IR 05000272/1996007
| ML18102A277 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 07/19/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102A274 | List: |
| References | |
| 50-272-96-07, 50-272-96-7, 50-311-96-07, 50-311-96-7, NUDOCS 9608020007 | |
| Download: ML18102A277 (49) | |
Text
Docket Nos:
License Nos:
Report N Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272' 50-311 DPR-70, DPR-75 50-272/96-07, 50-311/96-07 Public Service Electric and Gas Company Salem Nuclear Generating Station, Units 1 & 2 P.O. Box 236 Hancocks Bridge, New Jersey 08038 May 19, 1996 - June 29, 1996 C. S. Marschall, Senior Resident Inspector J. G. Schoppy, Resident Inspector T. H. Fish, Resident Inspector J. Shannon, Reactor Engineer N. Della Greca, Senior Reactor Engineer Larry E. Nicholson, Chief, Projects Branch 3 Division of Reactor Projects 9608020007 960719 PDR ADOCK 05000272 G
EXECUTIVE SUMMARY Salem Inspection Reports 50-272/96-07; 50-311/96-07 May 19, 1996 - June 29, 1996 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant suppor The report covers a 6-week period of resident inspection; in addition, it includes the results of licensing submittal timeliness assessment by the NRR Salem Project Manager, a Salem restart item closeout inspection and a safety related breaker inspection by regional engineering inspector Operations Overall, operators adequately ensured plant safety during the inspection perio For instance, operators appropriately complied with abnormal and event notification procedures following an ammonia leak in the Unit 2 turbine building basement. (Section 04.3)
In three other instances, however, operators did not demonstrate a thorough questioning attitude. For example, operators did not know the extent or nature of leakage from the Salem Unit 1 spent fuel poo The operating shift did not establish appropriate compensatory measures until inspector questions prompted these actions. (Section 02.1)
When a 13kv breaker failed to close, the senior reactor operator (SRO) did not discover that equipment operators failed to follow procedures in restoring the 13kv switchyard breaker to service. (Section 04.1)
Lack of operator attention to control room indication resulted in an attempt to start a fuel handling ventilation fan without control power available. The ineffectual attempt had no safety consequence due to plant conditions. (Section 04.2)
Inspectors observed several indications that PSE&G efforts to improve oversight functions have resulted in improvement. The Salem staff improved the effectiveness of the Operating Experience Feedback (OEF) program through management changes, improved performance monitoring, more effective screening, enhanced communication with the training organization, and revisions to the OEF procedur The new OEF screening process resulted in improved accountability for implementing corrective actions. The NRC restart inspection item remains open, however, due to inspector identified discrepancies in the OEF procedure. (Section 07.1)
During the past year, the Quality Assurance staff completed numerous audits and observations leading to significant finding The plant staff, however, did not provide a basis to conclude that line management had addressed the findings in a timely and effective manne As a result, this restart inspection item also remains open. (Section 07.2)
The inspectors also noted that, as a result of ineffective management of licensing priorities, PSE&G did not submit three requests for changes to Technical Specifications in a timely manner. (Section 07.3)
- ;
(Executive Summary Continued)
- Maintenance Many examples of poor quality maintenance occurred during the inspection perio For example, maintenance staff could not effectively correct long-standing no. 2 station air compressor tripping problems.(Section Ml.3)
Several problems with maintenance involved failure to adhere to procedure In one instance, technicians failed to comply with PSE&G work standards and procedure requirements during a service water pump installation. Maintenance managers did not effectively communicate previous similar problems, and, therefore, directly contributed to a repeat occurrence.(Section M3.l)
Inspectors identified two examples of procedure use and documentation deficiencies during no. 2A emergency diesel generator turbocharger aftercooler wor Maintenance technicians did not complete procedure steps, within a section, in order, and with supervisor approval they proceeded to another section in the procedure prior to completing the previous sectio They did not stop work and change a procedure to reflect the work as performe (Section M3.2)
Senior Reactor Operators failed to thoroughly review emergency diesel generator surveillances. There was no resultant safety consequence due to plant conditions (shutdown and defueled). (Section M3.4)
A technician appropriately identified that a work order did not provide adequate control of post-maintenance testing for safety related relays. Although the technician and a planner developed more detailed instructions, they did not ensure the instructions met the Technical Specification 6.8.1.a requirements for procedures to control safety related maintenance.(Section M4.l)
In addition, a lack of maintenance support contributed to little progress in the reduction of operator workarounds and control room indicator deficiencies.(Section Ml.4)
In response to the poor quality-maintenance, the Salem General Manager stopped maintenance activities for a day and a half. The inspectors noted that the Salem managers and NRC inspectors have previously observed poor maintenance on numerous occasion In this instance, the Salem General Manager. implemented substantial changes intended to improve the quality of maintenanc The inspectors noted that managers at the highest levels of the PSE&G Nuclear Business Unit took an active role in supporting and developing the measures to improve maintenance performanc The inspectors also noted that event-free performance of the Salem units requires that equipment reliability be significantly improved prior to Salem Unit 2 restart. (Section Ml.2)
Regarding the 4kv circuit breaker inspection, the inspectors found the root cause effort to be extensive and comprehensiv Documentation of troubleshooting, testing, and trips to the vendor site were excellen Salem's efforts to challenge the vendor for deeper investigation into the root cause and more decisive corrective recommendations was particularly noteworth The inspectors concluded that with the exception of consideration of the opening/closing speed of the breakers, the Root Cause Analysis Team (RCAT) appropriately considered the effects of their circuit breaker adjustments on breaker operability and performanc The RCAT performed a thorough analysis and developed far-reaching, comprehensive corrective actions. Relative to the refurbishing and overhaul activities of the electrical switchgear, the inspectors found weakness in Salem's quality iii
- - - - - - -
(Executive Summary Continued)
assurance (QA) controls of procurement and vendor interface. The licensee's failure to perform an evaluation of the defect of 4.16 KV circuit breakers or to submit an interim report within 60 days was a violation of 10 CFR 21.2 The cause of this violation indicated a lack of effective communication between the technical personnel and licensing departments, and a failure of station procedures to adequately ensure evaluation of defects for 10 CFR 21 reportabilit Engineering The inspectors concluded Salem engineers identified and corrected the causes for poor screen motor and controller performanc The system has not yet experienced significant challenge due to the extended plant shutdowns, however, the inspectors considered the substantive component improvements adequate to support reliable system performance. This NRC restart inspection item is close (Section E2~1)
A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description indicated a need for a special focused review that compares plant practices, procedures, and parameters to the UFSAR description: While performing the inspections discussed in this report, the inspectors noted that plant practices, procedures, and parameters for the spent fuel pool sump pump run alarm differed from the description in the USFA This item is unresolved. (Section.
02.1)
.
The efforts to resolve severa) engineering restart issues were technically acceptable. Therefore, five restart items were closed and three additional items will be closed when the ongoing closure activities are completed The inspectors found, however, that the licensee's evaluation of spurious high steam flow signals causing safety injection was too narrowly focuse Consequently, the design changes initiated to minimize the impact of these signals may not achieve the desired results. This inspection also identified four unresolved items that require review and attention. The quality of the licensee's restart packages was adequate with improvements noted in packages developed later in the inspection period. These improvements were primarily due to the detailed review of closure packages by the system readiness review committee and by the management review boar Plant Support After-review of circumstances leading to an ammonia spill, the inspectors concluded plant staff did not comply with the tagging procedure requirement The procedure non-compliance did not violate regulatory requirements since the work was not a regulated activity. The inspectors noted, however, that plant staff failed to recognize the need to apply red blocking tags to ensure isolation of the ammonia storage tank from open portions of system pipin As a result, they failed to protect other workers in the plan Had the work involved higher energy systems or safety-related equipment, or if the storage tank isolation valves remained open longer, the staff's inadequate performance iv
(Executive Summary Continued)
could have resulted in more serious consequence (Section RI.I)
A security guard did not patrol his assigned area continuousl Security supervision follow up did not thoroughly assess the guard's inattention to dut They limited the thoroughness of their followup action because of previous good performance of the guar During the exit meeting, the general manager noted this as a poor practice and provided the proper guidance and direction to the security organization. (Section S4.I)
v
TABLE OF CONTENTS EXECUTIVE SUMMARY TABLE OF CONTENTS ii vi I. Operations...........
