Once Maintenance replaced the 0-ring, operators raised output to full powe The unit remained on line through the end of the inspection perio Unit 2 began the period at full powe On August 11, operators reduced power to 80% in response to a main generator rectifier high temperature alar On August 11, operators reduced power to 50% to replace filters on the steam generator feed pump (SGFP) control oil power units (COPU).

On August 12, operators increased power to 100%.

On August 22, operators reduced power to 80% following a loss of a turbine auxiliaries cooling (TAC) pum On September 9, operators began a load reduction to 50% power to replace SGFP COPU filter On September 11, operators further reduced power to 19% in response to a problem opening the No. 23 turbine governor valve. Technicians corrected a governor valve control pushbutton malfunction and, on September 12, operators returned Unit 2 to 100% powe On September 13, operators again reduced power to 50% to replace the No. 21 SGFP COPU filte On September 14, operators returned Unit 2 to 100% power, where it remained for the remainder of the perio The inspectors noted that, during the five week inspection period, Salem Unit 1 reduced power twice, and Salem Unit 2 reduced power six time Balance of plant equipment problems caused all eight power reduction The inspectors concluded that the licensee demonstrated appropriate plant operation in reducing power in cases that regulatory requirements did not mandate a power reductio The inspectors also determined that an inordinately high number of non-safety related equipment problems presented an unacceptably high potential for challenges to safe plant operatio.0 SALEM OPERATIONS Inspection Activities The inspectors verified that Public Service Electric and Gas (PSE&G)

operated the facilities safely and in conformance with regulatory requirement The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety

system status and Technical Specification compliance, and review of facility record The inspectors performed normal and back-shift inspections, including 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> of deep back-shift inspection.2 Inspection Findings and Significant Plant Events 2.2.1 Salem Turbine Auxiliary Cooling Flow Reduction On August 21, 1994, operators removed the No. 23 turbine auxiliaries cooling (TAC) pump for repair. The No. 21 and No. 22 TAC pumps remained in service. The TAC system provides condensate quality water for cooling various turbine auxiliaries, generator auxiliaries, and secondary plant components in a closed loo TAC pumps (three per unit)

are each capable of supplying 50% of the design system flo Normally two pumps are running, while a third pump is kept in automatic standb On August 22, the No. 21 TAC pump tripped on thermal overloa The senior shift supervisor promptly directed a power reduction to 80% to reduce heat load on the TAC syste The operating crew quickly stabilized the plant and increased monitoring of affected component Within an hour, maintenance restored the No. 23 TAC pump to servic Operations continued to monitor the TAC system closely while returning the unit to 100% powe The inspector noted that the operating shift took prompt and appropriate corrective action The inspector noted that the operating shift relied heavily on their experience since no guidance exists for TAC system problems. Operators also depended upon a limited number of overhead annunciators and increased local monitoring of temperatures to monitor TAC system performanc The senior shift supervisor directed the reduction to 80% power based upon operating experienc The inspector noted that the senior shift supervisor correctly determined that loss of the TAC pump required a reduction to 80% powe The inspector noted, however, that other shifts may not react in the same manner since no documented guidance exists for loss of TAC pump Additionally, the inspector observed that a locked-in Generator Stator Coil in/out temperature high overhead annunciator, caused by a failed temperature sensor, could have masked an actual stator winding cooling water high temperature condition. Operators considered stator cooling water temperatures among the more critical and sensitive parameters during operation with reduced TAC flo Plant staff generated a work request to correct this problem on July 10, 199 Maintenance staff completed the sensor repair on September 6, 199 The inspector concluded that the potential for performance error imposed by the failed temperature sensor demonstrated a need for more prompt repair of systems or components that have the potential to affect the operators' ability to control plant operation.

  • 3 Rapid Shutdown in Response to Condensate Suction Header Damage At 9:18 a.m. on August 29, operators commenced a rapid shutdown from 75%

power in response to extensive damage to the condensate suction header pipe supports and expansion joints. The cause of the damage is discussed in section 3.3.1.A, belo During the shutdown the inspector noted appropriate command and control by the Nuclear Shift Superviso The inspector observed that the reactor operators closely observed appropriate key plant parameters during the power reduction, and coordinated well with equipment operators in directing the shutdown of secondary plant system The inspector noted that operators performed a safe, deliberate shutdown controlled by procedure Condenser Waterbox Upper Manway Failure On August 30, 1994, operators initiated maintenance involving the 23A circulating water (CW) pump for maintenance. At 12:14 a.m. on August 31, 1994, upon restoration, operators started 23A CW pum At 12:15 a.m. in response to decreasing levels in all of the heater drain tanks, a Unit 2 control room operator began reducing load at 1% per minut At 12:16 a.m. an equipment operator in the turbine building reported that large amount of water coming from the 22A waterbo Operators immediately stopped the 22A CW pum At 12:17 a.m. the equipment operator reported that the water actually came from the 23A manwa Control room operators stopped the 23A CW pum In approximately four minutes, the time that the 23A CW pump remained in service after the manway failed, between 30,000 and 50,000 gallons of water spilled into the Unit 2 turbine building from the failed manwa Operators reduced power to 75% and stabilized the plant. The turbine building drains and sump pumps removed the water from the lower level, as designe The operators increased monitoring of potentially effected components to ensure continued equipment reliabilit The licensee determined that when operators started the 23A CW pump, failure of a weld designed to hold a tie-down bolt in place allowed the manway cover to ope The licensee inspected all other waterbox manways and found no other failed or suspect weld On September 2 maintenance completed repairs to the 23A waterbox upper manway and operators restored the 23A circulator to servic On September 1, after verifying that the spill had not effected equipment necessary for full power operation, operators restored power to 100%.

The inspector noted that operators performed the appropriate actions from procedure 52.0P-AB.ZZ-0002 "Flooding". The inspector determined that no safety related equipment was damaged or threatened by the inciden The inspector considered the licensee's increased monitoring of potentially affected components appropriate. The inspector observed repair work on the damaged manway and found the activity properly

  • controlled and performed. The inspector noted that the licensee's root cause investigation was thorough and included a study of related industry event Operab;1;ty Determ;nat;ons On September 12, during a surveillance for the Salem Unit 1 No. IA emergency diesel generator (EOG), operators found that they needed to continuously adjust the governor to prevent electric power output from drifting above the range noted in the acceptance criteria. Operators evaluated the EOG performance, and determined that the EOG remained operabl The operators based their conclusion of operability on the determination that an electrical controls problem caused the oscillation and affected EOG operation only in the test mod The operators concluded that the ability of the EDG to operate under accident conditions remained unaffecte In addition to considering EDG operability, operators initiated a work request to trouble shoot and resolve the oscillatio The inspectors questioned the basis for the operators' determination of operability. The system engineers informed the inspector that no absolute basis existed to support the operators conclusions that the cause of the oscillations affected only the test mode of the EDG at the time of the initial operability revie As a result of the work requests, system engineers assisted in trouble shooting that resulted in replacement of components in both the mechanical and electrical governor Notwithstanding, the licensee demonstrated that the governor problems did not affect the ability to carry accident loads or to maintain constant frequency and consequently, operability of the EDG was not affecte As a result, the licensee concluded that the IA EDG governor problem did not affect operabilit Overall, the inspector determined that plant staff dealt adequately with the degraded EDG performance, despite the operators' initial lack of a valid basis for the operability decisio The inspector noted that, while.operators had received training on making operability determinations, they did not have clearly defined guidance relative to the process of applying criteria to formulate a valid decision of operability. The inspector concluded that, in the case of the IA EDG, the operators did not have the expertise necessary to assess the governor proble Notwithstanding, the operators felt responsible to determine operability without consulting the resources available in engineerin In response to this and previous inspector concerns of weakness in operator guidance on operability, Operations management developed a flow chart to provide guidance to operators for future

