IR 05000272/1991019

Insp Repts 50-272/91-19,50-311/91-19 & 50-354/91-14 on 910616-0730.No Violations Noted.Major Areas Inspected: Operations,Radiological Controls,Maint & Surveillance Testing,Emergency Preparedness & Security

ML18096A227
Person / Time
Site:	Salem, Hope Creek
Issue date:	08/16/1991
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18096A226	List: IR 05000272/1991019 ML18096A225
References
50-272-91-19, 50-311-91-19, 50-354-91-14, NUDOCS 9108270119
Download: ML18096A227 (69)

Text

Report No License No Licensee:

Facilities:

Dates:

Inspectors:

Approved:

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

50-272/91-19 50-311/91-19 50-354/91-14 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 June 16, 1991 - July 30, -1991 T. P. Johnson, Senior Resident Inspector

• S. M.. Pindale, Resident Inspector S. T. Barr, Resident Inspector H. K. Lathrop, Resident Inspector R. S. Bhatia, Reactor Engineer B. C. Westreich, Reactor Engineer

---

Inspection Summary:

g I \\l.o )91 Date Inspection 50-272/91-19; 50-311/91-19; 50-354/91-14 on June 16, 1991 - July 30, 1991 Areas Inspected: Resident safety inspection of the following areas: operations, 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: An executive summary follows.

9108270119 910816 PDR ADOCK 05000272 Q

PDR

EXECUTIVE SUMMARY Salem Inspection Reports 50-272/91-19; 50-311/91-19 Hope Creek Inspection Report 50-354/91-14 June 16, 1991 - July 30, 1991 OPERATIONS (Modules 71707, 71710, 93702)

Salem: The Salem units were operated in a safe manner. Operator response to a spurious auxiliary feed water pump start was appropriate. However, the four hour notification was lat Licensee response to this previously identified issue has not been effective nor timely. Operato response to a Unit 1 reactor trip caused by a lightning strike was appropriate. Licensee actions regarding a failed reactor trip breaker (RTB) were in a safe and conservative manner. The root cause of the RTB undervoltage trip attachment device is unresolve Hope Creek: The unit was operated in a safe manner. Operator response to a transient caused by a lightning strike at Salem were appropriate. A trip of both control room ventilation trains was adequately responded to by control room operators and engineering personne Good operator actions were noted in response to an automatic reactor recirculation runback. The reactor core isolation cooling system was determined to be appropriately aligned for automatic injectio RADIOLOGICAL CONTROLS (Modules 71707, 93702)

Salem: Periodic inspector observation of station workers and Radiation Protection personnel implementation of radiological controls and protection program requirements did not identify any deficiencie '

Hope Creek:

Periodic inspector observation of station workers and Radiation Protection personnel implementation of radiological controls and protection program requirements did not identify any deficiencie A contaminated pressure gauge alarmed the security exit portal monitors. The licensee's investigation into this event was timely *and thoroug MAINTENANCE/SURVEILLANCE (Modules 61726, 62703, 70323)

Salem: Routine observations did not identify any deficiencie A review of the licensee's program to select and examine nuclear class 3 welds did not identify any deficiencies. Licensee actions in response to a emergency diesel generator failure were appropriate. An unresolved item concerning containment penetration conductor overcurrent protection devices is closed. A Unit 1 containment integrated leak rate test report was reviewed and no deficiencies were identified.

• Hope Creek: Routine observations did not identify any deficiencies. An investigation into the cause of the "D" emergency diesel generator second start failure in ongoin *

EMERGENCY PREPAREDNESS (Modules 71707, 82301, 93702)

No noteworthy findings were identified..

SECURITY (Modules 71707' 93702)

- Routine observation of protected area access and egress showed good control by the license Security personnel were noted to be knowledgeable during a review of the service water intake structures security hardware arrangement ENGINEERING/TECHNICAL SUPPORT (Modules 71707)

Common: Corporate engineering and both the Salem and Hope Creek stations appropriately addressed the bases for extreme ambient temperatures on unit operatio Salem: Review of the management of engineering work activities determined that they were being performed in accordance with applicable procedures and were being properly prioritized and execute An open item regarding residual heat removal pump-to-pump interactions is closed. *

Hope Creek:

The Filtration, Recirculation and Ventilation System (FRVS) heater fuses experienced faihires during this period. Licensee actions appeared to be appropriate. However, root cause evaluation and corrective actions after the May 1991 failures was neither thorough nor complete. Licensee response to reactor protection system pow.er supply breakers (EPAs) is hampered by the unavailability of upgrade kits from the supplie *

SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 30702, 40500, 71707, 90712, 90713, 92700, 92701)

Salem: The inspector performed an independent root cause review of an engineered safety feature actuation.caused during 4kV undervoltage relay testing. The licensee's review of this

. event was acceptable. However, the licensee's review did not address that a previously identified human engineering deficiency existed. The Station Operations Review Committee is effectively

• implementing its review and audit functio Hope Creek:. The Station Operations Review Committee exhibited a questioning attitude and good safety perspective during reviews of two significant engineering issues and conducted itself in accordance with applicable procedure *

111

• SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 tripped on June 16, 1991, due to lightning strike on the main transformer. The unit restarted on June 24, 1991, and remained operational during the remainder of the perio.2 Hope Creek The unit remained operational during the period.

. ~

.

. OPERATIONS 2.1 *

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 Techn.ical Specification compliance, and review of facility record These inspection activities were conducted in accordance with NRC inspection procedures 71707, 71710, and 9370 The inspectors performed normal and back-shift inspections, including deep back-shift (23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />) inspections as follows:

-

Unit Inspection Hours Dates.

Salem

. 4:00 a.m. - 5:00 /19/91 Salem 5:00 a.m. - 7:00 /7/91 Salem 10:00 p.m. - Midnight 7/10/91 Salem Midnight - 3:00. /11191 Salem 4:00 a.m. - 5:00 /11/91.

Salem 5:00 a.m, --7:00 /15/91 Salem 9:00 p.m. - Midnight 7/21/91 Hope Creek Midnight - 5:00 /22/91 Hope Creek 4:00 a.m. - 5:00 /26/91 Hope Creek 6:30 a.m. - 9:30 /27/91

• .** --.

• -

2 Inspection Findings and Significant Plant Events 2.2.1 Salem Spurious Unit 1 Auxiliary Feedwater Pump Start On June 30, 1991, the Unit 2 No. 21 motor driven auxiliary feedwater (AFW) pump automatically started at 2:37 a.m. Each of two of the motor driven pumps are normally aligned to provide AFW flow to two SGs. The unit was operating at 100% power. Control room operators verified that AFW was not required and then attempted to secure the AFW pump. *

However, the pump could not be secured from the control room. The operators then manually closed the AFW control valves to terminate AFW flow to the steam generators (SGs) and the pump continued to operate in the recirculation mode. AFW was provided to the SGs for less than 30 second Operations personnel subsequently shutdown the No. 21 AFW pump at the local control panel after about 16 minutes. Followup licensee review identified that a solid state protection system (SSPS) output card had failed, resulting in the spurious start of the No. 21 AFW pum System/component response to the failed card was as per design. The card was subsequently replaced and satisfactorily tested, the AFW pump was functionally tested satisfactorily, and the system was returned to service.

The inspector reviewed the plant drawings and discussed the event with station personne Operator response to this AFW pump start was determined to be appropriate. However, the inspector determined that the four hour report to the NRC Operations Center, as required by 10 CFR50.72, was not made until 9:11 a.m. The licensee stated that they did not determine that the event was reportable as an Engineered Safety Feature (ESP) actuation until 7:00 a.m: Prior to that time, the licensee stated that the cause of the AFW pump start was Indeterminat CPR 50. 72 requires that a four hour report be made for any event or condition that results in a manual or automatic actuation of any ES NRC NUREG-1022, Supplement No. 1,

"Licensee Event Report System" was provided to clarify the types of events that require NRC notification. This document states that spurious actuations of ESP are challenges to the system and are reportabl NRC Unresolved Item No. 272/89-26-02 discussed potential programmatic weaknesses with respect to reporting ESP actuations. This item was again reviewed in NRC Inspection Report 272&311/91-01 and noted that licensee actions had not yet been completed. Licensee guidanc was developed on April 2, 1991. However, the inspector noted that some of the guidance is inconsistent with both 10 CPR 50. 72 and NUREG-1022. For example, the licensee's guidance states that accidentally bumping a breaker cubicle which causes an ESP pump to start is not reportable. The inspector concluded that the licensee's response to date to the unresolved item has not been effective in providing prompt and consistent reporting, and increased management attention is warrante :t

3. Unit.1 Reactor Trip Breaker Failure to Open During Test On Thursday, July 25, 1991, the licensee performed the mon~y undervoltage (UV) coil and auto shunt trip surveillance tests for the Salem Unit 1 reactor trip breakers (RTBs). The auto shunt tnps were performed satisfactorily. The first time the UV coil trip was tested on the 11A

- RTB, the breaker took approximately 16 cycles to trip. The maximum allowed time is 10 cycles. When the test was performed, the licensee suspected the data to be abnormal due to inaccurate operation of the sequence of eventS printer. The shift supervisor allowed the test to be reperformed in order to verify the test result. When the test was reperformed, the 11A 11 RTB failed to open. Salem Unit 1 Technical Specifications contain a 48 *hour Action Statement (TSAS) for either an inoperable RTB UV trip device or inoperable auto shunt, and a 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

TSAS for an inoperable RT The. licensee conservatively declared the entire 11A" RTB inoperable at 10: 10 a.m. and entered the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> TSAS. At 11: 10 a.m., the Senior Nuclear Shift Supervisor authorized and initiated a downpower maneuver to comply with the TSAS and begin to shut down Unit 1, and subsequently notified the NRC operation center as required by 10 CFR 50.7.