I I
I I
Conduct of Operations....
04
01.1 General Comments (71707)........
Operational Status of Facilities and Equipment.......
02.1 Spent Fuel Pool Liner Leakage, NRC Restart.Item II (Open)
........................
Operator Knowledge and Performance.........
0 Failure to Prepare a 13 kv Breaker for Closure, NRC Restart Item III.7....*...........
04.2 Operator Attention to Indications, NRC Restart Item III. 7 (Open).................
04.3 Ammonia Leak, NRC Restart Item 111.7 (Open)..
Quality Assurance in Operations.............
07.1 Adequacy of the Quality Assurance (QA) Program, NRC Restart Inspection Item II.20 (Open)
........
I
2
4
07.2 Operating Experience Feedback (OEF) Program, NRC Restart Inspection Item II.9 (Open).
07.3 License Change Request Timeliness.. :.
5
II. Maintenance.............
....
Ml Conduct of Maintenance.....
....
M General Comments
...................
Ml.2 Maintenance Stand-down, NRC Restart Item III.3 (Open).
Ml.3 Station Aii Compressor Repair, NRC Restart Item III.II and 11.2 (Open)..................
Ml.4 Operator Workarounds and Control Room Deficiencies, NRC Restart Item 111.8 (Open)............
M Review of General Electric Circuit Breaker Failures *.
Ml. Root Cause Analysis.............
Ml. Corrective Action for 4.16-kV Switchgear....
Ml. Control of Procurement and Vendor Interface.
Ml. Reportabil ity Requirements
....... *.
M3 Maintenance Procedures and Documentation
..........
. M Service Water Pump Installation NRC Restart Item 11 (Open)
........................
M Emergency Diesel Generator (EOG) Turbocharger Aftercooler Cleaning and Inspection..........
M Fuel Handling Building Ventilation, NRC Restart Item III.3 (Open)
.............
.....
M Emergency Diesel Generator Operability, NRC Restart Item III.3 (Open)...................
M4 Maintenance Staff Knowledge and Performance.........
M Use of Procedures for Post Maintenance Testing (PMT)
III. Engineering
..............
.......
E2 Engineering Support of Facilities and Equipmen vi
23
- E NRC Restart Issue T3 - Circulating Water Traveling Screen Motor Reliability (Closed) Engineering Restart Action Plan (Open)
.................
EB Miscellaneous Engineering Issues (92903)
........
EB.I Spurious High Steam Flow Signals Causing a Safety Injection - NRC Restart Issue 11.38 (OPEN)
......
E (Closed) Violation 50-272; 3II/94-I8-0I Nonconservative I25 Vdc Battery Acceptance Criteri E (Updated) Unresolved Item 50-272; 3II/95-06-0I Poor process for Configuration Control of Pipe Supports..
E (Updated) Unresolved Item 50-272; *311/94-32-05 Adequacy of the calculation for the new Pressurizer Overpressure Protection System............
E NRC Restart Issue II.37 - Concerns Over Service Water (SW) Piping Leaks (CLOSED)
............
E NRC Restart Issue II.29 - Reactor Head Vent Stroke Times *(CLOSED)
..................
E (Updated) Unresolved Item 50-272; 50-3II/93-26-0I -
Pressure Locking and Thermal Binding of Wedge Type Gate Valves PSE&G's resolution of the pressure locking and thermal binding of wedge type gate valves is Item II.24 of the NRC restart action plan......
E NRC Restart Issue II.28 - Reactor Coolant Pump (RCP)
Seal Water Flow Problems (CLOSED)..........
E (Closed) Unresolved Item 50-272 & 3II/92-0I-04 The containment spray motor operated valve*operability concern is Ite*m II.I of the NRC restart action pla E8.10 Conclusions and General Comments
EB.II Review of UFSAR Commitments..........
3B IV. Plant Support........................
3B RI Radiological Protection and Chemistry (RP&C) Controls....
R Ammonia Leak in Unit 2 Turbine Building.. *. *.
S4 Security and Safeguards Staff Knowledge and Performance.
S4.1 Security Awareness
....
....
V. Management Meetings........
XI Exit Meeting Summary...
X3 Management Meeting Summary X4 Management Changes
....
vii
....
40
40
I
- .
Report Details Summary of Plant Status Unit 1 and Unit 2 remained defueled for the duration of the inspection perio I. Operations
Conduct of Operations 01.l General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operation In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections belo Operational Status of Facilities and Equipment 02.1 Spent Fuel Pool Liner Leakage, NRC Restart Item III.7 (Open) Inspection Scope (71707)
The inspector conducted frequent tours of the fuel handling building
{FHB).
Fuel handling building ventilation and spent fuel pool cooling have increased safety significance with both units shutdown and defuele The *inspector discussed tour observations with the operating shift and the system engineering manage The inspector reviewed Updated Final Safety Analysis Report {UFSAR), section 9.1, Fuel Storage
- and Handlin Observations and Findings On May *21, 1996, the inspector toured Unit 1 FHB sump are The following equipment malfunction information system {EMIS) tags existed:
1) spent fuel pool {SFP) tell-tale no. 1 leaks excessively, dated 11/23/95; 2) FHB sump pump float switch does not start pump, dated 5/12/94; and 3) high level alarm float hangs up on sump cover plate, dated 5/19/96. Simply stated, the spent fuel pool liner may be leaking, the sump pump may not work, and the high level alarm may not alar Since equipment operators checked the sump once per day, an increase in leakage could remain undetected for at least one full da The Updated Final Safety Analysis Report section 9.1.3.3 states that the FHB sump pump running frequency will be observed through annunciators provided *in the control roo The inspector noted that FHB sump high level alarmed on the control room auxiliary typewriter, however, no control room alarm existed for sump pump run The sump pump float switch was not configured to provide this alarm. This item is unresolved pending resolution ~f similar nonconformances with the UFSAR and licensing basis {control air and fuel handling building ventilation).
(URI 50-272&311/96-07-01) (Also see NRC inspection report 50-272/96-06, Section E2.2)
In response to these concerns, the Senior Nuclear Shift Supervisor (SNSS) promptly generated a Condition Report (CR), CR 960529185, to address these issues. The CR stated that Operations submitted numerous action requests since 1988 identifying problems with the level devices in the Unit 1 FHB sum The CR requested that engineering evaluate long-standing sump pump and level float switch problems and determine methods to configure the plant in accordance with the UFSA In a followup inspection on May 30, the inspector noted that operating shift did not know the source of tell-tale leakage (SFP leakage or groundwater seepage). After the inspector questioned the boron concentration of the leakage, the SNSS directed chemistry to sample the leakag The chemistry technician reported a boron concentration of approximately 2400 ppm, indicative of SFP leakag The inspector subsequently questioned the prudence of continuing the current frequency of equipment operator (OE) sump inspections (once per day) given the degraded conditions. Thus, SNSS directed the Unit 1 EOs to perform sump inspections every four hour The inspector noted that chemistry last measured tell-tale leakage in November 199 The inspector questioned the present leak rate. The SNSS directed chemistry to periodically measure the tell-tale leak rate. *chemistry calculated a leak rate approximately equal to the November 1995 rate (400 ml/min).
c. Conclusions The inspector identified degraded conditions that presented a potential for undetected spent fuel pool leakage that were not well known by the operating shift. Once identified, the shift did not establish appropriate compensatory measures until inspector questions prompted these action Operator Knowledge and Performance 04.1 Failure to Prepare a 13 kv Breaker for Closure. NRC Restart Item II (Open) Inspection Scope (71707)
During a Unit 2 control room walkdown, the inspector reviewed the reactor operator's narrative lo Observations and Findings On June 6, 1996, Unit 2 control room operators attempted to close the 13kv bus section D-E breaker. The breaker failed to close because operators had not closed a control power breaker at the D-E breake Operators subsequently closed the control power breaker, closed the D-E breaker, and energized no. 23 station power transformer (SPT) to provide a second source of offsite power to the Unit 2 vital buse The senior reactor operator (SRO) initiated a procedure revision request to address the open D-E breaker control power breaker without reviewing
c.
requirements in the operating procedur The SRO did not initiate a CR to investigate why the control power breaker was not close In discussion with control room operators, the inspector found that Salem procedure SC.OP-S0.13-0014, Revision 9, 4, 14, and 23 Station Power Transformer Operation, step 5.3.11, requires equipment operators to close the control power switch after racking up.a 13kv breake On June 5, 1996, equipment operators racked up the 0-E 13kv breaker and failed to close the control power switch. This is a violation of TS 6.8.1 requirements which requires that procedures be adequately implemente (VIO 50-272&311/96-07-02)
The SRO took ineffective corrective actio He initiated a procedure change, but an existing procedure would have ensured the operators closed the control power breaker if operators had implemented it. In response, the Operations manager directed the SNSS to initiate a CR (960606369).
