IR 05000272/1991005

Safety Insp Repts 50-272/91-05,50-311/91-05 & 50-354/91-04 on 910213-0326.No Violations Noted.Major Areas Inspected: Operations,Refueling Outage Activities,Emergency Preparedness,Radiological Controls & Maint & Surveillance

ML18095A875
Person / Time
Site:	Salem, Hope Creek
Issue date:	04/11/1991
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18095A874	List: IR 05000272/1991005 ML18095A873
References
50-272-91-05, 50-272-91-5, 50-311-91-05, 50-311-91-5, 50-354-91-04, 50-354-91-4, NUDOCS 9104180046
Download: ML18095A875 (61)

Text

Report No License No Licensee:

Facilities:

Dates:

Inspectors:

Approved:

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

50-272/91-05 50-311/91-05 50-354/91-04 DPR-70 DPR-75 NPF-57 Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station February 13, 1991 - March 26, 1991 T. P. Johnson, Senior Resident Inspector S. M. Pindale, Resident Inspector S. T. Barr, Resident Inspector H. K. Lathrop, Resident Inspector A. E. Finkel, Senior

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P. Patn *

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~~-u/e. White, Chief, Projects ection 2A

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Inspection Summary:

Inspection 50-272/91-05; 50-311/91-05; 50-354/91-04 on February 13, 1991 - March 26, 1991 Areas Inspected: Resident safety inspection of the following areas: operations, refueling outage activities, startup from refueling, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering technical support, safety assessment/quality verification, and licensee event reports and open item followu Results: The inspectors did not identify any cited or non-cited violations for Salem or for Hope Creek. However, there were three unresolved items identified for Salem and one identified for Hope Creek. An executive summary follows.

• • --

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• SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 continued shutdown for its ninth refueling outage, which began on February 9, 199 Core offload was completed on March 2, 1991, and core reload was completed on March 16, 1991. The reactor head was installed and bolted, and the unit entered Mode 5 (Cold Shutdown) on March 24, 199 Unit 2 operated at or near full power for the entire inspection period. At the end of this period, the unit had operated continuously for 199 day.2 Hope Creek The unit began the period in cold shutdown, and in the final stages of the third refueling outage. The unit restarted from the refueling outage on February 16, 1991. A reactor scram on reactor water low level from 24% power occurred on February 19, 1991. The unit restarted on February 21, 1991; however, a shutdown due to excessive generator hydrogen leakage occurred on February 23, 1991. Restart from this forced outage occurred on March 2, 1991, and the plant operated at or near full power through the remainder of the report perio.3 Common On March 13, 1991, PSE&G announced the selection of Calvin A. Vondra as the new General Manager, Salem Operations. Mr. Vondra will replace Stan LaBruna, Vice President-Nuclear Operations, who has been acting in that position since October 1, 1990. Prior to this position, Mr. Vondra was the plant manager at the Sequoyah Nuclear Generating Station, Tennessee Valley Authority. Previously, he was the Operations Manager at Hope Cree.

OPERATIONS Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirements. Public Service Electric and Gas (PSE&G) Company management control was evaluated 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 records. These inspection activities were conducted in accordance with NRC inspection procedures 60710, 71707, 71711, and 9370 The inspectors performed normal and back-shift inspections, including deep back-shift inspections (40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />) as follows:

Salem Hope Creek Inspection Hours 11 :00 p.m. - Midnight 4:30 p.m. - 8:30 :00 p.m. - Midnight Midnight - 4:00 :00 a.m. - 4:00 :00 a.m. - Noon 2:45 p.m. - 11:00 Midnight - 1:30 February 17, 1991 March 24, 1991 February 15, 1991 February 16, 1991 February 16, 1991 February 17, 1991 February 17, 1991 February 18, 1991 Inspection Findings and Significant Plant Events 2. Salem Radiation Monitor Engineered Safety Feature (ESF) Actuations The following spurious radiation monitor ESF actuations occurred and were reported by the licensee during the period:

Unit Radiation Monitor Date Time

lRllA February 16, 1991 12:45 R41B February 18, 1991 6:46 lRllA February 20, 1991 2:03 R12A February 20, 1991 8:15 lRllA February 27, 1991 5:35 R1A March 2, 1991 8:54 lRllA March 4, 1991 11:59 *

2R1A March 5, 1991 5:54 *

lRlB March 6, 1991 10:01 The inspector concluded that these spurious events continue to be indicative of the degraded radiation monitor system. With the exception of two control room isolations (*), the ESF actuations occurred as designed by causing a containment ventilation isolation or a control room ventilation star Relative to the exceptions, the Unit 2 control room outlet damper 2CAA18 failed to closed in both the March 5th and 6th events. However, the redundant damper 2CAA19 closed. The inspector reviewed system operation and verified that damper 2CAA18 is not one of the Technical Specification related inlet dampers. The licensee initiated a work order after the

first failure; however, higher priority work and a tagging problem delayed repair activitie After the second failure, the licensee found that an air operated linkage arm had loose set screws, thus resulting in intermittent failure of the damper to properly stroke close Following, the screws were tightened, and the damper functioned normall The inspector questioned whether any preventive maintenance (PM) or surveillance testing (ST) should have noted this abnormality. Licensee maintenance personnel determined that the following PMs and STs are performed on the dampers:

(1)

Recurring 18 month PM to clean damper, check linkage and set screw tightness, and stroke damper for movement. This was last done December 19, 1989, and was scheduled again for June 30, 1991. The PM was previously performed in 1985 and 198 (2)

Monthly ST to check system operability including damper stroking. This was performed satisfactorily in February 199 (3)

Daily (midnight to 8:00 a.m. shift) operational check of the accident mode actuation of the system, including damper stroking. The system and dampers functioned correctly during this daily check on March 4, 5 and 6, 1991. Thus, the failures on March 5 and 6, 1991, appear to be intermitten The inspector concluded that licensee's PM/ST programs were adequate for these dampers and that the licensee's followup of this event was acceptabl Unit 1 Core Refueling Activities The Salem Unit 1 reactor core offload and reload occurred during the periods February 27 -

March 2, 1991, and March 14-16, 1991, respectively. The inspector verified that reactor operators and senior reactor operators were knowledgeable of refueling activities. Activities were observed from the control room and the refueling bridge inside containmen Contractor personnel conducting core offload activities were also interviewed. The fuel assembly pull sheets were checked, and the core status board was verified to be accurat Appropriate refueling procedures and Technical Specifications were also reviewed. No unacceptable conditions were noted. The inspector concluded that fuel offload and reload activities were being effectively controlle The inspector also observed the initial lifting of the reactor upper internals package (DIP) and the installation of the reactor head. Both activities were well controlled by the licensee. The inspector noted that enhanced controls were in place during the removal of the reactor DIP in response to a recent event at another facility in which two fuel assemblies were inadvertently removed from the reactor core during the DIP removal. Pre-job briefings were held for both activities. No unacceptable conditions were note *

4 Unit 1 Reactor Coolant System Midloop Operation During some portions of the refueling outage, in order to perform reactor coolant pump, valve and steam generator maintenance, Salem Unit 1 was maintained in midloop operation In midloop operations, the reactor coolant level is lowered to the midpoint of the reactor vessel hot and cold leg nozzles. In this state of reduced coolant inventory, additional instrumentation and monitoring of reactor water level is required to ensure proper core coverage and cooling. Licensee procedures require (1) thermocouples to be used to monitor core exit temperatures, and (2) intermediate leg loop flow differential pressure cells be used to measure water level. Vessel water level is also measured visually by use of transparent tubing connected to an intermediate leg loop drain. Temperature and level alarm setpoints are adjusted to provide early indication of a loss of cooling or a decrease in coolant inventory. Additional monitoring and logging of these parameters is required as wel During midloop operation, the inspector toured the plant in order to review the licensee's controls. The inspector determined that the required instrumentation had been installed, and all monitored parameters were indicating in the safe range. Through discussions with the control room operators, the inspector found the operators knowledgeable of plant conditions, the indications available to them, and of the procedures to be followed if core cooling were to be lost. The inspector also reviewed the control room logs and found them to be complete and satisfactory. Based on this review, the inspector concluded that midloop operations were conducted in a safe and proper manne Operations Troubleshooting Activities Corrective actions for a September 10, 1990, Unit 1 reactor trip on low-low steam generator level (reference LER 272/90-30) included the development of an operations troubleshooting procedure. This procedure, SC.OP-DD.ZZ-AD46(Q) (also known as AD46),

"Troubleshooting Abnormal Plant Conditions," revision 0, was approved on February 1, 199 During the report period, Unit 2 reactor coolant system (RCS) unidentified leak rate increased. The licensee suspected the boron injection tank (BIT) relief valve (2SJ10) to be leaking to the waste holdup tank. On March 12, 1991, the licensee conducted.an RCS leak rate check with the BIT isolated. This quantified the 2SJ10 leak to be approximately gpm. The RCS unidentified leak rate varied between 0.6 and 0.8 gpm. The Technical Specification limit is 1. 0 gp The inspector questioned whether the new operations troubleshooting procedure (AD46) was implemented for the performance of RCS leak rate with the BIT isolated. The licensee indicated that the procedure was not pertinent in this instance since all BIT inlet/outlet valves receive an open signal during safety injection actuation. While the BIT inlet valves are normally open, but closed for this leak check, there was essential change that would have

affected system or valve operation. The inspector did not disagree with the licensee's analysis and conclusion relative to the pertinence of AD46 in this cas The inspector questioned licensed operators and shift supervisors regarding their familiarity with the new troubleshooting procedure, AD46. Several operators and shift supervisors were unfamiliar with the new procedure. Further, the inspector could not locate an approved copy of AD46 in the control room. The licensee acknowledged this unfamiliarity, and they also obtained a controlled copy of AD46 for control room use. The licensee stated that there was a backlog for distributing revised procedure The inspector concluded that an unfamiliarity existed with the new operations troubleshooting procedure (AD46) as evidenced by interviews and by lack of procedure availability. The licensee indicated that training and familiarization would be performed. Later in the inspection period, the inspector noted that AD46 was adequately used in the evaluation of an event involving a Unit 2 charging pum Inadvertent Auxiliary Feedwater System Actuation On February 17, 1991, both Unit 1 motor driven auxiliary feedwater (MDAFW) pumps inadvertently started when an associated vital 125 volt DC distribution system power supply was being transferred to its emergency power supply. The plant was in Mode 5 (Cold Shutdown), and the AFW system was not required or expected to be operable at the time of the actuation. The AFW flowpaths to the four steam generators were isolated, therefore the pumps were run in the recirculation mode of operatio The licensee determined that the event was caused by inadequate administrative controls. The procedure used to remove the 125 volt DC cabinet from service, No. IV-5.3.3, "DC Breaker - Administrative Control," did not detail the sequence of steps necessary to remove the bus from service. The MDAFW actuation signal was initiated when a related relay and associated timer were reenergized during the switching proces Licensee corrective actions included initiating a procedure revision to include the necessary steps to preclude further inadvertent MDAFW system actuations during related bus switching activities. The inspector reviewed this event, including LER 91-07, and concluded that the licensee's response and corrective actions were appropriate. See Section 8.1.C regarding LER 91-07 deficiencie Unit 2 Steam Generator Feed Pump (SGFP)

At 10:54 p.m. on March 23, 1991, Salem Unit 2 began a power decrease to 80% in accordance with procedure IOP-4, "Power Operations," due to reactive power disturbances in the electrical grid system caused by a solar magnetic disturbance. (The Hope Creek unit also initiated a power decrease to 90% in accordance with OP-AB.ZZ-152 at 10:58 p.m.).