The licensee replaced the 11A 11 RTB with the 11B 11 RTB bypass breaker and conducted a functional test on the new breaker once it was installed.. The new 11A 11 RTB passed. the functional test satisfactorily, and the TSAS was exited at 12:30 p.m. The plant shutdown was halted at 90%

power, and the unit returned to full power. Subsequently, the UV coil and auto shunt trip surveillance test was performed on the Unit 1 "B" RTB, and that breaker successfully met all acceptance criteri The failed 11A" RTB (Westinghouse model DB-50) was taken to the Instrumentation and Control work area to be examined and tested. The licensee determined that the auto shunt* and the breaker trip bar were functioning properly, but the undervoltage trip attachment (UVTA), when*

de-energized, was not striking the trip bar with enough force to open the breaker contact PSE&G requested the breaker vendor to visit. the site and assist in determining the root cause of the breaker failur A Westinghouse representative arrived at Salem on July 26, 1991 and, with licensee personnel assisting, performed various tests on the breaker. The results of the tests indicated that the breaker itself was properly maintained and that the trip bar was functioning properly. When the UVTA was tested; it again failed to be able to lift the trip bar. Per a specially written test procedure, the UVTA was lubricated and retested. Subsequently, the UVTA was able fo lift the trip bar. The UVTA was further tested and, after the lubrication, proved to be able to lift the trip bar with an additional 300 grams added (the Technical Specification requirement) and also with an additional 460 grams added to the trip bar (per the licensee's semi-annual surveillance test procedure requirement).

-..1

The Westinghouse representative left the site after completing the tests on July 26~ 1991. The licensee rem_oved the faulty UVTA from the breaker and returned it to Westinghouse for further.

root cause determination. The licensee refurbished and tested.the breaker with a new UVTA and, at the end of the inspection period was plarining to place it back in service. _

.

-

The resident inspector was on site the day of the event and, when notified, responded tO the switchgear room to inspect the "A" RTB and witness its removal. The resident was informed of and followed all licensee actions on July 25, 1991, and determined the licensee had complied with all requirements concerning the RTB and had acted in a Safe and conservative manner. On July 26, 1991, a Region I electrical specialist inspector visited the site to follow up on the event, review the licensee's test method, verify preventive maintenance and examine previous surveillance testing of the devic The NRC will follow PSE&G's. and Westinghouse's

_ investigation into the root cause of the UVTA failure. This item is unresolved (UNR 272/91-19-.

01).

2.2.2 Hope Creek

- Technical Specification (TS) 3.0.3 Entry With Both Control Room Ventilation (CRV)

Trains Inoperable On May 22, 1991, the "B" CRY chilled water.unit was in service with the "A" CRY chilled water unit in standby. At 1:20 p.m., the. "B" unit tripped; the "A" unit started (as designed),

but then tripped shortly thereafter. Operators could not restart the "A" unit. The "B" unit compressor was restarted but would not load. Both units were declared inoperable and TS 3. was entered at 1 :20 p.m. After the "B" unit had cooled, it was successfully started in manual and, after temperatures had stabilized, was placed in automatic. The unit was declared operable and the action statement was exited at 1:48 No apparent cause could be determined for the trip of the "B" CRY unit. The ca.use of the "A" CRY unit trip was traced to a broken terminal post in the compressor terminal box. Corrective actions included performing a temporary repair of the broken post (a permanent repair to be performed during the next scheduled system outage) and further investigation into the "B" unit *

trip. LER 91-11 was submitted for this.even The inspector discussed this event, including the LER, with licensee engineering personnel. The inspector determined that a number of enhancements had already been implemented to improve system reliability and that this was the first such entry into TS 3.0.3 due to both CRYs units being inoperable since early 1989. The inspector had no further qu~stions pending the r_esults of the licensee's investigation of the "B" control room emergency filtration unit trip.. * *

5. Engineered Safety Feature (ESF). Actuation and Unscheduled Power Reductions On Jllne 19, 1991, during the implementation of a design change adding external test boxes to _ *

the emergency core cooling systems (ECCS) vertical boards, two leads in the Hll-P618 panel were inadvertently shorted. This resulted in a voltage spike in the trip units in the associated electronic card files. The following significant actions occurred:

Loss of coolant accident (LOCA) reactor water level one signal to the "B" channel load sequencer; Reactor core isolation cooling (RCIC) system initiated on reactor water level two signa However, RCIC did not. inject because of a simultanoous level eight (high level trip)

signal;

"B" reactor feed pump (RFP) and "B" reactor auxiliaries cooling water (RACS) pumps tripped;

"B" emergency diesel generator auto started; and

"B" residual heat removal (RHR) and "B core spray (CS) pumps auto-started. These systems did not inject due to high reactor pressure, The loss of "B" RFP with "C" RFP in manual control (due to a previous control problem)

caused reactor water level to drop to level four ( + 30"), resulting in an intermediate recirculation system run back to 65 % reactor power. Good. operator action was noted in using manual control of the "C" RFP to minimize the reactor water level transient. Operations personnel verified proper system response and returned safety systems to a normal standby lineup after stabilizing

. reactor power at 66 %.

During return to full power, at 12:28 a.m. on June 20, 1991, a second intermediate recirculation runback occurred while attempting to place the "B" RFP in service. The "C" RFP was still in manual control with the "A" RFP in governor (automatic) control. When the operator began feeding with the "B" RFP, the "A" RFP flow decreased, causing reactor water level to decrease to +30", which satisfied the runback logic (the "A" RFP was seen as "tripped" by the logic circuitry as it receives its input from turbine control valve limit switches) and initiated an intermediate runback from 78 % power. After plant conditions were satisfied, reactor power was increased, reaching 100% at 4:52 a.m. with no further difficultie The inspector discussed the.se events with licensee operations.and technical personnel. The design change (DCP 4HC-204) being implemented was intended to reduce the risk of inadvertent safety system actuations and system upsets during surveillance testing where physical entry into the logic cabinets had been required. Testjack boxes were installed _on the panel exterior with leads run from the appropriate terminal strips/relays inside the panel. A number of these test boxes had already been installed with no significant problems. In this case, the close proximity

of the landing points and cramped working conditions made the installation more difficult. The licensee's corrective actions to install exterior test jack boxes on the logic cabinets appears to be adequate to resolve further inadvertent safety system actuation. _The effectiveness of the actions will be assessed as the implementation of the design change continue The inspector also reviewed the Licensee Event Report (LER 91-14) discussing this event, noting that the licensee intends to complete the implementation of this design change during the fourth refueling outage. No-significant deficiencies were observed in this LE Reactor Core Isolation Cooling System Walkdow On June 25, 1991 through July 27, 1991, the inspector performed an Engineered Safety Feature (ESF) walkdown of the Reactor Core Isolation Cooling (RCIC) system per NRC inspection manual procedure 71710. The RCIC system valve lineup was reviewed in the control room and plant to verify flow paths and valve positions were consistent with plant procedures and valve status sheet Components in the system were verified against plant drawings to ensure proper installatio Valves and equipment were checked for packing leakage, proper labeling, missing handwheels, or damaged component Instrumentation was checked for proper installation and current calibratio *

.

.

A number of minor concerns were identified such as valve packing leaks, and housekeeping deficiencies. These concerns were communicated to licensee management and appropriate actions were take The inspector concluded that the system was properly aligned and in operational standby status capable of performing its design/safety function..

2.2.3 *Common Lightning Strike Onsite and Salem Unit 1 Reactor Trip A severe thunderstorm in Southern New Jersey on June 16, 1991, resulted in a lightning strike at Artificial Island. At 7:40 p.m., lightning struck the "B" phase of the Salem Unit 1 main power transformer (MPT). The unit tripped from 100% when power was partially lost in the 500kV and 13kV switchyards. The 500kV main generator output breakers opened to protect the main generator and three downstream 500kV breakers opened to protect the 500kV switchyard. *

The effect on Unit 1 was an automatic main turbine and reactor trip, a loss of two of four reactor coolant pumps (RCPs), a loss of one of two offsite power sources, a loss of the New Freedom 500KV line, and a fast transfer of the IB 4kV vital bus to its alternate source. Safety systems responded normally to the reactor trip. Reactor decay heat was removed with two RCPs and the atmospheric steam dump *

. ".. * ~

The Unit 1 emergency diesel generators (EDGs) were tested satisfactorily as required by Technical Specifications (TSs), however, the testing was not performed within the one hour as required by TSs. The testing was completed at 10: 15 p.m~ The_ testing was delayed because the control room* operators were focused on mitigating the consequences of the loss of the offsite power source to the reactor tri The switchyards were restored to normal by 4:00 a.m. on June 17, 1991, after completion of inspection and testing. The unit vital and non-vital buses were subsequently realigned. The unit

• was stabilized in Mode 3 (Hot Standby) at norm.al operating temperature and pressure. The NRC operations center was notified as required by 10 CFR 50. 72, and the licensee initiated a Significant Event Response Team (SERT) in addition to the normal licensee post-trip revie Saiem Unit 2 was operating at 94% with one heater drain pump out of service for maintenance prior to the Unit 1 trip. The lightning strike caused a loss of one of two Unit 2 offsite power sources. This resulted in a momentary power loss of the 2B 4kV vital bus when it transferred to its alternate source. A resulting radiation -monitor spike caused a containment ventilation isolation signal. The licensee reset the isolation and made an ENS call as required by 10 CFR 50. 72. The licensee satisfactorily tested the Unit 2 EDGs as required by Technical Specifications *

with the specified time period. The unit'.s electrical distribution was rettirned to a normal lineup by 4:00 a.m. on June 17, 1991, and the unit remained at 94% powe.

.

.

.