Preliminary results indicated that equipment operators did not follow the procedure because they did not know the procedure existed. Equipment operators relied upon skill of the craft, not procedure controls, to restore power sources that provide offsite power sources to the onsite vital buses:
Conclusions The SRO did not demonstrate a questioning attitude in addressing the failure of a 13kv breaker to close. Equipment operators failed to follow procedures in restoring a 13kv switchyard breaker to servic This NRC-identified failure to comply with procedure requirements is a violatio.2 Operator Attention to Indications. NRC Restart Item III.7 (Open) Inspection Scope {71707) Using Inspection Procedure 71707, the inspector conducted frequent control room tours and operating log review In addition, the inspector discussed operator performance with control room operators and operations managemen Observations and Findings On June 4, 1996, Unit 2 control room operators attempted to start no. 22 FHB exhaust fan following a temporary tag release to test the fa The operator pushed the start button, but the fan failed to star Operators identified that 28 VDC control power was still tagged out for the fa The operator could have detected the absence of control power, but he failed to notice that all the normal fan control indicating lights were not lit. Equipment operators restored 28 voe, the fan started, and the control room operator noticed the fan running six minutes later. Operator inattention contributed to a six minute run rather than the desired five second rotation chec The poor operator performance had no immediate safety consequence since the fan was not required for plant conditions existing at the tim *
c. Conclusions Lack of operator attention to control room indication resulted in an attempt to start a fuel handling ventilation fan without control power available. The ineffectual attempt had no safety consequence due to plant condition.3 Ammonia Leak-. NRC Restart Item III.7 COpenl Inspection Scope The inspectors observed licensee response to an ammonia leak in the Unit 2 turbine buildin Observations and Findings On June 7, at 9:00 a.m., a worker called the Control Room to report a strong ammonia smell coming from the basement area (88 foot elevation)
of the Unit 2 turbine building. The operators entered Abnormal Procedure SC.OP-AB.CR-0003(Q) - REV. 2, Toxic Gas Release, and directed all personnel to evacuate the Unit I and 2 turbine buildings. At 9:30 a.m., the SNSS declared an Unusual Event in accordance with section of the Emergency Classification Guid Operators identified the source
~f the leak at about 9:35 a.m~, and isolated it. At about II:OO a.m.,
Site Protection personnel verified the turbine area was free of toxic fume The SNSS subsequently terminated the Unusual Event and restored access to the turbine buildin No injuries occurred during the even (Section RI.I has additional details)
c. Conclusion Operators complied with abnormal and event notification procedures following the report of an ammonia smell in the Unit 2 turbine building basemen The inspectors concluded the operators responded appropriatel *
Quality Assurance in Operations 07.1 Adequacy of the Quality Assurance (QA) Program, NRC Restart Inspection Item I l. 20 CO pen l Inspection Scope Inspectors reviewed QA performance to assess effectiveness of licensee corrective action Observations and Findings The licensee described previous QA performance with the following problem statement: "Prior to the shutting the Salem Units down in I995, the Salem QA organization did not provide effective oversigh When QA identified problems the line organization did not always address the
- problems in a timely manne This resulted in the line organization not getting quality feedback on their performance, and subsequent failure to take effective corrective action."
In response to ineffective QA performance, PSE&G senior management made management changes, organizational changes to provide more meaningful assessments, and program change The management changes included a new Director of Quality Assurance and Nuclear Safety Review, a new Salem QA manager, and new direct reports to the QA manage The new QA management team initiated program changes to improve the quality of QA assessments, with some significantly improved result For example) an in-service testing (IST) audit determined that the Salem staff had not implemented an effective IST progra The QA staff initiated a stop work order for IST until the plant staff corrected the identified deficiencie The QA organization also took ownership for development of the Corrective Action Program (CAP).
The CAP includes a graded approach for root caused determinations. A separate NRC restart inspection item addresses the CAP in greater detai The inspector noted that the Management Review Committee reviewed and approved the closure package for adequacy of the QA progra This package is intended to provide an adequate basis for concluding that QA effectiveness has improved substantially. It does not, however, address the response of the line organization to problems identified by Q As a result, this item remains open until the licensee establishes a basis for concluding the line organization responds to QA findings in a timely and effective manne *
Conclusions During the past year, the Quality Assurance staff completed numerous audits and observations leading to significant finding Examples include the IST audit, with significant findings resulting in a stop work orde The inspector determined, however, that QA did not supply evidence that line management had addressed the QA findings in a timely and effective manne As a result, this*restart inspection item remains ope.2 Operating Experience Feedback COEF) Program. NRC Restart Inspection Item II. 9 (Open) Inspection Scope The inspectors reviewed the results of licensee actions to improve the OEF progra Observations and Findings Previous inspections concluded that the OEF program did not effectively prevent events that have occurred in the industry from occurring at NBU
facilitie In response to the concern about OEF effectiveness, the new OEF manager and the OEF staff improved the OEF screening process and program performance tracking capabilitie They also performed a self-assessment, implemented the resulting recommendations, and enhanced communication with the training organizatio The inspector reviewed a set of comprehensive performance indicators that provide managers the ability to assess staff timeliness in*
responding to assigned OEF actions. The inspector verified that OEF actions resulted in corrective maintenance, design changes, and procedure changes where appropriate. The Salem staff revised administrative procedure NC.NA-AP.ZZ-0054(Q), Operating Experience (OE)
Program, to clarify roles, responsibilities, and expectations. Although the revision incorporated numerous clarifications and improvements, the inspector identified that the staff could not provide a clear basis to establish that Salem staff met all of the responsibilitie For example, the staff could not furnish evidence that the General Managers, Hope Creek and Salem Operations had discharged their responsibilities as described in section 3.8 of the procedur The OEF staff initiated CR 960619251 to address this concern. This item remains open pending resolution of the CR and the resulting corrective actio Conclusions The Salem staff improved the effectiveness of the OEF program through better performance monitoring, improved screening, enhanced communication with the training organization, and revisions to the OEF procedur The performance monitoring resulted in greater accountability for implementing corrective actions. The inspector noted, however, that the OEF staff could not furnish evidence that plant staff met all of the responsibilities established in the.DEF procedur.3 License Change Request Timeliness Inspection Scope (71707)
The inspectors reviewed three licensing submittals to assess the timeliness of the submittal Observations and Findings On February 1, 1996, PSE&G informed the NRC that they planned to submit proposed amendments to the Technical Specifications for the control room ventilation system to reflect the reconfigured control room On April 2, 1996, the licensee informed the NRC that they planned to submit the proposed amendments on April 12, 199 The licensee submitted the amendments June 10, 1996, requesting that the NRC approve the amendments by July 22, 199 On February 1, 1996, PSE&G informed the NRC they planned to submit proposed amendments to the Technical Specifications for the Reactor Vessel Indication System (RVLIS).
