IR 05000272/1993020
| ML18100A620 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 09/22/1993 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18100A618 | List: |
| References | |
| 50-272-93-20, 50-311-93-20, 50-354-93-20, NUDOCS 9309280110 | |
| Download: ML18100A620 (29) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos. 50-272/93-20 50-311/93-20 50-354/93-20 License Nos. DPR-70 DPR-75 NPF-57 Licensee:
Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Facilities:
Salem Nuclear Generating Station Hope Creek Nuclear Generating Station Dates:
July 25, 1993 - September *4, 1993 Inspectors:
S. T. Barr, Senior Resident Inspector (Acting)
J. G. Schoppy, Resident Inspector T. H. Fish, Resident Inspector Approved:
f-tJ.:J-9 3 Date*
Inspection Summary:
This inspection report documents inspections to assure public health and safety during day and backshift hours of station activities, including: operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification. The Executive Summary delineates the inspection findings and conclusion PDR ADOCK 05000272
EXECUTIVE SUMMARY Salem Inspection Reports 50-272/93-20; 50-311/93-20 Hope Creek Inspection Report 50-354/93-20 July 25, 1993 - September 4, 1993 OPERATIONS (Modules 30702, 71707, 93702)
Salem: The licensee operated the Salem units safely. An incorrect operability determination involving a channel of the Solid State Protection System, which resulted in a Technical Specification non'compliarice, was considered an unresolved item. Also, another unresolved item involves a reactor coolant system cold leg accumulator that was not promptly declared inoperable though its level was recorded as slightly exceeding the technical specification limit, due to inattention by shift operating personnel and an improper alarm setpoint. Both these matters involved inappropriate and non-prompt response to indicators of deficient system performanc Hope Creek: The licensee operated the Hope Creek unit safely. The licensee conducted a well planned evolution to isolate a leak in the main steam isolation valve (MSIV) sealing system. A MSIV sealing system isolation valve was left in the failed open position and required a 10 CFR 50.59 review and safety evaluation. The performance of this review and safety evaluation remains an open item. On August 21, 1993, the operators made a smooth transition into and out of single loop operations in support of rotor brush replacement in both reactor recirculation system motor-generator sets. In an unrelated incident, on August 25, the crew performed well when they shifted reactor recirculation flow control from master manual control to individual manual control in response to an apparent failure of the master controlle MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
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Salem: The licensee initiated a Technical Specification-required shutdown of Unit 1 on August 24, in response to a degraded voltage on a cell in the 1 C 125 volt battery. The need to shutdown was relieved when the NRC exercised enforcement discretion for the event in response to the licensee's request and associated justification. Salem Technical Department system engineers performed well in response to the licensee's determination that the lC 125 volt battery was inoperable due to a faulty cell. The NRC closed an open item following successful repair of the Unit 2 automatic rod control summato *
Hope Creek: Licensee maintenance activities were well planned and executed. The high pressure coolant injection (HPCI) system was inoperable between August 14 and 19, 1993, while the HPCI-to-core spray injection valve was repaired. Other areas inspected included replacement of a intake screen spray water pump impeller and repairs to the air operator for a feedwater heater drain valv ENGINEERING (Modules 71707)
Salem: The inspectors noted that engineering personnel properly prioritized work activitie The inspector noted PSE&G Engineering properly and conservatively evaluated an emergency diesel generator cooling water flow setpoint error and closed a previously open unresolved ite Hope Creek: The inspectors noted that engineering personnel properly prioritized work activities. The licensee continued to install non-outage related hardware associated with the reactor water level modification. Approximately 90% of the non-outage work has been completed. The inspector also noted that the licensee is ahead of schedule for completing the replacement of deficient DC microswitches. These two efforts are positive indicators of engineering's ability to plan and manage special project PLANT SUPPORT (Modules 71707, 90712, 92700, 92701)
Salem: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirement The inspector noted good coordination between PSE&G Engineering and Site Protection personnel during the installation of the new Salem No. 2 fire pump and observed that the testing of the new pump was satisfactorily performed. The inspector attended the Salem General Manager's "State of the Station" presentation and found it to be an effective means to elicit improved performance and resolve employee concern Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirements. The inspector noted that good teamwork between the radiation.protection and chemistry departments contributed to minimizing the radiation exposure of workers repairing an air operator for a feedwater heater drain valv Common: PSE&G Radiation Protection Services initiated plans to simplify the processing of site personnel dosimetry by eliminating the issuance of thermo-luminescent dosimetry to personnel who normally do not enter radiologically controlled areas. The inspector monitored the licensee's preparations for the potential arrival of hurricane Emily and determined that the Emergency Preparedness organization and both plant staffs properly and conservatively implemented their respective procedures. The inspectors determined that the iii
- licensee appropriately implemented security program requirements. The NRC inspected PSE&G' s employee concerns programs and found them to be an effective means for licensee employees to raise safety concerns without fear of retribution; the programs are well-staffed and properly manage Safety Assessment and Quality Verification The licensee's Employee Concerns Program was surveyed for scope and depth. The results of the review are included as an attachment to this report. As detailed in Sections 2.2.1 A and B, two instances were noted this period involving inappropriate and non-prompt response to indications involving deficient performance or operability of systems described in the technical specifications. The findings may indicate a potential weakness relative to recognition and proper response to deficient conditions and situations. The current findings warrant continued licensee attention to this are iv
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TABLE OF CONTENTS EXECUTIVE SUMMARY...................................... ii TABLE OF CONTENTS....................................... v SUMMARY OF OPERATIONS............................... 1 Salem Units 1 and 2.................................. 1 Hope Creek........................... ;*........... 1 OPERATIONS........ *................................. 1 2.1 Inspection Activities..... :............................ 1 Inspection Findings and Significant Plant Events................
2.2.1 Salem...................................... 1 2.2.2 * Hope Creek................................... 4 MAINTENANCE/SURVEILLANCE TESTING..................... 6 Maintenance Inspection Activity.......................... 6 Surveillance Testing Inspection Activity...................... 7 Inspection Findings.................................. 8 3.3.1 Salem...................................... 8 3.3.2 Hope Creek.................................
