IR 05000272/1997019
| ML18106A233 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 12/24/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18106A232 | List: |
| References | |
| 50-272-97-19, 50-311-97-19, NUDOCS 9801080038 | |
| Download: ML18106A233 (30) | |
Text
Docket Nos:
License Nos:
Report N Licensee:
Facility:*
Location:
Dates:
Inspectors:
Approved by:
U. S. NUCLEAR REGULATORY COMMISSION 50-272, 50-311 DPR-70, DPR-75
REGION I
50-272/97-19, 50-311 /97-19 Public Service Electric and Gas Company Salem Nuclear Generating Station, Units 1 & 2 P.O. Box 236 Hancocks Bridge, New Jersey 08038 October 20, 1997 - November 30, 1997 M. G. Evans, Senior Resident Inspector F. J. Laughlin, Resident Inspector H. K. Nieh, Resident Inspector R. K. Lorson, Senior Resident Inspector L. M. Harrison, Reactor Engineer E. H. Gray, Sr. Reactor Engineer G. C. Smith, Sr. Physical Security Inspector E. B. King, Physical Security Inspector T. J. Kenny, Sr. Operations Engineer J. G. Caruso, Operations Engineer A. L. Della Greca, Sr. Reactor Engineer K. Young, Reactor Engineer James C. Linville, Chief, Projects Branch 3 Division of Reactor Projects 9801080038 6§6~~~72 PDR ADOCK PDR G
- EXECUTIVE SUMMARY Salem Nuclear Generating Station NRC Inspection Report 50-272/97-19, 50-311 /97-19 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection; in addition, it includes the results of announced inspections by regional inspectors of engineering activities, the operator requalification training program, and the security progra Operations
Licensee management's immediate corrective actions to address the increase in configuration control errors for Unit 1 were appropriate and effective in reducing the occurrence of similar error *
Overall, the Salem requalification program was satisfactory. However, several areas for improvement were identified regarding exam security measures, backlog of simulator deficiencies, and record keeping or oversight to ensure watch standing requirements to maintain licenses active were being met. Although observed operator performance was generally satisfactory, it was noted that there was a fairly high failure rate following the thirteen week startup training program and for the 1997 annual operating exam. Weak operator performance on exams coupled with recent plant problems caused the inspectors and the licensee some concern over the possible link to Salem requalification program effectiveness. The licensee had taken actions to document, investigate and resolve these concern Maintenance
The licensee's steam generator replacement project was done properly. Overall, the steam generator replacement, restoration of affected components and systems, and the related engineering evaluations to establish the extent of changes resulting from the replacement as a part of the 50.59 process were effective. Follow up work including testing, and training of plant operators to the slight differences between the Unit 2 original Series-51 and Unit 1 replacement Model F steam generators was adequately turned over to the plant for completion as part of the operational readiness proces *
The licensee met all Technical Specification requirements for the 2A emergency diesel gene_rator (EOG) failure. Appropriate trouble-shooting activities were performed, although the failure mechanism was not determined. Licensee management acknowledged that they could have been more aggressive in saving failed components for evaluation and more thorough in investigating for the root cause and implemented actions to address these weaknesse ii
Engineering
The design change package which installed feedwater flow elements and Leading Edge Flow Meters (LEFM) in the Unit 1 feedwater system, properly addressed the bypass feedwater flow concerns. The root cause evaluation and modification of the LEFM software to address apparent instrument drift errors were acceptabl *
The Unit 1 fuse control program procedures were in place and properly implemented. The validation of installed Unit 1 fuses was complete and acceptabl *
The licensee took effective corrective actions through hardware design changes and recurring maintenance activities to limit moisture in the Unit 1 EOG air start systems. Replacement of the 1 B and 1 C EOG rack booster air regulators before entering Mode 6 was a good initiativ *
The root cause analysis to address repetitive Safety Injection relief valve failures was thorough. Corrective actions taken to resolve the problems were adequat Plant Support
The licensee maintained an effective site security program. Management support of program objectives was evident. Performance of security department personnel and equipment were generally good. PSE&G's provisions for land vehicle control measures satisfied regulatory requirements and licensee commitments. The site protected area barrier was properly installed and maintained, and satisfied the requirements of the NRC-approved security pla iii
TABLE OF CONTENTS EXECUTIVE SUMMARY.............................................. ii TABLE OF CONTENTS.............................................. iv I. Operations
05 OS
...................................................... 1 Conduct of Operations..................................... 1 01. 1 General Comments................................... 1 01. 2 Unit 1 Configuration Control Issues....................... 1 Operator Training and Qualification............................ 4 0 Licensed Operator Requalification Training Program............ 4 Miscellaneous Operations Issue.............................. 10 O (Closed) Violation 50-272 & 311 /97-003-01................ 10 OS.2 (Closed) Licensee Event Report (LER) 50-311 /97-005-00....... 10 O (Closed) LER 50-311/97-014-00........................ 11 II. Maintenance................................................... 11 M 1 Conduct of Maintenance................................... 11 M 1. 1 General Comments.................................. 11 M1.2 (Open) NRC Technical Restart Issue 11.41: Steam Generator Replacement Project (Unit 1)........................... 1 2 M2 Maintenance and Material Condition of Facilities and Equipment....... 13 M2. 1 Failure of 2A Emergency Diesel Generator During Monthly Surveillance Test................................... 13 MS Miscellaneous Maintenance Issues............................ 1 5 M (Closed) Violation 50-272 & 311 /96-01 S-05 and LER 50-272/97-001-00............................................. 15 MS.2 (Closed) LER 50-311 /97-001-00........................ 15 MS.3 (Closed) LER 50-272/97-00S-OO........................ 16 MS.4 (Closed) LER 50-272/97-006-00........................ 16 Ill. Engineering.................................................... 17 E1 Conduct of Engineering.................................... 17 E1.1 (Closed) NRC Technical Restart Issue 11.10: Feedwater Nozzle Bypass Flow (Unit 1)...................................... 17 E1.2 (Closed) NRC Technical Restart Issue 11.12: Review Adequacy of Fuse Control Program(Unit 1).......................... 1 S E1.3 (Closed) NRC Technical Restart Issue 11.5: Moisture in the Emergency Diesel Generator (EDG) Air Start System (Unit 1 )............. 1 9 E1.4 (Closed) NRC Technical Restart Issue 11.36: Safety Injection (SI) Relief Valves Performance History of Leaking and Lifting (Unit 1)...... 20 ES Miscellaneous Engineering Issues............................. 21 E (Closed) Violation 50-272/94-24-04...................... 21 IV. Plant Support.................................................. 22 PS Miscellaneous EP Issues................................... 22 S 1 Conduct of Security and Safeguards Activities................... 22 iv
V. Management Meetings............................................ 22 X 1 Exit Meeting Summary.................................... 22
v
Report Details Summary of Plant Status Unit 1 entered Mode 6 and commenced fuel movement on November 30, 1997. Core reload activities were in progress at the end of the inspection perio Unit 2 operated at about 100% power throughout the inspection perio I. Operations
Conduct of Operations (71707, 71001, 92901 & 40500)
0 General Comments Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, operations were conducted well, in a professional, conservative, and safety-conscious manner; specific events and*
noteworthy observations are detailed in the section belo.2 Unit 1 Configuration Control Issues Inspection Scope During September to November 1997, several errors occurred on Salem Unit 1 which were indicative of an adverse trend in the area of configuration control. The number of errors increased the week of November 3. The inspectors reviewed details of three of the events which occurred including licensee evaluation and corrective actions for the specific events as well as overall corrective actions to address the adverse trend. Details of each issue are summarized belo Observations and Findings 1 2 Steam Generator Fill without Level Indication On November 4, 1997, chemistry and operations personnel began to fill the 12 steam generator (SG) from the containment demineralized water header in accordance with chemistry procedure S1.CH-AD.CN-1143. They had planned to fill the SG to 60% wide range (WR) level. When the activity was commenced, the WR level indicators were reading approximately -11 % and were believed to be availabl Operations personnel believed that the level was below the SG low tap which would partially explain the low reading. The control room supervisor (CRS) authorized filling of the 12 SG, and requested that Instrumentation &Controls (l&C) technicians fill the reference leg, believing that would bring the reading on scale. However, the power supply to the WR level indication was inoperable. Therefore, the operators filled the SG for about 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, without the level indication as required by the procedure. When the evolution was terminated, the WR level indicators were still reading about -11 %, while actual SG level was about 76%.