. operability determination The inspector also found that system engineers had not received training on operability determination In response to the inspector observation, plant management issued a copy of NRC Generic Letter 9I-I8 to system engineer Plant management planned additional training for system engineer The inspector noted that a member of the Salem Safety Review Group (SRG)

and a Quality Assurance auditor had independently identified the oscillation as a concern and questioned the basis for the operators'

operability determinatio.0 MAINTENANCE AND SURVEILLANCE TESTING Maintenance Observations The inspectors observed selected maintenance activities on safety-rel ated equipment to ascertain that the licensee conducted these activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard The inspector observed portions of the following activities:

Unit Salem 1 Salem 1 Salem 1 Salem 1 Salem 1 Salem 2 Work Order(WO) or Design Change Package CDCPl WO 940818105 WO 940814107 WO 940810169 WO 940820047 WO 940910031 WO 940812146 Descriotion Data Collection During 2A EOG Surveillance 15 CFCU Motor Cooler Head Gasket Replacement Repair 130' Air Lock Door Linkage 13 Condensate Pump Mechanical Seal Replacement 118 11 Reactor Trip Breaker/Six Month Inspection 21SW53 Check Valve Repair The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance progra.2 Surveillance Observations The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance package The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, approved *

procedures, and NRC regulation..

The inspector reviewed the following surveillance tests with portions witnessed by the inspector:

Unit Salem I Salem I Salem 1 Procedure N SI.OP-ST.CAN-0004 SI.OP-ST.DG-0001 SI.IC-ST.SSP-0013 Test Containment Air Lock Local Leak Rate Test IA Diesel Generator Surveillance Test Functional Test Reactor Trip Breaker Operability Test The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra.3 Inspect;on f;nd;ngs 3.3.l Salem Condensate Suct;on Header Damage On August 24, at 9:I8 a.m., Unit 1 operators commenced a rapid shutdown from 75% power in response to damaged pipe supports and expansion joints in portions of the condensate suction header. Operators reached Mode 2 shortly after noo The damage to the header occurred when equipment operators removed No. 12 condensate pump from service for repai As required by procedure, the operators stopped the pump, isolated the recirculation line, closed the discharge valve and its bypass valve, and began to close the suction valve (see figure 1).

As the equipment operator closed the suction valve, the rubber expansion joint located between the suction valve and the pump over-pressurized and partially failed so that water began spraying from the joint. The operator could not re-open the suction valve because of the large differential pressure (dp) across the valve. The operator notified the control room of the ruptured joint and that he could not open the suction valv The shift supervisor directed the operator to relieve pressure from the expansion joint by un-isolating the recirculation line. Once the operator accomplished this, leakage from the joint dropped significantly. The shift supervisor also contacted the system engineer, who discovered the suction piping support anchor pedestal and two other expansion joints were damage The licensee also found that the disc of the discharge bypass valve had separated from its ste The licensee determined that the discharge pressure of No. II and No. 13 condensate pumps had forced condensate flow back through the No. 12 condensate pump discharge bypass valve and discharge check valv The back leakage pressurized the pump suction line to about 200 psi (The

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Figure 1 - Salem Condensate System

~.s..,.rt um. (llillilll)

ilJ -*-111 ueluirpMeiiaal

--1'""\\..r -41ll,lla.ia* pint pump suction line normally operates at a vacuum.)

The resultant dp developed across the pump suction valve generated a very large axial force that shifted the suction header about 2 inches. Staff engineers calculated that the dp acting on the suction valve (a 30 inch gate valve) developed approximately 130,000 pounds of forc Engineering considered the anchor pedestal damage, pipe movement, and the pipe support skid displacement consistent with the calculated forc Licensee corrective actions included repair of the damaged components and inspection of No. 11 and No. 13 condensate system piping, as well as Unit 2 condensate system, for similar indications of wear or failur The operations staff also revised the procedure for removing a condensate pump from service so that operators close the suction valve before closing the recirculation valve. This process diverts any potential back leakage to the condenser, minimizing the possibility of pressurizing the suction pipin *

The inspector noted that the Engineering analysis adequately explained the observed damage to the suction header and that the corrective actions appropriately addressed the causes. The inspector observed that maintenance staff adequately controlled repair activities, and noted direct involvement of system engineering and quality assurance personnel throughout the event review, cause analysis, and restoration activitie "

8 Rod Control Process Circuitry During the inspection period, operators at Salem unit 2 observed that bank D group 2 rods occasionally stepped in with no obvious deman After the initial observation at unit 2, operators at unit 1 also observed that bank D group 2 rods occasionally stepped in with no obvious deman The rod control system inputs are Tavg (the average of reactor coolant system (RCS) hot leg temperature and RCS cold leg temperature), Tref (a signal representative of main turbine power), and auctioneered high nuclear powe The licensee found that process noise from nuclear instrumentation and Tavg caused the intermittent rod stepping. Westinghouse informed the licensee that the change to low leakage core design had reduced nuclear instrumentation current as a result of fewer neutrons reaching the neutron detectors. The reduced NI current required greater amplification of the NI signal. The increased gain also amplified the existing nois The rod control signal processing circuitry reacted to the noise, appearing as current spikes, as sudden rapid increases in nuclear powe As a result, the rod control circuit intermittently generated rod movement deman The licensee concluded that rod control had generated demand for steps out of, as well as into the core. Operators only observed the rods step inward, since the rods were typically fully withdraw The licensee also concluded that the rod stepping has occurred since the change to low leakage core desig The inspector noted that the licensee's attention to this matter was an apparent result of increased emphasis on documenting equipment performance problem Westinghouse informed the licensee that they have developed a neutron monitor canister that uses a polyethylene moderator material to increase

, thermalization of epithermal neutron Use of this design increases NI detector current, reducing the required signal amplification and thereby reducing the effect of noise on the signal processing circuitry. The licensee learned that Zion and Indian Point had installed the canister with positive result In addition, Westinghouse has recommended that other licensees reduce the lead time constant in the Tavg lead/lag circuit to reduce modulation of the Tavg signal by process nois At the end of the inspection period, the PSE&G engineering organization had initiated a review of the two measures to determine the feasibility of installing the neutron monitor canister and reducing the lead time constant in the Tavg lead/lag circui *