10 ENGINEERING.......................................
11 Salem.........................................
11 Hope Creek......................................
11 PLANT SUPPORT.................... *.................. 12 5.1 Radiological Controls and Chemistry......................
5.1.1 Inspection Activities............................
5.1.2 Inspections Findings - Salem.......................
5.1. 3 Inspection Findings - Hope Creek....................
5.1.4 Inspection Findings - Common......................
13 Emergency Preparedness..............................
5.2.1 Inspection Activities......... '...................
5.2.2 Inspection Findings - Common......................
14 Security........................................
5.3.1 Inspection Activities............................
5.4 Fire Protection....................................
5.4.1 Inspection Activities............................
5.4.2 Inspection Findings.............................
15 Safety Assessment and Quality Verification
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5.5.1 Salem............................ *.........
5.5.2 Common...................................
v
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TABLE OF CONTENTS (CONTINUED) LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOW-UP.....................
17 LERs and Reports*..................................
17 Open Items......................................
18 EXIT INTERVIEWS/MEETINGS............................
7.1 Resident Exit Meeting...............................
18 Specialist Entrance and Exit Meetings......................
Attachment................................................ 1
vi
- DETAilS SUI\\tmfARY OF OPERATIONS Salem Units 1and2 Both Salem units operated at power throughout the inspection period. The licensee initiated a Technical Specification-required shutdown of Unit 1 on August 24, 1993, in response to a quarterly surveillance test of the lC battery that revealed a weak cell. The need to shutdown was relieved when the NRC exercised enforcement discretion for the situation upon evaluation of licensee's request and associated justification for continuing operations. At the end of the inspection period, Unit 1 had been on line for 46 days and Unit 2 for 64 day.2 Hope Creek Hope Creek operated the plant safely throughout the inspection period. With the exception of small power reductions to support scheduled surveillance activities, the operators maintained the plant at 100% power. At the end of the inspection period, Hope Creek had been on line 108 day OPERATIONS Inspection Activities The inspectors verified that Public Service Electric and Gas (PSE&G) operated the facilities safely and in conformance with regulatory requirement The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. The inspectors performed normal and back-shift inspections, including deep back-shift (14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />) inspection.2 Inspection Findings and Significant Plant Events 2.2.1 Salem Technical Specification (TS) Noncompliance On July 11, 993, at approximately 5:30 a.m., operators stopped slave relay testing procedure Sl.OP-ST.SSP-0010, "Engineered Safety Feature - Solid State Protection System (SSPS)
Slave Relay - Train "B"," when a problem occurred in obtaining a test meter readin Operators were testing the "Slave Relay K601 - Safety Injection" circuit in the "B" train of the SSPS. The licensee believed, based upon an initial print review and past test circuit problems, that the problem was in the test circuit portion of the output relay. The licensee did not declare SSPS inoperable at this time, as the test circuit is independent of the normal
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SSPS function. The licensee initiated a work request to investigate the problem. At 5:30 p.m. on July 11, 1993, the maintenance supervisor informed operations that the test circuit had not failed, and that the surveillance results showed an SSPS circuit failure. The supervisor determined that buffer relay BD601 for feedwater isolation was inoperable. The licensee entered the action statement for the inoperable SSPS at 5:30 p.m. on July 11. Train
"A" remained operable for the period such that feedwater isolation continued to be availabl On August 5, 1993, as a result of management review of a subsequent reactor trip event investigation (see NRC Inspection 50-272/93-19), the licensee determined that the operability determination of the SSPS slave relay was not accurately diagnosed on July 11, 1993. The licensee also determined that the initiation of troubleshooting was inappropriately delaye The management review noted that there is a six hour action statement (TS 3.3.2.1 Action 13) associated with SSPS inoperability, and that the licensee commenced initial troubleshooting after the six hour period had expire The licensee found the root cause of the inadequate TS operability determination to be personnel error in that the initial presumption of test circuit failure was not correct. In addition, the review determined that operations decision to delay troubleshooting was inappropriate. Operations Department management reviewed the circumstances surrounding the lack of expeditious troubleshooting and initiated disciplinary action against the operations personnel involved, reviewed the operability determination procedures and requirements with all operation personnel and included such review in the requalification training of operations personnel, and initiated procedure review and revision to direct attention to technical specification action statements when deficient system performance or operability is indicate Specifically, Operations management issued instructions to all operating personnel regarding the appropriate action statement entry, including instruction to enter the SSPS action statement whenever any abnormal readings are encountered during system tests. The licensee is also reviewing and revising the slave relay functional testing procedure as appropriat The inspector attended the Safety Operations Review Committee (SORC) meeting discussing the TS noncompliance issue. The inspector noted that the licensee maintained a good safety conscious approach in making this determination. Licensee management, when presented with the concern, did not attempt to make excuses for its operators, but to question if the operability determination could have been more timely. The inspector observed that the operators used past test circuit malfunctions and a less than adequate electrical print review to determine SSPS operability. The inspector noted that the licensee's reasonable expectation of system operability and timely pursuit of problem identification and resolution must be commensurate with the potential safety significance of the issue as stated in Section 4.0 of NRC Generic Letter 91-18. The inspector determined that the relatively short action statement and SSPS safety significance should have demanded a more thorough review by the operations staff prior to accepting a possible, though less conservative, solution. This matter is considered unresolved pending further NRC review (URI 50-272 and 311/93-20-01).