- The licensee's investigation revealed several issues including that the 11-14 SG wide range level instruments were taken out of service to support performance of DCP 1 EE-0175, on October 8, 1997. An attachment, which listed the instruments affected by the DCP implementation, was suppose to be available to operators in the control room at the time filling of the SG commenced, however, it had been previously lost and was not replaced until November 6, 1997. Individual indication on each level instrument in the control room, such as a single strip of red translucent tape or an information sticker, as required by procedure SC.OP-DL.ZZ-0010, section 3.5, for removal and return of indications to/from service had not been used. In addition, the SG fill activity was poorly planned in that no one realized that work to restore the power supplies to the level indicators was not scheduled to be finished until almost 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after SG filling was scheduled to commence. Other issues identified included; operations did not effectively follow-up on their request for reference leg fill and l&C did not complete the fill during the 13-hour period; operators continued with the evolution, although they as well as chemistry personnel noted no change in WR level indication at several stages of the evolution; and the estimated fill rate (3%/hour) was an average fill rate, and in fact the fill rate for the lower part of the SG was about 6%/hour. During initial investigation of the issue on November 5, the inspector noted that although issues related to the SG fill were discussed during shift turnover meetings, the termination of the fill and the inoperable level indication were not addressed in the control room operator's shift log book. In addition, although chemistry management highlighted the problems encountered with the SG fill at the November 5, morning management meeting, operations management did not indicate that there were any issues with the SG fil Missed Unit 2 Technical Specification LCO Entry Related to 1R18 Radiation Monitor On November 5, 1997, a heater for 1R18 radiation monitor channel 1, located in the Unit 1 control room, failed, which resulted in a Unit 2 limiting condition for operation (LCO) entry. This issue went unidentified for about 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> until an oncoming CRS identified the issue. However, two previous crews did not identify the issue. A licensee investigation revealed that a control room operator did not adequately validate the initial alarm which was received at 2:26 a.m. on November 5. The operator attributed the alarm to a channel calibration of a different radiation monitor that was in progress. However, contrary to procedural requirements, the operator did not review the overhead annunciator cathode ray tube (CRT) monitor, which read "Unit 1 control room intake duct CH1 1 RB-Failure." Then while performing daily logs at about 8:00 am on November 5, a control room operator on the following shift discovered that the 1 R 1 B Channel 1 control room indication on panel 1 RP1 was indicating off-scale low and inadequately assessed this failed indication. This operator reviewed the issue with his CRS, but they inappropriately concluded that the 1 R 1 8-1 was operable and only the control room indication was inoperable, and initiated an action request (AR) to investigate and repair the assumed communication error between the 1R1 8-1 radiation monitor and the 1 RP1 repeater station. Neither the operator or the CRS reviewed the overhead annunciator CRT monitor, checked the status of the green "norm" light of the 1 R1 B-1, or requested assistance from l&C. Performance of any of those actions should have revealed that the 1 R1 B-1 monitor was inoperabl *
12 Containment Fan Cooler Unit Breaker Position Not as Indicated in the Tagging Request Information System On November 3, 1997, the licensee attempted to start 1 2 Containment Fan Cooler Unit (CFCU). The CFCU would not start because the breakers were in the "test" position. The Tagging Request Information System (TRIS) showed the breakers to be in the normal "racked in" position. The breakers had been previously tagged in the "racked out" position with special instructions for release to the "test" positio The Tagging Request (TR) was released on October 31, 1997. The breakers were placed and verified in test as the "as left~' conditio According to the TRIS coordinator, to release a TR in TRIS, the components must be listed in their normal position.* TRIS can then be updated after closing the TR to show a component in an off-normal condition. Procedure SH.OP-AP.ZZ-0015(0),
"TRIS Tagging Operations," Section 5.2, requires the operators who released the tags to ensure off-normal components are updated in TRIS, and the Work Control Center (WCC) to sign and date all release worksheets that TRIS was updated. The WCC senior reactor operator (SRO) directed the WCC NCOs to release the TR and update TRIS for the off-normal condition. The position was changed in TRIS from
"racked out" to "racked in," but was not updated to the off-normal "test" position, even though the release form was signed off as being update On November 6, 1997, the inspectors discussed the recent issues with licensee management and noted that the number of errors increased as the number of activities conducted in preparation for Mode 6 increased. To address the series of issues, immediate corrective actions included: bringing personnel from one of two licensed operator training classes back to the Salem station to supplement the operations staff through Mode 4; conducting stand downs for each operations crew to review conduct of operations and discuss several of the events; and removing two operations superintendents from their shift duties to support work planning and scheduling of Unit 1 activities. The inspectors found that these actions were effective and have resulted in a reduction in the number of errors of this type.* To address longer term corrective action, operations management implemented condition report (CR) 971106245 to further investigate and evaluate the adverse trend in the area of configuration control and identify any potential common causes for the issues. Licensee management indicated that additional corrective actions would be implemented prior to an increase in the number of activities being conducted in preparation for Mode 4 for Unit 1, in January 199 None of the configuration control errors which occurred were safety significant, however, the three issues discussed above involved several examples of procedural noncompliance. The inspector concluded that the licensee had taken appropriate immediate corrective actions related to these Unit 1 configuration control issue Although procedural non-compliance is a violation, these failures constitute a violation of minor significance and are being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Policy. (NCV 50-272//97-19-01)
. Conclusions The inspectors found that licensee management's immediate corrective actions to address the increase in configuration control errors for Unit 1 were appropriate and effective in reducing the occurrence of similar error Operator Training and Qualification 0 Licensed Operator Requalification Training Program Inspection Scope Three NRC inspectors evaluated the Salem licensed operator requalification training (LORT) program using NRC Inspection Procedure 71001, "Licensed Operator Requalification Program Evaluation" during the week'.> of October 20 and November 17, 1997. The inspectors evaluated the adequacy of the annual operating test and biennial written exams, and the administration of the exams to two crews comprised of a combination of staff and operating personnel using NUREG 1021,
"Operator Licensing Examination Standards for Power Reactors". In addition, the inspectors reviewed the procedures for maintenance and activation of operator licenses and verified that the requirements were met to reactivate inactive license Administrative procedures and documents associated with the training program and its implementation as well as plant operating history and self-assessments were also reviewed. Interviews with operators and various training staff were also conducte Observations and Findings Exam Materials:
The inspectors reviewed the written requalification exams that were used for the 1997 LORT program and concluded that the exams met the guidelines established in the examiner standards and had an appropriate level of difficulty. The inspectors found the questions to be challenging, both for the closed and open book categories. The inspectors verified that the overlap of exam questions was less than 15% for the five crews examined and concluded that this was well within the acceptable standard for maintaining examination integrit The job performance measures (JPMs) met the guidelines in the examiner standards and inspection procedure. The JPMs w~re generally good, however one JPM had to be modified due to an inappropriate critical task standard. The inspectors also identified that a limited number (seven) of faulted/alternate path JPMs exist in the Salem exam bank. It was determined by discussion that this may be due in part to a conservative interpretation of the requirements for that type of JP *The individual scenarios and sets met the criteria of the examiners standards and were appropriately challenging, good quality evaluation tools. The scenario writeups were detailed and easy to follo *