On April 2, 1996, PSE&G informed the
NRC that they planned to submit the amendments on April 19, 199 The licensee submitted the proposed amendments on May 31, 1996, requesting that the NRC approve the amendments by July 15, 199 Licensee Event Report (LER) 95-016-0, dated August 18, 1995, discussed a discrepancy between the peak containment temperature in the licensing basis Main Steam Line Break and the maximum containment air temperature in Technical Specification (TS) 5. In the LER the licensee committed to resolve this issue, as well as the other issues raised in the LER, prior to entry into Mode On June 18, 1996, PSE&G submitted the proposed amendment to TS 5.2.2, requesting NRC approval by July 29, 199 c. Conclusions The inspectors concluded that, as a result of ineffective management of licensing priorities, PSE&G did not submit three requests for changes to Technical Specifications in a timely manne II. Maintenance Ml Conduct of Maintenance Ml.I General Comments Inspection Scope {62703)
The inspectors observed all or portions of the following activities:
- * * *
960315187:
960504040:
960320206:
960224046:
2B EDG starting air and turbo boost system upgrade fuel rod ultrasonic (UT) inspectioP for Salem Unit 2 service water pressure gauges seismic monitoring 2B EDG inspect/replace relays The inspectors observed that the plant staff performed the maintenance effectively within the requirements of the station maintenance progra Inspection Scope {61726)
The inspectors observed all or portions of the following surveillances:
- * * *
S2.0P-ST.DG-0013:
S2.0P-ST.DG-0002:
S2.0P-ST.FHV-0001:
S2.0P-ST.RM-0002:
2B Diesel Generator Endurance Run 2B Diesel Generator Surveillance Test Fuel Handling Building Ventilation Surveillance Radiation Monitoring Check Sources The inspectors observed that plant staff did the surveillance safely, effectively proving operability of the associated system.
Ml.2 Maintenance Stand-down. NRC Restart Item 111.3 COpen) Inspection Scope {71707)
Inspectors reviewed the efforts by Salem managers to improve the quality of maintenanc Observations and Findings Many lapses in maintenance during a three week period prompted the Salem Maintenance Department to stop work and review the conduct and quality of performance. Salem maintenance managers stopped all work on June 1 The causes for the stop work (identified by Salem staff) included work management process deficiencies, poor scheduling, and procedure non-compliance The causes also included insufficient supervisory oversight, inadequate shift turnover, a weak sense of ownership and accountability, and worker fatigue. Specific equipment-related maintenance problems included not filling a diesel starting air compressor with oil, turning the no. 2 station air compressor over to operations with numerous discrepancies, work on no. 23 service water pump without a work order present at the job, and installing no. 22 fuel handling building ventilation fan backward* and without required washer Other problems included not performing post-maintenance testing (PMT)
for a 4kv supply breaker, and turning valve 2CV71 -0ver to operations with missing linkag To correct the poor performance, Salem man~gers increased the number of
. supervisors in the field, reviewed work assignments to ensure worker skills matched job requirements, reinforced expectations for quality of workmanship, and assigned PMT coordinator In addition, the managers planned to re-organize the Salem planning, scheduling, tagging, and maintenance organizations under a single manager reporting to the Salem General Manage The managers concluded that they required the re-organization to improve coordination, communication, and teamwork within the department They also put senior managers in charge of the outage control center (including backshifts).
Conclusions Many examples of poor quality maintenance occurred during the inspection perio In response, the Salem General Manager stopped maintenance *
activities for a day and a half. The inspectors noted that the Salem managers and NRC inspectors have previously observed poor maintenance on numerous occasion In this instance, the Salem General Manager implemented substantial changes intended to improve the quality of maintenanc The in~pectors noted that managers at the highest levels of the PSE&G Nuclear Business Unit took an active role in supporting and developing the measures to improve maintenance performanc The inspectors also noted that event-free performance of the Salem units requires that equipment reliability be significantly improved prior to Salem Unit 2 restar *
Ml.3 Station Air Compressor Repair, NRC Restart Item 111.11 and 11.2 (Open) Inspection Scope (92903)
The inspector observed no. 2 station air compressor maintenance to assess station air reliabilit Observations and Findings On April 25, 1996, no. 2 station air compressor (SAC) tripped on high vibratio The system manager initiated actions to investigate the frequent no. 2 SAC trip On May 31, equipment operators prepared to rack up the no. 2 SAC breaker for a decoupled motor ru Equipment operators discovered that electricians had not installed the breaker in the cubicl Electricians installed a replacement breaker and operators attempted to start the SAC, however, the compressor did not start. Electricians discovered that they had installed permissive start jumpers (used for rotation checks when decoupled) in the no. 3 SAC instead of the no. 2 SA (Electricians had installed the jumpers in no. 3 SAC in April 1996 due an inadequate procedure.)
- On June l, electricians installed jumpers in the no. 2 SAC control cabine The operators attempted to start the no. 2 SAC and it tripped on high vibratio On June 2, operators started the no. 2 SA After two minutes the SAC tripped on low cooling water pressure. Maintenance staff determined that the SAC needed a service water low pressure permissive jumpe During the above process, maintenance staff experienced other minor setbacks involving control panel relays and annunciator On June 2, maintenance managers stopped no. 2 SAC work due to the above series of maintenance-related difficulties (see maintenance stand-down in section Ml.2).
Following the June 2 work stoppage, maintenance managers tasked a special SAC troubleshooting team to restore the no. 2 SAC to servic The team met with limited success to dat On June 6, the SAC tripped on high vibration on star On June 14, maintenance staff believed they corrected previous problems and requested that operators start the SAC *
for dynamic tunin On June 14, operators started the no. 2 SAC and the compressor tripped on high vibratio Conclusions Maintenance efforts to correct long-standing no. 2 station air compressor tripping problems have been ineffectiv Performance results in this area indicate a lack of quality and reliability in maintenance practices.
Ml.4 Operator Workarounds and Control Room Deficiencies. NRC Restart Item 111.8 COpenl Inspection Scope (71707)
The inspector discussed operator workarounds and control room indicator status with Operations managemen Observations and Findings The Operations Restart Plan addressed the need to eliminate operator workarounds and control room indicator (CRI) deficiencie.
Operator workarounds represent degraded plant conditions that substitute operator action for the normal operation of structures, systems and components In mid-March 1996, the Operations manager assigned a workaround manager to provide full time oversight and control of the workaround and CRI deficiency list. Plant staff continued to make little progress in this area, since the number of new items added to the list nearly offset the limited number of items worke **
The workaround manager implemented an effective tracking progra The manager methodically developed and improved activity prioritization.
The trends indicated a very high reschedule rate and a relatively low work completion rat Operations and Planning managers supported this effort. The maintenance staff, however, rescheduled a majority of their activities in this are The inspector concluded that maintenance managers placed a low priority on operator workaround Conclusions A lack of maintenance support contributed to little progress in the reduction of operator workarounds and control room indicator deficiencie Ml.5 Review of General Electric Circuit Breaker Failures Inspection Scope (62705)
The purpose of this inspection was to evaluate the root cause, the corrective actions, and the generic implications of the recent problems experienced with General Electric (GE) Magne-Blast 4.16kV circuit breakers. Specifically, the inspectors reviewed the following areas:
- * *
root cause analysis corrective actions procurement process for initial purchase of the breakers
- procurement process for subsequent maintenance and overhaul services
reportability requirements Ml. Root Cause Analysis Inspection Scope The inspectors examined the efforts of the Root Cause Analysis Team (RCAT).
The inspectors reviewed the final report, trip reports, testing summaries, and operating experience report Observations and Findings Summary of 4.16 kV Circuit Breaker Problems There are approximately 144, type AM-4.16kV, Magne-Blast General
- Electric circuit breakers installed at Salem Electric Generating Station, Units 1 & At Salem, all breakers are considered safety-rel ated because they can be used in safety-related and nonsafety-related applications. Therefore, a breaker operating in a nonsafety-related cubicle can be inserted into a safety-related cubicle. Salem also uses 13.8-kV, GE Magne-Blast circuit breakers; these are in nonsafety-related applications. Both, the 4.16kV and 13.BkV circuit breakers employ ML-13 operating mechanism Starting from January 1996, Salem experienced 4.16kV circuit breakers failing to latch closed and remain closed upon a close signal. This problem affects the following vertical lift circuit breakers with ML~13 mechanism which have. a close and latch ratings of 77kA or above:
4.16kV-250MVA-8, -9HB 7.2KV-500MVA-6HB 13.8KV-750MVA-5, -6HB 4.16KV-350MVA-2H 13.BKV-lOOOMVA-3, -4H At Salem, the first observed failure occurred on January 5, 1996, when the 4.16kV breaker operating the 15 service water pump failed to latch close In the following ten weeks, four additional breakers also failed to latch closed upon a close signa Salem established a root cause analysis team (RCAT) to determine the root cause of the five circuit breakers which had failed to latch closed. The RCAT established administrative measures so that any breaker that fails to latch is not repeatedly cycled thereby retaining most of the attributes which may have caused the proble The RCAT has prepared Condition Report PR #960315194 which described the root cause analysi.16-kV. Magne-Blast. Circuit Breaker Failure Mechanism After extensive testing of the failed breakers, the RCAT determined that the following conditions prevented the breaker t6 close ~nd remain
closed. The prop pin in the ML-13 mechanism failed to achieve the required position under the prop and caused the latching mechanism prop to hit the prop pin. The impact of the prop hitting the prop pin caused the prop to bounce out of its position. This sometimes results in the leading edges of the prop being chipped and flatte The failure of the prop pin to achieve the required position under the prop may have been due to misalignment, which causes the latching mechanism prop to impact the prop pin and the prop to bounce out of position (see Attachment}.