Shortly after the Salem Unit 2 power reduction was initiated, 21 SGFP tripped. Operators

entered abnormal procedure AOP-CN-1, and power was reduced to 55%. The transient caused steam generator levels to decrease to a low value of 23 % for No. 24 steam generator (trip at 16%). The steam generator levels were subsequently recovered to normal (44%).

The licensee determined the No. 21 SGFP tripped due to an out-of-calibration low suction pressure trip device. The licensee replaced the pressure transmitter and subsequently verified the adequacy of the suction pressure trip device in 22 SGFP. Power was returned to 100 %.

The inspector followed up the licensee's actions, discussed the event with the on-shift operators and management personnel, and reviewed control room logs, procedures, and the related incident report. The inspector concluded that the control room operators actions were timely and in accordance with procedures, thereby effective in preventing a reactor trip. The inspector noted that a similar event previously occurred at Unit 2 on September 4, 1990, resulting in a reactor trip (reference NRC Inspection 50-311/90-22). The licensee is pursuing evaluation of pressure switches drifting out of calibratio Cold Weather Preparation Open Item Followup (Closed) Unresolved Item (272/90-26-02) Cold Weather Preparations. The inspector reviewed the results of the January 1991 performance of procedure OD-71, "Station Preparations for Winter Conditions," and found that it was properly performed, with associated work orders initiated and prioritized for deficient conditions. The inspector also noted that the licensee had issued a revised OD-71, dated January 15, 1991, which provided additional guidance to specify methods for determining equipment operability. Additionally, the inspector confirmed that work orders associated with cold weather preparations could be cross-referenced by area in the computerized work control system. The inspector concluded that the licensee's response to this item was timely and appropriate. This unresolved item is close. Hope Creek Preparations For Unit Startup From The Third Refueling Outage The Hope Creek unit shutdown for its third refueling outage on December 26, 1990 (see NRC Inspections 50-354/90-21 and 91-01). During the period February 11-15, 1991, and prior to unit startup, the inspector evaluated the licensee's readiness for restart in accordance with NRC Inspection Procedure 7171 The inspector performed a walkdown of the emergency diesel generators (EDGs), the AC electrical distribution system, and the high pressure coolant injection (HPCI) system. The EDGs and HPCI systems were determined to be appropriately lined up for automatic initiation, and the AC electrical distribution system was aligned for normal and standby conditions. These system walkdowns were completed after licensee maintenance, modification, testing, and system restoration activitie,-----

'

The inspectors also performed the following activities:

Toured the auxiliary/diesel, reactor, turbine, and service/radwaste buildings, Performed control room tours and walkdowns, Reviewed the Technical Specification Action Statement, Temporary Modification and Tagout logs, Reviewed training performed regarding plant modifications, Observed portions of the simulator startup training, Performed a closeout inspection of the drywell (see section 3.2.2.A),

Reviewed design change package completions and deferral status, Reviewed selected operations and surveillance testing procedures associated with startup, and Reviewed the licensee's progress towards attainment of outage goal The inspectors concluded that the licensee's program to ensure completion of outage activities was effectively implemented. PSE&G successfully met most of their goals. One exception, however, was exceeding the number of personnel contaminations (see NRC Inspection 50-354/91-01). The inspectors concluded that the Hope Creek unit was adequately prepared for startu Unit Startup and Power Ascension The Hope Creek unit was returned to service following its third refueling outage on February 17, 1991. The unit commenced startup at 9:00 p.m. on February 15, 1991, and criticality was achieved at 1:08 a.m. on February 16, 1991. The generator breaker was closed at 11:04 p.m. on February 17, 1991. Power was held at 24% to perform nucleaJ" instrumentation calibrations and to repair a main generator hydrogen leak. Subsequently, the unit automatically scrammed on February 19, 1991 (see Section 2.2.2.C).

The inspector observed startup activities, power ascension and surveillance testing in accordance with NRC Inspection Procedure 71711. During the period February 15 to 18, 1991, the resident inspector staff initiated deep back-shift coverage of the following related activities:

entry into Operational Condition 2 (Startup),

reactor startup and initial criticality,

• shutdown margin and reactivity anomaly testing, nuclear instrumentation testing and calibration, reactor heatup and pressurization, reactor core isolation cooling and high pressure coolant injection system testing, safety relief valve testing, entry into Operational Condition 1 (Run Mode), and turbine generator startup, testing and synchronizatio Startup activities in the control room were well planned and executed. Operator competence and effectiveness were noted as being excellent. Pre-test briefings were well conducte Procedural and Technical Specification compliance was goo Automatic Reactor Scram on February 19, 1991 At 10:10 a.m. on February 19, 1991, the Hope Creek unit scrammed from 24% reactor power due to low reactor water level. The plant responded as designed with all control rods fully inserting. Reactor water level was restored with reactor feedwater pumps after decreasing to a level of minus 20 inche The scram occurred as the nuclear control operator was attempting to shift reactor water level control from the startup level controller to the master controller in accordance with startup procedures. The operator noted that the master controller would not maintain programmed level. At +28 inches, he shifted back to the startup controller. The startup level control valve failed to respond, and reactor water level quickly dropped to the scram setpoint of

+ 12.5 inche The licensee's investigation determined that malfunctioning contacts in an Agastat relay in the startup level control circuitry caused erratic control valve operation. This relay was removed and replaced with a new relay and functionally tested. Similar relays in the master level control circuits were removed, cleaned and replaced. One of these relays was not correctly reinstalled, an error which was not detected and corrected until placing the level control system in operation during unit startup on February 20-21, 199 The unit commenced startup at 2:45 p.m. on February 20, 1991, and achieved criticality at 4:56 p.m. later that afternoon. Power was increased to 24% to continue tests/surveillances initiated during the previous startu The inspectors interviewed the operations personnel involved with the scram, reviewed applicable operating procedures and discussed the event with operations managemen Operator actions appeared appropriate, and in accordance with approved procedures and previous simulator training. Procedures were evaluated as adequate.

• The licensee initiated an independent Significant Event Response Team (SERT) review, and conducted normal line management reviews. A SERT report dated February 27, 1991, and Licensee Event Report (LER) 91-05 were written. The inspector reviewed both reports. The SERT report was well-researched and written. The SERT determined root cause of the scram to the failure of the C32-K9 relay contacts to properly make up when reactor feedpump control was shifted to manual. Six additional factors were identified as contributors to the event. Based on their findings, the SERT made sixteen recommendations, a number of which were implemented prior to the unit restart. Of particular note were recommendations to develop and implement a preventive maintenance program for balance of plant relays and to evaluate the upgrading of the current analog feedwater control system to a level of reliability that is comparable to digital control system The inspector concluded that the SERT recommendations appeared comprehensive and appropriately addressed the causes of this event. LER 91-05 was noted to be a condensation of the more important elements of the SERT report, including corrective actions taken to prevent recurrence. One minor discrepancy was noted in the LER (wrong revision number on page 5) which was brought to the licensee's attention. No discrepancies were noted in the SERT report. The inspector had no further questions regarding this event and concluded that the licensee was effective in determining the root cause and corrective actions for this scram. RADIOLOGICAL CONTROLS Inspection Activities PSE&G's conformance with the radiological protection program was verified on a periodic basis. These inspection activities were conducted in accordance with NRC inspection procedures 71707 and 9370.2 Inspection Findings 3. Salem Unit 1 Containment Tours The inspector conducted five Unit 1 containment tours during the refueling outage. The applicable radiological controls were verified to be in place and in accordance with program requirements. Hardware deficiencies identified by the inspector during the tours were brought to the licensee's attention for resolution. Among them were corroded electrical wire contacts in an accumulator cabinet and the lack of identification tags for the temporary power/air supply console for the steam generator nozzle dams. The licensee initiated the appropriate corrective action for both item *

• Spread of Radioactive Contamination On March 19, 1991, the licensee identified that radioactive contamination was inadvertently spread to portions of the Unit 1 reactor containment, the fuel handling building (FHB), and the Auxiliary Building at elevations 130 foot and 100 foot, including an associated stairwel The licensee concluded that the cause of the contamination was poor radiological protection practices by contractor personnel. Specifically, during transport of highly contaminated equipment (contained in plastic bag(s)) from reactor containment to the FHB, some of the bags had apparently ripped and resulted in the spread of radioactive contamination. Six persons had become slightly contaminated (less than 6,000 disintegrations per minute/100 square centimeters).