The Hope Creek unit was at 100% when the lightning strike hit the Salem Unit 1 MPT. This resulted in the following events at Hope Creek: The offgas system isolated, instrument air compressors tripped, two of three feedwater heater trains isolated on high level, reactor power increased briefly to 105 % due to loss of feedwater heating, reactor level oscillated slightly, and main generator megawatts/megavars fluctuated. The plant operators responded to this transient

. and reactor power was lowered to 80% using control rods and reactor recirculation flo Off gas, instrument air and feedwater systems were restored* to normal. No onsite or offsite power supplies were affected at Hope Creek. Once the Salem switchyard (New Freedom line) *

was restored, Hope Creek was returned to 100 % powe The site fire brigade responded to the Salem Unit i MPT. No fire or spill of transformer oil had occurred. Site security power was unaffected by the electrical transient.* The Salein Emergency Notification Syst~m (ENS) phone was rendered inoperative due to the lightning strike and a partial loss of the onsite telephone. system also occurred. However, the licensee was able to effectively communicate both onsite and offsite; and the phone systems were subsequently restore The inspector reviewed the operator response to the automatic Salem Unit 1 shutdown, the Salem Unit 2 ESF actuation, and the Hope Creek transient. The inspector concluded that the actions taken were appropriate. The inspector also reviewed the licensee's formal incident reports, logs, sequence of events, control room traces, and the post trip review. The inspector did not identify any deficiencies. Following repairs to the d_amaged MPT; Salem Unit 1 was restarted on June 24, 199 *.

~**.

8 RADIOWGICAL CONTROLS 3~1 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 3.2.1 Salem No noteworthy findings were identifie.2.2 Hope. Creek Radioactive* Material Found Outside Radiological Controlled Area (RCA)

At 9:35 a.m. on July 12, 1991, a Heise pressure gauge being transported from the M&TE shop

• to an offsite calibration facility alarmed the security portal radiation monitor.. A radiation protection (RP) technician was dispatched to the security center to survey the gauge. The gauge was determined to have fixed radioactive contamination (1000 counts per minute) with an RM-14 frisker. The licensee initiated an incident report (91-108), a radiological occurrence report (ROR 91-105), and commenced an investigatio Surveys were conducted on similar non-radioactive measuring and test equipment (M&TE) at the.*

• Hope Creek station and offsite at the calibration facility. The licensee's RP personnel surveyed *

the M&TE shop, the security center and the route taken from the M&TE shop to the security center. No radioactive contamination was deteeted. An isotopic analysis determined the material

• * to be activated corrosion products. A work order history search determined that the gauge_ was used in the diesel fuel oil system in May 1991, and in the RCA in February 1991, during the third refueling outage. No contamination was detected in the diesel fuel oil system or in the dieselbuilding. A contractor technician who used the gauge in the RCA was unavailable for interviews. At the end of the inspection period the licensee's investigation was ongoing. The licensee believes primary root cause to be an inadequate survey..

Initial corrective actions to prevent reoccurrence included:

Surveys of similar M&TE, Surveys of potentially affected areas, Confiscation of the contaminated gauge, and Discussion of the event, causes, and corrective actions with RP department personne *

The inspector reviewed the preliminary incident report and ROR, and discussed the event with RP and plant management personnel. The inspector concluded the licensee initiated a timely and thorough incident investigatio Initial corrective actions, both completed and proposed, appeared to be effective. The final reports and root cause analysis will be reviewed in a future inspectio..

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 l_

Salem 1 Salem 1 Salem 1

- Hope Creek Hope Creek Work Request (WR)/Order (WO) or Procedure 1IC18. l. l.010 -

W0910725091 M3Q-2 Various Various Various Description Reactor Trip Breaker (RTB) --

RTB Troubleshooting RTB Semiannual inspections; lubrication and testing Main power transformer FRVS -design changes* and troubleshooting

"D" Emergency Diesel Generator troubleshooting

.

.

-

.

The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance program.

--- ------------------------~

10 Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance package The inspectors verified that the surveillance.* tests were performed in accordance with Technical Specifications, approved procedures~ and NRC regulations. These inspection activities were conducted in accordance with NRC inspection procedure 61726.

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

Procedure N Salem 1&2 M3T*

4KV Vital Bus Undervoltage Relays Hope Creek OP-ST.KJ-004(Q)

D Emergency Diesel Generator Test *

Hope Creek OP-ST.GU-001 FRVS Monthly Test The surveillance testing activities inspected *were effective with respect to meeting the safety objectives of the surveillance testing progra *

4.3 * lllspection Findings 4.3.1 Salem

• Selection and Examination of Nuclear Class 3 Welds The inspector reviewed the process by which the licensee selects and examines pipe welds in Nuclear Class 3 piping. As per ANSI Standard* B31.7-1969, the licensee performs a random radiography (RT) exam for welds in Class 3 piping that is greater than four inches. The Standard requires that random RT exams be performed on 10% of each welder's welds only as a means to check welder performanc During the recent Unit 1 refueling and maintenance outage, a substantial portion of the Class 3 service water (SW) system was replaced. The inspector reviewed the licensee's documentation associated with several welders and found that the licensee properly implemented the 10% RT exam requirement for the new SW piping (greater than four inches).

The inspector observed portions of the pipe replacement activities.. Documentation was also reviewed for selected pipe welds, some of were radiograph~ while others were not. Some of the specific welds reviewed included FW-1-SW-P-5801-1 (ten inches, RT-accept), FW-l-SW-P-5801-2 (ten inches, No RT), FW-1-SW-P-5817-1 (sixteen inches, RT-accept), and FW-1-SW-P-

..

5806A-1 (ten inches, No RT). No deficiencies were identified. The inspector concluded that the licensee has a program in place to appropriately randomly select Nuclear Class 3 welds for RT exam to verify welder qualifications, and had no. further questions in this are B Emergency Diesel Generator (EDG) Failures On May 23, 1991, a valid 2B EDG test failure occurred when a relay failed in the switching tachometer circuit resulting in the turbo boost solenoid valves to remain open. During. post maintenance testing on May 25, 1991, a second failure occurred when the 2B EDG was manually shutdown by operations when a small jacket water leak was noted. The licensee classified this second failure as a non-valid test failure. *

The licensee repaired the defective relay and the cracked nipple in the jacket water piping. *Tue licensee is further reviewing the cracked nipple occurrence; This was the first failure for the 2B EDG and no additional testing was require * *The inspector reviewed special report 91-02 and discussed the item with licensee engineers. The inspector concluded that licensee actions were consistent with Technical Specifications and Regulatory Guide* 1. 10 Containment Penetration Conductor Overcurrent Protection Devices (Unresolved Item 272/91-15-02)

LER 91-21 addressed licensee identified non compliances associated with Technical Specification (TS) section 3/ 4. 8. 3.1 regarding Unit 1 containment penetration conductor overcurrent protection devices. This item was identified as unresolved (272/91-15-02) in a previous NRC inspection pending final licensee review and LER submittal. The licensee identified seven Unit 1 circuit

. breakers that the TS action statements and surveillance requirements were not adhered with. The licensee concluded that root cause was personnel error and inadequate documentation. Corrective actions are addressed in NRC Inspection 272/91-15 and in the LE The inspector concluded that once identified licensee actions including root cause determination and corrective actions were appropriate. The unresolved item is considered close Unit 1 Containment Integrated Leak Rate Test (CILRT) Report The licensee submitted the final results of the April 1991 Unit 1 CILRT. Test results were satisfactory and within Technical Specification limits of 0.075 volume percent per day. The CILRT performance was reviewed in NRC Inspection 272/91-09. The inspector reviewed this test report dated July 2, 1991. No deficiencies were noted.

4.3.2 Hope Creek

"D" Emergency Diesel Generator (EDG) Start Failure Followup Ori May 22, 1991, the "D" EDG suffered its second valid test failure within its last 20 valid starts (see NRC Inspection Report 354/91-12, Section 4.3.3.B), requiring an increase in surveillance frequency (from once per 31 days to once per seven days) until eleven consecutive successful tests. were performed. During the ensuing eleven starts, the EDG system engineer closely monitored diesel performance including operations personnel preparation for and conduct of each surveillance. No abnormalities were noted by the licensee and the diesel performed as required. The accelerated surveillance frequency was successfully concluded on July 30, 1991, and the "D" EDG returned to its normal surveillance test frequency ()f 31 day The inspector observed a number of the weekly surveillance runs, reviewed the surveillance and-operating procedures and discussed the diesel failure and licensee investigative activities with the engineering and operations personnel. While the licensee's investigation into the cause of the May 22, 1991; start failure on the "D" EDG is ongoing, the licensee indicated that procedural or mechanical problems did not appear to have been a factor, although a number of minor

• procedure enhancements were being considered. The inspector concluded that the licensee's actions taken to date, including clarification of the definition of a "valid test start" were appropriate. The final results of the licensee's investigation and corrective actions taken will be reviewed in a future inspectio.

. EMERGENCY 'PREPAREDNESS Inspection Activity

.

.

.

The inspector reviewed PSE&G's conformance with 10CFR50.47 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 No noteworthy findings were identifie.

• SECURITY Inspection Activity PSE&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 71707.

. Inspection Findings Service Water System (SWS) Intake Structures During a periodic tour of the protected area, the inspector noted differences in the Salem and Hope Creek SWS intake structure's detection arrangements. The inspector reviewed the security plan, and discussed these differences with alarm station personnel and security management. The inspector concluded that the arrangements were acceptable, and that security personnel were knowledgeable of these security hardware a.mlngement.

/ENGINEERING/TECHNICAL SUPPORT Salem Open Item Followup On May 5, 1991, during testing per OP;ST.GU-OOl(Q), the licensee identified blown fuses in the heater control circuits for three of the FRVS recirculation units. These heaters reduce the *

buildup of moisture on the charcoal absorbers and the HEPA filters. The heaters cycle on and off with a relative humidity controlle Hope Creek FRVS includes six 25% capacity

• recirculation units and two 100% capacity ventilation units. This system is-in lieu of the normal BWR. standby gas treatment system for post accident reactor bµilding pressure and radioactivity control. The licensee entered Technical Specification (TS) 3.0.3, replaced the fuses and revised the test current measurement location. (See LER 91-07 and NRC Inspection 354/91-12). During the FRVS testing in July the licensee again found multiple blown fuses. TS 3.0.3 was entered twice on July 6, 1991. The blown fuses were replaced, the units were tested satisfactorily and ENS calls were mad The.licensee initiated an investigation into these failures. Line management responded to site over the weekend (July 6-7, 1991) and corporate engineering organized several teams to review these failures; To date, the licensee has concluded that these failures due to blown fuses are apparently caused by the testing methodology. In 1986, the TS surveillance requirements (TS 4.6.5.3.b) were modified from testing the FRVS heaters in an automatic mode (cycling on.