Root Cause of Failures The inspectors determined several contributing factors causing the failure of the 4.16kV circuit breakers, namely, the alignment of the stationary cubicles and stacked tolerance The 4.16kV stationary cubicles may not have been aligned correctly during the construction of the plant. Also, all circuit breakers are treated as safety-related and are interchanged in stationary cubicle When a circuit breaker is inserted into a cubicle, adjustments are made to align the breaker so that it can operate successfull When the same breaker is placed in another cubicle, it should be realigned to suit that current stationary cubicle. The.adjustments made to the breaker may have induced stresses in both the cubicle and the circuit breake Salem routinely sent breakers to GE Nuclear Energy's Apparatus Service Center for maintenance and repair. During previous refurbishment activities, errors may have been introduced in the alignment of the operating mechanism causing the prop to twist. Additionally, the prop spring pulls the prop on the left hand side and the prop stop pin restricts movement of the prop on the right hand side aggravating the twis Symptoms of Failure To help prevent similar breaker failures, the RCAT has developed the following list of symptoms to ascertain if the breaker is susceptible to the failing to latch closed proble *
Ensure the prop stop pin is in the fully forward position in the inspection window when the breaker is in the closed positio *
Examine leading edges of the prop through the inspection windows to see if prop is chipped or has a flat surface on the ti *
Review the history of the breaker to determine if it failed to latch closed on previous occasion *
Determine if the arcing contacts overstroke by observing if the tips of the contacts have been damaged by their impact on the dividers in the stationary contacts.
Examine the buffer blocks for cracks'and chips.
- c. Conclusions The inspectors found the root cause effort to be extensive and comprehensiv Documentation of the RCAT troubleshooting, testing, and trips to the vendor sight was excellent. Salem's efforts to challenge the vendor for deeper investigation into the root cause and more decisive corrective recommendations was particularly noteworth Ml. Corrective Action for 4.16-kV Switchgear Insoection Scope The inspectors reviewed the root cause analysis, the associated corrective actions, and vendor (General Electric) recommendations to evaluate the appropriateness of returning the breakers to servic Observations and Findings The RCAT has taken a number of corrective actions to ensure breaker operability and to return breakers to servic Salem has contracted GE to inspect and adjust the stationary cubicle Salem intends to check cubicle misalignment from front to back by oil wipes on bottle inserts (bushings).
GE previously checked the wipe height on the bottles but did not compare the contact wipes from the front to bac The RCAT developed a data sheet of mechanism and frame dimensions and required all breakers that have been serviced to meet this criteri Salem conducted the following tests and adjusted every breaker before releasing it for operatio *
operate the breaker several times
observe if the breakers exhibits any of the symptoms as described above in Section Ml. *
verify crank shaft end play - The outboard cranks on the crankshaft should be adjusted so the end play side is less than 0.15 inch. After this adjustment is made, the clearance of the prop pin to the frame should be a minimum of 0.25 inc *
verify that the minimum distance between the prop pin and the prop before the prop pin changes direction as follows:
The minimum distance between either side of the prop and the prop pin is 0.06 inch.
- *
The maximum difference between one side and the other is 0.032 inc The average of the two shall be within 0.06 to 0.115 inc If the above clearances cannot be attained, Salem adjusts the tension on the opening spring as require Changing the opening spring tension will load the closing spring action and thus reduce the closing speed of the breaker. A change of 1/4" corresponds to approximately a few milliseconds in closing tim The nominal specification for the opening spring is 7 1/4"; GE approved adjustments up to 6 15/16" for Sale The licensee tests a breaker after making all adjustments to confirm that it operates successfully without tripping, and captures the motion of the mechanism o*n film to obtain GE concurrence. for breaker operabilit Changing the preload on the opening spring will change the breaker opening tim Even though Salem measured the breaker contact opening time, this value cannot be compared with GE closing and opening speed requirements because measurement methodology is different. Although the licensee had considered the effect of this *adjustment on overall closing time, GE has a requirement for the minimum closing and opening speed of the arcing contact. Additional testing and analysis will ensure that the adjustments will not put the breakers out of specification. This will be an inspector follow-up item until such testing and analysis can be performe (IFI 50-272&311/96-07-03)
The RCAT recommended corrective actions to address this concern and the licensee committed to evaluating the concern prior to restar The GE proposed corrective action was a combination of (1) replacing the current prop spring with a stiffer one, (2) installing a stop pin to restrict the prop movement on the left hand side, and (3) adjusting the compression on the main contacts. This solution was different from the Salem corrective action. Salem could not implement the GE solution because GE has not tested their fix and does not have the replacement
- parts manufactured at this tim GE approved the corrective action taken by Salem based on observation of tests conducted on the breakers, and based on viewing the prop movement which Salem captured on film with a high speed camer Salem has committed to not return any breakers to operable status without GE concurrence that the adjustment program and methodology is acceptabl Conclusions The inspectors concluded that with the exception of consideration of the opening/closing speed of the breakers, the RCAT appropriately considered the effects of their adjustments on breaker operability and performanc The inspectors concluded that the RCAT performed a thorough analysis and developed far-reaching, comprehensive corrective actions.