The inspectors noted that the technical support organization efforts in responding to the rod stepping were initially somewhat delayed since, as a result of previous transients caused by trouble shooting activities, the licensee initiated a careful, very deliberate process designed to eliminate the introduction of transient during trouble-shootin The inspectors also noted that the trouble shooting process thoroughly investigated and determined the cause of an intermittent conditio The inspectors concluded that the Instrumentation and Controls staff demonstrated trouble-shooting competence and detailed knowledge of the signal processing circuit desig The inspectors also noted that

  • Westinghouse had previous knowledge of the effect of low leakage cores on the rod control signal processing circuitry, but had not effectively conununicated that knowledge to all licensee.0 ENGINEERING Salem Diesel Starting Air System Deficiencies At 1:26 a.m. on September 8, 1994, a Salem nuclear equipment operator found the 2C emergency diesel generator 'A' starting air receiver pressure at 165 psi The 'B' receiver pressure was at 220 psi Operator logs specify a minimum allowed pressure of 200 psi In response, control room operators conservatively declared the diesel inoperabl Equipment operators started the 'B' air compressor and restored A receiver pressure to greater then 200 psig. Operators declared the 2C diesel operable at 1:40 a.m. on September The licensee determined that leakage past the 'A' receiver drain valve, when the A receiver air compressor was tagged out for maintenance, allowed the receiver pressure to decrease. With pressure in the 'A' or

'B' air receiver at or below 200 psig and both compressors in standby, system controls are expected to automatically start both compressor Operators did not know, however, that with the 'A' air compressor electrical supply breaker open, the 'B' compressor would not get a start signal when the 'A' air receiver pressure dropped to 200 psi Consequently, the inspectors noted that operation of the air start system with one compressor out of service requires increased operator awareness and monitoring to prevent a drop in air receiver pressure less than 200 psig. The licensee has planned action relative to this matte The inspector also noted that a significant number of previously identified deficiencies posed challenges to system reliabilit On June 25, 1994, the licensee identified that the 'A' receiver drain valve on the 2C diesel leake The licensee identified other leaking diesel air receiver drain valves dating back to May 21, 199 The inspector noted that all air receiver drain valves, on both units, leak somewhat (normally within the capacity of the compressors).

The licensee had placed drain valve caps near all air receiver drain valves, but did not use them to reduce the air leakage. Additionally, the licensee identified recurring deficiencies with air start check valve On September 9, the licensee replaced two check valves and one drain valve on the IA diesel air start syste On September 20, the licensee replaced a check valve on the 18 diesel air start syste The inspector also noted that the air receivers have a low pressure alarm that actuates at 90 psi The licensee stated that 90 psig provides enough air to ensure the diesel starts. The design of the starting air system requires that each air receiver hold sufficient air for three cold diesel starts. Engineering stated that 140 psig air

pressure is needed to provide three starts. The inspector reviewed the Certified Test Report for the acceptance of the EOGs dated August 28, 197 The results of the EOG start testing demonstrated that, under the test conditions, the EOG could be expected to start three times with 140 psig air pressure, and attain full run-up within 10 second The tests also indicated that, at less than 120 psig start air pressure, the EOG would not start within the 10 seconds assumed in the Final Safety Analysis Report. Thus, although a low air pressure alarm of 90 psig may provide sufficient pressure so that the EOG will start, it does not ensure sufficient air for three starts, as required by the FSAR, or even one start within 10 second In February 1994, the licensee stated their intent to determine whether the 90 psig alarm setpoint provided appropriate warning to operators of low starting air pressur As of the end of the inspection period, the licensee had not implemented a change to the alarm setpoint. Although the alarm has no actuation function, the inspectors considered the alarm setpoint inappropriate, and an additional barrier to safe plant operation. The response to this concern demonstrates untimely problem resolutio The inspector noted that engineering staff knew of the hardware deficiencies mentione Notwithstanding, engineering plans to replace carbon steel piping between the air dryer and receiver with similar carbon steel piping in the upcoming Unit 2 refueling outag Further, the licensee performs monthly check valve surveillances and continues to replace check valves and drain valves in kin The inspectors observed that the check valve and carbon steel corrosion issues are long-standing problem The licensee's resolution of the deficiencies has relied on short term compensatory measure The inspector concluded that the proposed resolution, using carbon steel replacement parts, will accomplish temporary resolution of the check valve problems, but will not likely achieve long-term resolutio The licensee is considering replacement of carbon steel piping and receivers with stainless steel in a future outag Control Oil Power Unit Filter Problems In 1993, the licensee added control oil power units (COPU) to the steam generator feed pumps (SGFP) to separate the SGFP control oil from the relatively dirty SGFP lube oil. Engineering designed the system to allow filter replacement at 100% powe Since modifying the units, however, the licensee has reduced power to 50% on several occasions in order to replace dirty filters, because the licensee does not have the confidence in the system to perform the filter replacement at 100%

powe System perturbations on previous occasions have justified their concern over losing a feed pump during the filter replacemen Until recently the licensee could operate for five to six weeks before an increasing differential pressure (dp) across the filter necessitated replacemen On August 11, 1994, operators reduced power to 50% to perform COPU filter replacement On September 9, operators reduced

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power to perform a COPU filter replacement on the 21 SGF In addition, maintenance drained and cleaned the 21 SGFP control oil reservoi On September 13, operators again lowered power to replace the 21 SGFP filters. At the end of the inspection period, the 21 SGFP COPU filter dp continued to tren~ upward, indicating filter blockag During the maintenance activities of September 10-11, engineering discovered an abnormal film lining the control oil reservoir. Although engineering could not detect filter blockage or control oil degradation on September 13, they sent the filters and control oil samples to an independent laboratory for analysi The inspector observed the filter replacement on September 1 The inspector noted that maintenance performed it in accordance with procedures with no fluctuations in control oil pressur The inspector observed appropriate engineering involvement and management oversight during this activity. The inspector observed that the control oil and filter were very clean. The inspector concluded that although the maintenance activity was appropriately conducted and controlled, COPU system performance continues to impose unplanned power reductions that pose potential challenges to uneventful plant operation. Engineering continues to investigate, but has not yet determined the cause of the high filter d Control Air System Degradat;on The control air system consists of two parallel and redundant air headers (A and B), designed to provide a clean and dry supply of compressed air to safety-related pneumatically operated instruments and valve Each control air header is common to both Salem units. Salem procedure SC.OP-DD.ZZ-0001 Operations Log - Control Room Reading Sheet Mode 1-4 lists90-120 psig as the normal operating range for control air pressur During the period of September 6-10, workers removed the No. 11 control air dryer from service resulting in a decrease of 'B' control air header pressure to 83-85 psig on the Unit 2 side of the header. Operators performed the required actions of procedure S2.0P-AB.CA-*0001 Loss of Control Ai These actions included operating an emergency control air compressor to limit air pressure decreas Unit 2 operators received an overhead annunciator alarm indicating low air pressure (85 psig) in an air accumulator for 2PR2, one of two pressurizer power operated relief valves (PORVs).