The inspector found that the licensee had initiated an Incident Report and a Radiological Occurrence Report (ROR) to evaluate the event. Corrective actions included stopping work in the FHB until the equipment was rebagged, decontaminating the affected area, and discussing the event in detail with applicable personnel, including reinforcement of the proper radiation protection practices for handling and transporting of contaminated materia The inspector concluded that the licensee's response to this event was acceptable. The licensee was continuing the ROR evaluation for additional followup at the end of the inspection period. An NRC Region I specialist inspector will review the closed ROR during a subsequent routine radiation protection program inspectio. Hope Creek Drywell Inspection and Closeout On February 14, 1991, the inspectors toured the drywell prior to final licensee closeout for the third refueling outage. Equipment, housekeeping and radiological conditions were noted to be good. The Manager, Radiation Protection and Chemistry, accompanied the inspectors during portions of the tour. A few minor lagging and insulation deficiencies were appropriately addressed by licensee personnel. The inspectors concluded that the condition of the Hope Creek drywell was acceptable to support unit restart activitie Semiannual Effluent Release Report The inspector reviewed the July to December, 1990, Hope Creek Semiannual Effluents Release Report dated March 1, 1991. The inspector noted that noble gases released in the fou~h quarter were about ten times higher than the third quarter, 1990 (69 curies vs 687 curies); but the report did not explain the reason for this difference. The fourth quarter release was 7.53 % of the Technical Specification 3.11.2.2(a) limit. The inspector discussed this item with licensee management who stated the increase was due to two reasons: (1) the fuel leak which occurred late September 1990, and (2) the unplanned release that occurred on November 4, 1990, after a reactor scram. The report did discuss item (2), but did not

I I

I

mention item (1). The licensee acknowledged the inspector's comments and stated they would consider revising the repor.

MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards. These inspections were conducted in accordance with NRC inspection procedure 6270 Portions of the following activities were observed by the inspector:

Salem 1 Salem 1 Salem 2 Hope Creek Hope Creek Hope Creek Hope Creek Work Request (WR)/Order (WO) or Procedure Description Various W0900730179 W0910306105 Various W0910132659 W0900819024 W0910228084 Service water pipe replacement/repair Main steam isolation valve modifications Control room damper 2CAA18 Hydrogen seal oil and turbine generator bearing No. 9 seal troubleshooting Repair accumulator instruments on control rod drive hydraulic control unit 38-59 Change high pressure coolant injection pump oil Repair "A" hydrogen/oxygen analyzer The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance progra.2 Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance packages. The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulations. These inspection activities were conducted in accordance with NRC inspection procedure 6172 *

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

Salem 1 Salem 1 Salem 2 Salem 2 Salem 2 Hope Creek Hope Creek Hope Creek Procedure N SP(0)4.0.5-V-CS-6 PI/S-CV-2 S2.0P-PT.SW-0021(Q)

SP(0)4.4.7.2d SP(0)4.8.1. Various startup tests OP-FT.AC-002(Q)

OP-IS.BJ-OOl(Q)

Inservice Testing Valves -

Containment Spray System No. 12 Charging Pump Flow Test No. 21 Containment Fan Coil Unit Performance Test Reactor Coolant Leakage Test Emergency Diesel Generator Monthly Test Shutdown Margin Determination, and Safety Relief Valve, High Pressure Coolant Injection, and Reactor Core Isolation Cooling Tests Main Turbine Functional Test High Pressure Coolant Injection Main and Booster Pump Inservice Test The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra.3 Inspection Findings 4. Salem Open Item Followup (Closed) Unresolved Item (272/89-21-03) Adequacy of the Technical Specification (TS)

Surveillance Program. Historically, there had been numerous cases of overdue and missed surveillances due to, in part, improperly implemented TS amendments and missing test procedures. The licensee performed a TS audit project which was completed in 1990. The final report was issued January 24, 1991. The audit included the following areas:

(1)

Computer data base verification, (2)

TS surveillance monitoring program,

• (3)

TS amendment implementation program, and (4)

TS surveillance reverification projec Licensee actions included a verification of historical information (items 1 and 4) and a review and enhancement of TS programs (items 2 and 3). Specific deficiencies uncovered were reported in LERs, each of which was reviewed in a previous NRC inspection. The licensee concluded that the completion of this project ensures compliance with the Salem TS The inspector reviewed the audit report, selected LERs, the action tracking report, the governing station administrative procedure AP-12, "TS Surveillance Program," and discussed this item with licensee personnel. Actions taken appear to be adequate, and the inspector had no further questions at this time. This item is close (Closed) Unresolved Item (272/89-11-06). During observation of surveillance test SP(0)4.0.5-P-AF(23), "Inservice Testing (IST) Auxiliary Feed Pump," the inspector noted that the pumps were not marked as to where the vibration probe should be placed to obtain the necessary reading. Also, the pump/motor drawing gave an approximate location to place the vibration probe, leaving the location subject to operator interpretation.

The licensee issued Work Request 0068855 to perform a walkdown of Unit 1 pumps to identify that the specific vibration test locations were marked. In addition to inspecting and marking the vibration locations on both Unit 1 and 2 pumps, the licensee changed procedure SP(0)4.0.5-P-AF (11), Revision 11, to SI.OP-ST-AF-OOOl(Q), Revision The new procedure added sections and statements to the old procedure to be completed by the surveillance organization. The vibration marking locations were identified for all required Unit 1 and 2 pumps during the second quarter of 199 IST personnel are mounting permanent connectors on motors so that the CSI Model 2110 Machinery Analyzer can be connected to them for recording vibration levels as well as other technical information. The data collected by the CSI probe system is downloaded to a computer for engineering review and analysis. Training on the CSI Model 2110 system was given to licensee personnel between November 1990 and January 1991 per lesson plan No. 301-D151-V1B01-00. The licensee plans to have the connectors installed on all Salem Unit 1 and 2 motors by the second quarter of 199 The new CSI Model 2110 system should eliminate the problem of location identification discussed in this unresolved item since procedure SI.O:P-ST-AF-OOOl(Q)

gives specific instruction on the connector mounting location. This item is close.

(Closed) Unresolved Item (272/89-22-02). During the performance of Limitorque preventive maintenance (PM) and surveillance testing on motor operated valve (MOV)

• 12SJ134, the licensee identified bum damage to wire insulation internal to the motor operator and in close proximity to the limit switch compartment heate The licensee believed that during the inspection of their MOV s based on Information Notice (IN) 86-71, "Recent Identified Problems With Limitorque Motor Operators, 11 all heaters were disconnected. To resolve this issue, Technical Department Engineering Memorandum 89-143, December 11, 1989, was issued. This memorandum required a reinspection of all Unit 1 and 2 MOVs, as referenced in IN 86-71, to ensure that the heaters were disconnected within the limit switch compartment, or work order CM-891025170 was used to perform the work. All identified MOVs for both Unit 1 and 2 have been verified with the exception of four on Unit 1. These four are scheduled to be inspected during the current Unit 1 outag The inspector closed this unresolved item based on a sample review of the work orders completed and the quality assurance documentation, which formed part of the closeout data package. This item is close.

(Closed) Violation (272/90-12-02). The licensee failed to identify the calculation errors in surveillance test procedure SP(0)4.5.2.H during a review subsequent to the identification of a similar problem in January 1990. To ensure that the responsible organization performs complete reviews as discussed in the licensee response to the violation, station management issued guidance to all operating organizations on July 23, 1990. The July 23, 1990, letter clearly specified the requirements for conducting reviews of safety significant issues. To support this effort, procedure NA-AP-ZZ.006l(Q), "Significant Event Response Team Management, 11 was revised and issue This procedure provides the guidance for an independent review of each reactor trip or other safety significant event. The guidance specified in licensee's letter of July 23, 1990, and the issuance of procedure NA-AP.ZZ-006l(Q) provide adequate controls and guidance to address this violation. This item is close Steam Generator Inservice Inspection On March 14 and 15, 1991, the inspector reviewed the following steam generator activities of the ninth Unit 1 refueling outage:

Stress relief of row two tube bends in all steam generator Replacement of a suspect heat lot of Inconel 600 plugs with Inconel 690 plugs in the hot leg of all steam generator Eddy current test of steam generator tubes (100 % ) using a bobbin coi Eddy current test of twenty percent of tubes in expansion transition region of tube sheet using a rotating pancake coi *

The inspector reviewed the following documents:

Certifications of eddy current data analysts on the job, Certifications on calibration standards, Stress relieving charts on row two U-bends and the procedure for stress relieving, and Material mill test certificates for mechanical plugs to be used during the outag There were no discrepancies noted in the review of the above. However, the inspector noted that the licensee did not have a plant specific Data Analyst's Guideline. A generic Westinghouse Data Analyst's Guideline was used during the eddy current data evaluatio The licensee stated that they would develop a plant specific Data Analyst's Guideline and use it during the next eddy current test of Salem steam generator The licensee's quality assurance inspection discovered two ruptured tubes in row one, columns two and three, in No. 14 steam generator during a post inservice inspection. Both tubes had been explosively plugged during the first refueling outage of the unit due to interference with the tube lane blocking device. The ruptured tubes had "fish-mouth" openings of approximately 1/4 inch in width and 1 1/4 inch in length. The tubes had bulged prior to "fish-mouth" opening. The ruptures were located approximately 1 112 feet above the tube sheet. The licensee replaced the explosive plugs with mechanical plugs in the hot and cold legs of both tubes. The licensee visually checked other explosive plugs for leaks while the secondary side was filled with wate In steam generator No. 11, the previously explosively plugged tube in row one, column two, had a hole believed to have been caused by inadvertent grinding during removal of the tube lane blocking device. The licensee intends to replace the explosive plug with a mechanical plug during the next outage to preclude leakage of the tube due to leakage past the existing plu Subsequent to their inspection, the licensee discovered that in steam generator No. 14, two tubes were incorrectly plugged during the previous outage. The hot leg side of the degraded tube (R18-C12) was plugged, whereas the cold leg side of the adjacent tube (Rl8-Cll) was inadvertently plugged. The licensee corrected the discrepancy by plugging the corresponding open tube ends. The licensee has an independent verification program to confirm eddy current findings and tubes to be plugged to preclude incidents of the above natur Also, subsequent to their inspection, the licensee discovered a circumferential tube crack in No. 14 steam generator at 0.04 inches below the top of the tube sheet during a rotating pancake coil (RPC) probe examination. The cracked tube was plugged and the adjacent tubes were examined using RPC probes. Conference calls on March 15 and 21, 1991, were held