Exam Administration The facility evaluators included the operations manager, lead simulator instructor, and one other instructor. An observer from Seabrook was also present and participated in the post scenario discussions. These critiques were appropriately detailed and critical, and the operations manager made his expectations for performance clea Operator Exam Performance During the week of October 20, 1997, an inspector observed five scenarios administered to two crews. The results for the two crews were that both passed, but one crew was evaluated as weak overall. Also, there was one individual failur The scenario with the individual failure was a leaking pressurizer power operated relief valve {PORV) with a steam generator tube rupture. The cause of the failure was that in the diagnostic steps of Trip 1, "Reactor Trip or Safety Injection" the control room supervisor misinterpreted a step checking for closed PORVs and did not enter LOCA-1, "Loss of Reactor Coola,nt" because he considered a leaking PORV to still be closed. This ultimately delayed entry into SGTR-3, "Steam Generator Tube Rupture with Anticipated Transient Without Trip - Subcooled Recovery" which would have specifically addressed the combined LOCA/SGT The scenario with the weak crew was a steam leak, anticipated transient without trip {ATWT), and faulted ruptured steam generator. In this scenario, the crew began a rapid down power in response to an identified steam generator tube lea As soon as the down power commenced, the crew interpreted decreasing pressurizer pressure and level as indicating the leak had increased to a rupture, and initiated safety injection. However, the indications the crew saw were a normal plant response to the down power, not a tube rupture which had not been inserted yet. Following the trip, a steam rupture occurred. One main steam isolation valve did not close and the crew was slow to get it closed (10 minutes). In the end, the crew ended up at the appropriate steps in the procedures, but they had acted too *
quickly in one instance and were slow to manually accomplish a failed automatic action in the othe One strength was noted in the overall skill and competence level of the reactor operators {ROs). For all scenarios, teamwork and communications were excellent with many instances occurring with an RO reminding or prompting the CRS to take appropriate action Two instances were observed where the licensee may be leaving too much to operator skill rather than procedural clarity. One was the. step in several emergency operating procedures {EOPs) requiring main steam isolation, which does not explicitly state the three means of shutting main steam isolation valves {MSIVs)
from the control room {emergency core cooling system bezels, individual fast close, individual slow close). The other was the step for restoring charging flow in FRCl-1,
"Response to High Pressurizer Level" which did not address the seal injection flow control valve as well as the charging flow contro Four individuals were observed performing simulator JPMs. All four individuals observed failed one of the JPMs which they performed. Three individuals failed a JPM requiring response to a stuck open pressurizer spray valve. The expected action was to determine the stuck valve could not be shut, trip the reactor, and then trip two reactor coolant pumps. One individual allowed a safety injection to occur, while the other two individuals tripped only one reactor coolant pump (RCP).
One individual missed a different JPM which required restoration of letdown. In this instance, it was expected operator knowledge that a step in FRCl-1 requiring the use of valve CV-77 to obtain a specified charging flow really meant to open CV-77 and also adjust the CV-71 seal injection flow control as necessary to obtain the specified flow. The operator was unable to obtain the desired flow, a critical ste Although operator performance was generally satisfactory, the inspectors noted that there was a relatively high failure rate following the thirteen-week startup training program in that 57% of the operators failed at least one portion of the exam and 28% of the operators failed portions of the 1997 operating exam. This will be discussed further under the plant operating history sectio Management Oversight and Training Feedback System The inspectors reviewed meeting minutes from the Operations Training Review Group (TRG) for the past year and concluded that feedback is prompting improvements to the LORT program, as well as satisfying the training needs of the operators. This was confirmed during interviews with the operator The inspectors noted that many improvements have been made to the LORT program as a result of management initiatives and operator feedback. Examples of program changes implemented included training scenarios were stopped and discussed when operator/crew errors were identified, the simulator was remodeled to match the new control room configuration, and individuals were required to complete remediation training for any JPM failure regardless of the total exam result The inspectors reviewed open simulator deficiencies, Simulator Action Requests (SARs), and concluded that although progress had been slow, plans were in place to significantly reduce the backlog in the near future. A large number of SARs were identified, 523 total with 257 that had the potential of affecting simulator fidelit The inspectors were told that a limited computer memory was a major contributor to the slow progress. The licensee planned to expand the memory by January 1998. This memory upgrade would allow the resolution of many of the items. A Salem-specific software modeling package (replaces the reactor coolant system, steam generators and reactor core simulation) was.essentially complete, which should provide operators with the most current tools to maintain their operational proficiency and further help to reduce the backlog. Interviews and the review of records showed a recent decrease in the total number of outstanding deficiencie *
Remedial Training Program The inspectors reviewed a sample of remediation records for individuals and crews who had failed exams and determined this area was satisfactory. The remediation packages reviewed indicated that evaluators and management were appropriately objective in their evaluations of individuals and crews. The licensee did not appear to be reluctant to remediate an individual or crew when performance did not meet expectation For written exam failures, areas for self-study were identified and the individuals were retested prior to returning to shift. However, most of the operators interviewed indicated that more analysis of weaknesses and more instructor/student interface would make this type of remediation more effective. Generally, the simulator remediations appeared to be more effective with considerable student/instructor interfac The inspectors' reviews identified some repetitive weaknesses/failures for certain individuals indicating that remediation may not have been fully effective. However, the licensee had identified these individuals and was evaluating long term corrective action Maintenance and Activation of Operator Licenses Various training attend~nce records, grades, and medical records were reviewed, including records for six individuals who re-activated their licenses. No weaknesses were identified. It was noted that ensuring the 56 or 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> of watch-standing time per quarter to maintain a license active (10 CFR 55 requirement) was the responsibility of each individual operator. Operation's management was not maintaining any independent record-keeping or oversight to ensure this requirement was being met. This was an area of potential vulnerability especially with the planned addition of many more licensed operators to the Salem staff in the next year or tw Exam Security and Validity Security measures for exam development and administration were reviewed and found to be adequate in that no instances of exam compromise were identifie However, some practices were considered weak and areas of vulnerability, relying heavily on the integrity of individuals to ensure exam security is maintained. For example, the program requirements identified in procedure SH.TO.IP ZZ-0028Z,
"Development and Administration of Licensed Operator Requalification Exams,"
allow crew exams to have two-thirds overlap of exam material (i.e., one-third different). In reviewing the simulator scenarios used for the 1997 annual operating exam, the inspectors noted that by the fifth week of the exam cycle all five of the scenarios administered to "E" crew had been used to examine crews in previous weeks (i.e., no new or different scenarios were utilized to test "E" crew).