Operators declared 2PR2 inoperable and shut the PORV block valve. After three minutes, operators subsequently restored the No. 11 control air dryer to service and reopened the PORV block valv Restoration of No. 11 control air dryer caused the control air header pressure to return to normal (93-95 psig) and operators exited from the abnormal procedure for loss of control ai At 5:11 a.m. on September 16, after Unit 1 operators removed the No. 21 control air dryer from service they closed the block valve for 1PR2 due to low air accumulator pressure. At 5:45 p.m. on September 18,

operators restored 1PR2 to operability. Operators needed to run an emergency control air compressor during the time the No. 21 control air dryer remained out of servic The inspectors determined that short-term corrective operator actions in response to control air problems met procedure and technical specification requirement Based upon operator use of emergency control air compressors and the need to close PORV block valves to perform routine control air maintenance, the inspectors remain concerned regarding the affect of control air on PORV operability. The inspector also noted that, following system restoration, control air header pressure normally remained low (93-95 psig) in the operating ban The inspectors observed that lack of reliability of the control air system, the control air dryers, and the service air system compressors that supply the control air system have been a long standing concern at Sale In an effort to address the lack of reliability the licensee installed three "temporary" portable diesel powered air compressors to supplement the three installed service air compressors. Despite the temporary air source, marginal control air system performance continues to have the potential to challenge normal plant operatio Open Item Followup (Closed) Unresolved Item (50-272 and 311/93-20-02); Safety Injection Accumulator Level Alarm Setpoint Discrepancies *

This item discussed discrepancies involving the alarm setpoints for the Safety Injection accumulators. Operations and Maintenance procedures had high and low level values that were different than those specified in Technical Specifications (TS).

The item was open pending the licensee revision of the affected Operations and Maintenance procedures to make them consistent with TS, and subsequent NRC review of the change The licensee corrected the Operations and Maintenances procedures such that the high and low level alarm setpoints are consistent with the TS values. The inspector reviewed these procedures and verified the licensee made the,appropriate changes to accumulator level alarm setpoint Based on the review, this item is close Controlled Leakage During the inspection period, the inspectors noted that seal supply to the Unit 2 Reactor Coolant Pumps (RCPs) exceeded 40 gallons per minute (gpm) by 1 to 2 gp The inspectors also noted that the Technical Specification (TS) definition of controlled leakage states: "CONTROLLED LEAKAGE shall be that seal water from the reactor coolant pump seals."

The inspectors noted that other Westinghouse plants define controlled leakage as: "CONTROLLED LEAKAGE shall be that seal water to the reactor coolant pump seals." The inspectors found the latter definition of controlled leakage in the Technical Specifications for Beaver Valley, Seabrook, and Millstone *'

The purpose of the controlled leakage specification is to assure that the high head safety injection system has adequate flow during a small break and large break loss of coolant accident (LOCA).

The RCP seal injection lines are not isolated during an accident and flow continues to be provided to the seals following a safety injection signal. The RCP seal flow diverts high head safety injection (HHSl) flow from the normal injection points to the RCP seals. The assumed reduction in HHS!

flow, due to seal injection, is an assumption made in the LOCA accident analysis. The technical specification for controlled leakage verifies that the LOCA analysis assumption, for RCP seal flow diversion, remains vali Seal injection to a RCP is nominally 8 gpm, with 5 gpm of the injection flow diverted down to cool the lower pump radial bearing and the remaining 3 gpm flowing up through the pump.seal packag The No. I seal injection line can only be manually isolated and the seal return isolates on a safety injection signal. The current Salem TS Limiting Condition for Operation (LCO) (TS 3.4.6.2) requires that the controlled leakage be limited to 40 gpm at a RCS pressure of 2230 +/-30 psi The safety significance of this issue is that by not having appropriate technical specification surveillance requirements, the licensee could operate in a condition that is beyond the plant design basis ECCS assumptions and not detect it during the surveillance test. The operational difficulty of imposing a valid TS would be minimal provided that the seal injection flow instrumentation has adequate accurac Based on the inspector questions, the licensee requested that Westinghouse determine the correct definition of controlled leakag This item will remain open pending review of the determination by Westinghouse and the licensee (IFI 50-2721311/94-19-01). Feedwater Nozzle Radiography During the tenth refueling outage of Salem Unit I, a radiographic examination was performed on the feedwater (FW) nozzle to the expander welds in the steam generators, subsequent to a leak found in a similar weld at TVA's Sequoyah Unit I. The examination revealed circumferential cracking in five out of eight welds in Salem 1, but none in Salem On Steam Generators (SGs) 12 and 14 (Salem 1), the welds between the FW nozzle to the expander and the expander to the 45° elbow were found to have crack On SG 13 (of Salem 1), the weld between the FW nozzle and the 30° elbow was also found to have a crack. Hence, PSE&G replaced all three expanders, and the 30° elbow on all steam generators even though SG 11 (of Salem 1) appeared to be unaffected. During the change out of these components, PSE&G found some erosion of the thermal sleeves that are installed inside the nozzle The sleeves showed maximum erosion of about 0.125" on the outside surface and very little on the inside surface. Although the thermal sleeve does not serve as a pressure boundary, the loss of wall thickness on the outside surface does provide increased bypass flow between the sleeve exterior and the nozzle bor Thus, during certain plant transients, when cold water is injected via

the auxiliary feedwater line, there is an increased potential for feedwater nozzle cracking due to thermal fatigue. Subsequently, PSE&G performed a thermal/hydraulic evaluation as well as a fatigue and fracture mechanics evaluation of the feedwater nozzle to justify continued operation until the eleventh refueling outage (lRll, November 1993), during which a modified FW nozzle was planned for installatio However, the planned modification was not incorporated during lRll, and is now scheduled for installation in 1R12 (1995).

As stated in the LER 92-014, PSE&G performed an ultrasonic examination of the nozzle to the expander welds for all four SG There was no relevant indication found as a result of the examination. Subsequently, PSE&G performed an evaluation of structural integrity of the existing FW nozzles based on the nondestructive examination results, and actual hours of auxiliary feedwater operation, which concluded that the integrity of the nozzles was ensured for two additional cycles of operation (i.e., Cycles 12 and 13).

The inspector reviewed all pertinent analyses performed in regard to the evaluation of structural integrity of the FW nozzles and concurred that the extension of the schedule for replacement of modified nozzles from lRll to 1Rl2, posed no safety concern. During the inspection, the design of the new FW nozzle was reviewed. It was found that the modified design will result in negligible bypass flow between the thermal sleeve and the nozzle and hence, will reduce the potential for developing cracks in the nozzle inside surface during injection of cold auxiliary F.0 PLANT SUPPORT Radiological Controls and Chemistry 5.1.l Inspection' Activities The inspector verified on a periodic basis PSE&G's conformance with the radiological protection progra.1.2 Inspections Findings - Salem Abnormal Radiation Reading At 9:45 p.m. on September 1, 1994, Salem Unit 2 operators initiated S2.0P-AB.RAD-0001, Abnormal Radiation, in response to a warning alarm on the 2RllA radiation monito The RllA monitors particulate activity in containment. Operators initiated a reactor coolant system (RCS) leak rate calculation and dispatched a crew into containment to search for leaks. Operators calculated the RCS leak rate and determined it to be norma The licensee did not identify any potential leakage paths during the containment walkdown.