with Region I, NRR and licensee personnel. Based on these conference calls, the licensee agreed to provide NRR with the eddy current test data for independent review and evaluatio The inspector concluded the licensee's steam generator tube examination program was conducted in accordance with the licensee's procedures and met applicable regulatory standards. However, the licensee decided to waive an owners' group recommendation for 100% RPC examination of tubes in steam generator No. 14 primarily for ALARA considerations. Within the scope of the inspection, no unacceptable conditions were note Technical Specification 3.0.3 Entry Due to Personnel Error On February 9, 1991, during a Unit 1 controlled shutdown for refueling, Technical Specification (TS) 3.0.3 was entered at 8:45 a.m. due to personnel error. The unit was at 18% power at the time of the TS 3.0.3 entry. With the No. 14 steam generator (SG) steam flow channel II out of service (since failure on February 8, 1991), a maintenance supervisor mistakenly valved out of service the No. 14 steam flow channel I while troubleshooting channel II. There are two steam flow channels per steam generator. Control room operators immediately received indication of a channel failure when channel I was isolated and directed the maintenance supervisor to unisolate steam flow channel I. The particular root valve (14MS4) that was mistakenly closed was reopened after ?bout one minute. TS 3.0.3 was exited at 8:46 The licensee concluded that this event was due to personnel error. The maintenance supervisor did not fully understand and properly assess an anomaly experienced while attempting to isolate channel II and did not review the appropriate documentation prior to manipulating plant components, resulting in the inadvertent channel I steam flow isolatio The licensee has taken corrective disciplinary actions with the supervisor involved and reviewed this event with the applicable maintenance department personne The inspector concluded that the licensee's review of and corrective actions for this event were appropriate. Section 8.1. C of this report discusses weaknesses associated with the licensee event report (see Unit 1 LER No. 91-03 for this event). Reactor Protection System (RPS) Actuation While Shutdown On February 17, 1990, an RPS actuation occurred at Unit 1 while in Mode 5 (Cold Shutdown). The cause of the event was personnel error/inattention to detail during maintenance. While performing work on source range nuclear instrumentation system (NIS)

channel 1N32, a maintenance technician inadvertently removed the fuse from an adjacent intermediate range NIS channel, No. 1N36. This action resulted in an RPS actuation signal by satisfying the one out of two system trip logic. All control rods were already inserted, and the reactor trip breakers were open prior to the actuation. The licensee reviewed this event with the applicable maintenance department personnel, stressing the use of self-checks during work activitie *

The inspector reviewed this event, including plant response, 10CFR50. 72 reporting and licensee corrective measures, and no concerns were identified. However, a concern was identified relative to the quality of associated Licensee Event Report 91-08 (Section 8.1. C). KV Sustained Degraded Voltage Relays Found Out-of-Specification On February 26, 1991, the licensee identified that the as-found setpoints for all nine Unit 2 sustained degraded voltage relays were less than the TS allowable values. The unit was operating at 100 % power at the time of discovery. This event was reported to the NRC via the Emergency Notification System per 10CFR50. 72 reporting requirements as being a condition outside the design basis of the plan The condition was identified during routine monthly surveillance testing of each of the three 4KV vital buses. Each vital bus has three 91 % sustained degraded voltage relays, which provide an input to the safeguards equipment control system to initiate vital bus emergency loading. Each vital bus is also provided with a single loss of voltage (70%) relay, however, none of those relays appeared to be similarly affected. Following the identification of each deficient reading, each relay was recalibrated to the TS required trip setpoint as specified in the surveillance procedure, S2.MD-FT.4KV-000l(Q), 0002(Q), and 0003(Q), "ESFAS Instrumentation Monthly Functional Test - 2A(B)(C) 4KV Vital Bus Undervoltage."

The February 26, 1991, testing was the first since the issuance of a new surveillance procedure, developed by the Procedure Upgrade Project (PUP) team. The licensee believed that the as-found low readings may have been due to the use of new calibration instruments having a higher accuracy than previously used instruments. The licensee instituted relay testing on an increased frequency (weekly) for several weeks to verify that the relay setpoints were not drifting. Additional licensee activities in progress are: 1) evaluation of the safety significance of the setpoints being below the TS values, 2) verifying that the 70 % relays are not similarly affected, 3) and determining how long the condition was present prior to the finding. This item is unresolved pending licensee resolution of the above issues, issuance of the LER and NRC specialist followup (UNR 311/91-05-01).

4. Hope Creek Startup Testing The inspectors observed several surveillances conducted during startup and power ascension testing. Testing was effectively planned and coordinated, and well conducte Steam Leak Detection Thermocouples On January 22, 1991, the licensee identified incorrectly wired room temperature monitoring thermocouples and reported this to the NRC in LER 91-02. During installation of a design change which involved the upgrading of the steam leak detection system (SLD) temperature

modules, the licensee discovered that two of four SLD thermocouples that provide input to the High Pressure Coolant Injection (HPCI) system isolation circuitry were incorrectly wire The HPCI logic is such that only one thermocouple is required to cause an isolation to occu The licensee concluded that an isolation signal caused by a HPCI steam line break would not have been generated from the two miswired functioning thermocouples. This configuration had apparently existed since initial construction, as a review of maintenance records indicated these subject thermocouples had never been worked on. Subsequently, the licensee rewired the thermocouples in the right configuration and verified operability. Further, the licensee verified that all other SLD thermocouples were correctly wired by a functional check utilizing a thermal bath. The licensee also verified that the Technical Specification HPCI isolation functions provided by the redundant thermocouples were operable and would have caused system isolation in the event of a high temperature in the HPCI room or pipe chas The inspector reviewed the licensee's corrective actions as stated in the LER, and their assessment of the minor safety significance of this incident. The inspector determined that licensee activities regarding corrective actions and safety significance appeared appropriate..

The inspector had no further questions on this issu Primary Containment Isolation System (PCIS) Actuations During Maintenance, Testing and Modification On February 3, 1991, after completing an environmental qualification (EQ) seal design change on a reactor vessel water level transmitter, a technician valved the instrument back into service, resulting in a channel "A" PCIS actuation. The actuation tripped the reactor building ventilation system, started the "A" and "E" filtration, recirculation and ventilation system (FRVS) recirculation fans, started the "A" FRVS vent fan, and isolated the torus water cleanup system. After determining that the PCIS actuation was the result of an invalid reactor water level signal, operators reset the initiation logic and returned equipment configuration to normal. On February 13, 1991, another channel

"A" PCIS actuation occurred, while technicians were performing a valve lineup check on reactor vessel reference leg instrumentation valves. After confirming a spurious signal, the isolation was reset, and plant equipment was returned to norma In both events, the licensee determined that the root cause for the PCIS isolation was the high sensitivity of the reactor vessel reference leg instrumentation to minor hydraulic transients produced by valve manipulations such as those above. The root and contributing causes, and subsequent corrective actions were discussed in Licensee Event Reports (LER) 354/91-04 and 91-04-01. The inspector noted that incidents of this type had occurred on several occasions in the past at Hope Creek (reference LERs in 1986 and 1987), and that similar events had occurred at numerous other boiling water reactors (BWRs).

The licensee implemented actions to address this matter, including enhanced training, procedural upgrades and additional guidance, barrier installation around sensitive instrument racks, and implementation of a BWR owners group recommended design change to add calibration volume chambers to further reduce instrument sensitivity during surveillances. The recommended design change is expected to be completed by the end of the next outage, September 199 The inspector discussed the issue of instrument sensitivity with licensee personnel in several departments. Those contacted were knowledgeable about the issue and the need for particular care when working around or with components associated with these instruments. When questioned on valve lineup checks, however, there appeared to be some confusion on how to verify full open or full closed positions without affecting the PCIS (industry practice is to verify both by attempting to tum the valve in the "close" direction). This issue was still under review by the inspector when the inspection period ended and will be carried as an unresolved item (UNR 354/91-04-01).

Licensee personnel indicated that it was common practice for instruments with trip units having a "test" position to be placed into "test" to prevent spurious signals being generated when the associated transmitters were removed or returned to servic However, a requirement to do so was not included in the applicable procedures. In LERs 91-04 and 91-04-01, the licensee committed to proceduralizing such a requirement for instrumentation so fitted. The inspector had no further question.

An engineered safety features actuation occurred to the primary containment isolation system (PCIS) during surveillance testing. LER 91-01 discussed this PCIS actuation, which occurred on January 11, 1991. Early on that day, the "B" reactor protection system (RPS) bus was manually transferred from the alternate to the normal power supply. The resultant alarms were acknowledged, however, the manual isolation logic for channel "B" nuclear steam supply shutoff system (NSSSS) was not reset and the signal remained "sealed in". No indication was present to reflect the "sealed-in" signa A short time later, while performing a functional test of the "B" emergency core cooling system (ECCS) reactor water level instrumentation, the "B" channel was placed in test. Consequently, both concurrent signals satisfied the "B" channel PCIS logic, and the PCIS actuations occurre The event was determined by the licensee to have been caused by a combination of personnel error (the NSSSS logic was not reset after the "B" RPS transfer as required by the transfer procedure), system design (no indication of isolation logic status for a single channel), and procedural deficiency (no prerequisite to reset PCIS logic before starting surveillances).

The inspector reviewed the actions taken by the licensee to correct these deficiencies as stated in LER 91-01, and determined that they appeared to adequately address the

• procedural and personnel issues in this event. No deficiencies were noted related to this LE.

An actuation of the "C" PCIS logic occurred on January 25, 1991, when a design change was being implemented concurrent with the performance of an ECCS instrumentation surveillance. The test required the "C" channel drywell pressure trip unit to be tripped, giving the expected half PCIS isolation signal. A contract technician implementing a design change in the steam leak detection (SLD) cabinet inadvertently grounded a lead in the cabinet, blowing a fuse in the NSSSS logic which then satisfied the rest of the PCIS logic causing the PCIS actuation. The design change was being implemented to enhance the testability of the temperature modules in the SLD cabinets due to limited accessibility, which had contributed to four previous PCIS actuation After resetting the isolation and returning the equipment configuration to normal, the design change was completed without further inciden The inspector noted that the licensee's corrective actions as stated in LER 91-03 appeared appropriate. No deficiencies were noted in this LER, and the inspector had no further question.