- In addition, the inspectors noted the principal simulator instructor was also part of the evaluation team. The inspectors were concerned with the apparent conflict of interest for this individual who had previous knowledge of the exam material used and at the same time was responsible for training the crews. For example, by the time "E" crew was examined, this individual had previously administered all the scenarios used for "E" crew to other crews during previous exams in that cycl The inspectors further noted that the operators were required to sign the security agreement and that the simulator instructor did not know the actual combinations of scenarios to be given to each crew until just before the exam was administered and after he had completed his instruction for. that crew. The inspectors concluded this practice relied heavily on the personal integrity of this individual to avoid compromising portions of the exa The inspectors noted that six of the nine scenarios used on the 1997 annual operating exam were also used as final exams to test the effectiveness of the 13 week startup training program. This was also viewed by the inspectors as a weak practic Similar exam security issues were raised during the last requalification program inspection. The licensee plans an increase in staffing and expansion/revision of the exam bank to improve controls in this are Plant Operating History The inspectors reviewed licensee event reports (LERs), since the last requalification program evaluation, to determine if the errors were related to training. The LER events reviewed showed a random pattern of errors with little similarity as to the cause. The errors were the result of individual actions rather than training related problems. Errors such as slight deviations from procedure or poor communications were typical example Weak operator performance on the thirteen week start up training program exams and the 1997 LORT annual exams, coupled with recent plant problems (as discussed in Section 01.2) caused the inspectors some concern. After discussions with the resident inspectors and the licensee staff the inspectors reviewed Action Request (AR) 971114216, issued by a training staff member on November 14, 1997. This AR outlined the above concerns as well as others regarding operator performance and a possible link to Salem LORT program effectiveness. The results of the evaluation were presented to management on November 24, 1997. The inspectors concluded that the licensee was aware of operator deficiencies and had taken the first step toward correcting the weaknesses identified abov Licensee Self Assessment The inspectors concluded that the evaluations reviewed were effective in identifying problems in the LORT program and corrective actions were being made as a resul The inspectors reviewed Quality Assurance Audit Report 97-040, which focused on facility staff and training programs for licensed operators, shift supervisors, shift
r
technical advisors, and non-licensed operators. The inspectors also reviewed a
"Comprehensive Self-Evaluation" which used procedure NC.TQ-TC.ZZ-0005(Z)
"Evaluation" to assess the operations accredited progra The findings included weaknesses in the training program records, failure of training instructors to comply with training procedures, lesson plans that were presented to trainees without approval, and training records that were found in an instructor's desk rather than in proper records storage. The inspectors verified that these findings were being addressed by the licensee. The inspectors found the "to date" corrective actions to be extensive, which included the dismissal of an instructor who was mainly responsible for many of the problem Operator Interviews The inspectors interviewed seven operators, who had the following comments concerning the LORT progra *
The thirteen week startup training program given by contractors was high quality and a very good review of basic system knowledge and theor *
Commitment type training on shift should help to improve the LORT program by allowing more time to focus on more important topic *
Training on plant design changes (DCPs) was an area for improvemen *
Some of the contractor instructor staff were considered better than permanent staf *
Classroom training was weaker than simulator training and is an area for improvemen Conclusions Overall, the Salem requalification program was satisfactory. However, several areas for improvement were identified regarding exam security measures, backlog of simulator deficiencies, and record keeping or oversight to ensure watch-standing requirements to maintain the license active were being met. Although observed operator performance was generally satisfactory, it was noted that there was a fairly high failure rate following the thirteen-week startup training program and for the 1997 annual operating exam. Weak operator performance on exams coupled with recent plant problems caused the inspectors and the licensee some concern over the possible link to Salem requalification program effectiveness. The licensee had taken actions to document, investigate and resolve these concerns.
- 08 Miscellaneous Operations Issue 0 (Closed) Violation 50-272 & 311 /97-003-01: operator training and qualificatio During June through November of 1995, the Operations Manager assessed the performance of the operations staff. A recertification diagnostic examination was given to all operators. The examination was written and executed by an independent contractor (a written portion consisting of 100 questions, 75 multiple choice and 25 short.essay, followed by simulator drills and then a plant walk-through).
After the results of the examination were analyzed, the licensee developed a restart training program that was intended to replace requalification training for 1996. The restart training was 13 weeks per individual followed by requalification testing similar to that given following the normal LORT program. The details of the program were documented in a letter to the NRC dat.;id November 7, 1996. In the concluding stage of the restart training program, start-up demands for the plant interrupted training for a two month period. Because of this delay the program was not completed as intended. The licensee was aware the program would not be completed and met with the NRC on December 5, 199 PSE&G submitted the request on January 6, 1997, which was late and in violation of 10 CFR 55.59(a)(1) and (2) which required that the requalification be continuous and that operators pass a comprehensive annual operation test. In January of 1997, PSE&G began a new LORT program in parallel with the restart training program. In May of 1997, PSE&G had completed requalification of *all licensed operators, and was back on a two-year training cycle required by 10 CFR 55. This inspection reviewed the completion of the 1997 LORT progra The inspectors reviewed PSE&G's response to the violation and had discussions with the training staff to assess the corrective actions. The inspectors concluded that PSE&G intended to continue following the systematic approach to training (SAT). This will be supplemented by systematic program changes, that have regulatory impact, being reviewed and approved by the Operations Training Review Group prior to implementation. This violation is close (Closed) Licensee Event Report (LER) 50-311 /97-005-00: pressurizer overpressure protection system Technical Specification violation. The licensee identified, during a review of operating logs, that from March 23 until March 27, 1997 both pressurizer overpressure protection system (POPS) channels were powered from the 28 125 VDC bus. This resulted in one of the two POPS channels being inoperable for approximately 112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> while Unit 2 was in Mode 5. Technical Specification 3.4.10.3.b required that the reactor coolant system be depressurized within thirty-two hours for this conditio Salem attributed the cause of this event to inadequate procedural guidance for powering the vital instrument bus. Salem revised the appropriate operating procedures to indicate that powering the POPS system from the alternate power supply would render one POPS channel inoperable. The safety significance of this J
event was minor since the reactor coolant system was operated at a low pressure (approximately 150 psig), and both POPS channels remained energized during this period. This licensee-identified and corrected violation of failing to depressurize the reactor coolant system as required by TS 3.4.10.3.b is being treated as a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-272/97-19-02)
(Closed) LER 50-311/97-014-00:Manual reactor trip from 100% power following loss of both operating steam generator feed pumps. This LER discussed a manual reactor trip of Unit 2 on October 2, 1997.. The failure of an analog circuit card in a data acquisition system (DAS) connected to the advanced digital feedwater control system (ADFCS) produced a signal failure in the ADFCS representative of low feedwater header pressure. The temporary DAS was being used to monitor ADFCS performance during modification acceptance testing and was subsequently removed. This issue was discussed in NRC Inspection Report 97-18. No new issues were identified in the LER, so this LER is close II. Maintenance M1 Conduct of Maintenance (50001, 62707, 61726, 92902, & 40500)