- Ml. Control of Procurement and Vendor Interface Inspection Scope The inspectors reviewed purchase order E157777 dated December 3, 1969, issued by PSE&G to GE and associated documents to evaluate the licensee's process for purchasing components to be installed in safety-related applications before 10 CFR Appendix B was in effect. The inspectors also reviewed purchase order 1069619614600000 dated April 4, 1996, issued by PSE&G to GE to refurbish type AM-4.16kV, 350-1200 A and 2000 A circuit breaker Obs1:rvations and Findings Although the original circuit breakers were purchased before 10 CFR 50, Appendix B was in effect, the inspectors noted evidence that the licensee exercised some quality assurance controls in the purchase and maintenance of these component Inspections had been performed at the manufacturing facility and overhaul facility. Also, a seismic analysis had been performed by General Electric to ensure operability of the switchgear for operation basis and design ~asis earthquake Purchase order 1069619614600000 referenced a GE proposal, letter G-KT-4-030, dated February 9, 1994, which detailed the work included in overhaul and repair of GE type AM-4.16kV circuit breaker The refurbishment was to include labor, tooling, test equipment, engineering and Quality Assurance personne For Class IE material, 10 CFR Part 21, 10 CFR Part 50, Appendix Band IEEE Standards were applicable as interpreted by GE Nuclear Energ In the proposal, GE requested PSE&G to identify a cognizant individual to interface with GE on all applicable matter Upon contract award, GE was to identify a single-point contact responsible for interface applicable to this wor Salem identified a planner to interface with G Salem's planner gave verbal instructions to GE which Salem's quality assurance personnel could not readily verify when they conducted vendor surveillance The purchase order scope described an overhaul procedure for circuit breakers and yet preventive maintenance and corrective maintenance were often performed instead of a complete overhau When inspectors asked how the vender knows what specific work to perform on a particular breaker, both Salem procurement and GE replied that the vendor performed the work described in the purchase order. However, the purchase order did not describe the differences between a preventive maintenance activity, corrective maintenance activity and a overhaul. Apparently, the specific work to be performed by the vendor was negotiated between the PSE&G planner and GE personnel via informal, undocumented telephone communication *
16 Conclusions Based on a review of the original procurement documents, the inspectors determined that the circuit breakers were adequately qualified to perform their intended safety-related function Relative to the refurbishing and overhaul activities of the electrical switchgear, the inspectors found Salem's quality assurance (QA) controls on the procurement and vendor interface to be wea Discussions with the QA and procurement engineering.personnel indicated that they did not know the difference between breaker preventive maintenance and overhau The purchase order had a broad scope that required typical overhaul-like actions by the :;ervice contractor and yet sometimes the service contractor only performed an abbreviated version of this scope. This lack of vendor control may contribute to configuration control problems and breaker maintenance traceability problem The licensee had initiated corrective actions, CRCA 22 and CRCA 24 of Performance Improvement Request Number 00960315194, to address these concern Although the purchase order only contained vague instructions as to the scope of work to be performed, upon completion of breaker servicing, GE supplied a product quality certification which consisted of detailed documentation of the inspection, repair, and testing performed on the individual breake Ml. Reportability Requirements Inspection Scope The inspectors examined the licensee's reporting process for compliance with the requirements of 10 CFR 2 This regulation requires evaluation of deviations and failures to comply to identify defects and failures to comply associated with substantial safety hazards as soon as practical, and in all cases within 60 days of discover Observations and Findings On March 14, 1996, the RCAT prepared a document describing the six recent failures of 4.16 KV circuit breakers to remain close following a closed signal, Attachment 5 of the RCAT final report. This document clearly described the failure to remain close to be due to the insufficient timing of alignment between the prop pin and the pro On March 15, 1996, Salem published an industry report which detailed that three of the six failed breakers were installed in safety-related applications and had been overhauled by the manufacturer within the last 18 month The inspector considered this date to be the discovery date since the documentation identifed the existence of a deviation potentially associated with a substantial safety hazar Overhaul procurement documents (Special Process Control Sheet of the Product Quality Certification for Purchase Order Pl06961961460) required satisfactory operation of the circuit breaker to trip close The
failure of the breaker to latch closed upon a trip signal constitutes a deviation from this technical requiremen On March 18, 1996, a request was made to evaluate reportability under 10 CFR 50.59, 50.72, and 50.73, to licensin On May 1, 1996, licensing initially determined that the failures were not reportabl By March 21, 1996, all installed safety-related 4.16 KV breakers that are normally in the closed position had been inspected to ensure that their prop pins were full forward due to the engineering department's concern about the generic nature of the failure mechanis On May 21, 1996, Form 1 from~uclear Administrative Procedure NC.NA-AP.ZZ-0035(Q) - Revision 5, "Nuclear Licensing and Reporting", was initiated to begin the 10 CFR 21 evaluation proces Form 1 identified the components in question as being necessary to assure the capability to shutdown/maintain shutdown of the reactor and necessary to prevent accidents or to mitigate the consequences of accident The completed form also identified the breakers as having a potential defect and a potential noncomplianc However, the initiation of this form was greater than 60 days from discovery and no report was submitted under 10 CFR 21, 10 CFR 50.72, or 10 CFR 50.73 within 60 days of discover This was violation of 10 CFR 21.2 (VIO 50-272&311/96-07-04).
Upon being unsure about completing the evaluation within 60 days, the regulation allows for filing an interim report until the evaluation can be complete The licensee did not submit an interim repor Upon receipt of the Form 1 and the final root cause report dated May 30, 1996, licensing decided to reconsider their original reportability determination and again chose not to perform a 10 CFR 21 evaluatio On June 27, 1996, the licensee submitted a four-hour report under 10 CFR 50.72(b)(2)(iii)(A) and on May 30, 1996, the licensee submitted a Licensee Event Report under 50.73(a)(2)(v).
The inspectors concerns were that there was a lack of communication between the technical personnel involved in the root cause and licensing in that the technical personnel had a clear understanding of the serious nature of the problem and an understanding of the failure mechanism of the basic component and yet licensing based their reporting decision on limited information. This lack of communication and licensing's willingness to wait for a completed, signed-off root cause report (that can take 5-6 months in some cases), resulted in inadequate timeliness for reporting requirement The inspectors were also concerned that plant procedures and processes may have contributed to the inadequate reporting of the defect of the 4.16 KV breaker The corrective action program automatically generated a reportability determination for 10 CFR 50.59, 50.72, and 50.73 upon the initiation of a Significance Level 1 Action Reques However, no automatic reportability determination is made for 10 CFR 2 *
- Also, Procedure NC.LR-AP.ZZ-0006(Q) - Rev. O, "10 CFR 21 Evaluation and Reporting," Section 5.4.2 defines "Discovery" as the date that the Manager - Licensing and Regulation concurs that the concern is potentially reportable under 10 CFR 21, whereas 10 CFR 21.3 defines discovery as "the completion of the documentation first identifying the existence of a deviation or failure to comply potentially associated with a substantial safety hazard."
The difference between these two definitions may create confusion to plant personnel in determining 10 CFR 21 reporting requirement Conclusions The inspectors concluded that the licensee's failure to perform an evaluation of the defect of 4.16 KV circuit breakers or to submit an interim report within 60 days was a violation of 10 CFR 21.21. This violation indicated a lack of communication between the engineering and licensing organizations, as well as a failure of station procedures to adequately ensure evaluation of defects for 10 CFR 21 reportabilit M3 Maintenance Procedures and Documentation M3.1 Service Water Pump Installation NRC Restart Item III.3 (Open) Inspection Scope C 62703)
The inspector observed work in progress and reviewed the work packages and associated procedures for work order 95042620 The inspector discussed the activity with maintenance technicians, supervisors, and manager Observations and Findings On May 31, 1996, the inspector observed work on the no. 23 service water pum The technicians did not maintain the work order at the job site as stated in the Salem Work Standards Handboo The inspector reviewed SC.MD-EU.SW-0002, Revision 5, Johnston Service Water Pump Removal and Installation. Technicians incorrectly marked step 5.1.l nqt applicable (N/A), although the step was required to document supervisor review of prerequisites, precautions and limitations prior to the start of the job. The inspector verified, by technician signature, that technicians had performed the pre-job requirement Technicians marked additional steps N/A without providing justification in the comments section of the procedure, as required by NC.NA-AP.ZZ-0001 (Revision 7), Nuclear Procedure System Requirements. This is another example of a violation of TS 6.8.l requirements to implement procedures for control of safety-related activities (see section 04.1).
The procedure violation is a repeat of a May 2, 1996, violation (see NRC Open Item 50-272&311/96-06-01).