EMERGENCY PREPAREDNESS 5.1 Inspection Activity The inspector reviewed PSE&G's conformance with lOCFRS0.47 regarding implementation of the emergency plan and procedures. In addition, licensee event notifications and reporting requirements per 10CFR50. 72 and 73 were reviewe.2 Inspection Findings Loss of Salem Emergency Notification System (ENS) Phone On February 13, 1991 at 4:30 a.m., during routine daily communications with the NRC, the Salem ENS phone was found not to be functioning. A one hour notification was made on the backup telephone system. The licensee traced the problem to the No. 11 emergency lighting inverter (power supply). Repairs were initiated, and the ENS phone was restore On February 19, 1991, at 8:00 a.m., the Salem ENS phone was again found not to be functioning. A one hour notification was made on the backup telephone system. This was due to another trip of the No. 11 emergency lighting inverter (power supply). The ENS phone was restored from an alternate power supply. Further licensee troubleshooting on the lighting inverter was in progress at the close of this inspection perio At about 4:00 a.m. on March 22, 1991, the Hope Creek ENS phone was found not to be functioning during daily routine NRC communications. A one hour notification was mad The licensee repaired the phon *

21 Hope Creek Emergency Drill An emergency training drill was held at Hope Creek on March 15, 1991. The inspectors participated in the drill from the control room (simulator) and the technical support center (TSC) facilities. Drill performance was adequate, and the licensee successfully evaluated and critiqued their performanc However, the inspector noted a potential weakness regarding the TSC's ability to follow emergency operating procedure (BOP) implementation. While the control room implements these flow chart BOPs for both Hope Creek and Salem, the TSC does not dedicate a knowledgeable individual to closely follow and track BOP implementation. Consequently, the TSC may not be able to thoroughly evaluate and assess plant conditions. Meetings and discussions were held with emergency preparedness, Hope Creek, and Salem management personnel on this matter. Proposed licensee corrective actions included the following:

ensure copies of BOP flow charts are available in the TSC, designate the Technical Support Supervisor (TSS) as responsible to follow BOP implementation, revise TSS briefing checklist to include status of BOP implementation and, provide BOP familiarization training for TSC engineering personne The inspector will assess the effectiveness of these actions in future drills and exercise.

SECURITY Inspection Activity PSB&G's conformance with the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries. These inspection activities were conducted in accordance with NRC inspection procedure 7170.2 Inspection Findings Fitness For Duty (FFD); Licensed Operator Testing Positive For Alcohol At about 10:00 a.m., on February 21, 1991, during a scheduled physical examination, a Hope Creek licensed reactor operator (RO) was determined to have a blood alcohol concentration (BAC) of 0.01-0.02%. The Medical Review Officer (MRO) calculated that the employee's BAC would have been greater than.04% at the individual's work start time of 7:00 a.m. The individual admitted to some alcohol consumption up until midnight prior to the start of the shift. Upon notification by the MRO to Hope Creek Operations, the RO was

suspended from plant access and all licensed duties and referred to the licensee's Employee Assistance Progra According to operations management, the RO had reported for work at 7:00 a.m. as an extra-duty operator. He attended the shift tum-over briefing, then reported for his physical. He did not relieve an operator before taking the physical, nor did he exhibit any unusual or abnormal behavior while in the control room. Since the RO apparently proceeded directly from the security access to the control room area, it was considered unlikely that any unusual behavior would have been noted when he processed through the security screening area to obtain his access badg The NRC Operations Center was notified of this FFD event by the licensee at 6: 17 p. m. on February 21, 1991. The inspector was also informed and reviewed the licensee's FFD actions. The inspector verified the RO had not assumed any license duties. FFD related actions appeared to be adequate and consistent with program requirement Information Pickets Onsite On March 4, 1991, the licensee informed the residents of the potential for informational pickets demonstrating onsite. The International Brotherhood of Electrical Workers (IBEW) is seeking to become the bargaining agent for personnel who work for certain firms employed by various NRC licensees to provide outage and maintenance related services. At Salem and Hope Creek, 110 health physics workers from Bartlett Nuclear, Incorporated and General Technical Support, Incorporated were affected. The majority of these workers were supporting the Salem Unit 1 refueling outag On March 6, 1991, the licensee established a reserved gate and activated the auxiliary guard house for these affected employees. All other PSE&G and contractor personnel used the normal access gate and guard house. On March 7, 1991, at 8:00 a.m., approximately twenty IBEW members demonstrated for one hour. Contractor egress/ingress was not affected. The inspector monitored picket activities and auxiliary guard house activation. No unacceptable conditions were note.

ENGINEERING/TECHNICAL SUPPORT Salem Open Item Followup (Closed) Unresolved Item (272/89-20-02), 13 KV underground cables cut in the switchyard. This event occurred on August 30, 1989, when excavation was in progress for a paving project. The cables cut were the Hope Creek temporary feed to the Salem circulating water pumps (three of six on Unit 1). The licensee completed their investigation, and concluded that inadequate installation specifications resulted in the

cables being ten inches deep rather than the expected 36 inches. In addition, no protective cover was used, the job was apparently rushed, cable location and depth was not known by the excavation contractor, and a "temporary" installation had remained for several years. The licensee implemented the following corrective actions:

completed investigation report on September 22, 1989; issued a "safety alert" to all personnel; formed an underground task force to review the process to bury and excavate cables; and discussions were held with appropriate contractor, licensee and management personne The inspector reviewed the licensee's report, including root causes and corrective actions. In addition, the inspector reviewed the safety alert and discussed this item with licensee personnel. The inspector had no further questions, and the unresolved item is close.

(Closed) Violation (272/90-05-01), Inadequate design change for the diesel fire pump An automatic start feature of both fire pumps had been disabled. This feature was on a timing circuit, and the licensee believes this was disabled prior to Salem licensin Apparently, the fire pumps were procured with this auto-start feature; however, licensing requirements did not require this feature. Licensee corrective actions include:

immediate development of a safety evaluation and temporary modification to document the configuration change; UFSAR change issued July 1990; and, development of a permanent design change packag The inspector reviewed the licensee's response (May 14, 1990) to the violation and verified their corrective actions. This violation is considered close.

(Closed) Unresolved Item (272/91-01-03), Containment Fan Coil Units (CFCUs)

In response to NRC Generic Letter No. 89-13, the licensee reviewed the heat removal capability for both Unit 1 and 2 CFCUs. The unresolved item was initiated pending completion of the licensee's inspection, cleaning and testing activities on the ten CFCU s (five per unit).

The licensee submitted Unit 1 LER 91-05 addressing these CFCU issues. All the Unit 2 CFCU s were tested with the following satisfactory results:

CFCUN BTU/hr (million)

8.6 8.8 9 The design heat removal valve is 81 million BTU/hr. Numbers 21 and 22 CFCUs were inspected and cleaned before the heat removal test. Numbers 23, 24 and 25 CFCUs were tested with no prior cleaning activities. The licensee stated that these results were consistent with their expectations based on recent (1988-1990) cleaning and inspection activitie The Unit 1 CFCUs were opened, inspected and cleaned during the current refueling outage. Heat capacity testing is scheduled for unit restart. In addition, the licensee intends to test the heat removal capability of the CFCUs on a periodic basi The inspectors reviewed Unit 1 LER 91-05 and the test results for all ten CFCUs, witnessed portions of testing for No. 21 CFCU (section 4.2), and discussed this item with licensee engineering, test, operations and management personnel. Based on the above licensee actions and inspector review, the unresolved item is close Unit 1 Refueling Outage Activities The licensee identified two failed fuel pins during post core offload fuel examination Babcock and Wilcox (B&W) performed this ultrasonic inspection using their ECH0-330 system process. The fuel pins (assembly L-23, pin B-13 and assembly L-26, pin B-15) were both second row pins that were located in once burned fuel assemblies. The licensee conducted core reload with substitute assemblies. Westinghouse is performing additional inspections to determine root cause. Dose equivalent iodine averaged approximately 0.004 microcuries per milliliter. However, iodine spikes noted during unit shutdowns and periodic isotopic analyses and ratios indicated a small fuel leak during the last Unit 1 cycle. The inspector reviewed the fuel inspection procedure, "B&W Fuel Assembly Examination," FO-SAL-001, revision 2. The inspector also discussed this item with licensee engineers and had no further question Accident Mitigation Deficiency On February 15, 1991, a licensee evaluation concluded that an unsealed horizontal portion of the seismic gap between the Unit 1 inner mechanical penetration area and the adjacent electrical penetration constituted a condition that could have prevented the fulfillment of the safety function of systems needed to mitigate the consequences of an accident. The seismic gap consists of a horizonal annular section that is six inches wide by 66 inches long and a vertical portion that is six inches wide by 40 inches high. The Unit 1 vertical seal was found to have been installed in accordance with design requirement The purpose of the high energy seal is to prevent the steam environment that would exist in the inner area during a postulated main steamline break from entering the mild environment of the adjacent electrical penetration area. This condition was initially found at Unit 1 by the licensee on December 20, 1990, while the unit was operating at 100% power. However, on February 8, 1991, the licensee recognized that the area had not yet been sealed and initiated a

• '

request to evaluate its safety significance. The evaluation was completed on February 15, 1991, when Unit 1 was in Mode 5 (Cold Shutdown). The condition was reported to the NRC on February 15, 1991, in accordance with 10CFR50.72 reporting requirements. The licensee plans to install the horizontal seal prior to Unit 1 restart from its current refueling outag When the deficient seal condition at Unit 1 was identified on February 15, 1991, Unit 2 was operating at full power. An initial investigation revealed that the associated Unit 2 horizontal and vertical areas were sealed. However, on February 19, 1991, the licensee identified that the horizontal portion of the Unit 2 seismic gap was actually not properly sealed in that only an anchored flashing was in place vice the required rubberized fabric material. That portion was then properly sealed in accordance with the design requirements on February 22, 199 The Unit 2 vertical seal was verified to be acceptabl Also during this inspection period, the licensee informed the inspector that in May 1990 the Unit 2 vertical seismic gap seal was missing. An engineering analysis was then initiated, and completed in November 1990. The analysis concluded that there was minimal safety significance for the missing vertical seal (i.e. no increase in core damage frequency).

Nonetheless, the Unit 2 vertical seismic gap was properly sealed in November 1990. Also, at that time, the Unit 1 vertical seal was inspected and found to be acceptabl The licensee's February 15, 1991, Unit 1 evaluation concluded that the core damage frequency increased due to the identified condition (no horizontal seal). At that time, the licensee reviewed the November 1990 evaluation for the Unit 2 vertical seal and determined that the Unit 2 evaluation was incorrect due to a personnel error (incorrect assumption).