. humidity) to testing the heaters continuously on and energized. The licensee believes that testing these 100 KW heaters for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> continually energized causes elevated local temperatures in

the panels resulting in deg~dation of the 40 amp fuse causing it to blow below the phase current value of 30 amps. The licensee contacted several other utilities,* reviewed the preoperational test results, reviewed design basis information, and contacted the vendor (NuTherm). Based on this, the licenSee concluded that the revised testing methodofogy, wherein the heaters are initially energized and allowed to cycle in automatic, is appropriate and does not result in blown fuse The monthly FRVS surveillance test was completed satisfactorily on July 9, 199 The licensee processed a design change package (DCP) removing the doors from the local heater control panels for the FRVS recirculation and ventilation fans to provide better heat dissipatio Test and experiment DCP (4EX-3133) was conducted to yerify system operability with the panel doors removed during accident conditions and to deterinine if degradation had. occurred to environmentally qualified (EQ) components during previous surveillance tests. This test was run twice over the weekend of July 20-22, 1991, first with the doors off all of the units, then with the doors installed only on the "D" recirculation and "A" ventilation fan heater control panel Based *on the test results, the licensee concluded that, with the heater control panel doors removed, FRVS was operable and capable of fulfilling its design function. With the panel doors installed, fuses in both the "A and "D" panels blew during the second test, operability could not be determined. Additionally, some degradation had occurred, reducing the EQ lifetime of a number of components. The licensee continues to evaluate the EQ issues and is designing a permanent solution to the heater* control panel temperatures by installing internal fans and reinstalling the panel doors on the vent fans and installing expanded metal screens on the recirculation units~ The licensee is evaluating a potential 10 CFR 21 report on this issue. On July 30, 1991, the panel vendor, NuTherm, notified the NRC of a potential deviation involving the heater control panels with further investigations and testing to be complete The inspeetor reviewed this event. as follows:

Discussed it with licensed o!Jerators, system engineers, maintenance and management

• personnel, Inspected selected FRVS heater panels; Reviewed the incident reports, Reviewed the FRVS heater technical manual and prints (PM 786Q-0194-04),

• Reviewed the appropriate TS sections, Observed surveillance test OP-ST.GU-OOl(Q) performance in the control room and in the field, Observed the July 17, 1991, Station Operations Review Committee (SORC) meeting evaluating DCP 4EX-3133,

. ' -*.*:*.\\~ '

\\

Discussed with licensee management the results of the special test and actions taken/recommended,

.Reviewed the 1986 TS amendment and safety evaluation, and Reviewed. FRVS design bases documentation including FSAR, Section The inspector concluded that licensee actions were thorough and timely for the July 1991 heater and fuse FRVS failures. This issue is unresolved pending completion of all licensee actions, including the submittal of an LER and Part 21 report (354/91-14-01). However, the root cause evaluation and corrective actions after the May 1991 failures were not thorough nor complet Engineered. Safety * Feature (ESF) Actuation Due to Failed Electrical Protection Assembly (EPA).

On June 26, 1991, while the 11A 11 Reactor Protection System (RPS) motor-generator (MG) set was out-of-service for maintenance, the control room received a half-scram, reactor water cleanup system isolation and various valves closed when the 11A 11 RPS alternate feed power supply EPA breaker tripped, de-energizing the 11A 11 RPS bus. The same EPA breaker tripped again about twenty minutes later when operators were attempting to restore power to the II A II

• bus. The "A 11 bus was successfully re-energized an hour later when the 11A 11 RPS MG set was returned to servic The licensee could not determine the cause of either trip of the EPA breaker, but did note that

• there had been a similar occurrence in 1990 (see LER 90-07). As a result of the 1990 event, the licensee decided to upgrade the EPA cards as recommended by the vendor - General Electric (GE) in Service Information Letter (SIL) 496, Revision 1. At the time of the June 26, 1991 trip, the upgrade kits had not been received from G The inspector reviewed both LERs associated with these events (LERs 90-07 and 91-15), as well as, GE SIL 496, Revision 1 and concluded that the licensee's corrective actions appeared appropriate. It was noted, however, that difficulties were being experienced by the licensee in obtaining the upgrade kits in a timely manner due to quality assurance problems at GE's supplie The licensee still does not have. a delivery date from GE for the upgrade kits.

16 Station Response to Extreme Temperature Conditions During the inspection period, ambient temperature approached a high of 100 degrees F for

. several days and was above 80 degrees F for the majority of the time.. The inspector reviewed the effect and station response (Hope Creek and Salem) to these extreme temperature condition This included the effect on the ultimate heat sinks (Delaware River Cooling to Service Water Systems), containment air temperatures, building ambient air temperatures, and Hope Creek torus water temperatur Temperature limits were either specified in the respective FSARs or Technical Specifications (TS). The following table itemizes these limits and the highest noted during the inspection perio Limit Highest Temp

• System Station (Degrees F)

(Degrees F)

Service* Water Hope Creek 8 Service Water Salem

84 Containment Air Hope Creek 135 103 Containment Air

• Salem 120 112 Building Ambient Hope Creek 104-120 76-98 Building Ambient Salem 105-120 85-95 Torus Water Hope Creek

93 The Hope Creek service water temperature limit was previously 90.5 degrees F. However, an engineering evaluation in 1990 determined this limit to be non-conservativ A new administrative limit of 85 degrees F was established (see NRC Inspection 354/90-16). The licensee performed an engineering analysis and safety evaluation, and concluded that the temperature limit could be raised to 87.5 degree Station Operations Review Committee (SORC) approved this safety evaluation (H-l-EA-MEE-0591) at meeting number 91-67 on July 11, 1991. Based on an engineering evaluation of the heat removal capabilities of the Safety Auxiliary Cooling System (SACS) heat exchangers, the licensee determined that the terr,.perature limit could be increased to 88.1 degrees F. This new limit was reviewed and approved by SORC and implemented via TS interpretation (TSI-3. 7.1. 3b) on July 26, 1991. The licensee has indicated that a further evaluation of SACS and its associated heat loads would be performed over the following six to nine months to determine if an additional margin is available. Based on the results of this evaluation, the licensee intends to submit a TS change request to formalize the maximum ultimate heat sink temperature. The licensee revised LER 90-14 which addressed this issue to include the 87.5 degrees F temperature limit and supporting evaluation (See LER 90-14 revision 1).

• The Salem service water temperature limit as stated in the FSAR is listed as both 85 and 90 -

degrees F. The licensee performed an engineeririg analysis and safety evaluation (S-C-M600-

- NSE-214) dated August 12, 1983, This evaluation concluded that the service temperature limit

- could be raised to 90 degrees F. The FSAR was never updated with this information. The inspector met with licensee representatives from licensing, engineering and operations on July 11, 1991. At that meeting the licensee stated that the engineering evaluation and supporting calculations would be formally re-revjewed for the next FSAR change submittal (July 1992).

In the interim, engineering has reviewed the calculations and assumptions, and stated that the engineering analysis appears to be sound. SORC subsequently reviewed and concurred with the 1983 evaluatio The inspector concluded that corporate engineering, and the Salem and Hope Creek stations had _

appropriately addressed the extreme ambient temperature effects on 11nit operation.

SAFETY ASSESSMENT/QUALITY VERIFICATION Salem Independent Root Cause Investigation for Engineered Safety Features (ESF)

Actuation

On June 6, 1991, an inadvertent ESF actuation occurred on Unit 1 during surveillance testin *

During the test, a technician touched a jumper's allegator clip across two relay connection points, located on a relay that was adjacent to the relay to be tested. This event is discussed in NRC Inspection Report 272/91-1 During this inspection period, the inspector conducted a detailed investigation to independently ascertain the root cause of the event. The investigation consisted of conducting worker and supervisor interviews, surveillance procedure reviews, observing similar testing on other vital buses and performing a system/test walk-throug The inspector determined that the relay which was to be jumpered was installed on the lower inside portion of a 4kV bus door. The relay was approximately nine inches from the floor and

• the connection points were located on the underside of the relay. The connector points were therefore difficult to read under normal conditions. The adjacent relay was located about 1/2 inch away from the relay to be tested and the associated contacts were not physically guarded

_ to prevent an accidental actuation. Additionally, in order to connect the jumper, the technician must lie on the floor to see the relay connection points on the underside of the relay to apply the jumper. The inspector found that the environmental conditions in the 4kV vital bus room may also have contributed to the event. The ambient temperature was high, the lighting at the relay connections was poor, the noise level was high, and the work area was cramped.

~....... '. c

.

