IR 05000272/1987007
| ML18092B515 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 04/02/1987 |
| From: | Norrholm L, Roxanne Summers NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18092B514 | List: |
| References | |
| 50-272-87-07, 50-272-87-7, 50-311-87-08, 50-311-87-8, NUDOCS 8704140456 | |
| Download: ML18092B515 (21) | |
Text
Report No * Docket No License No Licensee:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/87-07 50-311/87-08 50-272 50-311 DPR-70 DPR-75 Public Service Electric and Gas Company 80 Park Plaza Newark, New Jersey 07101 05000272-870312 05000311-870312 Facility Name:
Salem Nuclear Generating Station - Units 1 and 2 Inspection At:
Hancocks Bridge, New Jersey Inspection Conducted:
February 24, 1987 - March 23, 1987 Inspectors:
Reviewed by:
Approved by:
Inspection Summary:
Kenny, Senior Resident Inspector Gibson, Resident Inspector DRP C ief, Reactor Projects Projects Branch No. 2, DRP YfLs2 da e u;,* In
~
Inspections on February 24, 1987 - March 23, 1987 (Combined Report Numbers 50-272/87-07 and 50-311/87-08)
Areas Inspected:
Routine inspections of plant operations including: opera-tional safety verification, maintenance, surveillance, review of special reports, regional and 2515 program temporary instructions, allegation followup, site meetings, and a management chang The inspection involved 140 inspector hdurs by the resident NRC inspector Results:
Unit 2 experienced a reactor trip and one violation was identified by the licensee during this report perio These events are described in Section 2 of this repor There were two meetings with regard to the 500KV electrical system at Artificial Island as discussed in Section 7 of this repor PDR ADOCK 05000272 a
- DETAILS Persons Contacted Within this report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspection activit.
Operational Safety Verification 2.1 The following documents.were reviewed:
Selected Operators' Logs; Senior Shift Supervisor's (SSS) Log; Jumper Log; Radioactive Waste Release Permits (liquid & gaseous);
Selected Radiation Work Permits (RWP);
Selected Chemistry Logs; Selected Tagouts; and, Health Physics Watch Lo.2 The inspector conducted routine entries into the protected areas of the plants, including the control rooms, Auxiliary Building, fuel buildings, and containments (when access is possible).
During the inspection activities, discussions were held with operators, technicians (HP & I&C), mechanics, supervisors, and plant managemen The purpose of the inspection was to affirm the licensee's commitments and compliance with 10 CFR, Technical Specifications, and Administrative Procedure. On a daily basis, particular attention ~as directed to the following areas:
Instrumentation and recorder traces for abnormalities; Adherence to LCO's directly observable from the control room; Proper control room shift manning and access control; Verification of the status of control room annunciators that are in alarm;
.
Proper use of procedures; Review of logs to obtain plant conditions; and,
2.. Verification of surveillance testing for timely completio On a weekly basis, the inspector confirmed the operability of selected ESF trains by:
Verifying that accessible valves in the flow path were in the correct positions; Verifying that power supplies and breakers were in the correct positions; Verifying that de-energized portions of these systems were de-energized as identified by Technical Specifications; Visually inspecting major components for leakage, lubrication, vibration, cooling water supply, and general operating conditions; and, Visually inspecting instrumentation, where possible, for proper operabilit On a biweekly basis, the inspector:
Verified the correct application of a tagout to a safety-related system; Observed a shift turnover; Reviewed the sampling program including the liquid and gaseous effl~ents; Verified that radiation protection and controls were properly established; Verified that the physical security plan was being implemented; Reviewed licensee-identified problem areas; and, Verified selected portions of containment isolation lineu.3 Inspector Comments/Findings:
The inspector selected phases of the units operation to determine compliance with the NRC 1 s regulation The inspector determined that the areas inspected and the licensee's actions did not
constitute a health and safety hazard to the public or plant personne The following are noteworthy areas the inspector researched in depth:
Unit 1 Unit 1 began this report period at 100% powe On March 1, 1987, the island lost the 500 KV Keeney transmission line {5015) which connects Hope Creek Generating Station with the State of Delaware across the Delaware Ba The loss of the line forced all the generating units of Artificial Island to reduce power to 75%
in order to stay within the stability limits of the 500KV electrical grid in the northeast secto The unit was reduced to 75% power on March 2, 198 On March 8, 1987 at 11:47 p.m., the unit was removed from service to repair rod drive vent fans, re-connect No. 1 auxiliary power transformer and complete other smaller repairs to the uni The unit was in Mode 3 at 6:00 a.m. on March 9, 198 On March 10, 1987, No. lF Group B~s was takeri out of s~rvice in support of work on No. 12 Station Power Transforme The 115VAC Control Center failed to transfer to its alternate~