3 Reactor Coolant System Accumulator High Level At 7:57 a.m. on August 24, 1993, Salem Unit 1 shift supervision declared No. 12 cold leg accumulator inoperable due to channel "B" level being above the maximum Technical Specification (TS) level of 65 % * At that time, control room operators read 65. 3 % on channel "B" and 64.5% on channel "A" for the No. 12 accumulator. Operators immediately drained the accumulator to within specification and at 8:09 a.m. restored the accumulator to operability. The oncoming clayshift operators subsequently noted that the midnight readings, as recorded by the previous shift control room operator, indicated that the No. 12 accumulator was out of specification at 65.1 %. The midnight shift operator had not recognized that this reading was outside the required range (51-65%), however, and took no action. The licensee promptly took disciplinary action against that operato The inspector reviewed the control room logs and noted that operators did not receive the accumulator high level alarm during this incident. The inspector also noted that the licensee entered the TS Action Statement (TSAS) at 7:57 a.m. instead of at midnight when the accumulator level was first noted to be out of specification. Dayshift operators entered the TSAS at their time of discovery even though the accumulator was known, as indicated by the control room log, to be inoperable at midnight when level was first recorded out of specification (i.e., 65.1 % vs. the technical specification of 65 % ). The time of entry for this particular event had no significance as the licensee was still within their allowed TSAS time limit prior to being required to shut the unit down. However, operators using the time of discovery of component inoperability vice the time the component is known to have been inoperable could lead the licensee into TS non-complianc Shift supervision was also quick to follow up on the lack of alarm response. The alarm response card (ARC) indicated that this alarm would actuate at 70/55 %, as opposed to 65/51 % as required. However, the licensee determined that this was a misprint on the ARC and a change to the ARC was initiated. An I&C technician checked the alarm setpoint and determined that the high level alarm setpoint was 65. 6 % vice 65 %. The licensee had no immediate explanation as to the setting of these accumulator alarms. Engineering is investigating the alarm setpoints to determine if other hi/lo level accumulator alarms on both units are affected, and subsequently assure the proper adjustment of those setpoints. The inspector noted that these alarms alert the operator to potential situations which could reduce the effectiveness of the accumulators in combating a major loss of coolant accident (LOCA).
The inspector determined that the operator's actions to correct the accumulator high level, once properly identified, were prompt and appropriate. The inspector noted that the licensee fully comprehended the significance of such an inattentiveness to duty or part of the control room operator, even though the safety significance of accumulator level at 65.1 % was minimal. In addition, the inspector noted that the licensee initiated prompt corrective action to address the errant level alarm setpoints. This item will remain open pending engineering disposition of the alarm setpoints, proper adjustment of the setpoints, and final NRC review of the event (URI 50-272 and 311/93-20-02).
2.2.2 Hope Creek Main Steam Isolation Valve (MSIV) Sealing System Leakage On August 10, 1993, the licensee identified a six liter/minute packing leak on the isolation valve (KP-HV-5835B) for the outboard MSIV sealing system on the "B" main steam lin The valve is located in the steam tunnel. The licensee opened the valve remotely to attempt to stop the leakage by manually backseating the valve. However, increased leakage past the open valve prevented the operators from gaining access to the valv On August 11, operations, maintenance and engineering personnel met to discuss methods available to isolate the leakage. The licensee was very methodical in exploring all available options. The inspector noted good communication between interfacing departments and a concerted safety consciousness. A great deal of consideration was given to personnel safety as well as plant operational concerns. The licensee determined that using a steam blanket and cheater-bar (for extended reach) was the most straightforward approach. Engineering continued to develop the option of electrically backseating the valve. The licensee gave full consideration to the potential for damaging this motor operated valv At approximately 3:00 p.m. on August 11, operators successfully manually backseated KP-HV-5835B after using a steam blanket (shield to allow operators access to the handwheel).
The licensee used no mechanical or electrical advantage in backseating the valve. The inspector observed this maintenance evolution and determined that the licensee took appropriate radiological, personnel safety, and operational precautions in performing this task. The licensee was successful in backseating the valve and isolating the leak in the steam tunne The inspector reviewed the Technical Specifications and Updated Final Safety Analysis Report (UFSAR) as they pertain to the MSIV sealing system. The inspector noted that although the "as left" condition of the valve resulted in a fully operable system, an interlock specified in the UFSAR was permanently bypassed. The interlock is designed to prevent inadvertent operation of the MSIV sealing system. In particular, this interlock prevents multiple valve openings that would result in blowing high pressure steam to the reactor building whenever the pressure in the connecting main steam lines exceed the MSIV sealing system initiating pressure. The UFSAR allows for bypassing this interlock for periodic testing (stroking) of the valve. The inspector determined that the licensee acted appropriately in initially opening the valve, however, questioned leaving the valve "failed open" until the next outage of sufficient duration, as was the licensee's plan. The inspector discussed the need for a 10 CFR 50.59 review with operations since this action appeared to constitute a change to the UFSAR. Operations stated that, prior to opening the valve, operability and valve manipulation was discussed. The licensee determined that opening the valve, and leaving it in that position, was covered by the UFSAR allowance of bypassing the interlock for testing. On August 26, the licensee informed the NRC staff that engineering had in fact initiated a deficiency report (DR), which included a 50.59 review, on August 10, 1993. The
DR was initiated for environmental qualification (EQ) concerns due to the packing leak blowing steam on the valve actuator. On August 27, members of the licensee's maintenance, operations, and engineering staff met with the NRC resident staff to discuss the MSIV sealing system, the 50.59 review process, and the safety evaluation. At the time of the meeting, the engineering 50.59 review was still in draft and thus was not available for discussion. The inspector was satisfied that a 50.59 review was initiated although fortuitously by engineering vice operations. The inspector noted poor communication between engineering and operations as engineering was two weeks into a 50.59 review without operations cognizance. In addition, the inspector observed a weakness in operation's reluctance to conduct 50.59 reviews for changes to the plant as specifically mentioned in the UFSAR. This item will remain open pending NRC review of the licensee's 50.59 review (URI 50-354/93-20-01). Single Loop Operations During the current operating cycle the brushes on the generator end of the reactor coolant system recirculation pump motor generator (MG) sets exhibited abnormal wea Consequently, on August 21, 1993, Hope Creek operators reduced plant power to approximately 45 % power in order to alternately remove each recirculation pump from service so that maintenance could be performed on the MGs. While in single loop operation Hope Creek maintenance technicians replaced the generator brushes on each MG set while its respective recirculation loop was idle. Once the MG set maintenance work was completed, Hope Creek operators restored the recirculation system to its normal configuration and returned plant power to 100 %.