By the end of the inspection period, the inspector confirmed that the Unit 2 seismic gap was properly sealed and that plans were in place to properly seal the Unit 1 horizontal seismic ga The inspector expressed concerns relative to equipment qualification/operability in the Unit 1 and 2 electrical penetration areas under postulated accident conditions with the degraded seals. The licensee stated in Unit 1 Licensee Event Report (LER) 91-09 that an evaluation is in process to address the effects on the motor control centers, located in the electrical penetration areas. The inspector also expressed a concern that the Unit 1 seal deficiency was not previously identified (May-November 1990) upon discovery of the similar Unit 2 degraded condition. Resolution of this issue, including equipment operability concerns, licensee evaluation results, root cause of event, and any potential NRC enforcement actions, is an unresolved item (UNR 272/91-05-02). See Section 8.1. C for further discussion on weaknesses associated with Unit 1 LER 91-0 Main Steam Isolation Valve (MSIV) Modifications In the summer of 1990, concerns arose regarding the Salem MSIVs' ability to meet their design basis closing times and IEEE code requirements (see NRC Inspection Report 50-272 and 50-311/90-20). The licensee adequately addressed these concerns at the time, yet planned on performing modifications to the MSIV s to improve valve performanc During the Unit 1 refueling outage all four MSIVs were disassembled, inspected and modified. The hydraulic actuator and cylinder for each valve were removed and returned to the vendor, Atwood and Morrill, for refurbishment. The valve stems and gates were also removed and taken inside the turbine building, where the stems and disc faces were polished, and the springs between the double discs were removed and checked for the proper tensio In addition to this maintenance performed on the valves, a modification was made to the steam piston on the valve shafts. These pistons have an equalizing orifice that permits steam pressure to equalize across the piston and maintain the valve in the open position. The design modification involved enlarging this orifice in order to provide a higher pressure on the top of the piston and thereby induce better condensate drainage flow from above the pisto Previously, PSE&G engineering had determined that it was the collection of condensate above the piston that was the primary cause of the valve closing times exceeding the Technical Specification (TS) limit PSE&G had requested and received from the NRC an extension in the TS closure time limit from five to eight seconds for the last operating cycle to compensate for the identified

• condensate collection problem. The licensee has requested that this extension be carried over to this next operating cycle so that plant operations will not be restricted while the design modification is evaluated once the plant is started up. As of the end of the report period, NRR had not yet responded to the licensee's reques The inspector observed portions of the valve disassembly, associated maintenance work, and reassembly. The majority of the work done on the valves was performed by contractors under the supervision of PSE&G personnel. The work was well planned and executed. The inspectors reviewed the design change package for the modification of the MSIV s and the request sent to NRR for maintaining the required fast closure time at eight seconds. The work orders and design change package associated with the work on the MSIV s was found to be conservative in its approach and complete. The inspector will observe the testing of the MSIV s when the plant returns to power and will continue to monitor the performance of the modified valve.2 Hope Creek The inspectors noted that system engineers and corporate engineering (E&PB) were directly involved in the refueling outage activities. System and reactor engineers provided support for returning plant systems to service and for returning the unit to power operations. The inspectors concluded that engineering was effective and aggressive in these activitie..

27 SAFETY ASSESSMENT/QUALITY VERIFICATION Salem Open Item Followup (Closed) Violation (272/89-01-02), Failure to correct and prevent recurrence of self-identified shelf life non-conformances for over a three year perio.

The licensee performed a review of existing stock material during 1988. A stockroom walkdown resulted in approximately 1000 problem reports being issued. The problem reports identified that items with discrepancy tags were stored in the stock bins with material that was considered acceptable. Consequently, the tagged items were controlled in accordance with procedure Mll-P-300, and subjected to an engineering evaluation to determine acceptability for us Due to the problems identified in this area, additional administrative controls were put in place to physically identify, tag and prevent issuance of material with potential deficiencies. These controls are discussed in procedure Mll-P-30 A revised shelf life program procedure PM.AP.ZZ-030l(Q), Revision 0, dated August 1989, has been issued which supersedes Mll-P-301, Revision 2, of June 1988. The use of expired shelf life items is described in paragraph 4.7.7 of PM-AP.ZZ-0301(Q).

Detailed engineering and quality assurance evaluations and documentation are required before the tagged items can be issued. Inspector discussions with stock room personnel verified that they have been using the new shelf life program procedure and understand the criteria for release of expired shelf life items. It appears that the previous problems (1988) relative to expired shelf life have been corrected by new procedures, training of personnel and verification of stock material both by engineering and quality assurance personnel. This item is close (Closed) Unresolved Item (272/89-01-03), The amount of nonconforming material in the storage area and lack of formal verification of material acceptability upon issuance provides a significant potential that nonconforming materials could be issued for use in safety grade equipmen A review of the administrative controls that have been in place and the requirements of procedure Mll-P-301, Revision 2, June 1988, indicated that adequate guidance to the storage room personnel has been given. Quality audits (Procedure QAP 6-1) verified compliance with the various procedures that are used by the storage room personnel in the release of both acceptable and tagged material. Problems have been identified in this area by the quality assurance organization, however, they are being handled within the quality program plan for the site. An engineering review of the material identified in the Shelf-Life Problem Reports has been completed. The records identified that both * engineering and quality assurance reviews have been performed on nonconforming material that has been released from the storeroom for use in the plant. Relative to the samples reviewed by the inspector, engineering and quality assurance evaluation documentation was available to support the use of the material. This item is close (Closed) Unresolved Items (272/89-11-05 and 90-81-02), Temporary modifications (T-Mods) were not reviewed within the requirements of procedure AP-13, including the required Station Operations Review Committee (SORC) periodic reviews. Engineering has reviewed and classified all T-Mods for Units 1 and 2 as described in "Control of Temporary Modification," procedure NC.NA-AP.ZZ-0013(Q). In addition to the revised procedure requirements, engineering reports the T-Mod status at the weekly plant staff meeting. The T-Mod status is also tracked in the "Salem Technical Department T-Mod Status Report," and "Minor Design Change Worklist" repor A review has been completed on all old T-Mods to ensure that a 10CFR50.59 (if required) has been performed and updated. This review data has been documented and is now part of the weekly management report. The licensee's review did not produce any safety significant concerns nor any reports to the NRC as a result of the review. In discussions with both SORC and engineering personnel, the inspector verified that the personnel did follow the procedure requirements of NC.NA-AP.ZZ-0013(Q) and that the present monitoring programs should eliminate the identified concerns. These items are close (Closed) Unresolved Item (272/90-05-04) and Violation (272/90-11-01), Approximately 27% of the station's 2922 affected procedures were past their review date, and the original corrective action taken was ineffective in resolving the procedure review criteria of Technical Specification 6.8.2 and ANSI N18.7-1976 and Salem Administrative Procedure No. AP-3 To correct and prevent the above stated problem, the licensee has initiated a procedure upgrade program (PUP) which has been reviewing and updating implementing procedures. The Operation Department procedures were reviewed and updated in July 1990, and the maintenance and chemistry procedures reviews and updating were completed in October 199 The chemistry department identified an additional twelve procedures that required review. These procedures are presently in the review cycle as described and tracked by the PUP program. Procedure NC.NA-AP-ZZ-0032(Q) was issued and implemented in November 1990. This procedure combines the Salem and Hope Creek procedure review process into one program for the licensee's site. In addition, a trend report and computer listing of the due dates of procedures by organization is now issued to both the responsible organization and station management. This program identifies which documents are due for review during the next quarte To verify that the corrective action programs described in the licensee's response to the notice of violation of June 25, 1990, the licensee performed a quality audit (QAR N M29-89-021). This audit was performed to evaluate the effectiveness of.the program implementation and the status of selected procedures. The audit stated that the program was working and that the selected procedures audited were within their required date The inspector also selected ten procedures and verified that the procedures were reviewed within their date cycle and that the tracking system was tracking these procedures. The PUP issues a weekly and quarterly status report of the overall procedure status for both the Salem and Hope Creek site The inspector reviewed the report of February 17, 1991, for selecting the ten procedures that were reviewed for compliance with the requirements of Technical Specification 6.8.2, and ANSI N18.7-1976, and site procedure NC.NA-AP-ZZ-0032(Q). The inspector verified that the PUP program was performing as stated in procedure NC.NA-AP-ZZ-0032(Q) for both Units 1 and 2. This item is close Control of AC Electrical Power Sources During Refueling Outages During the Salem Unit 1 refueling outage, maintenance was performed on the offsite and onsite electrical power sources. This included switchyard maintenance, vital bus de-energization, and substantial diesel generator (DG) maintenance. The licensee was cognizant of recent loss of power events at other reactor sites caused by switchyard activities and out of service equipment. The licensee conducted a review of their planned work activities assoCiated with power sources. The licensee conducted safety meetings to communicate to all personnel the details of these events and to raise awareness of electrical power configurations during outage period The licensee reviewed Technical Specifications (TSs) associated with AC power sources (onsite and offsite). During Modes 5 and 6, redundancy for AC power is not required. The TSs allow one of two offsite sources and one of three DGs to be out of service. The licensee stressed the importance of minimizing the number of vehicles in the switchyard, of maintaining attention to detail when working, of following established procedures, and of maintaining proper work standards. *

The inspector discussed this item with licensee outage and operations management personne The inspector reviewed the outage plans, including equipment out of service, and related TS The inspector periodically toured the switchyard and electrical power source areas. During the Unit 1 outage, only one power source (offsite or onsite) was out of service at a tim The inspector also noted one instance where the licensee delayed core reload activities for several days until an emergency power source (lB DG) was operable for backup power to the operating residual heat removal pum *

The inspector concluded that the licensee was aggressive in ensuring personnel were informed of the recent loss of AC power events. Licensee actions associated with continuity of AC power appeared to be conservativ Licensee Event Report Quality The inspector noted deficiencies relative to four Unit I licensee event reports (LERs)

reviewed during this inspection. LER Nos. 91-03, 91-07 and 91-08 were missing information relevant to the event. Specifically, LER 91-03 failed to properly assess the actual consequences of having both steam flow channels for one steam generator in operable; LER 91-07 did not specify whether the auxiliary feedwater system actually injected water into the steam generators with the unit shutdown during an inadvertent system actuation; and LER 91-08 failed to state the condition of the control rods and reactor trip breakers and whether they were challenged when a reactor protection system actuation occurred while the unit was shutdow Additionally, LER 91-09 contained inaccurate information for event date and mode/power level, did not clearly describe the event for both Units 1 and 2 relative to the seismic gap seal configuration, and did not commit to providing a supplemental report when relevant evaluations were continuing which may possibly increase the safecy impact of the even The inspector discussed the above deficiencies with the appropriate licensee personnel and management, who acknowledged the inspector's concerns. The licensee indicated that revised LERs would be issue Safety Injection Charging Pump Run With Suction Valve Closed On March 19, 1991, Unit 1 safety injection charging pump No. 12 was inadvertently run for about four minutes with its suction valve tagged closed. The pump was being tested using the associated surveillance procedure, No. SP(0)4.0.5-P-CV(l2), "Inservice Testing -