power supply, the 2H Group Bus, resulting in a loss of control power to the auto-start initiation logic for both diesel driven fire pump Both diesel fire pumps started on loss of AC power to the auto start initiation logic, and an alarm was received in the control roo When station personnel investigated the alarm, they found the diesel fire pumps operating and notified the control room of the situation. *The fire pumps were stopped, then placed in manual control to prevent unnecessary operation. *An operator was stationed in the fire pump house to monitor proper fire suppression header pressure and start the fire pumps if necessar Site maintenance was notified of the failure of the 115VAC Control Center to swap to its alternate power sourc The licensee made the necessary notification in accordance with Technical Specifications. The repairs were made and the system ~as returned to servic On March 12, 1987 at 11:00 a.m., a licensee radiation protection technician identified a normally required locked, High Radiation Area (greater-than 1000 mrem/hour) door, for the Unit No. 1 bioshield area, propped open with a yellow anti-c booti The door had been previously verified locked closed by radiation protection personnel at approximately 9:00 that morning:
As a result, the licensee's management took the following corrective actions: Checked all locked H1gh Radiation Area doors in both Units 1 and No other deficiencies were foun.
Reviewed PREMS (computeriied access and exposure monitoring system) and Radiation Work Permit (RWP) data and identified six (6) personnel who had been in the bioshield area between 9:00 a.m. and 11:00 One of the six was the technician who identified and reported the deficienc Access to the Auxiliary Building for the six individuals was administratively barred (via PREMS) until the licensee's investigation was complet.
The thermoluminescent dosimeters (TLD) worn by the six were processed and no excessive or unusual exposures were identifie.
Each of the six were interviewed and counseled by radiation protection management as to the requirement and importance of keeping High Radiation Area doors locke None of those interviewed admitted propping the door open.
It was also determined that no one was in clear sight of the door while it was ope.
Distributed a letter to station managers concerning the issue, which was to be discussed with their personnel at the next safety meetin In addition, the Salem General Manager discussed the incident with the six individuals and placed a letter describing the incident into each person's personnel fil Failure to maintain a High Radiation Area door locked is a violation of Technical Specification 6.1 (50-272/87-07-01)
. However, in accordance with 10 CFR 2, Appendix C, a notice of violation is not being issued since this violation meets all of the following criteria: It was identified by the licensee; It fits in Severity Level IV or V; It was reported to the resident inspectors; It was corrected, including measures to prevent recurrence, within a reasonable time; and
- It was not a violation that could reasonably be expected to have been prevented by the licensee 1s corrective action for a previous violatio The inspector reviewed the licensee 1 s corrective actions and considers this item close On March 16, 1987 at approximately 1:00 p.m. during plant startup, a leak was identified by the secondary plant operator, on No. 12 steam generator feed pump (SGFP)
recirculation line to the condense No. 11 SGFP was placed in service and the leak was isolate The recirculatton line is only in service during startup or trip of the uni The break in the line occurred at a point where erosion had thinned the section of pipin Thinning had been identified in this area by the licensee previously, but the UT method of identification was performed on quadrants other than where the break occurre The erosion was localized to about a one inch strip near the bottom of a six inch header, downstream of an orific Because of the previously
identified thinning in the area, the licensee had issued Design Change Requests 2SM00192 for Unit 2 (issued December 19, 1986) and 1SM00201 for Unit 1 (issued February 12, 1987).. These requests were to disposition a Deficiency Report which identified the thinnin The design change on Unit 1 was scheduled for the next refueling outage and the piping was to be replaced with chrome-molly stee (See Section 3 of this report for more details.)
On March 19, 1987, the licensee was going to perform a hydro-static test on a section of Auxiliary Feedwater (AFW) piping in accordance with Section XI of the ASME cod After the operations department isolated the section of piping, five hours passed before the test technicians arrived at the N AFW pump and found that one of the gages on the suction side of the pump was pegged high (600#).