The inspector discovered that the site services division of the maintenance department did not receive the May
- les~ons-learned training provided to other members of the maintenance departmen The inspector also noted that technicians did not perform steps specified by SC.MD-EU.SW-0002 in the required sequence. Step 5.3.20 required installation of a Maloney kit (anti-corrosion sleeves for fasteners) and pump discharge flange fastener The technicians stated that they could not complete the step in proper sequence because the Maloney kit, 8 stud~ and 16 nuts were missin They obtained identical studs and nuts from another service water pump package and temporarily installed the discharge flange without installing a Maloney kit. The inspector considered the partial completion of step 5.3.20 acceptable since the technicians needed to immediately install the flange to prevent service water bay flooding on the incoming tide. Technicians planned to pull one stud at a time to install the Maloney kit when it became availabl The inspector considered this a reasonable approach to avoid service water bay flooding, but noted that no procedure controls existed for this proces In this case, no safety consequence resulted from the technicians not following procedures or insuring that they obtained all parts necessary to perform a time-critical task prior to starting the jo The inspector discussed the performance problems with Unit 2 senior maintenance manage He promptly stopped work on the no. 23 service water pump until the maintenance supervisor reviewed and adhered to the required procedures. Maintenance managers conducted a roll-down meeting with all personnel in the group to communicate circumstances of the problem, and to emphasize the importance of adherence to work standards and compliance with procedure requirement Conclusions Maintenance technicians failed to comply with PSE&G work standards and procedure requirements during the conduct of service water pump installation. Failure to effectively communicate past shortcomings in this area directly contributed to this repeat occurrence. This NRC-identified failure to comply with procedure requirements is a violatio M3.2 Emergency Diesel Generator CEDGl Turbocharger Aftercooler Cleaning and Inspection a. Inspection Scope (62703)
The inspector reviewed the work package and associated procedure for work order 95082419 The inspector discussed this activity with maintenance technicians, supervisors, and manager b. Observations and Findings On June 26, 1996, the inspector observed work in progress on the 2A EO The inspector reviewed SC.MD-PM.DG-0002(Q), Revision 4, Diesel Generator Turbocharger Aftercooler Cleaning and Inspe~tion. The inspector noted
- that technicians completed steps 5.2.14 through 5.2.17 prior to completion of step 5.2.13 steps in section 5.2 Removal/Disassembl The inspector also noted that the technicians proceeded to section Reassembly/Installation, prior to completing all the steps in section 5.2, without appropriate documentatio The technicians obtained supervisor approval to perform the steps out of order, however, they made no effort to revise the procedure to reflect the manner in which they actually performed the wor Nuclear Administrative Procedure, NC.NA-AP.ZZ-OOOI{Q), Nuclear Procedure System (NAP-I), Revision 7, Section 5.3.7.D, requires that steps identified with numbers or letters (e.g., 5.1.2 or 5.1.2.A) should be completed. in order unless the procedure. a 11 ows otherwise. Sal.~m common procedure SC.MD-PM.DG-0002(Q), Revision 4, Diesel Generator Turbocharger Aftercooler Cleaning and Inspection, step 3.11, requires that applicable steps within a procedure should be completed prior to starting the next sectio Failure to perform the procedure steps and sections in sequence are additional examples of violation of NC.NA-AP.ZZ-OOOl(Q),
Nuclear. Procedure System (Revision 7), requirement The inspectors concluded that performing the procedure steps out of order had no immediate safety consequence, since technicians completed the missed actions prior to restoration of the EO Conclusion The inspector identified two examples of procedure use and documentation deficiencies. Technicians performing work on the turbocharger aftercooler did not complete the steps within a section in order, and, with supervisor approval, the technicians proceeded to another section in the procedure prior to completing the previous section. They did not stop work and change the procedure to reflect the work as performe M Fuel Handling Building Ventilation. NRC Restart Item III.3 (Open) Inspection Scope (61726)
In preparation for fuel movement, the inspector reviewed SC.RP-ST.FHV-1140, Revision 0, Fuel Handling Building Ventilation System Negative Pressure Tes The inspector discussed observations with Radiation Protection managemen Observations and Findings On June 5, 1996, the inspector reviewed SC.RPST.FHV-114 The inspector disc.overed an improperly calculated average pressure readin The irispector also found that technicians did not perform an independent verification of the calculations as required by step 5.2.7 of SC.RP-ST.FHV-114 In developing the procedure, Radiation Protection {RP)
staff assigned a procedure use category that did not require use of the procedure in the field nor individual step documentatio The inspector determined that the RP staff chose an inadequate procedure use classification since they performed the surveillance infrequently {every
refueling outage) and the procedure required documentation-of equipment performance necessary to prove operability, as specified in Technical Specification 4.9.12.d.3. Licensee procedure NC.NA-AP.ZZ-0001 (Revision 7), Nuclear Procedure System, attachment 3 requires use categories be assigned based on the importance of documentation and sequential performance of procedural steps with regard to personnel and equipment safety and to safe plant operatio Lack of a required independent verification and improper procedure use classification are additional examples of failure to comply with procedures, as required by TS 6. (see section 04.1).
Radiation Protection management took prompt and appropriate action to address the deficiencies. They broadened the scope of their investigation to include all RP owned Technical Specification surveillance procedure The review identified other incorrect calculations in past surveillances and similar procedure use category inadequacie The RP technicians initiated a process to improve the quality of RP surveillance procedures, including upgrading the procedure use categor The fnspector noted that the miscalculation in SC.RP-ST.FHV-1140 and RP identified miscalculations did not affect previous satisfactory surveillance determination *
c. Conclusions An RP technician failed to perform an independent verification of calculations as required by a fuel handling building surveillance. This NRC-identified failure to comply with procedure requirements is a violation. Radiation Protection management took corrective action intended to identify and correct similar deficiencies in all RP sponsored Technical Specification surveillance procedure M Emergency Diesel Generator Operability, NRC Restart Item III.3 COpen) Inspection Scope (61726)
The inspector reviewed the results of EOG surveillance Observations and Findings On June 11, 1996, the inspector reviewed S2.0P-ST.OG-0001, Revision 19, 2A Diesel Generator Surveillance Tes The inspector noted that the equipment operator marked a required diesel fuel oil day tank check for accumulated water N/ The SRO reviewed the EOG surveillance without questioning the equipment operator about the meaning of N/ The inspector determined that the equipment operator had performed the required check and the surveillance satisfactor The inspector also reviewed S2.0P-ST.OG-0003, Revision 21, 2C Diesel Generator Surveillance Tes The no. 21 diesel fuel oil storage tank level (OFOST} did not meet the criteria specified on the restoration
- checklist. The equipment operator annotated this fact in the comments section of the surveillance with a reference from the restoration checklist. The SRO reviewed the EDG surveillance and declared the surveillance satisfactory without documenting how the no. 21 DFOST met the criteria as specified in the procedure. There was no resultant safety consequence due to plant conditions (shutdown and defueled). The inspector noted that operators used a mode 6 EDG operability surveillance to verify ari undefined mode EDG availability determinatio Conclusions Senior Reactor Operators failed to thoroughly review emergency diesel generator surveillances. There was no resultant safety consequence due to plant conditions (shutdown and d~fueled).
M4 Maintenance Staff Knowledge and Performance M Use of Procedures for Post Maintenance Testing CPMT) Inspection Scope (62703)
The inspector reviewed PMT for relay installation on the no. 2B EDG to ensure that plant staff implemented required procedures and control Observations and Findings On June 13 an Instrumentation and Controls (l&C) technician noted that work order (WO) 960224046 required PMT for relays replaced on the no. 2B ED He also noted that the WO did not provide adequate guidance for a complicated task. The technician worked with~ planner to develop a twenty-eight step PM They added to steps to the work order "D" page, and the technician successfully performed the post-maintenance tes The instructions required the technician to open and shut 24 VDC and 125 VDC circuit breaker It also required him to install and remove jumper The inspector noted that Salem uses the "D" page to provide general information to worker The work control procedure does riot require review and approval of the "D" page equivalent to the review and approval for safety related procedure Failure to develop and implement a procedure to control safety related post-maintenance testing is an additional example of failure to comply with procedures, as required by TS 6.8.1. {see section 04.1).
c. Conclusions A technician appropriately identified that work order 9602254046 did not provide adequate control of post-maintenance testing for safety related relays. Although the technician and a planner developed more detailed instructions, they did not ensure the instructions met the Technical Specification 6.8.1.a requirements for procedures to control safety related maintenanc *
E2
III. Engineering Engineering Support of Facilities and Equipment E NRC Restart Issue T3 - Circulating Water Traveling Screen Motor Reliability (Closed) Engineering Restart Action Plan (Open) Inspection Scope Newly installed circulating water traveling screen motors did not exhibit reliable operation. Also, the control circuits for the screens did not perform reliabl Observations and Findings Salem engineers determined poor workmanship during initial motor construction, aggravated by the compact design of the motor, caused the motor failure They determined the causes for control circuit failures were:
misadjusted, corroded, or fouled limit switches for the automatic spray control valves; and an inadequate procedure for calibrating the speed control bistable Design engineers revised the motor specifications and required a substantially more rugged and conservative design.* The new motors have a larger than standard frame size, a new requirement for limiting casing heat rise, a new requirement for end turn windings to be insulated to eliminate winding cross-overs, and a higher insulation rating. The vendor tested the new motors under loaded conditions while measuring parameters such as motor speed, torque, horsepower, full load amps, and motor temperature rise. The new motors met o~ exceeded all specified criteria. The inspector reviewed test data and noted that, for normal screen speed, the temperature rise for the new motors was about 21 degrees Fahrenheit compared with the failed motors that experienced nearly a 250-degree rise. Also, the amperage draw on the new, more efficient motors was about 80% of the nameplate rating at slow speed compared with 95% to 110% of nameplate for the failed motor Salem personnel replaced the automatic spray valves with manual, normally-open spray valves, eliminating all limit switch and speed interlock The water demand for the consequential continuous spray is within the capacity of the spray wash pump Personnel also revised the calibration procedure for the screen speed control bistable Inadequacies in the old procedure had resulted in bistables trying to energize two motor speeds simultaneousl Consequently, bistables failed and in turn caused speed controller failure The root cause team also noted that the original design change package (DCP) should have identified that the originally-specified motor design was inadequat Problem Statement 2, items 5.b and 5.c of the Engineering Restart Action Plan, addresses this and other DCP quality issues.