M 1. 1 General Comments The inspectors observed all or portions of the following work activities and Technical Specification surveillance tests:
W/O 950307013:
W/0 970704104:
W/O 950417018:
W/0 970211024:
W/0 971210025:
W/O 971113067:
W/O 970201006:
SC.RE-FR.ZZ-0001 (Q):
S1.OP-ST.SSP-0004:
Transfer of New Fuel From New Fuel Pit to Spent Fuel Pit 1 EC3626-01 - No. 13 Aux Feed Pump Safety Related/Non Safety Related Instrumentation Circuit Separation 1 RCE1 - Reactor Head 0-ring Replacement and 1 RCE1 - Remove and Inspect Primary Source Assemblies Type B Leak Rate Test on the 100' Containment Airlock Verify Upper Bearing Lock Nuts 21 SW Strainer
- 2PT457 - Pressurizer Pressure Channel Ill Functional Test 2PT647 - No. 22 RHR Pump Discharge Pressure Transmitter Sensor Calibration Fuel Handling Engineered Safety Features Manual Safety Injection 1 C Vital Bus The inspectors observed that the plant staff performed the maintenance effectively
- within the requirements of the station maintenance program, and that the plant staff did the surveillances safely, effectively proving operability of the associated syste *
M1.2 (Open) NRC Technical Restart Issue 11.41: Steam Generator Replacement Project (Unit 1 l Inspection Scope Inspection was performed to obtain an overview of current and planned work, related procedures, documentation, quality inputs and progress of the Salem, Unit 1 steam generator replacement project (SGRP). By October 1997, the physical SGRP work and the project turnover to the Unit 1 plant were complete. The Design Change Packages (DCPs) were in the final steps of close out and provision for testing through the work order process was mad Specific areas inspected included the status of project nonconformance reports (NCRs); the identification and plans for testing of SGRP affected components and systems; turnover of the project segments to the respective system engineering managers; provision for operator training on differences between the Unit 1 and Unit 2 steam generators; the DCP closeout process and status; and DCP's 1 EA-1273, 1 EA-1244, and 1 EE-0367. The replacement steam generator report and the 50.59 process for the SGRP were reviewe Observations and Findings By October 1997, the four replacement steam generators were fully installed and related instrumentation lines were in place in the Unit 1 containment building. The Replacement Steam Generator Report (77-1258763-00)dated March 1997, summarizes the differences between the original Series-51 (OSG) and replacement Model F (RSG) steam generators and provides references to more detailed engineering analysis. The functional differences between the OSGs and RSGs are minimal but include an increase in secondary side steam pressure and changes in secondary side water level/span condition The SGRP NCRs were noted to have been dispositioned and closed out with remaining work covered by documented Field Change Requests (FCRs) or work orders (WOs). Turnover of SGRP details to the respective system manager/engineers including those responsible for the reactor coolant system (RCS),
feedwater, main steam, and turbine controls had been completed. The operator training group was aware of the differences between the Unit 2 OSGs and the Unit 1 RSGs and were factoring these changes into simulator programming and training for the plant operators. DCP 1293 provid_ed a summary of safety analysis performed on the steam generator replacement and a summary of each of the -
individual DCPs. This DCP, in combination with the Replacement Steam Generator Report, provided full detail on the RSG and OSG steam generators. The DCP closeout process included identification of affected documents, procedure changes and work order * Conclusions The licensee's steam generator replacement project was done properly. Overall, the steam generator replacement, restoration of affected components and systems, and the related engineering evaluations to establish the extent of changes resulting from the replacement as a part of the 50.59 process were effective. Follow up work including testing, and training of plant operators to the slight differences between the Unit 2 original Series-51 and Unit 1 replacement Model F steam generators was adequately turned over to the plant for completion as part of the operational readiness proces However, NRC Restart Issue 11.41 will remain open pending additional review by the NRC Office of Nuclear Reactor Regulation of the 1 OCFR 50.59 safety evaluations associated with the accident analysi M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Failure of 2A Emergency Diesel Generator During Monthly Surveillance Test Inspection Scope The inspector followed up on the October 22, 1997, failure of the 2A emergency diesel generator (EOG) to start during the monthly surveillance tes Observations and Findings On October 22, 1997, licensee operators attempted to start the 2A EOG during the monthly surveillance in accordance with procedure S2.0P-ST.DG-0001. The diesel did not start immediately, and after about six seconds the operators manually interrupted the start sequence when they determined that it did not sound like a normal start. The diesel was declared inoperable and the licensee correctly entered Technical Specification (TS) action statement 3.8.1.1.b. Surveillance requirement (SR) 4.8.1.1.1.a was performed within one hour as required. The licensee also performed SR 4.8.1.1.2.a.2 to demonstrate the operability of the 28 and 2C EDGs, and verified that no common mode failure existed which would affect all of the Unit 2 EDGs. The licensee reported the 2A EOG failure in a special report (50-311197-015-00) dated November 21, 1997, as required by SR 4.8.1.1.4 and TS 6. The licensee performed trouble-shooting activities to determine the cause of the failure. These included cleaning the air start motor gear threads, manually barring over the engine, and checking the operability of the rack booster plunger and the air start motors. Licensee personnel could not determine the cause of the 2A EOG failure during trouble-shooting activities. When those activities were complete, the diesel was run in accordance with procedure S2.0P-SO.DG-0001 and the diesel started satisfactorily. About 50 minutes later, the monthly surveillance run was performed again and it was satisfactory as well. The diesel was then declared operable by a joint decision of Operations and Engineering management, although the root cause of the failure was not determined. The licensee successfully ran the
- 2A EOG on a weekly basis until the next scheduled monthly surveillance to assure no repeat failure At the time of the diesel failure, both fuel rack booster air regulators were leakin This caused the air start air compressors to run more than usual, which increased moisture formation in the air start system. Additionally, the water bottle which collects water from the blowdown of the air receivers and moisture separator was filling up more than normal, which confirmed the increased moisture productio The licensee stated that it had no operability concern due to this increased moisture since the 2A EOG had passed its recent monthly surveillance tests. The licensee subsequently concluded that a likely apparent cause of the diesel failure was water
- accumulation in the air start system. The inspector concluded that, although there was no reason to question diesel operability, that the air regulator leaks placed the air start system in a degraded condition which was rot clearly understood by the licensee. After the diesel failure, the licensee drained approximately 0.5 ounces of water from each rack booster air regulator. These regulators are the low point in the air start system, so moisture would tend to accumulate there. When the rack booster was tested after the failure, the first air regulator provided sluggish movement of the booster plunger, and water was leaking from around the plunge However, the plunger did operate satisfactorily. The licensee replaced both leaking air regulators on October 23, 199 The EOG system engineer was concerned about the leaking rack booster air regulators several weeks before the 2A failure, and completed an "Attachment F" on September 25, 1997, to schedule a work activity to replace the regulator However, the system engineer did not request priority attention for this item by engineering and maintenance management, resulting in the work being scheduled for December 1997. The inspector concluded that the licensee missed an opportunity to replace the air regulators in a more timely manner and reduce moisture accumulation in the air start syste The inspector discovered that one rack booster air regulator on the 2A EOG and one on the 1 B EOG had been replaced previously in 1997 due to air leakage. The system engineer stated that neither of these regulators were saved by the maintenance department for evaluation. Also, immediately after the 2A EOG failure, maintenance personnel cleaned the air start motor gear threads to remove the