The technicians removed the gage and replaced it with a test gage and read a ~ressure of 900 pound (The suction piping is schedule 40 piping rated for 195 psig).
The pressure was relieved and an investigation was starte The results of the investigation were: The overpressure condition happened because check valves in the AFW system leaked by, which caused the main feed system to pressurize the piping back through the No. 11 AFW pump to the suction isolation valv The licensee has been monitoring this piping for steam binding in the AFW system, but has never seen temperatures greater than 12 degrees F within the piping, which indicated that the leak was small. It was also calculated that, over a five hour period, about one quart of water leaked by the check valve *
6 Magnetic particle testing was performed on all the welds that were subjected to the overpressur No cracks or weld failure indications were identifie.
Stress calculations were performed on the p1p1ng, The calculations indicate that all components were within their stress 1 imi t.
The licensee contacted the pump manufacturer who stated that the pump seals were the only vulnerable component of the pump. The seals were designed for a pressure of 1000 ps.
The licensee contacted the valve manufacturer who stated that, if the valves could be manipulated and if there was no physical damage, they were all righ The valves were inspected and cycle.
The licensee is investigating to identify what procedures and measures will have to be taken to preclude similar incident The resident inspector has examined the documents related to the licensee's investigation and has no further questions at this tim The pump was tested and returned to service on March 20, 1987 at 3:37 On March 27, 1987, No. 11 SGFP was returned to service and the unit power was increased to 71%, 790 MWe (maximum generation with the Keeney 500KV line out of service).
Unit 2 The unit began this report at 100% powe On March 1, 1987, the unit power was reduced to 75% due to the loss of the 500KV Keeney lin On March 12, 1987 at 9:30 a.m., the unit tripped from 100%
power on an indicated 11Generator Differential or Loss of Field
which tripped the turbine and the reacto The direct cause of the trip was loss of the generator field when the field breaker opene All systems functioned as designe Curves and recordings showed that the unit was operating within the design range of the voltage regulato The licensee began an investigation into the trip with the following results:
- 7 All relays and circuits associated with the voltage regulator, both de-energized and energized, were teste In addition, related control room annunciators were teste The testing indicated that the equipment associated with the voltage regulator was not the direct cause of the field breaker openin.
After a meeting with the SORC and members of the test group, plant management determined that the probable cause for the trip was the operation of the generator with too much 11out 11 vars (volts-amps-reactive, causing an over excited generator), which had been ordered by the system load dispatche The amount of vars was within the operating curves supplied by the generator manufacture.
The generator operating curves were re-issued and a restriction of 400 11out 11 vars. has been established as a maximum continuous limi On March 14, 1987 at 9:47 a.m., the unit was returned to servic No further problems with the field breaker or main generator were encountere The unit was operatin~ at 72%
power with 790 MWe at the close of this report perio.
Maintenance Observations The inspector reviewed the following safety related maintenance activity to verify that repair:s were made in accordance with approved procedures and in compliance with NRC regulations and recognized codes and standard The inspector also verified that the replacement parts and Quality Control utilized on the repairs were in compliance with the licensee's QA progra During Unit 1 startup on March 16, 1987 at ap~roximately 1:00 p.m.,
the licensee identified a leak on N~. 12 steam generator feedpump (SGFP) recirculation line to the condense The leak resulted from a 1/2 inch by 1 inch hole in the piping near a carbon to carbon weld located between a stainless steel flow restricting orifice and valve 12BF31 (see Attachment 3 to this report).
The piping is 6 inch A106 Grade B carbon steel with 0.432 inch nominal wall thicknes The break in the pipe occurred where erosion had thinned the pipe near the weld backing ring which protruded into the pip Although thinning in the recirculation piping had been identified previpusly by the licensee (discussed in Inspection Report 50-272/86-32; 50-311/86-36), the section between the carbon to carbon weld and carbon to stainless weld had not been inspecte Upon discovery of the leak, immediate actions by the licensee included shifting to No.. 11 SGFP and isolating the leaking recirculation line.
Further licensee actions included:
- ..
5.