  • Containment particulate readings trended upward from approximately 12,000-13,000 counts per minute (cpm) to the 2RllA warning setpoint of 30,000 cp Operators shifted the 23 and 25 containment fan cooler units to slow speed to take advantage of the increased filtering. At 11:45 p.m. on September 1, operators exited the Abnormal Radiation procedure due to decreasing 2RllA radiation levels. Containment particulate levels decreased to 16,000 to 18,000 cp Containment noble gas (2Rl2A) and containment iodine (2Rl2B) reacted similarly over the same period of tim Radiation Protection staff continued to closely monitor and trend radiation reading The inspector determined that the licensee responded promptly and in accordance with their abnormal radiation procedur The inspector concluded that radiation levels did not impose increased radiological risk to plant workers or the general public and that the increased levels did not exceed regulatory limit In addition, the inspector concluded that the licensee had taken appropriate steps to identify the source of the lea.0 LICENSEE EVENT REPORTS (LER}, PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP LERs and Reports The Salem and Hope Creek Monthly Operating Reports for July were reviewed for accuracy and content, and were determined to be acceptabl The inspectors also reviewed the following LERs to determine whether the licensee took the corrective actions stated in the report, and to determine if licensee responses to the events were adequate, met regulatory requirements conditions, and commitments:

Salem LERs Unit 1 Number LER 94-011 LER 94-012 LER 94-013 Event Date July 14, 1994 July 18, 1994 July 25, 1994 Description Manual trip following lightning induced trip of all circulating water pump Entry into TS 3.0.3 to support analog rod position indication maintenanc Containment pressure relief with manual isolation capabilit..

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Unit 2 LER 94-008 LER 94-002-02; LER 94-002-03 I6 June 29, I994 January I9, I994 Reactor trip due to 23 steam generator low-Low level during return to on-line power operatio Unit 2 operation above licensed thermal power limi For the LERs listed above, the inspectors determined that there were no violations or deviations, and considered the LERs close. 0 DETAILS OF INSPECT I.ON OF ACTIVITIES COMMON TO SALEM AND HOPE CREEK CFR 50.59 Program IO CFR 50.59 Program Inspection From September I9, I994 to September 23, I994, the NRR project managers reviewed the Public Service Electric and Gas Company (PSE&G) IO CFR 50.59 program to verify conformance with IO CFR 50.59, "Changes, Tests and Experiments" (CTEs).

The project managers reviewed the extensive revisions *to procedure NC.NA-AP.ZZ-0059(Q), Revision 2, 10CFR50.59 Reviews and Safety Evaluations (NAP-59).

The project managers concluded that the changes to NAP-59 were appropriate, and that NAP-59 adequately implemented the requirements of IO CFR 50.59 with two exception The project managers noted that NRC Inspection Report 50-272&3II/94-07 and 50-354/94-05 identified that NAP-59 provided optional peer review, but did not alert the reviewer that if a peer review was not required, the approver assumed the duties and responsibilities of the peer reviewe At the time of the inspection, engineering agreed to address the issue but had not decided on a vehicle to make the appropriate chang The project managers also found that the NAP-59 definition of the Safety Analysis Report omitted SAR changes that had been approved and implemented but had not been incorporated into SAR and transmitted to the NRC as required by IO CFR 50.7I(e).

This definition would allow changes to be made to the facility or FSAR without consulting the changes that had been approved since the last formal update of the FSA The PSE&G licensing staff had recognized the deficiency and was preparing a request to the sponsoring organization to change the definition. This NRC will review the licensee change of the SAR definition in during future inspection (IFI 50-272&3II/94-I9-02, 50-354/94-05).

The project managers found that the licensee revised training module, 0903-0I8.0IN-5059ZZ-OI, IO CFR 50.59 Reviews/Safety Evaluations, to reflect the changes in NAP-5 The PSE&G staff was knowledgeable of the program and satisfied with the current revision of NAP-5 Overall, the

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project managers found that the training program provided an adequate mix of discussion of 10 CFR 50.59 requirements and workshop practice in practical applicatio Technical Specification 6.5.2.4.2.a requires that Offsite Site Safety Review (OSR) (PSE&G's independent internal audit group) independently review completed safety evaluations to verify that actions taken did not involve an unreviewed safety question. Based on inspection of the OSR independent reviews, the project managers concluded that OSR provided useful comments and trending to organizations responsible for preparation of safety evaluation In addition, OSR periodically surveys 10 CFR 50.59 applicability review In the February 17, 1994, report OSR audited 81 Salem applicability reviews and 43 Hope Creek applicability reviews. The OSR identified three documents that incorrectly concluded that 10 CFR 50.59 did not appl The OSR also found one temporary modification that reviewers determined potentially

"affected nuclear safety." The reviewers determined that 10 CFR 50.59 did not apply and the temporary modification was not reviewed by the Station Operations Review Committee (SORC).

While it was correct that 10 CFR 50.59 did not apply, Technical Specification 6.5.1.6.b and d require SORC to review all proposed tests, experiments, and changes to plant systems or equipment that may affect nuclear safety. Based on the OSR finding, SORC reviewed the proposed temporary modificatio The project managers examined approximately 18% of the 136 Hope Creek safety evaluations prepared between March 1993 to June 1994, as reported in the monthly operating reports. The inspector found no significant issues with the completed 10 CFR 50.59 safety evaluations and considered the Hope Creek 10 CFR 50.59 program acceptabl The project managers also examined 25 completed Salem 10 CFR 50.59 safety evaluations. This represents about 8% of the 10 CFR 50.59 safety evaluations performed from January 1, 1993 through June 30, 1994 as reported in the Salem 1 and 2 monthly operating report The project managers also examined a sample of 6 completed 10 CFR 50.59 reviews with the determination that 10 CFR 50.59 did not appl The project managers did not identify any significant issue.0 EXIT INTERVIEWS/MEETINGS Resident Exit Meeting The inspectors met with Mr. J. Hagan and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activitie Based on NRC Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.

  • 18 Salem Specialist Entrance and Exit Meetings Inspection Reporting Date Cs>

Subject Report N Insoector 8/8-12/94 EDSFI Open Items 50-272 and 311/94-18; Skokowski Followup 50-354/94-18 8/29 - 9/2/94

- Radwaste 50-272 and 311/94-20; Noggle Inspection 50-354/94-20 9/8 - 12/31/94 PSE&G Self-50-272 and 311/94-22 Drysdale Assessment Inspection 9/12-16/94 Inservice 50-272 and 311/94-21 Dempsey Inspection Management Meetings On September 19, 1994, the NRC Region I Regional Administrator visited the Hope Creek station for a plant tour with the resident inspectors and meetings with senior PSE&G managemen On August 24, 1994, a management

  • meeting was held to discuss the effects of detritus on Salem and Hope Creek circulating and service water intakes. -Attachment 1 pertain.