"grease" on them. The air start motors are replaced or rebuilt every other refueling outage, and there is no necessity to lubricate them. The licensee did find excess grease on the diesel barring device, which engages the same flywheel as the air start motors. However, the licensee never determined what the grease on the air start motor threads was or where it came from. An inspection of the other five Salem diesels revealed no grease on the air start motor threads. The inspector concluded that the licensee staff could have been more aggressive in saving failed components for evaluation and more thorough in investigating for the root caus Licensee management acknowledged this weakness and implemented actions to address i Conclusions The licensee met all Technical Specification requirements for the 2A emergency diesel generator (EOG) failure. Appropriate trouble-shooting activities were performed, although the failure mechanism was not determined. The rack booster air regulator leakage resulted in increased moisture accumulation in and resulting degradation of the air start system, which potentially caused the 2A failure. The system engineer attempted to have the leaking regulators replaced about one month before the diesel failure, but did not request priority attention for the item by engineering and maintenance management. This resulted in the untimely scheduling of regulator replacement, which was completed the day following the 2A EOG failure. Licensee management acknowledged that they could have been more aggressive in saving failed components for evaluation and more thorough in investigating for the root cause and implemented actions to address these weaknesses. The inspector also concluded that Special Report 50-311/97-015-00 was adequate, and had no further question. Therefore, this Special Report is close MS Miscellaneous Maintenance Issues M (Closed) Violation 50-272 & 311 /96-018-05 and LER 50-272/97-001-00: boron injection tank isolation valves not included in the inservice test program. The NRC identified in Inspection Report 96-18 that the safety injection charging pump to boron injection tank isolation valves (SJ4 and SJ5) were not included in the lnservice Test (IST) program. These valves are required to close to terminate safety injection flow during a postulated steam generator tube rupture event. PSE&G revised the test procedures (S1.OP-ST.SJ-0003 and S2.0P-ST.SJ-0003) to require testing of SJ4 and SJ5 in the closed direction. Additionally, PSE&G revised procedure, SC.OP-AP.ZZ-0113, Emergency/Abnormal Operating Procedures Program to require IST personnel notification of all EOP changes. PSE&G reviewed their EOPs and revised the applicable IST procedures to ensure an additional twelve valves were properly tested. The LER adequately described the test program deficiencies and corrective actions. The inspector concluded that PSE&G implemented comprehensive corrective actions for this violation, and it is close M8.2 (Closed) LER 50-311 /97-001-00: inadequate surveillance testing of pressurizer over-pressure relief (PORV) system accumulator discharge check valves. Technical Specifications and inservice testing requirements of the American Society of Mechanical Engineers (ASME)Section XI Code necessitate leak testing of these valves at the functional maximum differential pressure (dp) or by providing a correction factor to the lower dp test results up to the functional maximum d Upon identification by the licensee on January 15, 1997, that these valves had not been tested at a functional maximum dp, the licensee satisfactorily tested the accumulator check valves on January 16, 1997. The failure to perform testing at the required pressure was attributed to a previous procedure change that was made*
in response to industry concerns about a gradual loss of control air versus a catastrophic loss of control ai,
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The inspector reviewed the corrective actions taken by the licensee, as detailed in the LER, *and concluded that such actions were appropriate and thorough. These actions included proper testing of the valves at low and high differential pressur Based on the inspector's review of the licensee's corrective actions, this LER is closed. In addition, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Polic (NCV 50-311/97-19-03)
M8.3 (Closed) LER 50-272/97-008-00: inadequate surveillance testing of pressurizer power-operated relief valve accumulator solenoid valves and check valve Technical specification 4.0.5 and ASME Section XI Code require the PORV accumulator solenoid valves be full cycle exercised and stroke time tested. On March 21, 1997 the licensee identified that the solenoid valves were only being tested in the open position and not stroke time tested and that the check valves were only being tested in the closed position, thereb*/ failing to verify adequate recharging of the PORV accumulators. An inservice inspection test (IST} program assessment performed by PSE&G in 1995 identified that these valves were to be included in the IST program, however, the valves were misclassified as non-nuclear and subsequently not included. Although the stroke time and full cycle testing were not properly performed, the partial testing performed by the licensee verified that these components would operate in their required safe mode of operation to mitigate the consequences of an acciden Corrective actions taken by the licensee included the satisfactory completion of required valve testing and procedure revisions for future testing performance as detailed in the LER. Additionally, as described in LER 50-311 /95-008 and NRC inspection report 50-311 /97-80, section 3.3.6, a technical specification surveillance improvement project (TSSIP} has been initiated to improve the quality of inservice testing. Based on the inspector's review of the licensee's corrective actions, TSSIP plan, and revised IST procedure S2.RA-IS.PZR-0025(0}, Revision 1, "IST Pressurizer PORV/POPS Normal and Accumulator Air Sources" this LER is closed. In addition, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Polic (NCV 50-272/97-19-04)
M8.4 (Closed) LER 50-272/97-006-00: inadequate TS required surveillance test for the pressurizer overpressure protection system (POPS}.
On March 12, 1997, Salem determined that a test procedure for POPS initiation logic did not include testing of two relays. The reactor operator promptly declared the POPS inoperable and entered TS 4.0.3 which required the relays to be tested within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee revised the test procedure, satisfactorily tested the POPS channels within the required time, and exited TS 4.0.3. Salem is currently upgrading their surveillance procedures as part of TSSIP. The inspector concluded that the corrective actions for this event were adequate and this LER is closed. In addition, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Polic (NCV 50-272/97-19-05)
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Ill. Engineering E1 Conduct of Engineering (37551, 92903)
E1.1 (Closed) NRC Technical Restart Issue 11.10: Feedwater Nozzle Bypass Flow (Unit 1) Inspection Scope This restart item was opened to evaluate the licensee's resolution of a feedwater nozzle bypass flow condition that had resulted in the Salem Unit 2 being operated at thermal power levels of up to 101.4% (3459 MWth) during operating cycle 7 and at sustained thermal power levels of up to 102.58% (3499 MWth) +/- 0. 7% during operating cycle 8. Resolution of this issue for Unit 2 was reviewed previously and found acceptable, as documented in inspection report (IR) 50-272; 311/96-10. The scope of this inspection was to evaluate the differences between Unit 1 and Unit 2 and to verify proper resolution of the same issue for Unit Observations and Findings The inspectors determined that the licensee had developed, as they did for Unit 2, a design change package (DCP) to replace the feedwater flow nozzles that were eroded and/or corroded. This degradation had caused some bypass flow being unmeasured. The inspectors' review of DCP 1 EC-3394, Revision 1, "Replacement of Main Feedwater Flow Elements and Installation of the Leading Edge Flow Meters (LEFMs)," determined that the changes were consistent with those of Unit 2 and that design documents were of good quality. The package included an evaluation of the effect of this change on the design and licensing basis, necessary procedure and drawing changes, adequate installation instructions, and appropriate retest instruction The inspectors verified the installation of the feedwater flow nozzles and LEFMs during a walkdown of the system for Unit 1. The inspectors noted that installation was complete, except for the pipe insulation that required reinstallation and the inservice leak test that was scheduled for prior to restar Discussions with the licensee revealed no operational problems with the Unit 2 feedwater modification. When the Unit 2 LEFMs were initially put in service, erroneous feedwater flow readings were originally attributed to instrument drif Later, the licensee determined that a LEFM software calculation was creating a cumulative error that,.over a long period of time, made the instrumentation appear to have drifted. Because the LEFMs were used only to verify the flow nozzle performance, the software error was not a safety concern. The licensee, nonetheless, generated AR 971017199to modify the software and correct the LEFM drift errors. As of the date of this inspection the software modification had been implemented only for Unit 2. Unit 1 will use the same software packag Based on procedures S1 and S2.RE-ST.ZZ-001 (Q), "Calorimetric Calculation," daily secondary side calorimetric and recording of feedwater flowrate data are required from both the new feedwater flow elements and the LEFM *