Cut out the section of pipe, as shown on attachment 3, for analysis to determine metallurgical root cause of the failur The metallurgical laboratory's preliminary assessment of the cause was water impingement erosion as evidenced.by flow disturbances indicated by swirl patterns _observed through an etching techniqu Performed ultrasonic (UT) inspection of No. 11 SGFP recirculation pipin The minimum wall thickness was identified as 0.360 i"nches (localized area).
This has been determined acceptable by the licensee in their engineering analysi Performed UT inspection of Unit 2 SGFP recirculation line These lines do not have an orifice,-however the BF 32 valves are throttled to effectively act as an orific Results indicate a minimum wall thickness of 0.305 inches (localized area at the valve).
This also was determined as acceptable by the licensee through their engineering analysi Qualified a welding procedure for A106 carbon to 410 stainless stee Welded in new A106 p1p1ng as shown on attachment The inspector noted that the backing ring technique was not used because the licensee believed that the backing ring of the previous weld protruding into the piping may have contributed to the thinnin The following data represents the normal operating conditions of the SGFP recirculation lines which are in operation (BF 31 valve open)
only during startup and following a trip; Chemistry pH:
Dissolved Oxygen:
Hydrazine!
Cation Conductivity:
Specific Conductivity:
Ammonia:
Chloride:
Sulfate:
Sodium:
Potassium:
Calcium:
Magnesium:
Iron:
Copper:
8.8-less than 5ppb 30ppb 0.06 micro-mho 2.5 micro-mho 0.25 ppm less than 0.1ppb less than O.lppb less than O.lppb less than O.lppb less than 0.lppb less than 0.lppb less than 4ppb*
less than 1.0ppb
Velocity 0 ft/sec - 28 ft/sec @ shutoff head, with discharge valve closed; nominally 12 ft/se Temperature Range Startup:
Trip:
Operation 100 Degrees F - 200 Degrees F 400 Degrees F - 100 Degrees F Unit 1 for 1 year period - approximately 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />s/pump on recir-culation flow pat The inspector monitored the licensee's progress during replacement of the piping and testing of the other pump and unit recirculation pipin In addition, the following documents were reviewed:
Code Job Package No. 2-87-060; Deficiency Report No. SSP-87-049; Work Order No. 870316027; Welding Procedure Specification NDWP-13; (SA-106 Grade B to SA-106 Grade B)
Welding Procedure Specification NDWP-11; (SA-240 Type 410 to SA-106 Grade B)
Procedure Qualification Record No. PQ 141; Weld Map for DR No. SSP-87-049; Weld History Records; M-Sl-FWR-12-19-A M-Sl-FWR-12-20-A M-Sl-FWR-TDWJN-171 M-Sl-FWR-TDWJN-172 M-Sl-FWR-TDWJN-173 Code Job Package Approval Cover Sheet;
)
Maintenance Instruction A-28 11Department Control of Code Work11 ;
Inspection Point Checklist; and, Hot Work Permit (Hot Work Nos. 587-0317001 and 587-0320004).
No violations were identifie The metallurgical laboratory's report will be reviewed by the inspector upon receipt from the license.
Surveillance Observations During this inspection period, the inspector reviewed in-progress surveillance testing as well as completed surveillance test package The inspector verified that the surveillance tests were performed in accordance with licensee approved procedures and NRC regulation The inspector also verified that the instruments used were within calibration tolerances and that qualified technicians performed the surveillance test The following surveillance tests were reviewed:
4.1 Unit 1 Work Order Number 80320020 870322034 870322035 Procedure lPD-16.3.007 lPD-4.2003 lPD-4.2.004 Description Nuclear Instrumentation System/Power Range Channel 1N41 Calibration Check Radiation Monitoring System - Channel Functional Tests, 1-R5 Refueling Building Area Radiation Monitor (ARM), 1-R9 Fuel Storage Area ARM Also, the inspector witnessed portions of a flux map on Unit 1 per Reactor Engineering Manual Part 12 - Flux Mapping Procedures and Reactor Engineering Manual Part 13 - Incore Flux Mapping System Operatio During power up of the incore instrumentation, the licensee discovered that the detectors would not mov Investigation by the licensee revealed that the six drive unit breakers had not been closed following the recent Unit 1 mini-outage in which detector 11D 11 was replace A containment entry was made, the breakers returned to the operable condition, and the flux map complete Entry into the seal table room is controlled by use of a key which will allow the door to be unlocked only when the six drive unit keys are correctly positioned and the six corresponding breakers are ope Repositioning of the drive unit keys and breakers may have occurred several times during the mini-outage by several station groups including Radiation Protection, Reactor Engineering, ISI and Operations
in order to facilitate seal table entries and flux drive testin However, it appears that the responsibility for ensuring that the drive unit keys and breakers are returned to operable condition prior to startup is not define For ALARA considerations, in that an unplanned at power containment entry was required to close the breakers, the inspector is concerned that this responsibility has not been defined.