'

.,

.~

. *

The inspector acknowledged that the 4kV undervoltage relays being tested have experienced problems over the recent months and are the subject of NRC Unresolved Item 311/91-05-0 The problems have prompted the licensee to perform surveillan~ testing much more frequently than normal. Resolution of the relay operational problems and therefore, a return to normal testing frequency, will reduce the potential challenge to the associated ESP circuitr During the investigation, the inspector also ascertained that procedure writers and the technicians

• had previously noted that human engineering deficiencies existed. Specifically, recommendations were made to either change the location at which the jumper is applied or to provide permanent banana clips. However, none of the actions were implemented to correct the problems. Only following this recent ESP actuation did the licensee commit to investigate and resolve the deficienc Based upon the investigation the inspector concluded that the event was initiated by personnel error, however, the root causes were related to human engineering deficiencies. Specifically, in the area of man-machine interface, labelling was less than adequate (LTA) in that the relay connection points could not be easily read under operating and maintenance conditions, and component arrangement placement was also LTA in that the adjacent relay's contacts were not physically guarded to prevent accidental actuation. Additionally, the physical location of the relays on the 4kV doors introduced a significant hazard to inadvertent ESF actuations. In the area of work environment, ambient temperature, lighting, ambient noise and work space were all LTA and may have contributed to the even The inspector reviewed the licensee event report (LER) No. 91-22 associated with this event and found that the licensee's root cause determination was in agreement with the above independent determination (human engineering deficiencies). However, the licensee's evaluation did not address that it was previously noted that a human engineering deficiency existed. The licensee's stated corrective action in the LER was to review the vital bus cubicle design to determine the feasibility for installing more accessible terminal test connectors and/or test switches. The licensee also intends to review this event with the appropriate personnel to highlight the details related to performing functional testing, with a clear recognition that exposed connector points are accessible and therefore require additional vigilance to prevent im~dvertent contact and to maintain attention to detail. Continued efforts are in place to resolve the relay drift concerns to eliminate the increased frequency testing requirements. The inspector concluded that the planned licensee's corrective actions are appropriate to address the root causes of this even Station Operations Review Committee (SORC)

The inspector attended two SORC meetings during the period. This included meeting numbers 91-70 and 91-77. The topics reviewed included the post-trip review for the June 16, 1991, turbine/reactor trip and a 1983 safety evaluation which addressed continued plant operation with river water temperatures up to 90 degrees F. The inspector verified that these meetings met the requirements of Technical Specification 6.5.1 and administrative procedure NC.NA-AP.ZZ-0004(Q).

The inspector noted that SORC thoroughly reviewed each issue. A good questioning attitude and an excellent safety perspective was noted. Although it appeared that the SORC members did not have sufficient time to prepare in advance of the meeting fQr.the specific issues that were presented, a sufficient period of time was allowed during the meeting for the members to read the associated documentatio *

The inspector concluded that SORC is effectively implementing its review and audit functio.2 Hope Creek Station Operations Review Committee (SORC)

. The inspector attended two SORC meetings during the report period, the first dealing with the *

safety evaluation and engineering analysis supporting an increase in the maximum allowable ultimate heat sink (UHS) water temperature (SORC meeting 91-67), the second reviewing a test *

and experiment design change package (DCP) for the Filtration, Recirculation and Ventilation System (FRVS) operability determination (SORC Meeting 91~72). The inspector observed that each issue was thoroughly reviewed after a presentation by the responsible engineering grou SORC members displayed a professional, questioning attitude and good safety perspective throughout the technical review of both the UHS and FRVS packages. Issues raised by SORC members appeared appropriately addressed/resolved with nuclear safety being the primary focus.

For example, the engineering evaluation supporting an increase in allowable UHS temperature from 85 degrees F to 87. 5 degrees F was analyzed and a number of inconsistencies extensively involving service water pump performance degradation were noted and resolved. Both meetings were conducted in a businesslike and professional manner with proper voting quorums established and. resultant action items appropriately summarized with responsibility assigned prior to any recommendation for approva '

.

.

.

Based on the above, the inspector concluded that SORC activities were conducted in conformance.

with the applicable Technical Specification (TS 6.5.1) and licensee procedures (NC.NA-AP.ZZ-0004). LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP

• 9.1 LERs and Reports PSE&G submitted the following licensee event reports, and special and periodic reports, which

• were reviewed for accuracy and evaluation adequac *

Special and Periodic Reports Salem and Hope Creek Monthly Operating Reports for June 1991. No deficiencies were note *

Salem Special Report 91-02 addressed failures of the 2B emergency diesel generator (See Section 4.3.1.B).

Salem Unit 1 Containment Integrated Leak Rate Test Report (See Section 4.3.1.D).

Hope Creek Special Report 91-03 documented the test failure of "D" emergency diesel generator (EDG) on May 22, 1991. This was the second valid test failure in the last 20 tests and the licensee wa8 required-to increase the surveillance frequency from monthly to weekly (the first failure occurred on January 7, 1991). The_ cause of the second failure is under investigation and results will be detailed in a supplement to this report. No deficiencies were noted in the report. (For details on -this event, see Inspection Report

- 354/91-12, Section 4.3.3.B.)

Salem LERs Unit J --

LER 91-22 (See Section 8.1.A)

LER 91-22 discussed two ESF actuations which occurred on June 6 and June 13, 1991, and

. resulted in inadvertently starting and loading the 1 C and lB diesel generators, respectively; This event was previously reviewed in NRC Irispection Report 272/91-15 and in Section 8.1.A of this report. No inadequacies were noted relative to this LE LER 91-23 concerned a failure of the 1Rl2A, 1R12B and lRllA radiation monitors due to sample pump belt failure. Licensee corrective actions and root cause analysis were determined to be acceptabl Unit 2 LER 91-07 concerned a containment ventilation isolations-due to the 2R12B and 2R41C radiation monitor failures. -These events were reviewed in NRC Inspection 311/91-15. No inadequacies were noted relative to this LE Hope Creek LERs-LER 91-11 (See Section 2.2.2.A)

LER 91-12 dealt with a Technical Specification (TS) 3.0.3 entry due to the concurrent inoperability of the High -Pressure Coolant Injection (HPCI) system for surveillance testing and the "B" Low Pressure Coolant Injection (LPCI) system for maintenance. The root cause for this entry was attributed to personnel errors on the part of two supervisors (operations and

-

i

!

maintenance).

This first-time occurrence haa minimal safety significance. * The inspector determined that this LER appeared to be thoroughly researched and well-written, with no discrepancies note LER 91-13 is discussed in detail in NRC Inspection Report 354/91-12, Section 8.3.C. No discrepancies were noted in this repor LER 91-14 (See Section 2.2.2.B)

.LER 91-15 (See Section 7.2.B)

LER 90-14-01 (See Section 7.2.B)

9.2 Open Items The. following previous inspection items were followed up during this inspection. and are tabulated below for cross reference purpose *

272/89-26-02.

272/91-15~02.

272/90-81-14 Hope Creek None Report Section 2.2..3... 1 EXIT INTERVIEWS/MEETINGS 1 Resident Exit Meeting Closed

• Closed Closed The inspectors met with Mr. C. Vondra 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 irispection activitie Based on Region I review and discussions with PSE&G, it was determined that this report does

• not contain information subject to 10 CFR2 restrictions.

. 22 1 Specialist Entrance and Exit Meetings Date(s)

7/8-12/91 7/8-12/91 Subject HV AC Effluents Controls and Monitoring Generic Letter 88-17 Commitment Implementation 7/15-19/91 Generic Letter 89-10

• MOVs Inspection Report N &311/91-20 272&311/91-21 354/91-80 1 Salem and Hope Creek Management Meetings Psychological Examination Program Reporting Insi)ector Jang Lopez-Goldberg Yerokun A meeting was held at the Artificial Island Processing Center on June 27, 1991, to discuss the licensee's Psychological Examination Program. Attachment 1 is a list of attendees. Observed Trend of Deficient Performance A meeting was held in the NRC Region I King of Prussia office on July 18, 1991, to discuss an observed trend of deficient performance. This included personnel errors at both the Salem and Hope Creek facilities, and the higher than expected Hope Creek scram rate. Attachment 2 is a list of attendees and Attachment 3 is the licensee's handou ***

ATTACHMENT 1 LIST OF ATTENDEES JUNE 27, 1991 NUCLEAR REGULATORY COMMISSION R. Blough, Chief, Reactor Projects Branch 2, Rl R. Keimig, Chief, Safeguards Section.

S. Pindale, Resident Inspector

. S. Barr, Resident Inspector K. Lathrop, Resident Inspector PUBLIC SERVICE ELECTRIC AND GAS COMPANY S. LaBruna, Vice President - Nuclear Operations M. Butz, Manager - Nuclear R.R. & Administrative Services Dr. R.. Mack, Nuclear Medical _Director Dr. R~ McCarthy, Psychological Services Administrator D. *Ahr, Psychologist P. Moeller, Manager - Site Protection F.. Thomson, Manager - Licensing and Regulations R. Brown, Principal Licensing Engineer R. Beckwith, Station Licensing Engineer.

. AITACHMENT 2 LIST OF ATTENDEES JULY 18, 1991 NUCLEAR REGULATORY COMMISSION J. Wiggins, Deputy Director, Division of Reactor Projects (DRP), RI R. Blough, Chief, Reactor Projects Branch 2, R J. White, Chief, Reactor Projects Section No. 2A, DRP, RI.

L. Bettenhausen, Chief, Operations Branch, Division of Reactor Safety, RI W. Pasciak, Chief; Facilities Radiation Protection, RI

, T. Johnson, Senior Resident Inspector S. Pindale, Resident Inspector S. Barr, Resident Inspector K. Lathrop, Resident Inspector B. Westreich, Reactor Engineer P. Srinivasan, Co~op, Engineering Aid D. Caphton, Senior Technical Reviewer, RI R. Albert, Physical Security Inspector, RI*

J. Stone, Salem Project Manager, NRR R. Nimitz, Senior Radiation Specialist P. Ray, NRR PUBLIC SERVICE ELECTRIC AND GAS COMPANY S. LaBruna, Vice President - Nuclear Operations C. Vondra, General Manager - Salerri Operations J. Hagan, General Manager - Hope Creek Operations *

F. Thomson, Manager - Nuclear Licensing J. Fest, Assistant to the General Manager - Salem Operations

• M. Alpaugh, Lead Engineer, Nuclear Licensing and Regulation D. Cooley, Onsite Safety Review Engineer - Hope Creek C. Manges, Lead Engineer, Nuclear Licensing and Regulation OTHER E. Krufka, Lead Engineer, Atlantic Electric.