The resident inspector was present in the Hope Creek control room for the conduct of single loop operations and for the transition from one recirculation loop to the other. The inspector verified that the operators conducted single loop operations in accordance with the proper procedure, HC.OP-SO.BB-0002(Q), "Reactor Recirculation System Operation," and complied with the requirements of the Technical Specification thermal power versus core flow figures. The inspector noted that Hope Creek shift supervision ensured proper control room decorum during the scram-sensitive portions of the single loop operations and provided good oversight of plant operations during the evolutio The inspector also monitored portions of the MG brush replacement maintenance and discussed the necessity for the work with a Hope Creek Maintenance supervisor. The inspector was informed that the accelerated brush wear was suspected to be due to internal fouling of the generators with dirt and debris and consequent abrading of the generator slip ring which resulted in abnormal brush erosion. PSE&G has placed slip ring repair on the Hope Creek forced-outage work list. Jhe inspector noted that the activity was well planned, managed and performed.
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6 Recirculation Master Flow Controller Malfunction On August 25, 1993, while Hope Creek was operating at 100% power, a reactor operator noted that core thermal power had decreased slightly, from rated power of 3293 megawatts to 3265 megawatts. He checked for a corresponding drop in main generator output, observed that electrical power had declined, which confirmed the loss in core power. The crew then investigated for possible causes for the slight power reduction. When they checked for changes in reactor recirculation system parameters the crew discovered that both pump speeds had dropped slightly from previously observed values. The crew determined that the cause for the speed decrease on both pumps was a malfunction in the recirculation master flow controller, since the master controller is common to both pumps. Subsequently, the operators shifted flow control from the master controller to each pump's individual controller and returned to rated powe Troubleshooting during the next few days indicated that a failed circuit board card in the master flow controller caused the power decrease. Technicians replaced the card and the crew returned recirculation flow control to the master controlle The inspector determined that the crew's response to the power reduction was very good for several reasons. First, the power drop was small enough such that no annunciators or alarms came in. Therefore, it was an especially alert operator that first noticed the chang Second, the crew's follow-up actions to search for additional indications which corroborated the power loss as being valid, as opposed to being an instrument malfunction, demonstrated their excellent understanding of integrated plant operations. Finally, the crew's accurate determination of what component had caused the reduction was an example of good technical assessmen.
MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that the licensee conducted these activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard The inspector observed portions of the following activities:
Salem 1 Work Order(WO) or Design Change Package <PCP)
Description WO 930821097 lC - 125VDC Battery/cell No. 47 replacement
Salem 2 WO 930718090 Hope Creek DCP-4EC-3407 Hope Creek WO 921027237 Hope Creek WO 930827116 Hope Creek WO 930127046 Hope Creek WO 930812111
U2 Rod control system summator repair Reactor vessel water level instrumentation modifications Refuel floor bridge mast removal Control rod drive pump bearing replacement Motor operator repair for high pressure coolant injection-to-core spray injection valve Recirculation MG brush replacement 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 regulation The inspector reviewed the following surveillance tests with portions witnessed by the inspector:
Procedure N Salem 1 SC.MD-ST.125-0003 Salem 1 S 1.IC-ST.SSP-0005 Salem 1 Sl.OP-ST.RHR-0001 Hope Creek OP-IS.BJ-101 125 VDC Battery Quarterly Inspections Reactor Trip and Reactor Bypass Breakers - P4 Permissive Tests No. 11 Residual Heat Removal Pump Performance Test High Pressure Coolant Injection Valves 92 Day Inservice Run
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Hope Creek IC-CC.SE-029 Hope Creek OP-IS.EG-002 Hope Creek OP-IS.EP-004
Local Power Range Monitor Calibrations Safety Auxiliaries Cooling System 92 Day Inservice Run Spray Water 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 3.3.1 Salem Unit 1 Technical Specification Shutdown and NRC Enforcement Discretion On August 19, 1993, Salem operators performed the quarterly surveillance test of the Unit 1 lC 125 volt battery. The results of the test revealed the voltage on cell number 47 (of the 60-cell battery) was 2.08 volts. Technical Specification (TS) 3.8.2.3, requires each cell of the battery must be verified greater than 2.13 volts under a float charge. During the time period, August 19-23, the licensee attempted, through an individual cell equalizing charge and by increasing the battery float voltage, to address the weak cell and maintain battery operability. However, on the morning of August 24, Salem station management recognized the lC 125 volt battery could no longer be demonstrated to be operable, and at 8:49 a.m.,
operators initiated a shutdown in order to comply with TS 3.8.2.3. At the same time, PSE&G approached the NRC with a request for enforcement discretion so that the plant could be maintained at power while the faulty battery cell was replaced. PSE&G based its request on a safety evaluation which licensee engineering had prepared which showed that the lC battery could fulfill all of its safety functions with 59 operable cells. The NRC granted the licensee's request of enforcement discretion for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> beginning at 9:04 a.m. on August 24, and the licensee terminated the Unit 1 shutdow During the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> discretion period, PSE&G implemented a temporary modification and replaced cell 47 of the lC battery with a new cell. By 7:30 a.m. on August 25, PSE&G determined that the new cell voltage was still below 2.13 volts. PSE&G management determined the new cell could not be declared operable and requested an additional six day discretion period in order for the entire battery to properly equalize with the new cell. Based on the licensee's original justification and on the belief that the new cell's performance was not indicative of a bad cell, the NRC concluded the extension of enforcement discretion involved minimum or no safety impact and granted PSE&G enforcement discretion until 9:04 a.m. on August 31, 1993. The licensee subsequently performed an equalizing charge on the entire battery, let the battery settle for an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per their procedures, and finally declared the lC battery operable at 1: 13 p.m. on August 3 *
The resident inspector monitored the licensee's performance throughout the August 19-30 time frame. The inspector noted good cooperation between Salem Operations, Maintenance and Technical Departments personnel in the addressing and resolving this matter. The licensee's engineering evaluation and written request for enforcement discretion were thorough and well written. The inspector observed portions of the installation of the new cell and subsequent battery testing and concluded the licensee performed well in their overall response to the event. However, a weakness was noted in station management's ability to clearly discern whether the battery was operable on the morning of August 25, following the installation of the new cell. This matter was referred to and further inspected by an NRC specialist as part of an NRC Electrical Distribution System Functional Inspection (see NRC Report 50-272 and 311/93-82). The preliminary findings of that inspection were discussed at an exit meeting on September 3, 1993.