. The inspector discussed the concern with licensee managemen The licensee is developing a checklist system requiring sign-offs for each entry.and exit from the seal table roo The licensee is also considering several other options to ensure the flux drives are operable prior to startu The inspector will review the controls when implemente.2 Unit 2 Work Order Number 870201002 4.3 Unit 1 and 2 Procedure MlO-SST-028..:2 Description Fire Damper Functional Test (18 Mo.) - The inspector witnessed testing both from the control room and in the field.
TI 2515/64, Rev. 1, Near Term Inspection Followup to Generic Letter 83-28 11 Required Actions Based on Generic Implementation of Salem ATWS Events
Item 04.05b of the TI requires verification of the licensee's performance of surveillance testing of the shunt trip attachment and manual trip capability for the RTS breaker The inspector reviewed the following licensee procedures and has previously witnessed portions of these test lIC-18.1.006 2IC-18.l.006 lIC-18.1. 007 2IC-18.l.007 Solid State Protection System Reactor Trip -
Breaker and Permissive P-4 Test Prior to S/U
- Train A Solid State Protection System Reactor Trip -
Breaker and Permissive P-4 Test Prior to S/U
- Train B
-*
lIC-18.1.010 2IC-18.l.010 12.
Functional T~st, SSPS - Train A Reactor Trip Breaker UV Coil and Auto Shunt Trip lIC-18.1.011 2IC-18.1.011
- Functional Test, SSPS - Train B Reactor Trip Breaker UV Coil and Auto Shunt Trip The inspector concluded that the necessary surveillance tests are in place to satisfy the concerns of Item 04.05b of the T.4 During the review of Pressurizer Overpressure Protection System, surveillance tests performed on the system for both units were reviewe (See section 6 for details)
The inspector concluded that the systems on both units function as designe No violations were identifie.
Review of Periodic and Special Reports Upon receipt, the inspector reviewed periodic and special report The review included the following:
inclusion of information required by the NRC; test results and/or supporting information consistent with design predictions and performance specifications; 'planned corrective action for resolution of problems, and reportability and validity of report informatio The following periodic reports were reviewed:
Unit 1 Monthly Operating Report -
February 1987 Unit 2 Monthly Operating Report -
February 1987 No violations were identifie.
Regional and 2515 Program Temporary Instructions (TI's)
6.1 TI-RI-86-02 - Subject:
Inspection of General Electric Type AK-F-2-25 Breaker The resident has determined that this type of breaker is not used at Salem Statio *
6.2 TI 2515/64 Subject:
Near Term Inspection Followup to Generic Letter 83-28 "Required Actions Based on Generic Implementation of Salem ATWS Events.
- See Section 4.3 for detail.3 TI 2515/19 Subject:
Reactor Vessel Transient Pressure Protection for PWR's.
- 6.3.1 Background The Pressurizer Overpressure Protection System (POPS) was installed to mitigate the severity of low-temperature overpressure transient conditions in a pressurized water reacto Based on nuclear
-
industry operating experience these transients had usually occurred during startup or shutdown operations when the reactor coolant system (RCS) was in a water-solid condition (with no steam bubble in the pressurizer). During this condition minor changes in RCS temperature and/or related systems pump starts can create major pressure transient The operating nuclear power plants were required to install the POP Salem Station installed the systems as follows:
The Unit 1 system was installed in 1977-78 and the Unit 2 was installed during con-structio Unit 1 design (explained later) was installed on the existing power operated relief valves (PORV 1s).