18 Conclusions The inspectors concluded that DCP 1 EC-3394, which installed feedwater flow elements and LEFMs into the feedwater system, properly addressed the bypass feedwater flow concerns for Unit 1. The root cause evaluation and modification of the LEFM software were acceptable. Proper procedures were in place to perform daily secondary side calorimetric and recording of flowrate data to monitor potential overpower conditions. Based on the above, Restart Issue 11.10 for Unit 1 is close E1.2 (Closed) NRC Technical Restart Issue 11.12: Review Adequacy of Fuse Control Program(Unit 1 l Inspection Scope The adequacy of the Salem fuse control program wa~ evaluated previously, as documented in IR 50-72 & 311/96-16. In this report (96-16),the NRC inspectors concluded that the licensee had taken appropriate steps to address the fuse related concerns and that they had established an acceptable fuse control process. The inspectors also concluded that, for Unit 1, the fuse validation program was still incomplete. The scope of this inspection was to evaluate the licensee's actions to validate the plant fuses and to implement an appropriate Unit 1 fuse control program. Additionally, the inspection assessed the licensee's resolution of an oversized fUse concern for Unit 1. For Unit 2, resolution of this issue was reviewed and found acceptable, as documented in IR 50-272 & 311 /97-0 Observations and Findings The inspectors determined that the existing design and fuse control procedures were common to Unit 1 and Unit 2. These procedures, which allow the licensee to gather fuse data on an ongoing basis, validate design information, and resolve identified discrepancies, were previously reviewed and found acceptable. Only fuse maintenance procedure SC.IC.GP.ZZ-0121 (Q), dated May 28, 1997, had been reissued since the last NRC inspection of this item. The inspectors' review of this procedure identified no areas of concern and concluded that the fuse control program procedures that were currently in place were acceptable and were being properly implemente Through discussions with licensee personnel and a review of walkdown punch lists, the inspectors determined that walkdowns had been performed of the Unit 1 safety and nonsafety-related electrical distribution system (EDS) fuse configurations; and that all EDS fuses had been inspected. The inspector performed a sample verification of the walkdown punch list associated with Turbine Generator Area N, Turbine West 230V Control Center, 1 E Auxiliary Building 460/230V Control Center, and the 1 B Diesel 230 V Vital Control Center. The inspectors found no fuse discrepancies during this review.
The inspectors' sample review of Unit 1 ARs determined that" most of the ARs involved inconsistencies between documentation, the installed fuse, and the
description in design drawings or bills of material (BOMs). Review of the Master Fuse List (MFL), document number 604993, Revision 0, September 12, 1997, provided reasonable assurance that, when discrepancies are found, ARs are generated and that the MFL and other documentation is updated accordingl Based on the above review, the inspector concluded that verification of the Unit 1 EDS fuses had been acceptably complete The inspector performed a walkdown of selected fuses installed in Unit 1 to verify fuse condition and rating. The inspector found that the fuses were sized and I
labeled consistently with the MFL. The inspector also found that the* Unit 1 fuses were in good physical conditio The inspectors reviewed the resolution status of the oversize fuse concern and determined that the two change requests, initiated on February 22, 1996, to replace the 1 5 Amp fuses with 5 Amp fuses were still open and design change packages had not yet been prepared. The licensee classified this work as post-restart. The NRC inspectors previously concluded (IR 97-02) that delaying the replacement of the fuses until after the restart of the plant was acceptabl DCP 1 EC-3486, Revision 3, which adds control circuit transfer switches for the Unit 1 alternate shutdown, includes a replacement of 1 5 Amp fuses with 5 AMP fuse This DCP had been prepared, but disposition was still incomplete. Completion is planned for before Unit 1 restar Conclusions Based on the above review, the inspector concluded that applicable fuse control program procedures were in place and properly implemented for Unit 1. The inspector also concluded the validation of installed Unit 1 fuses was complete and acceptable. Appropriate actions had been taken by the licensee to resolve the oversize fuse concern for Unit 1. Based on the above review, Restart Issue 11.12 is closed for Unit 1.
E1.3 (Closed) NRC Technical Restart Issue 11.5: Moisture in the Emergency Diesel Generator (EOG) Air Start System (Unit 1). Inspection Scope Salem IR 50-272 & 311/94~19 noted the following deficiencies with the Salem EDG air start system: 1) Leaking air receiver drain valves, 2) Inappropriate setpoint for the EDG air receiver low pressure alarm (90 psig), 3) Air receiver inlet check valve failures, and 4) Carbon steel piping corrosion products interfering with check valve operation. For Unit 2, resolution of this issue was reviewed and found acceptable, as documented in IR 50-272 & 311 /96-15. Licensee actions for Unit 1 were reviewed during this inspection.
- Observations and Findings The licensee implemented design changes to upgrade the EOG air start system hardware. All air receiver drain valves were replaced with stainless steel ball valves to minimize leakage. An air receiver low pressure alarm was added to each air receiver tank. The alarm setpoint is 182 psig, which provides a margin above the minimum pressure required for three EDG starts (160 psig). The air start system carbon steel piping between the air compressors and the air receiver tanks was replaced with stainless steel piping to minimize corrosion. Air receiver inlet check valves were replaced with a stainless steel soft seat design to provide improved leak tightnes Additionally, the licensee implemented various maintenance activities to provide additional assurance that the air start system will not be fouled by moisture or particulate material. The air start moisture separaton and air receivers are blown down twice daily to eliminate moisture. The in-line air strainers to the air start motors are blown down following each EOG operation. The afterfilter cartridges are replaced during each refueling outage, and the air start motors are replaced or rebuilt every second refueling outage, in accordance with plant procedure The licensee also replaced the booster rack air regulators on the 1 B and 1 C EDGs before entering Mode 6 in response to the recent failure of the 2A EOG (See Section M2.1 ). The regulators on the 1 A EOG had previously been replace Conclusions The inspector concluded that the licensee took effective corrective actions through hardware design changes and recurring maintenance activities to limit moisture in the Unit 1 EDG air start systems. Replacement of the 1 B and 1 C EDG rack booster air regulators before entering Mode 6 was a good initiative. Restart Issue 11.5 is closed for Unit E1.4 (Closed) NRC Technical Restart Issue 11.36: Safety Injection (SI) Relief Valves Performance History of Leaking and Lifting (Unit 1) Inspection Scope The inspector reviewed the Restart Issue 11.36 Closure Package for Unit 1. The package included the closure basis, the root cause analysis for the issue, condition reports 950901391 and 960321090,procedures NC.NA-AP.ZZ-0006(0),
"Corrective Action Program" and SC.OP-AP.ZZ-0006(0), "Operability Determination." The inspector also reviewed design change package (DCP) 1 EC-3679-01, "Safety Injection Discharge Pressure Re rating," which increased SI relief valve set points and rerated portions of the SI discharge piping. For Unit 2, resolution of this issue was reviewed and found acceptable, as documented in IR 50-272 & 311/96-1 '.