P. Duca, Delmarva Power Site Representative T. Kolesnik, Nuclear Engineer, State of New Jersey C. Dell, Nuclear Engineer, State of New Jersey

. SALEM

--

---

ATTACHMENT 3 Ps~G Public Ser*v*ice f:j Electric and Gas

. *

.

.

Compa*ny

.

MANAGEMENT MEETING JULY 18, 1991 HOPE'- CREEK SENERATINB STATION *

• * BEtEAATIN8 STATION (

NRC/PSE&G MANAGEMENT MEETING AGENDA INTRODUCTION ASSESSMENT OF EVENTS PERSONNEL PERFORMANCE ENHANCEMENT INITIATIVES COMPREHENSIVE SCRAM ANALYSIS SCRAM REDUCTION INITIATIVES CONCLUSION

..

S. LaBRUNA VICE PRESIDENT -

NUCLEAR OPERATIONS C. VONDRA GENERAL MANAGER -

SALEM.GENERATING STATION J.. HAGAN GENERAL MANAGER -

HOPE. CREEK GENERATING STATION S. LaBRUNA VICE PRESIDENT -

NUCLEAR OPERATIONS

NRC/PSE&G MANAGEMENT MEETING

. INTRODUCTION BACKGROUND

• INSPECTION REPORT 91-09

- CITED VIOLATION-3 RELATED SPECIFIC EXAMPLES

- OTHER EVENTS NOTED.

• EVENTS INVOLVED

- PERSONNEL ERROR-LACK OF ATTENTION TO DETAIL-PROCEDURE NON-COMPLIANCE

• INSPECTION REPORT 91-15-DISCUSSED OTHER SIMILAR EVENTS

NRC/PSE&G MANAGEMENT MEETING INTRODUCTION MEETING OBJECTIVES

• COMMUNICATE PSE&G's FIRM COMMITMENT AND MANAGEMENT INVOLVEMENT IN IMPROVING PERSONNEL PERFORMANCE

• PROVIDE PSE&G's IN-DEPTH ASSESSMENT OF PERSONNEL ERROR EVENTS AND NRC's SPECIFIC CONCERNS

• DESCRIBE PSE&G's RECENT AND ONGOING FOCUSED PERSONNEL PERFORMANCE ENHANCEMENT INITIATIVES

• PROVIDE UNDERSTANDING OF COMPREHENSIVE SCRAM ANALYSIS FOR HOPE CREEK AND INITIATIVES FOR SCRAM REDUCTION

• SHARE PSE&G's EXPECTATIONS AND CONFIDENCE RELATIVE TO THE RESULTS OF THESE INITIATIVES

ASSESSMENT OF EVENTS AND PERSONNEL PERFORMANC~ ENHANCEMENT INITIATIVES CALVIN A. VONDRA GENERAL MANAGER - SALEM OPERATIONS

• NRC/PSE&G MANAGEMENT MEETING INTRODUCTION

• EVENT ASSESSMENT -

- * DATA COMPARISON

• OVERALL ASSESSMENT OF ANALYSIS

• ONGOING INITIATIVES

• NEW INITIATIVES

• SUMMARY

MM3-37

• NRC/PSE&G MANAGEMENT MEETING PERSONNEL ERROR EVENT ANALYSIS

• ONGOING ANALYSIS PROGRAMS

- RADIOLOGICAL OCCURRENCE REPORTS

- NON-REPORTABLE EVENTS

- REPORT ABLE EVENTS-HUMAN PERFORMANCE ENHANCEMENT SYSTEM (HPES)

A EVENT ANALYSIS

• VOLUNTARY REPORTING ANALYSIS

• ANALYSIS OF 20 SIGNIFICANT EVENTS

- 3-MONTH STUDY (COMPLETED APRIL 1991)

-9-PERSON MULTI-DISCIPLINARY TEAM

- REVIEW INCLUDED:

• ANALYSIS FOR BROADER UNDERLYING CONCERNS

• ADEGUACY OF CORRECTIVE ACTIONS

• ADDITIONAL ANALYSIS OF RECENT EVENTS

- HPES TRAINED EVALUATORS

- REVIEW INCLUDED:

.A CAUSAL FACTOR ANALYSIS

• CORRECTIVE ACTION REVIEW-OF INDIVIDUAL EVENTS

• ASSESSMENT OF BROADER IMPLICATIONS

• MM9-i7 NRC/PSE&G MANAGEMENT MEETING REPORTABLE EVENTS COMPARISONS

• EVENTS WITH ROOT CAUSE OF-PERSONNEL ERROR 1988 1989 1990 1991*

SALEM

. 16

25

HOPE CREEK

9

4

• THAU 6/30/91

• INCREASED OCCURRENCES DURING OUTAGES

• PERSPECTIVE ON INCREASED EVENTS IN 1990

- IMPROVED ROOT CAUSE ANALYSIS-INCREASED SENSITIVITY TO PERSONNEL ERROR

• ANALYSIS REVEALS IMPROVED PERFORMANCE

• CONTINUED IMPROVEMENT REQUIRED

• NRC/PSE&G MANAGEMENT MEETING

• INDUSTRY EVENT ANALYSIS COMPARISON

• HPES EVENT ANALYSIS DATA (INPO)

. - INDUSTRY DAT A

.A. WORK PRACTICES

.A. WRITTEN COMMUNICATIONS

.A. VERBAL COMMUNICATIONS

• SALEM GENERATING STATION DATA

- LEADING CAUSAL FACTORS:

.A. WORK PRACTICES

.A. WRITTEN COMMUNICATIONS

.A. VERBAL COMMUNICATIONS

..& SUPERVISORY METHODS

• HOPE CREEK GENERATING STATION DATA MM3-i9

- LEADING CAUSAL FACTORS:

.& WORK PRACTICES

.& WRITTEN *COMMUNICATIONS

.& VERBAL COMMUNICATIONS.

INDUSTRY DATA CAUSAL FACTOR DISTRIBUTION*

CAUSAL FACTOR VERBAL COtll.JNICATION WRITTEN COtil<<JNICATION INTERFACE DESIGN & EQUIPMENT CONDITION ENVIRCH4ENTAL CotllITIONS

. NORK SCIEDl WORK PRACTICES NORK OR6ANIZATION/PLANNIN6

-, SUPERVISORY METHODS TRAINING/QUALIFICATION METHODS.

TRAINING/QUALIFICATION CONTENT CHANGE MANASBENT

.RESOURCE MANAGEMENT MANAGERIAL METHODS

5

15

• FREQUENCY (%)

• BASED ON 495 RECORDS OF INAPPROPRIATE ACTIONS FROM 1/90 llflOUGH 1/91

2 *

NRC/PSE&G MANAGEMENT MEETING EVENT ANALYSIS COMPARISON ANALYSIS OF RECENT EVENTS

• 18 EVENTS ANALYZED

• CONTRIBUTING CAUSAL FACTORS:

- POOR WORK PRACTICES

- WRITTEN COMMUNICATIONS

- MANAGERIAL METHODS

• SIMILAR TO INDUSTRY DATA Ml<'3-20

• NRC/PSE&G MANAGEMENT MEETING EVENT ANALYSIS COMPARISON 20 SIGNIFICANT EVENTS ANALYSIS

• SIGNIFICANT EVENTS FROM JUNE 1989 THROUGH NOVEMBER 1990

• 10 EVENTS * INVOLVED PERSONNEL ERROR

. *

• IDENTIFIED CONTINUED FOCUS NEEDED IN FOLLOWING

MM3-21 AREAS:

- WORK STANDARDS

- ATTENTION TO DETAIL-PROBLEM AWARENESS & IDENTIFICATION

- ROOT CAUSE ANALYSIS-TIMELY & EFFECTIVE CORRECTIVE ACTIONS

. - SELF-ASSESSMENT e ANALYSIS PROVIDED IMPETUS FOR:.

-REFOCUS OF ONGOING INITIATIVES

- DEVELOPMENT OF NEW INITIATIVES-CONTINU~D HEIGHTENED MANAGEMENT AWARENESS OF PERSONNEL ERROR-RELATED EVENTS

NRC/PSE&G MANAGEMENT MEETING OVERALL ASSESSMENT OVERALL ASSESSMENT

• CAUSAL fACTORS ARE CONSISTENT WITH INDUSTRY

/

• PAST INITIATIVES HAVE PROVIDED IMPROVING TREND

• CONTINUED IMPROVEMENTS ARE NEEDED

• DATA PROVIDES BEST AREAS TO FOCUS MANAGEMENT ATTENTION

.* CORRECTIVE ACTION~ ADDRESSED. ROOT CAUSES

, CONCLUSION.