At that time, the NRC raised concerns relative to procedure adherence and environmental factors involving the operability and functioning of the lC 125 volt batter Open Item Follow-up (Closed) Unresolved Item (50-272 and 311/93-19-01); Automatic Control Rod Inward Rod Movement. This item was opened in the last routine resident inspection report pending summator repair and completion of the licensee's root cause determinatio On July 22, 1993, during I&C troubleshooting, the licensee was able to identify a fault in the signal summator, which erroneously produced a high inward demand signal for a relatively small temperature error input. I&C technicians installed additional monitoring equipment to analyze summator input and output signals. Technicians performed a detailed inspection and bench calibration of affected modules (2TM412Q/2PC412 DIC). Internal components were inspected and repaired/replaced as needed. Technicians reinstalled all modules and fuses and performed a channel calibration. With the rods in manual, technicians continued to monitor summator input/output from August 6-9. Technicians noted no spiking during this time. At 9:00 a.m. on August 9, rod control was returned to automatic and the summator monitore The licensee monitored the rod control summator input/output for two days and observed no rod movement or channel spiking. On August 10, technicians removed all monitoring equipment from the summator cabine The inspector observed I&C troubleshooting, instrumentation monitoring, and rod control operations. The inspector noted good communication and interaction between I&C and operations. The inspector determined that the maintenance activity was well planned, properly supervised, and methodically executed. The inspector determined that the troubleshooting was sufficiently detailed and the corrective actions appropriate in identifying and rectifying the erratic automatic control rod movemen *
3.3.2 Hope Creek High Pressure Coolant Injection (HPCn Valve Inoperability On August 14, 1993, while conducting in-service test OPISBJ-101 for HPCI system valves, the HPCI-to-Core Spray injection valve, BJ-HV-F006, failed to fully stroke open when its open pushbutton was momentarily depressed. The crew opened the valve fully by holding down the open pushbutton. When they stroked the valve closed, however, the valve's thermal overloads tripped. Consequently, the crew declared the F006 valve, and therefore HPCI, inoperable. Since the valve also functions as a primary containment isolation valve, the operators complied with Technical Specification (TS) 3.6.3 and closed and deactivated the valve. The Maintenance Department repaired the valve and HPCI was declared operable on August 1 The inspector determined that the crew's operability determination and follow-up TS action were correct. The facility's maintenance activities with respect to repairing the F006 valve will be discussed in NRC Inspection Report 50-354/93-2 Spray Water Pump Impeller Failure On August 17, 1993, following completion of test OP-IS.EP-004(Q), "D Spray Water Pump Inservice Test," results indicated that the pump's performance was outside the acceptance range. For rated flow conditions, pump head was 37.8 psid compared to the allowable range of 39.1 - 42.8 psid. Because pump head was below the Action level, a work order was written against the spray pump. An inspection of the pump's impeller confirmed what the inservice test had indicated: The impeller was pitted, worn, and clearly the reason for degraded pump outpu Following the repair work, part of the retest included establishing new baseline date for pump performance. The system engineer entered this data into the computer bank associated with the "D" spray water syste The inspector concluded that the facility's Inservice Test Program had been effective in identifying a degraded component which needed to be replaced. Also, discussions held with the lead engineer for the spray wash system indicated the staff had a thorough understanding of pump performance and the applicable industry codes. The engineer displayed good familiarity with computer-based system performance data and was readily able to interpret pump data trend Repairs to Feedwater Heater Drain Valve On August 26, 1993, with the plant operating at 100%, feedwater heater drain valve AF-LV-1523A failed closed. The instrument and control technicians dispatched to troubleshoot the valve's failure determined that the valve's air operator had a failed solenoid. Subsequently,
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maintenance coordinated an evolution between the operations, chemistry, and radiation protection personnel to replace the solenoid to the air operator and then return the affected feedwater heater to servic The inspector concluded that maintenance's repair effort was efficient, sensitive to ALARA concerns, and well directed. Factors which contributed to the smooth evolution were the pre-staging of tools outside the heater bay and pre-rigging a ladder beneath the valve, a good pre-job briefing by the maintenance supervisor, and full time presence of the supervisor at the job sit.
ENGINEERING Salem Open Item Follow-up (Closed) Unresolved Item (50-272 and 311/93-08-02); Emergency Diesel Generator (EDG)
Cooling Water Flow Outside Design Basis. PSE&G performed an engineering evaluation to determine the impact of the error in the setpoint of the differential pressure controllers for the valves which modulate service water to the EDG jacket water coolers and lube oil coolers at both Salem units. The evaluation concluded that there was no degradation in EDG capabilities based on the cooling margin found to exist in the original design of the EDG The licensee therefore concluded that the Salem EDGs had always remained operable during times of high service water (i.e. Delaware River)* temperatures at all flow rates which may have resulted from the setpoint error. The inspector reviewed the licensee's engineering evaluation and discussed the issue with the responsible senior mechanical engineer from the PSE&G Engineering and Plant Betterment organization. The inspector found the evaluation to be properly conservative and accurate, and the licensee's EDG operability determination to be appropriate. The inspector therefore closed this ite.2 Hope Creek DC Powered Microswitch Replacement As a follow-up to licensee-identified deficiencies in a particular series of DC powered microswitches (NRC Inspection Report 50-354/93-11), the inspector reviewed the licensee's progress towards replacing the deficient switches. PSE&G has targeted December 1993 as the completion date for replacing all affected switches. To date, approximately 90 of 130
"non-Q" class switches have been replaced. The remaining 40 will be replaced when panels sensitive to the load on the grid can be opened, which should be early Fal With respect to the "Q" class switches, about 200 are also targeted for replacement by December 1993. Replacement switches are in stock, with the associated design change package completed. The licensee has established a priority schedule for switch replacemen Switch replacement is expected to start in mid-Septembe Engineering i§ meeting, or ahead of, their schedule for microswitch replacement. The inspector concluded that effective engineering management has been responsible for this project's good progres Vessel Water Level Instrumentation Modification In response to NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," PSE&G initiated steps to incorporate certain modifications to their vessel water level system. A letter from the facility to the Commission, NLR-N 93126, dated July 30, 1993, describes PSE&G's short term compensatory actions and the hardware modifications planned for the next cold shutdown. The inspector reviewed the facility's efforts to date, in particular the status of the non-outage hardware modification These modifications include the installation of four flow test stations (which set the trickle, or purge flow, into the respective reference line), and the associated piping and valves connecting these stations to the water level instrument lines and the control rod drive (CRD)
header. The inspector noted that the scheduled work is about 90 % complete, with full completion expected by mid-September when the remaining parts arrive. The actual tap into the CRD and water level instrument lines is scheduled for the outag The inspector noted that to date, the water level instrumentation modification has proceeded per engineering's schedule. The inspector also observed that the quality of the hardware installation has been high, based on no re-work being necessary. The inspector concluded that engineering's management of the modification has been strong and produced good result.