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Electnc and Gas Company PSE&G/NRC MANAGEl\\IBNT l\\IBETING TO DISCUSS EFFECTS OF DETRITUS ON SALEM AND HOPE CREEK UNITS AUGUST 24, 1994 SALEM HOPE CREEK GENERATING STATION GENERATING STATION

  • ' 1.. -

NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES AGENDA INTRODUCTION MEETING OBJECTIVES DELAWARE RIVER OVERVIEW SALEM CIRCULATING WATER OVERVIEW SALEM SERVICE WATER OVERVIEW HOPE CREEK SERVICE WATER OVERVIEW CHARACTERIZATION OF DELAWARE RIVER DETRITUS SERVICE WATER CAPABILITY /CONTINGENCY IMPROVEMENT OF SALEM CIRCULATING WATER CAPABILITY SUMMARY /CONCLUSIONS S. LaBRUNA S. LaBRUN T.TAYLOR T. TAYLOR T. TAYLOR T.TAYLOR J. BALLETIO T.TAYLOR D. McCOLLUM S. LaBRUNA

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NRC/PSE&G MANAGEMENT :MEETING DETRITUS IMPACT ON PLANT WATER INTAKES MEETING OBJECTIVES

  • To characterize the nature of the Delaware River detritus conditions*
  • To demonstrate that the Service Water Systems are not being unduly challenged, that Service Water Systems are unaffected by the Circulating Water operational status, and that adequate contingency planning is in place
  • To provide an overview of PSE&G's holistic approach and planned activities to enhance plant water intake availability and capability to cope with future episodes of high detritus loading
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NRC/PSE&G MANAGEI\\1ENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES DELAWARE RIVER OVERVIEW

  • Physical Features
  • Plant Orientation
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  • Design Features 94Ml046

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  • Salem Circulating Water (CW) System

- Open Loop Cooling System

- Draws approximately 1.1 million GPM per Salem Unit

- Provides cooling to condense steam from turbine in power cycle

- Six CW pumps per unit feed condenser through six concrete pipes of 7 foot diameter

- After passing through condenser tubes, six pipes merge to 3 ten foot diameter pipes which discharge 500 feet off shore

- Service Water System also discharges through these pipes

94MM10-02

lce-Oarrier Trash Rack Rake SALEM CIRCULATING WATER INTAKE STRUCTURE H 120:0" Traveling Trash Rack I

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SALEM CIRCULATING WATER OVERVIEW

  • Salem Circulating Water (CW) System 94MM1(}..()3

- 2000 HP, 84-inch diameter mixed flow wet pit pump

- 7-foot diameter discharge pipe

- 42-inch start-up recirculation line

- Full depth multi-speed traveling screen (3/8-inch square wire spacing)

- Screens run constantly - speed a function of differential pressure across screen:

Differential Pressure Across Sreeen

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> 8 in manual high speed Screen Speed 7.5 fpm 9.5 fpm 12.5 fpm 17.5 fpm

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NRC/PSE&G MANAGEMENT :MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SALEM CIRCULATING WATER OVERVIEW

  • Salem Circulating Water (CW) System

- Screen wash pump

- Full depth trash bar rack (3. 5 inch spacing between bars)

- Traveling trash rake to clean the trash bars

- Partial depth ice barrier (installed seasonally)

- Local plant elevation datum (ground level) is 100 f Intake sill is at elevation 50 f Dredged approximately 20 ft. below nominal river bottom

- Tides vary from 86.4 ft. mean low water level to 92.2 ft. mean high water level, a 6 f variation

94MM10-04

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SALEM CIRCULATING WATER OVERVIEW

  • Based on the following nominal conditions:

- 10 foot traveling screen width

- 36.4 ft. water depth (based on 86.4 ft. mean low water and 50 ft. sill)

- Rated 185, 000 gpm per pump intake

- Top automatic screen speed of 12. 5 feet per

. minute. Top manual speed of 17.5 feet per minut * The nominal intake velocity is 1.0 foot per second

  • The intake volume flux across the screen is 508 gpm per square foot of screen (stopped screen)
  • The intake volume filtered by 1 square foot of screen at the highest automatic speed (1 fpm) is 1480 gallons per square foot of traveling screen (1057 gallons at 17.5 fpm).

This represents the gallons of intake water filtered between spray cleanings per square foot of scree MMIO-OS I

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94M10-34 NRC/PSE&G MANAGEMENT. MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SALEM SERVICE WATER OVERVIEW

  • Design Features

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- Open loop cooling system

- 6 SW pumps installed per Unit

- Normally 2 to 4 pumps are running. For accident service, only 2 pumps are required

- Draws approximately 44,000 gpm per Salem unit (normal, summer)

- Provides cooling water for safety related and non-safety related loads. Provides ultimate heat sink for the plant

  • Water enters Service Water system from pumps, passes through buried concrete yard piping to heat loads in plant, and returns to river via connections to 3 CW system discharge pipes 94MM10-06
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94Ml0-07 NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SALEM SERVICE WATER OVERVIEW

- Vertical, multi-stage, centrifugal pumps rated at 10,875 gpm and discharge pressure of 262 fee inch diameter pump discharge pipe feeds into two 24 inch nuclear headers and one 30 inch Turbine Building header

- Full depth single speed traveling screen (8. 5 fpm). 3/8 inch square wire spacing

- Screens and sprays run upon a 4 inch differential across the screen

- Control Room alarm annunciates at 6 inch differential pressure

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94Ml0-08 NRC/PSE&G MANAGEMENT l\\IBETING DETRITUS IMPACT ON PLANT WATER INTAKES SALEM SERVICE WATER OVERVIEW

- Screen wash

- Automatic strainer with backwash

- Full depth trash bar rack (3. 5 inch spacing between bars)

- Traveling trash rake to clean the trash bars

. - Full depth ice barrier (permanent)

  • - Local plant elevation datum (ground level) is 100 f Intake sill is 70 f Tides vary from 86.4 ft. mean low water level to 92.2 ft. mean high water level; a 6 f variation

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NRC/PSE&G MANAGEMENT l\\ffiETING DETRITUS IMPACT ON PLANT WATER INTAKES SALEM SERVICE WATER OVERVIEW

  • Based on the following nominal conditions:

- 3 foot traveling screen width

- 16.4 ft water depth (based on 86.4 mean low water and 70 ft sill)

- Rated 10,875 gpm per pump intake

- Screen speed of 8. 5 feet per minute

  • The nominal intake velocity is.35 feet per second
  • The intake volume flux across the screen is 221 gpm per square foot (stopped screen)
  • The intake volume filtered by 1 square foot of screen with the screen running is 420 gallons per square foot of traveling screen. This represents the gallons of intake water filtered between spray cleanings per square foot of screen

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES HOPE CREEK SERVICE WATER OVERVIEW

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES HOPE CREEK SERVICE WATER OVERVIEW 94MIO-IO

- Open loop cooling system

- 4 SW pumps feed two independent loops

- 3 pumps required during summer operation During accident conditions, 2 pumps are required

- Draws approximately 49,500 gpm (typical summer)

- Provides cooling water for safety related and non-safety related loads. Provides ultimate heat sink for the plant

  • Water enters SW system from river intake structure pumps, passes through buried piping to heat loads in plant, and discharges to the Cooling Tower as makeup for the CW system
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94Ml0-ll

- Vertical, single stage, centrifugal pumps rated at 16,500 gpm

- 28 inch diameter pump discharge pipe feeds two service water loops

- Full depth traveling screens and spray wash run

. continuously (1/8 x 1/2 wire spacing).