. * PSE&G MUST ELIMINATE PERSONNEL ERROR TO THE MAXIMUM PRACTICAL EXTENT AND TREAT EACH.INSTANCE*

APPROPRIATELY

• WE CANNOT BE SATISFIED WITH JUST AN IMPROVING TREND

• WE ARE NOT COMFORT~~b~ WITH THE CURRENT LEVEL OF PERSCN£1.. ERROR

• WE ARE AND HAVE BEEN WORKING TO IMPROVE PERFORMANCE

• NEED TO KEEP OUR PEOPLE CONSTANTLY INVOLVED* AND FOCUSED ON PERSONAL PERFORMANCE 'IMPROVEMENTS

• CORRECTIVE ACTIONS GO BACK TO THE FALL OF 1989 MM3-41

---

--

NRC/PSE&G MANAGEMENT MEETING PERSONNEL PERFORMANCE IMPROVEMENT ONGOING INITIATIVES

• HPES VOLUNTARY REPORTING

• GUALITY/SAFETY CONCERN REPORTING

• PEOPLE ACHIEVE COMPETITIVE EXCELLENCE (PACE)

PROGRAM

• ATTENTION TO DETAIL VIDEO TAPE

• PROCEDURE UPGRADE PROGRAM e

1 VISION 1 ROLLDOWN MEETINGS/TRAINING

• ROOT CAUSE TRAINING

• SALEM REVITALIZATION PROGRAM

• REINFORCEMENT COMMUNICATIONS -

• WORK STANDARDS, COMMUNICATIONS

• MANAGEMENT WORK STANDARDS MONITORING

• OFF HOUR/HOUSEKEEPING TOURS

• DAILY ACCOUNTABILITY MEETINGS

• PROFESSIONALISM TASK TEAMS llG-38

,

NRC/PSE&G MANAGEMENT PERSONNEL PERFORMANCE IMPROVEMENT NEW INITIATIVES

• INPO GOOD PRACTICE (OE-906) ROLLDOWN

. *PERSONNEL PERFORMANCE ENHANCEMENT PANELS (PEP)

• SELF VERIFICATION CARDS

• WORK STANDARDS UPGRADE

• WORK CONTROL PROCESS IMPROVEMENTS

• REWORK ACCOUNTABILITY

• MONTHLY TEAMWORK AWARDS

• NRC/PSE&G MANAGEMENT MEETING INPO GOOD PRACTICE (OE-906) TRAINING GOAL:

• INCREASE PERSONNEL AWARENESS OF FREQUENT CAUSES OF HUMAN PERFORMANCE PROBLEMS IMPORTANT ASSUMPTIONS

• MOST WORKERS MOTIVATED TO DO A GOOD JOB

MM3-23

• MOST ERRORS NOT CAUSED BY CARELESSNESS

• ERRORS NOT RANDOM/HAVE IDENTIFIABLE CAUSES

• HUMAN ERRORS BEST REDUCED BY IDENTIFYING AND CORRECTING ERROR-PRONE SITUATIONS

.

~

NRC/PSE&G MEETING INPO GOOD-PRACTICE (OE~906) TRAINING

• ii CAUSAL FACTOR LESSON PLANS

- WORK PRACTICES

- WRITTEN COMMUNICATIONS

- VERBAL COMMUNICATIONS-INTERFACE DESIGN/EQUIPMENT CONTROL-ENVIRONMENTAL CONDITIONS

_ *

- WORK SCHEDULING

--WORK ORGANIZATION AND PLANNING

- SUPERVISORY METHODS-TRAINING CONTENT AND QUALIFICATION METHODS-CHANGE MANAGEMENT-PROBLEM IDENTIFICATION AND RESOLUTION

• ROLLDOWN PROCESS

• ONE EVERY TWO WEEKS

• PLANT SPECIFIC EXAMPLES DISCUSSED

• MM3-24

NRC/PSE&G MANAGEMENT MEETING INPO GOOD PRACTICE (OE-906) TRAINING

. PSE&G ENHANCEMENTS:

• DEVELOPING MATERIAL TO STRENGTHEN LESSON PLAN ON SUPERVISORY METHODS

. *DEVELOPING NEW LESSON PLANS ON:

- RESOURCE MANAGEMENT

- MANAGERIAL METHODS

.. '

GOALS:

NRC/PSE&G MANAGEMENT MEETING PERSONNEL PERFORMANCE ENHANCEMENT PANEL _(PEP)

• OPEN COMMUNICATION CHANNELS

• FULLY UNDERSTAND ROOT CAUSES

• SURFACE UNDERLYING ISSUES

• ASSURE ADEQUACY OF CORRECTIVE ACTIONS

• POSITIVELY 'REINFORCE LESSONS. LEARNED

• MM3-SCOPE:

• ALL PERSONNEL ERROR RELATED LEAS

• EVENTUALLY PERSONNEL ERROR RELATED INCIDENT REPORTS LEA PANEL COMPOSITION:

• STATION GENERAL MANAGER

• STATION MANAGERS

• INVEST I GA TORS

• INVOLVED PERSONNEL

- NRC/PSE&G MANAGEMENT MEETING SELF-VERIFICATION CARDS GOALS:

• REDUCE WORK PRACTICE-RELATED EVENTS

• REINFORCE SELF-VERIFICATION REQUIREMENTS

.. SALEM

.s.ToP*

.b.OCATE IOU CH Y.ERIFY ANTICIPATE MANIPULATE

.O.SSERVE HOPE CREEK ENERATINI STAnCll

• DISTRIBUTED TO ALL EMPLOYEES MM3-27

• NRC/PSE&G MANAGEMENT MEETING WORK STANDARDS UPGRADE GOALS:

• -IMPROVE COMMUNICATION OF WORK STANDARDS

• IMPROVE WORK PRACTICES UPGRADE

• BOOK REDUCED TO POCKET SIZE

• INCREASED EMPHASIS ON SELF VERIFICATION

• INCREASED EMPHASIS ON QUESTIONING ATTITUDE

• DISTRIBUTED TO ALL EMPLOYEES

1'1M3--3 ~

NRC/PSE&G MANAGEMENT MEETING WORK CONTROL PROCESS (WCP)

IMPROVEMENTS GOALS:

• ENHANCE AND STANDARDIZE WORK CONTROL PROCESS AT BOTH STATIONS*

• IMPROVE INTERFACE AND COMMUNICATIONS BETWEEN FIRST LINE SUPERVISORS, WORK CONTROL CENTER AND CONTROL ROOM WCP STUDY RECOMMENDATIONS:

• CONFIRMED NEED FOR SRO TO BE ADDED TO WORK CONTROL CENTER (WCC) AT SALEM STATION

• TECH SPEC ACTION STATEMENT TO BE SIGNED ON BY SRO AT we APPROVED BY SSS

• SCAFFOLD ANO T ~OD LOSS, KEY CONTROL AT wee

• DOCUMENTED TA60UT VERIFICATION BY JOB SUPERVISOR

• EMPHASIS ON COl44UNICATION INTERFACE BETWEEN wee AND FIRST LINE SUPERVISION

• WALKDOWNS CLOSER TO SYSTEM OUTAGE START

• DEVELOPMENT OF ISLAND WIDE PROCEDURE FOR WORK CONTROL COORDINATION

• IMPLEMENTATION OF RECOMMENDATIONS lN PROGRESS

NRC/PSE&G MANAGEMENT MEETING REWORK ACCOUNTABILITY GOAL:

. * PROVIDE IDENTIFICATION, TRACKING & CORRECTION OF MAINTENENCE REWORK PROCESS

• RECENTLY IMPLEMENTED

• REWORK IDENTIFICATION FORMS IN PLACE

• CRITERIA ESTABLISHED

• TOO EARLY FOR RESULTS

NRC/PSE&G MANAGEMENT MEETING

• TEAMWORK AWARD

. GOAL:

• RECOGNIZE AND REWARD TEAM-EFFORTS THAT INVOLVE

. TEAMWORK AND IMPROVED COMMUNICATIONS SALEM GENERATING STAT.ION

. * MONTHLY AWARD

• CITING NOTEWORTHY EFFORT EXHIBITING A HIGH LEVEL OF TEAMWORK AND COOPERATION

• PLAQUE WITH PHOTO AND TASK DESCRIPTION HUNG AT PROMINENT SALEM.LOCATIONS

• QUARTERLY LUNCHEON FOR HONOREES HOPE CREEK GENERATING STATION

• PERIODICALLY AWARDED

• RECOGNIZING EXEMPLARY TEAM EFFORT *TEAM MEMBERS RECEIVE* TEAMWORK AWARD

• AWARD PRESENTATION COMMUNICATED WITH ALL PERSONNEL.

MM3-32

NRC/PSE&G MANAGEMENT MEETING SUMMARY

• WE RECOGNIZE THE NEED FOR CONTINUED IMPROVEMENT IN PERSONNEL PERFORMANCE

• PERSONNEL ERROR REDUCTION/PERSONNEL PERFORMANCE ENHANCEMENT HAS BEEN AN ONGOING CONCERN

• A VARIETY *OF PROGRAMS AND INITIATIVES ARE IN PLACE TO IMPROVE RESULTS

• FOCUSED EFFORT MUST CONTINUE-PROVIDE CONSTANT REINFORCEMENT-PERIODIC EFFECTIVENESS REVIEWS

• EXPECTATIONS:

-REDUCE THE NUMBER OF PERSONNEL ERROR EVENTS-MAINTAIN A TREND OF CONSTANT IMPROVEMENT MM3-33

COMPREHENSIVE SCRAM ANALYSIS AND SCRAM REDUCTION INITIATIVES JOSEPH J. * HAGAN GENERAL MANAGER - HOPE CREEK.OPERATIONS

- NRC/PSE&G MANAGEMENT MEETING CURRENT STATUS BACKGROUND MM3-3

• SCRAM AND POWER REDUCTION ELIMINATION TEAM (SPRE).

• SCRAM REDUCTION IMPROVEMENT DCP PROGRAM SINCE 1988

• BWROG SCRAM REDUCTION EFFORT

• PAST ANALYSIS PERFORMED YIELDED 1 ISOLATED EVENT 1 DETERMINATION

-

1 COMMON THREAD 1 STILL NOT OBVIOUS

NRC/PSE&G MANAGEMENT MEETING CURRENT STATUS PROBLEM STATEMENT AND INITIAL RESPONSE

.... -MM3-2

• HOPE CREEK SCRAM RATE IS ABOVE OUR EXPECTATIONS

.

.

.