Charging Pumps," to verify operation following maintenance and to satisfy Technical Specification (TS) surveillance requirements. The unit was in Mode 6 (Refueling) at the time of this even The licensee initiated an investigation into the cause of this event. The inspector conducted an independent evaluation and found that there were multiple problems that led to the pump operation with the suction valve closed. Among them were personnel errors by both licensed and non-licensed personnel during the tagging and release process, procedure quality and implementation deficiencies associated with administrative and test procedures, failure to identify and communicate a known hardware problem (suction valve reach rod disconnected),

inadequate training and/or technical competence, and the failure to maintain adequate communications with the control room operators during the testing of components operated from the control room. It appeared that several programmatic barriers related to the licensee's safety tagging system had been breached. The inspector also identified that the

• licensee's programmatic process by which a safety tagout is released (i.e. system restored to normal) relies upon perfect performance of two separate but related activities, with no formal mechanism to verify actual versus recorded component statu The inspector discussed the above concerns associated with this event with Operations and Station management. Several corrective actions *were initiated by the licensee, including interim modification of the safety tagging release process, enhanced operator training related to valve and breaker verification, and disciplinary actions, where appropriate. The licensee also committed to do full system lineups for all safety related systems upon completion of the refueling outage to ensure proper system restoration. An independent third party review will be conducte The licensee subsequently performed detailed mechanical and engineering analyses of the N charging pump, including several pump performance runs. A documented assessment was then reviewed by the Station Operations Review Committee on March 21, 1991, and the pump was declared operable. No significant pump damage was evident, however, additional full flow testing was scheduled when plant conditions were favorabl The inspector concluded that this event exhibited multiple deficiencies which require prompt management attention and corrective action. Additionally, while the tagging process for removing equipment from service appears to be adequate, the restoration process appears to be weak. Particular attention is warranted for Unit 1 as the refueling outage is nearing completion, and multiple safety systems are being released back to service. Pending resolution of this issue, this item is unresolved (UNR 272/91-05-03).

8.2 Hope Creek Control Rod Drive Scram Pilot Solenoid Valve Failures In November 1990, the licensee was notified by Cleveland Electric Illuminating Company (CBI) that a number of scram pilot solenoid valves manufactured by Automatic Switch Company (ASCO) had malfunctioned during operation. The valves in question had been identified as coming from ASCO lot number F61191A. Hope Creek had received 30 solenoids from this lot under PSE&G purchase orders P2-374654 and P2-356422. At CBI, during the period from July 27, 1990, to October 28, 1990, six solenoids had either failed to fully shift or leaked air during testing. In four cases, the problem could not be duplicated during later investigation. Twenty-six unused and two used (malfunctioning) solenoids were returned to ASCO for detailed examination, which was conducted on October 22-23, 199 The preliminary results of an ASCO study did not indicate any operating anomalie However, a number of solenoids were noted to contain evidence of contamination from unknown source Pending resolution of this issue, the Hope Creek licensee placed the 30 solenoids in a hold status in early December 1990. A meeting was held on December 19, 1990, between the

licensee and the solenoid valve supplier, General Electric (GE). GE informed the licensee that based on the ASCO test data derived in part from the functional testing and dimensional checks of the 28 solenoids, GE considered the solenoids furnished to the licensee from lot n F61191A acceptable for use. Subsequent to the receipt of a confirmatory letter from GE dated December 22, 1990, the licensee released the solenoids from hold status and placed them into llie inventor Based on personnel interviews and reviews of the ASCO tt'.st data and various licensee documents, the inspector concluded that the licensee had acted appropriately in placing the solenoids in a hold status and, upon evaluation of the available test data, in removing the hold and placing the solenoids into the inventor Refueling Recovery Activities Based on a review of pre startup preparations (2.2.2.A) and shift coverage during startup and power ascension (2.2.2.B, 4.3.2.A, and 7.2), the inspectors concluded that the licensee was effective in safely returning the Hope Creek unit to power operation.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP LERs and Reports PSE&G submitted the following licensee event reports, and special and periodic reports, which were reviewed for accuracy and evaluated for adequac Special/Periodic Reports Salem and Hope Creek Monthly Operating Reports for January and February 199 No unacceptable conditions were note Hope Creek Semiannual Effluent Release Report (June - December 1990) (See Section 3.2.2.B)

Salem and Hope Creek Fitness for Duty Semiannual Performance Data Report (June -

December 1990).. No unacceptable conditions were note Salem and Hope Creek Personnel Exposure and Monitoring Annual Report for 199 No unacceptable conditions were noted.

• Salem LERs Unit 1 LER 91-01 concerns two radiation monitor system (RMS) spikes on lRllA that resulted in containment ventilation isolation signals. The events were reviewed in :NR.C Inspection 50-272/91-01. Root cause could not be identified; however, this may be related to the recent RMS spikes. Licensee planned actions include short and long term design changes and equipment replacements. No unacceptable conditions were noted relative to this LE LER 91-02 concerns several through wall leaks in the service water system. These events were reviewed in NRC Inspection 50-272/91-01. The inspector reviewed the LER and had no further question LER 91-03 (See Section 4.3.1.C)

LER 91-04 concerns a turbine runback that occurred on February 6, 1991. The event was reviewed in NRC Inspection 50-272/91-01. No cause could be identified. The licensee intends to submit a supplemental repor LER 91-05 (See Section 7.1.A.3)

LERs 91-06 and 10 concern several radiation monitor system actuations. These events are reviewed in section 2.2.1.A of this repor LER 91-07 (See Section 2.2.1.E)

LER 91-08 (See Section 4.3.1.D)

LER 91-09 (See Section 7.1. C)

Unit 2 LER 90-29 (Revision 1) concerns a Unit 2 reactor trip that occurred on June 28, 1990. The revised LER addressed an update to the root cause and corrective actions. The trip occurred when low steam generator water level resulted when a failed transformer caused a loss of steam generator feed pump. The licensee concluded that inadequate preventive maintenance was the root cause. The inspector reviewed the LER and determined it to be adequat LER 91-01 concerns a twenty minute late firewatch patrol (hourly) that occurred on January 4, 1991. The cause of late patrol was due to a personnel error made by the firewatch. He had performed the patrol out of sequence. Licensee corrective actions appeared to be adequate and included verification that the areas were free of any fires, briefing other firewatch patrols, and disciplining the individual. The inspector had no further question *

LER 91-02 concerns three RMS spikes on radiation monitor 2R1A that resulted in a control room ventilation actuation. These events were reviewed in NRC Inspection 50-311/91-0 Licensee planned actions include short and long term design changes and equipment replacements. No unacceptable conditions were noted relative to this LE LER 91-03 concerns two through wall lea lcs in. the service water system. These events were reviewed in NRC Inspection 50-311191-01. The inspector reviewed this LER and had no question Hope Creek LER 91-01 (See Section 4.3.2.C.2)

LER 91-02 (See Section 4.3.2.B)

LER 91-03 (See Section 4.3.2.C.3)

LERs 91-04 and 91-04-01 (Revision) concern ESF actuations (two occurrences) - Channel

"A" primary containment isolation system actuations due to valve manipulations. (See Section 4.3.2.C.1 of this report for details.)

LER 91-05 concerns reactor scram on low reactor water level. (See Section 2.2.2.C of this report for details.)

9.2 Open Items The following previous Salem inspection items were followed up during this inspection and are tabulated below for cross reference purpose Open Item Report Section Status 272/90-26-02 2.2. Closed 272/89-21-03 4.3. Closed 272/89-11-06 4.3. Closed 272/89-22-02 4.3. Closed 272/90-12-02 4.3. Closed 272/89-20-02 7. Closed 272/90-05-01 7. Closed 272/90-01-03 7. Closed 272/89-01-02 8. Closed 272/89-01-03 8. Closed 272/89-11-05 8. Closed 272/90-81-02 8. Closed 272/90-05-04 8. Closed 272/90-11-01 8. Closed

1 EXIT INTERVIEWS/MEETINGS 10.1 Resident Exit Meeting The inspectors met with Mr. S. LaBruna and 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 Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CPR 2 restriction.2 Specialist Entrance and Exit Meetings Date(s)

Subject 3/11-15/91 Chemistry 2/19-27/91 Fire Protection 3/4-8/91 Radiation Protection 3/25-29/91 Security 10.3 Management Meetings Inspection Report N & 311/91-06 272 & 311/91-07 272 & 311/91-08 272 & 311/91-10; 354/91-07 Service Water Meeting On Site Reporting Inspector Kottan Paolino*

Nimitz Albert On March 5, 1991, the licensee gave a presentation of their service water pipe replacement program for the Salem Station. The licensee discussed background and historical information, their inspection and replacement programs, and their new structural integrity verification program. Attachment 1 is a list of attendees, and Attachment 2 is a copy of the licensee's handout used at the meetin *

ATTACHMENT 1 LIST OF ATTENDEES MARCH 5, 1991 NUCLEAR REGULATORY COMMISSION W. Lanning, Deputy Director, Division of Reactor Safety (DRS), RI J. Durr, Chief, Engineering Branch, DRS, RI J. White, Chief, Reactor Projects Section No. 2A, Division of Reactor Projects, RI J. Stone, Salem Project Manager, NRR T. Johnson, Senior Resident Inspector S. Barr, Resident Inspector PUBLIC SERVICE ELECTRIC AND GAS COMPANY S. LaBruna, Vice President - Nuclear Operations & Acting General Manager -

Salem Operations F. Thomson, Assistant to General Manager - Salem J. Ronafalvy, Manager - Nuclear Engineering Design M. Shedlock, Outage Manager - Hope Creek D. Beckwith, Station Licensing Engineer J. Jackson, Technical Engineer L. Lake, ISI Engineer I. Owens, Senior Staff Engineer J. Rowey, Senior Staff Engineer M. Ahmed, Lead Engineer S. Roche, Senior Staff Engineer N. Mistry, Senior Staff Engineer OTHER E. Krufka, Lead Engineer, Atlantic Electric P. Duca, Delmarva Power Site Representative L. Finic, Project Supervisor, Atlantic Electric T. Kolesnik, Nuclear Engineer, State of New Jersey

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.