PLANT SUPPORT Radiological Controls and Chemistry 5.1.1 Inspection Activities The inspector verified on a periodic basis PSE&G' s conformance with the radiological protection progra.1.2 Inspections Findings - Salem The inspectors noted good performance by Salem Chemistry and Radiological Protection Department personnel in the implementation and conduct of routine radiological protection programs. No noteworthy specific findings were identifie *
5.1.3 Inspection Findings - Hope Creek Radiation Protection Support of Feedwater Heater Drain Valve Repair On August 27, 1993, the Maintenance Department repaired the air operator to a feedwater heater drain valve. This repair work required two men to work in a feedwater heater bay where the general radiation field at 100% power ranges from 150 mrem/hr to 500 mrem/h The Radiation Protection Department took several steps which helped to minimize the worker's exposure to this field. A ~rmanently installed camera in the heater bay was used to familiarize the work crew with the area. Detailed radiation survey maps of the area clearly showed local hot spots, and radiation protection coordinated with the Chemistry Department to reduce the hydrogen injection flow rate into the feedwater system just prior to the crew's entry into the heater bay, which greatly reduced the radiation field due to N-16 gamma The inspector observed these efforts to minimize the workers' exposure to radiation and concluded that the Radiation Protection Department performed well in supporting the maintenance repair work. Their precautions were a significant reason why the actual exposure for the competed job was 0.220 man-rem compared to the projected exposure of 0.800 man-re.1.4 Inspection Findings - Common Reduction in Thermo-luminescent Detector (TLD) Use On August 11, 1993, radiation protection services met with the NRC resident to discuss forthcoming changes in their dosimetry program. In August 1993, the Dosimetry Group in Radiation Protection Services began removing TLDs from the security badges of employees and contractors who have not made a radiologically controlled area (RCA) entry in 199 Removal of the TLDs will have no affect on site access outside of the RCAs. Dosimetry had made arrangements to allow for one-time RCA entries or more frequent access if necessary for these individuals. The licensee's plan is to simplify on-site access requirements while maintaining safe, reliable, high quality monitoring for those individuals requiring such services. The inspector noted that the licensee clearly communicated this plan to plant workers through articles in PSE&G's "Nuclear Today" daily newspaper and information notices to affected individual The Dosimetry Group's plan for the future includes further streamlining of the number of TLD's issued and processed, use of the Teledyne Isotopes Lab for TLD processing, and more reliance on electronic dosimetr The inspector reviewed the proposed program changes and determined that they were in accordance with the requirements of 10 CFR 20, "Standards For Protection Against Radiation," and there existed no adverse impact to plant or personnel safet.2 Emergency Preparedness 5.2.1 Inspection Activities The inspector reviewed PSE&G's conformance with 10 CFR 50.47 regarding implementation of the emergency plan and procedures. In addition, the inspector reviewed licensee event notifications and reporting requirements per 10 CFR 50. 72 and 7.2.2 Inspection Findings - Common Hurricane Emily Preparations During the week of August 23, 1993, hurricane Emily formed in the central Atlantic Ocean and headed toward the United States' eastern seaboard. PSE&G Site Protection and Emergency Preparedness (EP) personnel informed the NRC resident inspector on August 27, that they were tracking the storm and that the licensee would respond as appropriate if the hurricane neared Artificial Island. On August 30,. Hope Creek Operations implemented procedure HC.OP-AB.ZZ-0139(Q), "Acts of Nature," and Salem Operations implemented procedures Sl and S2.0P-AB.ZZ-000l(Q), "Severe Weather," in order to prepare the respective units for storm arrival. PSE&G EP coordinated the Artificial Island response to potential hurricane impingement, including removal of loose articles from the unit switchyards, the securing of site trailers and preparations for emergency response facility mannin Hurricane Emily eventually veered back into the Atlantic ocean without having any effect on the operation of either Salem or Hope Creek. The resident inspector monitored the licensee's preparations and determined that both plant staffs had properly and conservatively implemented their respective procedures. The inspector also noted that the PSE&G EP organization had functioned prudently and very well in the coordination of site activitie.3 Security 5.3.1 Inspection Activities The NRC verified PSE&G's conformance with the security program, including the adequacy of staffing, entry control, alarm stations, and physical boundaries. The inspectors observed good performance by Security Department personnel in their conduct of routine activitie.4 Fire Protection 5.4.1 Inspection Activities The inspector reviewed PSE&G's fire protection program implementation in accordance with nuclear department administrative procedures. Items included fire watches, ignition sources, fire brigade manning, fire detection and suppression systems, and fire barriers and door J. *
5.4.2 Inspection Findings - Salem Salem No. 2 Diesel Fire Pump Replacement PSE&G procured a new pump in July 1993 to replace the Salem No. 2 diesel fire pum The new pump was the same model which PSE&G had used to replace the failed Salem N diesel fire pump in April 1993 (see NRC Inspection Reports 50-272 and 311/92-07 and 93-15). The licensee implemented design change package (DCP) 1EC3217, Package 2, and installed and tested the new diesel fire pump through the month of August. When final DCP acceptance testing had been satisfactorily completed, the No. 2 diesel fire pump was turned over to Salem operations and declared operabl The resident inspector reviewed the DCP and monitored the installation and testing of the new fire pump. The inspector determined that the licensee's effort to replace both Salem diesel fire pumps with new, identical-model pumps was prudent and should improve the maintainability and availability of the station's fire pumps. The inspector noted good coordination between PSE&G Engineering and Site Protection personnel during the installation of the new fire pump and observed that the testing of the new pump was satisfactorily performe.5 Safety Assessment and Quality Verification 5.5.1 Salem Salem General Manager "State-of-the-Station" Presentation The General Manager - Salem Operations (GM) presented his annual "State-of-the-Station" presentations to all Salem station employees on August 4, 1993. The Salem GM discussed the disappointing aspect of several operational events which have occurred at Salem, including three NRC Augmented Inspection Teams in an 18 month period and the six reactor trips which had occurred thus far in 1993. The presentation also included the positive performance of the Unit 2 seventh refueling outage and actions PSE&G is taking to further improve Salem units' performance. The GM ended the presentation by reinforcing the value of the PSE&G Quality Assurance/Nuclear Safety Review organization and then by entertaining questions from the employee The resident inspector reviewed the GM's presentation material in advance and attended one of his sessions with Salem employees. The inspector found the GM to be frank and open in his discussion with Salem personnel and in response to their questions. The inspector further determined the "State-of-the-Station" forum to be an effective means for Salem management to elicit improved performance and resolve employee questions and concern *\\..