- Control Room alarm annunciates on screen malfunction.

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES HOPE CREEK SERVICE WATER OVERVIEW 94M10-12

- Screen wash booster pump/per service water pump

- Automatic strainer with backwash

- Full depth trash bar rack (3 inch spacing between bars).

- Traveling trash rake to clean trash bars

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES HOPE CREEK SERVICE WATER OVERVIEW 94Ml0-13

  • Based on the following nominal conditions:

- 8 '-4" ft traveling screen width

- 16.4' water depth (based on 86.4' mean low water and 70.0 ft sill)

- Rated 16,500 gpm per pump intake

- Screen speed of 5 feet per minute at low speed and 10 feet per minute at high speed

  • The nominal intake velocity is 0.27 feet per second
  • The intake volume flux across the screen is 121 gpm per square foot (stopped screen)
  • The intake volume filtered by 1 square foot of screen with the screen running at low speed is 198.1 gallons per square ft. of traveling screen (99.0 gallons at high speed) This represents the gallons of intake water filtered between spray cleanings per square foot of screen

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES CHARACTERIZATION OF DELAWARE RIVER DETRITUS 94Ml0-30

  • The four major types of materials found in the detritus are:

- Marsh grasses

- Tree leaves

- Other (trash)

- Submerged aquatic vegetation

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ft[RCEHT COMPOSITION BY T AXA AU DATES COMBINED

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1.1 X D GRASS (~~~~$1 SHRUBS AND TREES II SAV D OTHER MEAN PERCENT COMPOSITION OF TAXONOMIC GROUPS FROM ALL DATES AND COLLECTIONS ANALY2ED DURING NI.JC SEM:£ D..ECl1llC AND GAS CO. THE SALEM DETRITUS CHARACTERIZATION STUD FIGURE 1 ENVIRONMENTAL CONSULTING SDMCES IN,.

NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES CHARACTERIZATION OF DELAWARE RIVER DETRITUS Nature of Detritus in River

- Phase 1 Plant material freshly torn in river marshes by hard freezes and transferred to river by high tides

  • Floats near the surface
  • Coarse and reedlike

- Phase 2 The plant materials begin to decompose, losing buoyanc * The Material has fibrous consistency and occupies essentially the entire river water colum Phase 3 Detrital material decomposes further, losing buoyancy and settles to the river bottom

- Phase 4 Matted detrital material on the river bottom undergoes anaerobic deca * The gasses can be sufficiently trapped to cause the detritus to ris en 0:

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES CHARACTERIZATION OF DELAWARE RIVER DETRITUS Predictive studies to understand the detrital cycle during the seasonal events in the river has identified that the most significant input factors are:

  • Frozen precipitation (e.g. ice, snow, slush)
  • Delaware River flow rate Other important factors:
  • Tide level
  • Debris return direction The model provides an indication of the severity of detritus to be expected over the next 90 days

94M10-32

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES

MEETING OBJECTIVES
  • To characterize the nature of the Delaware River detritus conditions
  • To demonstrate that the Service Water Systems are not being unduly challenged, that Service Water Systems are unaffected by the Circulating Water operational status, and that adequate contingency planning is in place
  • To provide an overview of PSE&G's holistic approach and planned activities to enhance plant water intake availability_ and capability to cope with future episodes of high detritus loading 94MM10-01

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94M1047 NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER SYSTEM CAPABILITY

  • The Salem and Hope.Creek Service Water systems have not been, and will not be detrimentally challenged by Delaware River *

Detritus

  • Adequate contingency planning is in place to assure safety and preclude challenges to plant safety systems

NRC/PSE&G MANAGEI\\IBNT :MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER SYSTEM CAPABILITY Service Water System Strengths and Margins

  • Solid curtain wall to elevation 81 f M10-36
  • Filtration duty of the Salem and Hope Creek Service Water Systems is several times less severe than that of the Salem Circulating Water Syste * The "zone of influence" of the Salem Circulating Water does not encompass the Salem Service Water Syste * The "zones of influence" of the Salem and Hope Creek Service Water Systems are small
  • History has shown that the service water systems have not been detrimentally challenged during high detritus period * Only 2 out of 6 Salem SW pumps per unit are required to perform accident dut * Only 2 out of 4 Hope Creek SW pumps are required to perform accident duty

NRC/PSE&G MANAGEMENT :MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER CAPABILITY Salem Nominal Intake Velocity (ft per second)

Filtration Duty - Gallons filtered between screen cleanings per square foot of traveling screen (gallons per ft squared)

94Ml0-18 cw SW (Normal Operations)

.35 (3rd Speed Auto)

420 1480 (Hi Speed-Manual)

420 1057 Ratio 2.8 to 1 3.5 to 1 2.5 to 1

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER CAPABILITY Hope Creek Nominal Intake Velocity (ft per second)

Filtration Duty - Gallons filtered between screen *

cleanings per square foot of traveling screen (gallons per ft squared)

94Ml0-20 Salem CW HCSW 0.27 198.1@ LS 99.0@HS Ratio 3:1 7.8:1 14.9:1

NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER SYSTEM CAPABILITY Service Water System Strengths and Margins

  • Solid curtain wall to elevation 81 f * Filtration duty of the Salem and Hope Creek Service Water Systems is several times less severe than that of the Salem Circulating Water Syste * The "zone of influence" of the Salem Circulating Water does not encompass the Salem Service Water Syste * The "zones of influence" of the Salem and Hope Creek Service Water Systems are small
  • History has shown that the service water systems have not been detrimentally challenged during high detritus period * Only 2 out of 6 Salem SW pumps per unit are required to perform accident dut * Only 2 out of 4 Hope Creek SW pumps are required to perform accident duty
    • -**~94.M.10-.36---------------------*

NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER CAPABILITY Service Water Operating Experience

  • Traveling screen shear pin failure rate

- Shear pin failures are infrequent

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- No Shear pin failures are directly attributable to high Detritus loads

  • Service Water trash rake use has not been required for Detritus removal

.. 94M10-S2

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER SYSTEM CAPABILITY Service Water System Strengths and Margins

  • Solid curtain wall to elevation 81 f Ml0-36
  • Filtration duty of the Salem and Hope Creek Service Water Systems is several times less severe than that of the Salem Circulating Water Syste * The "zone of influence" of the Salem Circulating Water does not encompass the Salem Service Water Syste * The "zones of influence" of the Salem and Hope Creek Service Water Systems are small
  • History. has shown that the service water systems have not been detrimentally challenged during high detritus period * Only 2 out of 6 Salem SW pumps per unit are required to perform accident dut * Only 2 out of 4 Hope Creek SW pumps are required to perform accident duty

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES SERVICE WATER SYSTEM CAPABILITY

  • Generic Contingency Planning

- PM program optimization

- Predictive capabilities

  • Salem CW as an indicator
  • Results of predictive studies
  • Monitoring

- Reinforcement of management expectations for conservative plant operations

- Heightened level of awareness

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,~.Ml.~.8......................................

  • NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES OFF NORMAL CONDITION RESPONSE SGS SERVICE WATER Alarm response to control room indication initiated from Service Water Screen/Strainer Instrumentation
  • Alarms are bay specific

- Screen high D/P

- Screen timer not reset

- Strainer high D/P

  • Dispatch operator to investigate problem and monitor situation
  • Provides specific direction to correct problem

- Valve operation

- Pump cycling

- Monitor DIP on screens in affected bay Loss of Service Water header pressure (abnormal operating procedure)

  • *Gives operators indications of pump cavitation
  • If cavitation occurs and additional pumps cannot be started reduce flow demand

- Shutdown to Mode 3 ASAP/comply with appropriate Tech Spec action statement

- Locate source of pressure reduction

94M10-61

  • NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES OFF NORMAL CONDITION RESPONSE HCGS SERVICE WATER
  • Initiated from service water screen and strainer instrumentation in control roo Alarms are bay specific

- Power malfunctions

- Strainer DIP

- Screen malfunction

- Screen DIP

  • Dispatches operator to investigate problem (equipment failure, ice, grass)
  • Provide multiple explicit success paths to clear screen or strainer DIP

- Valve manipulations

- Pump cycling

- Changing flow rates

  • Specifies heat load reduction including unit load reduction

94M10-31

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY

  • Original Design Features
  • Key Design Enhancements
  • Ongoing Design Enhancements

94Ml(}.S3

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY Original Design Features

  • Equipment exposed to elements
  • Travelling screen detritus trough in front of screens
  • Single level of spray
  • Detritus discharged into dumpsters
  • Manual screen chain tensioning

94Ml0-S4

  • NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY Key Design Enhancements
  • Equipment protected from elements
  • Traveling screen detritus trough improvements
  • Additional levels of spray
  • Upgraded material for troughs
  • Enclosed fish counting basins
  • Stainless steel screens
  • Automatic traveling screen chain tensioners
  • . *.~~.M.1~.ss.........................................
  • NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY On going design enhancements
  • 1990 overall material condition upgrade

- River interface

- Traveling screen upgrades

- Screenwash upgrades

- Bearing lubrication

- Electrical upgrades

- Material upgrades

- Condenser upgrades

94M10-56

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY Material condition upgrade program

  • River Interface
  • - Upgrade trash rakes to "clam-shell" type 't} <{'f

- Refurbish ice barriers. Add lower supports/ shims to barriers

  • - Replace degraded trashrack with offset racks allowing full rake penetration L\\ - ~ ~

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  • Improves detritus handling

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY Material condition upgrade program

  • Traveling screen upgrade
  • - Replace 62 baskets on 14 traveling screens with baskets of composite materials and smoother wire mesh
  • - Add additional screen wash spray nozzles
  • - Increase carriage speed and automate all fou~

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speed changes L~ ~

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  • - Replace carriage drive system (motor, reducer, carrier chain, etc.)
  • - Improve basket flap seals to better mate with debris troughs
  • - Replace spray wash pressure regulators c~,~~~5-~~

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY Material condition upgrade program

  • Screen Wash Upgrades
  • - Install blowdown fittings on screen wash headers
  • - Purchase new screen wash pumps capable of digesting detritus. Replacement of stilling tubes and base plates included ~

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- Upgrade screen wash pump motors and cables

  • - Upgrade of corroded portions of screen wash

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  • - Refurbish screen wash control panels to allow automatic screen wash operation
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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAP ABILITY Material condition upgrade program

  • Bearing Lubrication

- Upgrade Bearing Lube Strainers to basket type

- Upgrade strainer controls (low flow alarms downstream of strainers)

- Upgrade circulator bearing lube piping (carbon to fiberglass)

- Add circulator stuffing box blowdown capability

- Addition of bearing lube trouble annunciator panels

94Ml0-39

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY Material condition upgrade program

  • Miscellaneous Electrical Upgrades

- Install lights behind CW Traveling screens ~

- Provide power to CW traveling screen ~

laydownpad

- Replace <;irculatin!! Water System substation

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- Upgrade Circulating Water System electrical panels and controls

- Upgrade grounding

- Refurbishment of motor control centers (A,;:7' ( ~ ~

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  • ~;~~94.M.1040--------------------*

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAP ABILITY Material condition upgrade program

  • Miscellaneous material upgrades 94Ml0-41

- Demolition of abandoned CW chlorination

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- Addition of an operator station at structure

- Repair/replace corroded structural steel

- Enclose circulating water pipe vents

.. - Replace circulating water pump discharge vacuum breakers

- Add additional drain holes in intake structure floor

- Install divider wall in intake structure

- Replace corroded grating supports/clamps

- Repair cracked concrete walls/floors

- Repair wall and roof openings for weathertight operation; add hinged covers

- Repair circulator pump pad deterioration

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NRC/PSE&G MANAGEl\\fENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES IMPROVEMENT OF SALEM CIRC WATER CAPABILITY Material condition upgrade program

  • Condenser Upgrades

- Condenser waterbox manway replacement and addition of fiberglass ladders

- Restoration of water boxes and application of epoxy coating to walls and tubesheet Isolate condenser waterbox priming from steam space evacuation

- Replacement of waterbox vacumn pumps with single stage pumps

- Install condenser air inleakage monitors

- Elimination of priming float valves I

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River

HOLISTIC APPROACH Waterfront Intake Design Operation and Maintenance

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Detritus Characterization Studies Predictive Modeling Bathymetric and Detrital surveys Maintenance dredging Hydrological studies 94ml0-27 Design enhancements identified through our experience and changes in available technologies Proactive approach to future design enhancements Schedule maintenance to maximize readiness for periods of expected heavy detritus loading Optimize frequency of maintenance Contingency plans

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NRC/PSE&G MANAGEMENT MEETING DETRITUS IMPACT ON PLANT WATER INTAKES CONCLUSIONS

  • PSE&G understands the nature of Salem Circulating Water System operating environment, and is taking an aggressive approach to eliminating future plant challenges
  • Systems are designed and maintained to operate in the presence of Delaware River detritus loadings experienced to date and anticipated *in the future
  • Based on our analyses and understanding of the Circulating Water and Service Water systems' spheres of influence, the operability of the Salem and Hope Creek Service Water Systems is independent of the status of the Salem Circulating Water System MMI0-29
  • -£~-**--iiiiillll-------------
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