SALEM SERVICE WATER SYSTEM

~

~

n

r:

STRUCTURAL INTEGRITY REIVIEW

~

N MARCH 5, 1991

• PRESENTATION AGENDA

• OBJECTIVE

• SWS PIPING REPLACEMENT PROGRAM BACKGROUND WORK PRIORITIZATION MONITORING PROJECT SUMMARY

• SWS INSPECTION PROGRAM BACKGROUND NRC GENERIC LETTER 89 - 13

• SWS STRUCTURAL INTEGRITY PROGRAM PROJECT TEAM APPROACH SITE SELECTION METHODOLOGY EVALUATION METHODOLOGY t NOM It MIN COMPARISON CHART IMPLEMENTATION SCHEDULE

• OBJECTIVE Develop an Overall Plan to Confirm the Operability Status of the Salem Service Water Syste BASIS The Structural Integrity of the Pipinc1 System would be tfle Basis for this....

Confirmatio '

.

• SERVICE WATER SYSTEM - PIPING REPLACEMENT PRtOGRAM BACKGROUND

1976 -1986

-

From early in plant life, the SWS experienced erosion I corrosion problem * May, 1987

-

The need for a comprehensive SW'S piping replacement plan was recognizetd and a Project Team was forme * July, 1987

-

Development of the SWS Piping Replacement Project Plan was complete *

November, 1987 The first 6 % Molybdenum Stainless Steel Piping was installe SERVICE WATER SYSTEM - PIPING REPLACEMENT PFIOGRAM WORK PRIORITIZAT~ON The Project Team performed a review of the existing Service Water System piping based on material condition, historical information (Def~ciency Reports, Work Orders) and subject matter expertise. Piping replacement was prioritize The priority rankings were defined as follows:

1. HIGH

-

High Incidence of Failur. MEDIUM 3. LOW

-

High Safety Related Impact Potential for Problems Over the Next Fiv1e (5)

Years Based on Existing Failure Requires High Surveillance Rates (i.e., Visual Inspection I Repair) to Ensure Unit Reliabilit Can be Repaired While Unit is at Powe Short Duration I Quick-Fix Job Observed Good (Relative) Conditio Low Impact on Plant Operation and Safe1t *

'-

SERVICE WATER SYSTEM - PIPING REPLACEMENT PROGRAM WORK PRIORITIZATION, (Continued)

The original (1987) project prioritization was as follows:

HIGH

-

CFCU (Containment above El. 102 ft.)

-

CFCU {Penetration Area)

-

Component Cooling Heat Exchanger Piping

-

Room Cooler Piping Chiller Condenser Piping

-

Turbine Bldg. Miscellaneous MEDIUM

-

Service Water Intake Structure

-

Nuclear Cross-Ties

-

Diesel Generator Piping

-

Turbine Bldg. Miscellaneous LOW

-

CFCU (Containment below El. 102 ft.)

-

Lube Oil Cooler Piping

-

Turbine Bldg. Miscellaneous

• SERVICE WATER SYSTEM - PIPING REPLACEMENT PROGRAM MONITORING OF SYSTEM ACTIVITY & UPGRADES

Inspections of Piping and Equipment in Selected Areas of the System are Performed Every Refueling Outag.

Equipment Operators Visually Observe Material and Equipment Conditions and Operations Dail NOTE: Project Priorities May Change or Expand Due to the Results of these Inspections and Visual Observation *

Sample Test Spools Remain in Operation and are Inspected on a 12 to 15 Month Cycle. The Results, to Date, have been very Positiv *

Random NOE (RT) Performed During New Replacement Projects are Used as Baseline Data and Randomly RT'd Every Outage to Monitor Performanc SERVICE WATER SYSTEM - PIPING REPLACEMENT Pl~OGRAM PROJECT SUMMARY

Aggressive Project Plan Includes Over 90 % of Nuclear, Safety Related Linear Footag *

By the End of 1 R9, Approximately 46 % of the Nuclear Project Plan will have been Complete *

The Completed Piping Includes 70 % of the Total Linear !Footaqe In Containment

...

By the End of the Salem Unit 1 - Tenth Refueling Outage, (15 Months from Now) 80 % of the Nuclear Project Plan Will have been Completed Including 100 % of the Containment Pipin *

• SERVICE WATER SYSTEM - INSPECTION PROGRAM.

BACKGROUND

Since Start-Up, Visual (i.e., Disassemble & Inspect) Inspection has been a Part of the SWS Monitorin *

Numerous Inspections Were Done on a Routine Basis *

(Le., Alf in.MMIS)

Additional Inspections Were Performed Each Refueling Based on Engineering Directio *

.

SERVICE WATER SYSTEM,_ INSPECTION PROGRAM NRC GL 89-13

Inspection Activities were Incorporated into MMI *

Procedures were Issued I Revised to Perform Inspection *

Approximately 150 Inspection Activities Per Unit were Generate Valves (And Associated Piping) -

50 %

-

Piping -

20 %

-

Heat Exchangers (And Associated Piping) -

30 %

Results of Inspections Will be Factored into Piping Replacement Progra *

Findings During Visual Inspections Could Generate the Need for Additional and I or Follow-Up Inspection *

STATION TECH.:

LEAD I

J.JACKSON l

• • • • • • • • • • • • • • • • • • • • =:

DESIGN/ENG LEAD J.ROWEY

• • .*=***=*:*.*=*********=***=*=*=:*:=*=*:

NUCLEAR LICENSING R.BROWN R. BECKWITH i

• • • • • • • • • • • • • • • • • • • • • =

REVIEW TEAM

-

TASK

MANAGER

/RA OWENS

• • • • • • • • • • • • • • • • • • • • =:

I ISi SUPPORT LLAKE W. DENUNGER [

-:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*::

PROBABUSTIC :

_RISK ANALYSIS j J. scorr

1:::*:::*:::*:::::::::::::::::::::*:::::::!

COST

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M. JIANNOIT/ !:

P.PAGE

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SALEM MECH. :

ENG'ING

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N. FERR.ET

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STRESS

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D. BHAVM4NI :

M.AHMED i

PIPING/

MATERIAL N. MISTRY 1':*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:*:

-

APPROACH Perform non-destructive examination (NOE) at various sites throughout the Service Water System to Augment the existing Visual Inspection Progra Evaluate the as-found results against the design requir1ements Develop acceptance criteria, evaluation methodology, initial sample size, additional sample selection guidelines, et Assess system status basis on the results of the inspec1tion and evaluation progra *

SITE SELECTION METHODOLOGY

Limit the assessment to the safety-related portion of the Service Water Syste *

Exclude areas already replaced with 6% Maly Stainless Stee *

Divide the system into discrete areas based on functio *

Prioritize the functional areas based upon PRA inpu *

Identify the known corrosion mechanis *

Select sites for inspectio Known problem areas

-

Suspected problem sites

-

Random sites

EVALUATION METHODOLOGY

Review the guidance provided in NRC Generic Letter 90-05:

-

Flaw evaluation

-

Code repair vs. temporary non-code repair

-

Reporting requirements

-

Additional sample requirements

Review the guidance provided in ASME Code Case N480:

-

Flaw evaluation

-

t MIN, t PROJECTED, t NOMINAL, et Additional sampling methodology

Consider PSE&G's past experience with SWS degradation

Develop a methodology which would best address PSE&G's situation

• PIPE INSIDE DIAMETER

• • • • • • • -:*:*:*:*:*:*:*:*:*:*:*:*:*:***

-:***:-:.:*:-:-:*:*:*:*:-:-:*:*:*:*:-:-:

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____________ \\/ _____________________ -------

MIN

• 5 t NOM t p PIPE OUTSIDE DIAMETER __/

ITARI'

ISi PERFORM S.W. ULTRASONIC TEST EXAMl*TIONl ISi DETERMINE t MEAS NTIATE DEFlCIENCV REP'OllT (DA)

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l"IPINQ CALCULATE CORROSION RATE re l"IPING CALCULATE tp

&f\\AW Tm:

ADD'LEXAM (PERNOTE2)

NO NO NO ADDIT1CNAL

~TICHI l'IEQUIE)

(NO'M1 l

!VALUATE 11£111 CCIMIO IN:)/~

CIENB'IC L!TTER GIO *GI Tl!CHDl!l'T (~~~)

NO ADDITIONAL EXAMSREQ'O NO NO EVALUATION METHODOLOGY FLOWCHART T!CHDl!P'I'

NO ADCfTD l!XMINATICNI

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ITIBI l!VAWATE U9G CCIMIO

~82 WA TitlHNQ MEntOO VD Tl!CH Dl!l'T c~~D1R)

NO nleM l!VAUJATE 11£111 GI.. 80-0!5 RELIEF REQUEST NO TECHD!PT DISPOSrTION DR TEMPORARY NO~CE REPAIR CODE REPAIR T!CHD!"1'

ADDITlONAL EXAMINATIONS

• LEGEND/NOTES FOR FLOWCHART t

= Wall thickness identified in ANSI B36.10 NOM t

= Thickness measured during examination MEAS t p

-

( t MEAS)

[ r c ( p ) ]

I Where NOTE NOTE NOTE P =Time period (IN MONTHS) until the next refueling outage

-

Calculated minimum wall thickness based on primary stres (See Code Case N-480, Para. 3610).

-

Corrosion rate ( t

)

( t

)

NOM

-

MEAS

Examine similar item(s) in the sister train(s) if applicabl Examine one (1) similar ite H flaw size is ~ 3 inches or 15% of pipe circumference, (whichever is less) it may be considered a *1ocalized* fla >

t NOM It MIN COMPARISON CHART PIPE DIMENSIONS SITE NUMBER PIPE SIZE, Inches t MIN

8 0.322 0.063

24 0.500 0.180

20 0.500 0.150

4 0.237 0.060

3 0.216 0.050

6 0.280 0.100

IMPLEMENTATION SCHEDULE Pursue an aggressive schedule on Unit 1 to take advantage of the outag Utilize the recently removed Unit 1 Containment Fan Coil Unit piping to obtain additional dat Perform selected inspections on Unit 2 based upon the Unit 1 results.