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5.5.2 Common PSE&G Employee Concern Programs The Energy Reorganization Act, Section 211, and Part 10 of the Code of Federal Regulations, Paragraph 50. 7, prohibit employers from discriminating against employees for raising safety issues to the NRC or its licensees. On July 29, 1993, the NRC issued Temporary Instruction (TI) 2500/028, "Employee Concerns Program," to the NRC Inspection Manual. The NRC issued the TI to determine the characteristics of employee concerns programs that licensees use to provide employees who wish to raise safety issues an alternate path from their normal line management to express the issues without fear of retributio The resident inspector determined that PSE&G maintains a number of programs at Salem and Hope Creek to address employee concerns. The two primary programs the licensee maintains for the resolution of nuclear safety concerns are _the Quality Concern Reporting System (QCRS) and the Human Performance Enhancement System (HPES). Both of these programs operate as part of the PSE&G Quality Assurance/Nuclear Safety Review (QA/NSR) Department and are independent from any line organization at either Salem or Hope Creek. In addition to the QCRS and HPES, PSE&G has other programs that also respond to employee concerns: Quality Improvement Committee (non-safety issues);
Employee Industrial Relations (labor relations and union grievances); Safety Hazard Reporting System (industrial safety program); and "Miss Peggy" (a question and answer forum in the PSE&G corporate newspaper).
The NRC inspector focused the inspection effort on the QCRS and HPES by reviewing the licensee procedures which govern the programs, discussing the programs with the General Manager - QA/NSR and members of his staff, and interviewing a number of licensee employees at Salem and Hope Creek to sample the employees' feelings about the program The inspector concluded that PSE&G has provided very good programs for their employees to raise safety concerns to the appropriate licensee management level without fear of *
retribution for doing so. The inspector further determined that these programs are well-staffed and properly managed. The inspector documented the details of the inspection in an attachment to TI 2500/028. The completed attachment is included with this repor Response to Technical Specification Action Requirements As detailed in Sections 2.2.1 A and B, two instances were noted this period involving inappropriate and non-prompt response to indications involving deficient performance or operability of systems described in the technical specifications. While the licensee initiated proper corrective actions for each of these particular instances, the findings may indicate a potential weakness relative to recognition and proper response to deficient conditions and situations. Though these failures, relative to technical specifications, appear to be isolated
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and not programmatic, the findings are similar in nature to other previous instances of inappropriate and non-prompt event response that required substantial licensee management attention to rectify. The current findings warrant continued licensee attention to this are.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLWW-UP LERs and Reports PSE&G submitted and reviewed for accuracy and evaluation adequacy the following special and periodic report *
Salem and Hope Creek Monthly Operating Reports for July 1993 The inspector concluded that the licensee appropriately issued the above report Salem LERs Unit 1
LER 93-13 discussed a reactor trip on No. 14 steam generator low level coincident with steam flow/feed flow mismatch. The licensee submitted this LER on August 13, 1993. The report was required by 10 CFR 50. 73(a)(2)(iv) to be submitted by August 10, 1993. NRC Region I granted the licensee an extension per teleconference on August 10, 1993, due to a licensee desire to incorporate late breaking information into this LER. The inspector reviewed the reactor trip in NRC Inspection 50-272/93-19. The inspector discussed the technical specification noncompliance associated with this event in Section 2.2.1.A of this report. The inspector closed this LE *
LER 93-14 described the licensee's determination that both Salem units' 4 kv vital bus second level undervoltage protection setpoints may not be satisfactorily conservative. This event was described in NRC Inspection Report 50-272 and 311/93-18 and remains a NRC Unresolved Item. PSE&G stated in the LER that a supplemental report will be submitted upon completion of their engineering analysi The inspector determined the LER adequately described the circumstances of the event, but the LER will remain open pending the submittal of the LER supplemen Unit 2
LER 93-10 described three separate circumstances where the licensee was required to enter Technical Specification 3.0.3 due to the inoperability of more than one control rod analog rod position indicator (ARPI). In all three cases, the ARPI inoperability was declared due to at least one rod group's ARPI indication drifting too far from the
- group demand counter reading, and.in all three cases, the TS 3.0.3 shutdowns were terminated due to operators restoring the ARPI indication to within specification prior to the TS expiration. PSE&G determined the root cause of the ARPI drifting was the system design, a problem being addressed by an industry user's group. The LER stated that PSE&G will take corrective action based on the user's group recommendations. The inspector reviewed the LER, determined it adequately described the three events and their cause, and noted the licensee's actions to be appropriate. The inspector therefore closed the LE Hope Creek None Open Items The inspector reviewed the following previous inspection items during this inspection. These items are tabulated below for cross reference purpose and 311/93-19-01 50-272 and 311/93-08-02 Hope Creek None Report Section 3.3...