Unit 2 1 s design differed in that parallel valves (Marrotta) were installed fQr the purpose of the low temperature relief functio Both units* relief systems were installed such that the overpressure relief function was aided by a relief valve in the RHR pump suction pipin The setpoint of this valve was then reduced from the original design of 425 psig to 375 psi This arrangement has been evaluated in the 50.59 review and safety analysi.3.2 Inspection The inspector reviewed the documents listed in Attachment 2 of this repo~t and noted that the design of Unit 1 was installed on the existing PORV's and must be armed by the operators utilizing key switches, in the control room, during plant cooldow Once enabled, the system is fully automati Unit 2 wa~ designed utilizing Marrotta valves in parallel with the PORV 1 s, to relieve pressure transient However, the operator still had to manually enable the system during cooldow This is contrary to the direction given for plants licensed after April 18, 198 The inspector determined, after a review of the Safety Evaluation Report (SER) and discussions with NRC-Office of Inspection and Enforcement, that, since the design was initiated prior to April 18, 1980, the manual feature was allowed as was discussed in the SE The licensee has since determined that the Marrotta valves were very difficult to keep operational and had caused inability to shut down Unit 2 in an orderly manne They also made restart of the ~nit difficul In addition, an incident occurred (a stuck open Marrotta valve, reference LER 84-18, 50-311)
which caused a safety injection and a difficult plant shutdow As a result the Unit 2 system was redesigned in September, 1983 to be like Unit 1 and is currently operating in that configuratio The inspector has determined the following with regard to the Unit 1 and 2 POPS:
-
The design meets or exceeds the requirements of Appendix G of 10 CFR 50 and there are drawings.depicting the desig The design also meets the single failure criteria for electrical and mechanical system *
A backup air supply system, in excess of the recommended 10 minutes, is provided for PORV operation in the event the station air system is los A 10 CFR 50.59 evaluation was performed and all setpoints and postulated accidents were considered, including calculations for opening times over temperature ranges likely to be seen in a startup or shutdown conditio Procedures are in place to minimize both time in water-solid conditions and the temperature differential between steam generators and the reactor vessel while in a water-solid condition; and, to restrict pump starts during water-solid condition Alarms are in place to alert operators, during plant cooldown, to the need for the POPS and procedures are in place to test the system prior to placing it in servic There are also alarms to alert the operator if a pressure condition is approaching the relief valve setpoints while POPS is in servic The operators have received training on the above procedures and design changes.
The systems were installed in accordance with station approved procedures and construction practice There are surveillance procedures in place to test the system in accordance with Technical Specification.3.3 Conclusion The inspector concludes that both units have an operable POPS and has no further questions at this tim No violations were identifie.
Allegation Followup Region I received an allegation from an individual who was briefly employed by a contractor at Sale He alleged that he was originally hired to do work which involved no radiation exposur But upon arrival at the site, he was reassigned to work in a radiation are The inspectors determined that the individual received approximately 20-30 millirem exposure while at Salem, which is within the 10 CFR 20 and licensee's administrative exposure limit Region I referred the alleger to the U.S. Department of Labor since the concern appears to be a labor issu *** *
Site Meetings Two meetings on the Salem electrical distribution system were held during this report perio The following are summaries of these meeting The attendees at both meetings are listed in Attachment l'of this repor.1 An NRC/PSE&G meeting was held on Februa,ry 24, 1987 to discuss the licensee's short and long term corrective actions pertaining to the Salem 4KV electrical distribution system as a result of the August 26, 1986 false loss of offsite power even The meeting discussion included:
the root cause of the August 26 event, review of the PTI (licensee consultant) model and validation,
.short term relay scheme modification, and status of the long term electrical stud The licensee has identified the root cause of the AtJgust 26 vital bus 11 fl ip-flopping 11 between the station power trans-formers ( SPT) to be the failure of the 11A 11 91% transfer relay on the No. 22 SPT to reset at the 95% valu The licensee's short term relay scheme modification consists of eliminating the 91% transfer relays on the SPTs, adding three 91% undervoltage (UV) relays on each vital bus and reducing the reset value to 92.25%.