-

• TWO OCCURRENCES OF RELATED TYPE SCRAM EVENTS

• PERSONNEL ERROR CAUSED SCRAM EVENT ON MAY 7, 1991

• ONSITE SAFETY REVIEW GROUP WAS TASKED TO COMPREHENSIVELY ANALYZE 12 SCRAMS SINCE AUGUST 1988

- IDENTIFY COMMON THREAD

- IDENTIFY INITIATIVES TO REDUCE THE NUMBER OF SCRAMS

• NRC/PSE&G MANAGEMENT MEETING COMPREHENSIVE SCRAM ANALYSIS COMPREHENSIVE SCRAM ANALYSIS (AFTER MAY 7 EVENT)

eCHARTER -

1 DIG DEEP

,

IDENTIFY MOST PROBABLE COMMON THREADS

• COMPOSITION

- ONSITE SAFETY REVIEW (ISEG) ENGINEER

- OFFSITE SAFETY REVIEW ENGINEERS. (2)

MM3-4

- STATION QUALITY ASSURANCE ENGINEERS (2)

- HPES STAFF ENGINEER (CURRENT SRO)

• INVESTMENT - 7 WEEKS: APPROXIMATELY 1300 WORK HOURS

• METHOD - MANAGEMENT OVERSIGHT AND RISK TREE (MORT) AS DEVELOPED BY_EG&G INTERTECH

• GOAL - IDENTIFY CAUSES OF UNSATISFACTORY SCRAM PERFORMANCE

NRC/PSE&G MANAGEMENT MEETING RESULTS AND FINDINGS OF.

COMPREHENSIVE*scRAM ANALYSIS ESSENTIAL ELEMENTS OF SCRAM-FREE OPERATION IDENTIFIED BY THE ANALYSIS

• PEOPLE ACTIVELY SEEKING TO -PREVENT UNNECESSARY SCRAMS

• A *scRAM-TOUGH. PLANT

• EFFECTIVE ROOT CAUSE AND CORRECTIVE ACTION PROCESSES

.

'

.

COMBINATION.OF ALL NEEDED TO PRODUCE CONSISTENT*

RESULTS MM3-6

NRC/PSE&G MANAGEMENT MEETING RESULTS AND FINDINGS OF COMPREHENSIVE SCRAM ANALYSIS HAZARD - BARRIER - TARGET ANALYSIS

• EFFECTIVENESS OF MAINTENANCE 10 OF 12 EVENTS

• IMPLEMENTING PROCEDURES *

B OF 12 EVENTS

• OPERA TOR PERFORMANCE 7 OF 12 EVENTS

• DESIGN 7 OF 12 EVENTS _ -

• OPERATING EXPERIENCE FEEDBACK 7 OF 12 EVENTS

• COMPONENT OPERABILITY/INTEGRITY 6 OF 12 EVENTS

• DESIGN CHANGE PROCESS 3 OF 12 EVENTS e FREQUENCY /SCHEDULING 3 OF 12 EVENTS THE TEAM ALSO NOTED THAT BALANCE OF PLANT-RELATED SCRAMS INCREASED FROM 501 TO 831 AFTER AUGUST 1988.

. MM3-5

..

NRC/PSE&G MANAGEMENT MEETING

- RESULTS AND FINDINGS OF COMPREHENSIVE SCRAM ANALYSIS*

PEOPLE ACTIVELY SEEKING TO PREVENT UNNECESSARY SCRAMS -

• MAINTENANCE WORK PRACTICES MAY HAVE CONTRIBUTED TO EQUIPMENT FAILURE

• INSUFFICIENT OWNERSHIP/UNDERSTANDING OF HOW

-

.

.

iMY* WORK CAN CONTRIBUTE TO AN EVENT

• SOME EMPLOYEE SUGGESTIONS NOT AGRESSIVELY

PURSUED

• SCRAM & POWER REDUCTION ELIMINATION TEAM (SPRE)

LACKS CLEAR FOCUS AND DIRECTION

• DILUTION OF EXPERIENCE DUE TO NORMAL CAREER PROGRESSION MM3-7

NRC/PSE&G MANAGEMENT MEETING RESULTS AND FINDINGS OF

• coMPREHENSIVE SCRAM ANALYSIS A *scRAM-TOUGH. PLANT MM3-8

• MAIN TURBINE LOGIC IS NOT *FAULT TOLERANT*

• DESIGN CHANGE PRIORITIZATION FOR BALANCE OF PLANT ISSUES REQUIRES STRENGTHENING

• FEEDWATER LEVEL CONTROL HAS *coNTRIBUTED. TO 8 OF 12 EVENTS*

• TESTABILITY ENHANCEMENT DCP's HAVE BEEN EFFECTIVE AND NEED TO BE CONTINUED 8MULTI-LAYER BARRIERS SHOW SUFFICIENT DEPTH IN PROTECTION

NRC/PSE&G MANAGEMENT MEETING RESULTS AND FINDINGS OF COMPREHENSIVE SCRAM ANALYSIS EFFECTIVE ROOT CAUSE ANALYSIS AND CORRECTIVE ACTION MM3-9

• SIGNIFICANT EVENT RESPONSE TEAM (SERT) HAS BEEN EFFECTIVE

- SOME EVIDENCE OF LACK OF COMPREHENSIVE FOLLOW-THROUGH ON INTENT OF R~COMMENDATIONS

• OPERA TING EXPERIENCE FEEDBACK/WELL-DEFINED AND PROPER MANAGEMENT ATTENTION-INTERNAL PROCESS DID NOT PREVENT REPEAT EVENTS

• NRC/PSE&G MANAGEMENT MEETING SCRAM REDUCTION INITIATIVES INITIATIVES *

• • COMMUNICATE EXPECTED SCRAM PREVENTION GOAL AND CONSTANTLY REINFORCE

• *LATENT* ERROR REDUCTION PROGRAM (INPO OE-906)

• REFOCUS SPRE FOR VISIBILITY AS SCRAM GOAL

• cHAMPioN*

• CONTINUE PROCEDURE REVISION ADDRESSING SCRAM-RELATED IMPROVEMENTS

• INCREASE EMPLOYEE PARTICIPATION IN SCRAM REDUCTION IDEA GENERATION

• IMPROVE EFFECTIVENESS OF MAINTENANCE VIA CONTINUING TRAINING/OPERATING EXPERIENCE/STANDARDS OF PERFORMANCE MM3-10A

NRC/PSE&G MANAGEMENT MEETING SCRAM REDUCTION INITIATIVES

• ENSURE THOROUGH FOLLOW-THROUGH ON SERT RECOMMENDATIONS-GM APPROVAL AND ACCEPTANCE PRIOR TO CLOSURE

- CONCURRENCE OF SPRE

• CONTINUE DEDICATED RESOURCES WITHIN SIX-YEAR CAPITAL PLAN

• INCLUSION OF DIGITAL FEEDWATER CONTROL IN LONG-TERM PLANS

~SHORT TERM:

ENHANCE PRESENT ANALOG SYSTEM

• CONTINUE EMPHASIS IN LICENSED OPERATOR AND REGUALIFICATION PROGRAMS MM3-10B

&..-

,..

....

. I

-- -----------------------::c,---,

NRC/PSE&G MANAGEMENT MEETING CONCLUSIONS

• NOT A SIMPLE RELATIONSHIP: NO QUICK FIX

• HOPE CREEK CAN ACHIEVE< 1 SCRAM PER YEAR-HAVE ACHIEVED 150, 175 AND 221 DAY RUNS

• HAVE SHOWN IMPROVEMENT THROUGH CORRECTIVE ACTIONS

-FOLLOW THROUGH ON MOISTURE SEPARATOR EVENTS-JUNE 16, 1991 LIGHTNING STORM

-NUMAC RADIATION MONITORS

• CONSISTENT APPLICATION OF INITIATIVES WILL RESULT IN REDUCED UNNECESSARY SCRAM EVENTS MM3-11

. &..:

,,

• -

'

NRC/PSE&G MANAGEMENT MEETING CONCLUSION

• ASSESSMENT

• RECENT AND ONGOING INITIATIVES

• COMMITMENT TO IMPROVEMENT

• STRATEGY FOR IMPROVEMENT-COMMUNICATE CLEAR EXPECTATION

• PROVIDE CONSTANT REINFORCEMENT

- REQUIRE INDIVIDUAL ACCOUNTABILITY-PERFORM MONITORING AND FEEDBACK-ENSURE WORK ENVIRONMENT CONSISTENT WITH HIGH PERFORMANCE EXPECTATIONS

• MATERIEL CONDITION

£EQUIPMENT

. A PROCEDURES A SUPERVISION

• LASTING IMPROVEMENT LIES IN AN INTEGRATED

• APPROACH TO ABOVE FIVE ELEMENTS MM3-43

.....

J'

'*

• '

NAC/PSE&G MANAGEMENT MEETING SALEM OVERVIEW 1/1/91 - PRESENT

• 3 MILLION SAFE WORKHOURS

• 1 REACTOR TRIP SINCE 9/90 (DUE TO LIGHTNING ST.RIKE)

• 148~DAY DUAL UNIT RUN (RUN ENDED DUE TO U/1 9TH REFUELING OUTAGE)

• U/1 9TH REFUELING OUTAGE WAS SECOND MOST SUCCESSFUL IN SALEM HISTORY

• * U/2 SURVIVED SGFP LOSS FROM >901 REACTOR POWER WITH NO REACTOR TRIP. TRIP AVOIDED DUE TO:

- PROMPT OPERATOR ACTION.

-IMPLEMENTATION OF LESSONS LEARNED FRO~ 9/90 EVENT

,

• U/2 COMPLETED 245-DAY RUN ON 5/ 11/9 RUN ENDED BY PLANNED MAINTENANCE OUTAGE

• U/2 PLANNED MAINTENANCE OUTAGE SUCCESSFULLY COMPLETED (5/11-5/22)* *

• U/1 AND U/2 BOTH CURRENTLY RUNNING WELL

NRC/PSE&G MANAGEMENT MEETING HOPE CREEK OVERVIEW RECENT ACCOMPLISHMENTS

• CONTINUED CONSISTENT PERFORMANCE

• PROVEN SUCCESS IN OUTAGE PLANNING, SCHEDULING AND EXECUTION

• COMPLETED MOST SUCCESSFUL OUTAGE TO DATE

• ACHIEVED 1 MILLION SAFE WORK HOURS IN 1990

• CONTINUE TO REACH FOR HIGHER GOALS.*

MM3-42