EXIT INTERVIEWS/MEETINGS Resident Exit Meeting Closed Closed The inspectors met with Mr. C. Vondra and Mr. R. Hovey and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activitie Based on NRC Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.
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7.2 Specialist Entrance and Exit Meetings Date(s)
8/16-20/93 and 8/30-9/3/93 Inspection Subject Report N Electrical 50-272 and 311/93-82 Distribution System Functional Inspection Reporting Inspector Cheung
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Attachment EMPLOYEE CONCERNS PROGRAMS PLANT NAME: Salem/Hope Creek LICENSEE: PSE&G DOCKET#: 50-272, 311 & 354 NOTE: Please circle yes or no if applicable and add comments in the space provide PROGRAM: Does the licensee have an employee concerns program?
(Yes/Comments)
See comment 1 on the last page of this attachmen.
Has NRC inspected the program? (No) SCOPE: (Circle all that apply) Is it for: Technical? (Yes) Administrative? (Yes) Personnel issues? (Yes) Does it cover safety as well as non-safety issues?
(Yes) Is it designed for: Nuclear safety? (Yes) Personal safety? (Yes) Personnel issues - including union grievances?
(Yes/Comments)
QCRS & HPES handle personnel issues but not union grievances, which are covered by Employee Industrial Relation.
Does the program apply to all licensee employees?
(Yes) Contractors?
(Yes) Does the licensee require its contractors and their subs to have a similar program?
(No/Comments)
7.
All contractors are free and encouraged to use the licensee's QCRS and HPE Does the licensee conduct an exit interview upon terminating employees asking if they have any safety concerns?
(Yes)
Issue Date: 07 /29/93 A-1 2500/028 Attachment
.... INDEPENDENCE: What is the title of the person in charge?
General Manager - Quality Assurance/Nuclear Safety Review (GM-QA/NSR). Who do they report to?
Vice President and Chief Nuclear Office.
Are they independent of line management?
Ye.
Does the ECP use third party consultants?
N.
How is a concern about a manager or vice president followed up?
Concerns are escalated to the next organizational management level for investigation and resolutio RESOURCES: What is the size of the staff devoted to this program?
QCRS - licensee staff directed as necessary by QCRS Coordinator to respond to concern HPES - currently one HPES Group Head and two HPES staff engineer.
What are ECP staff qualifications (technical training, interviewing training, investigator training, other)?
BS degree in engineering discipline, INPO HPES Evaluator training, Root Cause training,
"Managing with People" trainin REFERRALS: Who has followup on concerns (ECP staff, line management, other)?
HPES or QA engineer (ECP Staff); licensee management if concern is escalate CONFIDENTIALITY: Are the reports confidential?
(Yes) Who is the identity of the alleger made known to (senior management, ECP staff, line management, other)?
(if other explain)
GM-QA/NSR, QCRS Coordinator, and appropriate QA or HPES enginee /028 Attachment A-2 Issue Date: 07 /29/93 Can employees be: Anonymous? (Yes) Report by phone? (Yes/Comments)
Licensee has a dedicated "Hotline" number with recording backu FEEDBACK: Is feedback given to the alleger upon completion of the followup? (Yes - If so, how?)
Letter from GM-QA/NSR and a response form for QCRS; written report from HPE.
Does program reward good ideas?
N.
Who, or at what level, makes the final decision of resolution?
Responsible licensee General Manage.
Are the resolutions of anonymous concerns disseminated?
QCRS - N HPES - Yes, all concern resolutions are disseminate.
Are resolutions of valid concerns publicized (newsletter, bulletin board, all hands meeting, other)?
QCRS - N HPES - Yes, through written report dissemination and incorporation into Operating Experience Feedback progra EFFECTIVENESS: How does the licensee measure the effectiveness of the program?
No formal measures; concerns are resolved to the satisfaction of the alleger and the HPES or QA enginee.
Are concerns: Trended? (No) Used? (Yes) In the last three years how many concerns were raised? QCRS - 112; HPES - 7 Of the concerns raised, how many were closed? QCRS - 111; HPES - 5 What percentage were substantiated? QCRS - none; HPES - 92 %.
Issue Date: 07 /29/93 A-3 2500/028 Attachment
1 ** How are followup techniques used to measure effectiveness (random survey, interviews, other)?
No formal followup techniques employed by licensee; HPES engineers meet with individual work groups and relevant comments and suggestions are acted o.
How frequently are internal audits of the ECP conducted and by whom?
Both HPES and QCRS were individually audited in 1993 by the QA Audits Group. Such audits are routinely performed every two year ADMINISTRATION/TRAINING: Is ECP prescribed by a procedure? (Yes) How are employees, as well as contractors, made aware of this program (training, newsletter, bulletin board, other)?
General Employee Training, licensee company newspapers and newsletters, concern submittal forms posted throughout the plan ADDITIONAL CO:Ml\\fENTS: (Including characteristics which make the program especially effective, if any.) Answers in this attachment refer to the licensee's Quality Concern Reporting System (QCRS) and Human Performance Enhancement System (HPES). The licensee has other programs that also respond to employee concerns: Quality Improvement Committee (focuses on non-safety issues); Employee Industrial Relations (employee labor relations and union grievances); Safety Hazard Reporting system (industrial safety program); and
"Miss Peggy" (a question and answer forum in the company newspaper).
These programs are mentioned in the attachment, where necessar NAN.lE: Stephen Barr TITLE: Sr. Resident Inspector (Acting) PHONE #: (609)935-3850 DA TE COMPLETED: 9/8/93 2500/028 Attachment A-4 Issue Date: 07 /29/93