The long term study is projected to be complete in July 198 The licensee has committed to include, with their February update letter for NRC ~eview, a Justification for Continued Operation for the revised relay scheme and a return to normal auxiliary power transformer configuratio.2 An NRC/PSE&G meeting was held on March 10, 1987 to discuss the licensee's actions and plans regarding the loss of the 500KV Keeney line which occurred on March 1, 1987 when an oil tanker had a collision with two of the towers which support the lin The line was severed and is inoperabl During the course of the meeting the licensee discussed the following agenda:
Problem Description Generalized Stability Analysis Hope Creek/Salem Stability Guidance Analytical Techniques Available Models Model Comparison
Future Operational Options Remain at Reduced Power Restore SOOKV Circuit Unit Trip Stability Protection Schedules Degraded Grid Submittal The conclusion reached was that, as a result of the loss of the SOOKV Keeney line, the next most important line leaving or entering the.combined Salem and Hope Creek stations was the SOOKV Oeans line to Sale The licensee performed simulated modeling with regard to the additional loss of the Deans line and has determined, in the simplest terms, that only 2000 MWe can be generated with the loss of the Deans line, and still maintain system (electrical) stability on the SOOKV syste Therefore, the load generated by Salem and Hope Creek generating stations should be limited to 2000 MWe until one of the Future Operational Options (see above)
can be incorporate The licensee presented a best estimate time frame for the completion
- of repairs on the Keeney line. This could take, depending on piling damaged caused by the tanker, anywhere from 8 to 18 month The licensee also presented a conceptual design to trip Salem Unit 1 if the Deans line were to be lost. This would enable operation at or near 100% power for all three units at the two station In the event the Deans line were lost, Unit 1 would trip leaving the remaining two units generating less than the 2000 MWe necessary for SOOKV stabilit The NRC will review the design change when availabl The licensee has decided* that the unit trip upon the loss of the Deans line concept would be an interim operating scheme until the Keeney line could be restored or another SOOKV line could be run from Deans to New Freedo The license~ has been operating all three affected units at reduced power and has committed to do so until the SOOKV system can be restored or the unit trip concept has been installe No violations were identifie.
Management Change Public Service Electric and Gas announced, on March 17, 1987, the election of:
Corbin A. McNeill, Jr. as Senior Vice President - Nuclear; and, Steven E. Miltenberger as Vice President - Nuclear Operations effective April Mr. McNeill has been Vice President - Nuclear since 1985 and Mr. Miltenberger has been General Manager - Nuclear Operations for Union Electric Company in Fulton, Missour *
1 *
Exit. Interview At periodic in~ervali during the course of.the inspection, meetings were held with senior facility management to discuss the inspection scope and finding An exit interview was held with licensee management at the end of the reporting perio The licensee did not identify 10 CFR 2.790 material.
ATTACHMENT 1 Meeting of February 24, 1987 PSE&G R. Skwarek W. Drummond D. Dodson P. 0 1Donnell L. Griffis M. Bachman F. Mccann W. Moo Meeting of March 10, 1987 PSE&G T. Piascik J. Hebson, J R. Wernsing B. Burricelli L. Reiter J. Leech D. Dodson B. Preston U. Po 1 i zz i M. Morroni R. Skwarek L. Corl etta R. Schoenberger L. Hajos J. Boettger C. McNeill L. Mi 11 er R. Salvesen J. Zupko, J NRC L. Bettenhausen L. Norrholm 0. Chopra K. Gibson F. Paulitz NRC L. Bettenhausen L. Norrholm C. Anderson T. Kenny K. Gibson D. A 11 so pp 0. Chopra T. Koshy
ATTACHMENT 2 Documents reviewed for Pressurizer Overpressure Protection Syste Technical Specifications, Units 1 and 2 FSAR Station Procedures, Units 1 and 2 21C-2.*6.071 Channel Functional test for 2PT-405 Reactor Coolant Pressure Indication and 2RH2 Interlock 21C-2.6.070 Channel Functional test for 2PT-403 Reactor Coolant Pressure Indicator and 2RH1 Interlock II.1.3.4 Reactor Coolant System Filling and Venting II.1.3.l Reactor Coolant Pump Operation II.2.3.4 Pressure Overpressure Protection - Operability Check of PRl and PR2 Salem Training Manual Design Changes Design Change Package for installation of Pressurizer Overpressure Protection (POP) for Unit 1 Design Change Package for modification to POPS on Unit 2 SGS/M-DM-042 Design calculations for POPS on Units 1 and 2 Unit 2 Safety Evaluation Report original - Supplement 6
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