21 Observations and Findings The root cause analysis specified corrective actions to reduce the risk of relief valve failures. The corrective actions taken were identical to those specified for Unit Procedural changes were used to correct relief valve failures due to valve seat scuffing, chattering, and 0-ring failure. One change was to test relief valves for seat leakage prior to and following lift setpoint testing. This action verifies the as left condition; and verifies that no seat leakage exists prior to installation. Also, relief valve procedures were modified to include steps to prevent damage to relief valve nozzle 0-rings during installatio To prevent relief valve failures due to seat contamination from relief valve test stands, a recurring task had been implemented to periodically inspect and maintain test stand components. This action minimizes the introduction of foreign particles into the relief valve during testin DCP 1 EC-3679 increased the lift setpoints of 1SJ167, 11 SJ39, and 12SJ39 from 1750 psig to 1 910 psig. This action was necessary to prevent valve chattering due to transient pressure spikes during safety injection pump starts, which causes unnecessary relief valve wear. The inspector verified proper completion of the DCP field work. The DCP will be closed out following the performance of an inservice leak test and safety injection surveillance test. The inspector verified that these tests were scheduled to be performed prior to entry into Mode Conclusions The root cause analysis to address repetitive Safety Injection relief valve failures was thorough. Corrective actions taken to resolve the problems were adequat Restart Issue 11.36 is closed for Unit ES Miscellaneous Engineering Issues E (Closed) Violation 50-272/94-24-04: feedwater nozzle bypass flow. This violation pertained to the licensee's failure to promptly identify and correct sustained periods of steady state reactor core power levels in excess of 100%. The licensee described the reason for the violation and the proposed corrective actions in their letter No. NLR-N94228, dated December 23, 199 As documented in Inspection Report 50-272 & 311/96-10, the inspectors found the corrective actions to address the Unit 2 concerns acceptable; the corrective actions for Unit 1 were equally acceptable, as documented in section E1.1 of this repor Based on the satisfactory resolution of this issue, this item is closed.
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. IV. Plant Support PS Miscellaneous EP Issues NRC Region I and Headquarters personnel attended a Steering Committee Meeting to discuss issues in preparation for the Salem Ingestion Pathway Exercise scheduled for May 5-7, 1998. The participants also included representatives from the States of New Jersey and Delaware, the Department of Energy and Emergency Preparedness personnel from PSE&G. Discussion topics included reviews of the Delaware and New Jersey Emergency Plan, integration of federal support, time line for generic plan development and review of resources available for the exercis NRC Region I emergency preparedness personnel will continue to participate in upcoming Steering Committee Meetings in support of the Salem Ingestion Pathway Exercis S 1 Conduct of Security and Safeguards Activities A routine core inspection of the security program was conducted by regional*
security specialists during the period of November 3-7, and 12, 1997. Areas inspected included: management support; audits; alarm stations, communications, and assessment aids; testing, maintenance and compensatory measures; training and quafification; protected area access control of vehicles; and the vehicle barrier system. The inspectors found that PSE&G maintained an effective site security program. Management support of program objectives was evident. Performance of security department personnel and equipment were generally good. PSE&G's provisions for land vehicle control measures satisfied regulatory requirements and licensee commitments. The site protected area barrier was properly installed and maintained, and satisfied the requirements of the NRG-approved security plan. The inspectors' detailed findings are documented in Hope Creek intergrated inspection report 50-354/97-0 V. Management Meetings X 1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on December 5, 1997. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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INSPECTION PROCEDURES USED IP37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 50001:
IP 61726:
Steam Generator Replacement Inspection Surveillance Observations IP 62707:
Maintenance Observations IP 71001:
IP 71707:
Licensed Operator Requalification Program Evaluation Plant Operations IP 71750:
IP 92901:
IP 92902:
IP 92903:
IP 92904:
IP 93702:
Plant Support Activities
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Plant Operations Follow up Maintenance Follow up Engineering Follow up Plant Support Follow up Event Follow up ITEMS OPENED, CLOSED, AND DISCUSSED Opened/Closed 50-272/97-19-01 50-311 /97-19-02 50-311/97-19-03 50-272/97-19-04 50-272/97-19-05 Closed 50-272/94-24-04 50-272&311 /96-18-05 50-272&311/97-003-01 50-272/97-001-00 50-272/97-006-0 /97-008-00 50-311/97-001-00 50-311 /97-005-00 50-311 /97-014-00 50-311/97-015-00 NCV NCV NCV NCV NCV Unit 1 Configuration Control Issues POPS TS violation Inadequate Surveillance Testing of PORV System Accumulator Discharge Check Valves Inadequate s*urveillance Testing of PORV Accumulator Solenoid Valves and Check Valves Inadequate TS Requirement Surveillance Test for POPS VIO Feedwater Nozzle Bypass Flow VIO Boron Injection Tank Isolation Valves Not Included in the IST Program VIO Operator Training and Qualification LER Boron Injection Tank Isolation Valves Not Included in the IST Program LER Inadequate TS requirement surveillance test for POPS LER Inadequate Surveillance Testing of PORV Ac.cumulator Solenoid Valves and Check Valves LER Inadequate Surveillance Testing of PORV System Accumulator Discharge Check Valves LER POPS TS violation LER Reactor Trip from 100% Power Following Loss of Both Operating Steam Generator Feed Pumps Special Report - 2A EDG failure
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ADFCS AR ASME ATWT BO Ms CFCU CR CRS CRT DAS DCPs dp EDG EDS EOPs FCRs l&C IST JPM LCO LE Rs LEFMs LORT MFL MS IVs NC Rs NRC OSG PDR POPS PORV PSE&G QA RCP RCS ROs RSG SA Rs SAT SG SGRP SI SR SRO TR
LIST OF ACRONYMS USED Advanced Digital Feedwater Control System Action Request American Society of Mechanical Engineers Anticipated Transient Without Trip Bills of Material Containment Fan Cooler Unit Condition Report Control Room Supervisor Cathode Ray Tube Data Acquisition System Design Change Packages Differential pressure Emergency Diesel Generator Electrical Distribution System Emergency Operating Procedures Field Change Requests Instrumentation & Controls lnservice Inspection Test Job Performance Measures Limiting Condition for Operation Licensee Event Reports Leading Edge Flow Meters Licensed Operator Requalification Training Master Fuse List Main Steam Isolation Valves Nonconformance Reports Nuclear Regulatory Commission Original Series-51 Steam Generator Public Document Room Pressurizer Overpressure Protection System Power Operated Relief Valve Public Service Electric and Gas Quality Assurance Reactor Coolant Pump Reactor Coolant System Reactor Operators Replacement Model F Steam Generator Simulator Action Requests Systematic Approach to Training Steam Generator Steam Generator Replacement Project Safety Injection Surveillance Requirement Senior Reactor Operator Tagging Request
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TRG TRIS TS TSSIP UFSAR wee WOs WR
Training Review Group Tagging Request Information System Technical Specification Technical Specification Surveillance Improvement Program Updated Final Safety Analysis Report Work Control Center Work Orders Wide Range