24 Conclusions The inspectors concluded Salem engineers identified and addressed the causes for poor screen motor and controller performanc The system had not experienced significant challenge due to the extended plant shutdowns, however, the inspectors considered the improvements adequate to support reliable system performance. This NRC restart inspection item is close ES Miscellaneous Engineering Issues (92903)
On February 23, 1996, the NRC issued their Restart Action Plan for the Salem Units. This Plan contains the programs and corrective actions that the NRC will inspect prior to the restart of the Salem plants. The items described below are included in the NRC restart action pla ES.I Spurious High Steam Flow Signals Causing a Safety Injection - NRC Restart Issue II.3S COPEN)
Inspection Scope On April 7, 1994, during an automatic Unit *1 reactor trip, the sudden closure of the turbine stop valves caused a pressure wave in the main
.
steam pipin The resulting high steam flow signal, coincident with the low reactor coolant temperature at the time, caused an inadvertent automatic actuation of the safety injection system that complicated the reactor shutdow This event is described in detail in Inspection Reports Nos. 50-272;311/94-80 and 50-272;311/94-1 The purpose of the inspection was to review PSE&G's actions to address the inadvertent safety injection signal and prevent its recurrenc Observations and Findings PSE&G's evaluation of the April 7, 1994 event determined that the high steam flow signal was the result of *short duration pressure pulses initiated by the rapid closure of the turbine stop valve To preclude inadvertent high steam flow signals in the future, the licensee decided to add a lag function to the main steam flow transmitters and, thus, filter out the high frequency pulses that had created the signal. The original modification replaced the existing electronic board of the Rosemount flow transmitters with a "R" type boatd that had adjustable dampin The licensee selected a damping of 225 +/- 25 milliseconds (msec).
To ensure the adequacy of the damping selected, later PSE&G constructed a mathematical model of the main steam system, from the steam generator to the stop valv Using this model, they simulated stop valve closures at different power levels and calculated the transient pressure response as a function of time in the main steam piping. These pressure transients were then mathematically filtered through a resistance-capacitance (RC) circuit. Varying the value of the RC-circuit
components, the licensee was able to select a time constant such that the amplitude of the pressure wave was less than the amplitude required to initiate a high steam flow signal. This time constant was then used to set the time response of the transmitter PSE&G also selected for this analysis a level of protection ~p to maximum power level of 40%.
The licensee stated that this power level was selected because, for a reactor trip from above 40%, a spurious high steam flow signal is always generate In addition, the coincidence of this signal at high power with a low reactor temperature was considered unlikel The insp~ctor's review of calculation s~C-MS-MDC-1377, Revision 0, dated February 2, 1995, determined that the licensee had evaluated wave amplitudes with damping between 500 and 700 msec. and that, at 40% flow, a damping greater than 550 msec. would. cause the amplitude of the differential pressure wave at the transmitters to drop below 0.75 psi The inspectors identified no concerns with the licensee's assumptions and the calculation metho Based on the results of the calculation, the licensee decided to set the damping of all transmitters to between 55o*and 700 mse The design change packages (DCPs) for Unit 1 (lEC-3328) and Unit 2 (2EC-3293) were revised accordingl The upper damping limit was selected to ensure the required instrumentation system respons To evaluate the adequacy of the licensee actions, the inspectors reviewed a variety of documents, including applicable sections of the FSAR and technical specifications, flow diagrams and instrument loops, the DCP safety evaluation and instrument calibration record FSAR and Technical Specification Review In reviewing the emergency core cooling system design bases, the inspectors determined that Section 6.3.3.7 of the FSAR included a time-table for safety action initiation. This table stated that the initiation of a safety injection signal (SI) plus associated instrument lag would occur within 1.2 second Further review of-other licensee documents determined that a response time of 2.0 seconds, rather than the 1.2 seconds, was being used as a.basis for initiating protective action For instance, Table 3.3.5 of the technical specification requires the response time for reactor trip (from SI) due to high steam line flow coincident with low steam line pressure to be 5 2.0 second The.same maximum time was used in the Unit 2 master time response procedure No. S2.IC-TR.ZZ-0002(Q), Revision 0, for the same signa In addition, for high steam line flow coincident with low-low average reactor coolant temperature CT.vs the same documents required the SI signal to be initiated within 5.75 second The discrepancies were discussed with the licensee who initiated a problem report (No. 00960502113) to review the design bases and initiate necessary corrective action The preliminary review by the licensee
identified additional discrepancies in this area that are being reviewed under the same problem report. This item is unresolved pending the licensee's evaluation of the identified discrepancies and the NRC's review of the corrective action. (50-272&311/96-07-05)
Transmitter Response lime Measurement As stated previously, to resolve the inadvertent high steam flow signal issue, the licensee decided to replace the electronic board of the main steam flow transmitters with a "R" board which contains a RC circuit to provide for adjustable dampin The response time of the transmitter is adjusted by changing the resistance of this circuit. * For any given resistance value~ ho~ever, the response time of the transmitter is not fixe Instead, it follows an exponential function that is based on the resistance and capacitance values (time-constant).
In a letter to the licensee, dated July 6, 1994, Rosemount defined the time-constant as the time for the unit to reach 63.2% of a step input pressur In the same letter, Rosemount also provided some guidance regarding the use of a ramp input to measure the response time of the transmitter and included an example of the difference between the ramp and step function response times~ This example showed that for the same time-constant, the response time to a step function is longer than the one measured with a ramp functio The inspector's review of special test procedure STP-1, Revision 0, a modified version of Maintenance procedure SC.IC-TR.ZZ-OOOl(Q),
Revision 2, determined that, in August 1994, the response time of the Unit I steam flow transmitters was changed using the ramp method and that the lag time was measured at the 50% mark of the ram The response time curves contained within this procedure also showed that the measured response time would be considerably higher if it were measured at 75-80% of the curve, for instance, and very long as the ramp approached 100%.
Considering that the actual response time of a transmitter is longer than that measured by the ramp input method, as indicated by the example in the Rosemount letter's, and that the transmitter output is.an exponential function, the inspectors expressed a concern that the true response time of the transmitter might be longer than desirable. The longer time may not be a concern for the purpose of avoiding an inadvertent SI, following a fast closure of the turbine stop valve The longer time, however, could be unacceptable for the purpose of initiating a SI within the TS or FSAR specified time, in the event of a main steam line brea The design analysis had not addressed this issue or how the transmitter response time would be affected by different size line break This issue is unresolved, pending appropriate analysis and action by the licensee and review of its acceptability by the NR (50-272&311/96-07-06)
- Safety Evaluation The inspector's review of the design change package lED-3328 determined that the licensee had reviewed the revised design for applicability of the 10 CFR 50.59 and addressed the various questions regarding its impact on the FSAR, TS, and procedure, but concluded that a safety evaluation was not required. Apparently, the same conclusion was reached by the Offsite Safety Review group during the review of the original design change package, in 199 At that time, the conclusion was based primarily on the basis that the additional time did not impact the initiation of safety injection signal time specified in th~ FSA Based on the licensee understanding of the issue at the time of transmitter change, the inspectors believed that the results of the evaluation would have remained the sam The inspectors, nonetheless, disagreed with the licensee's conclusions in that the electronic board changes modified the response time of transmitters that are required to perform a function described in the FSAR and the T Therefore, a safety evaluation according to 10 CFR 50.59 was require The inspectors also observed that the current procedure, as well as the procedure in effect at the time of the modification, contained acceptable instructions for the engineering staff to properly address the changes.
The inspectors discussed this issue with the licensee who indicated that, while reviewing the inspector's technical comments, they would also reevaluate the need for a the safety evaluation under 10 CFR 50.5 They also indicated that they would reevaluate their process to determine if it could be strengthened, particularly in light of the new guidance contained in the NRC inspection manual, part 990 This item is unresolved pending the licensee's reevaluation of this issue and the NRC review of their corrective action {50-272&311/96-07-07)
Transmitter Calibration The inspectors reviewed the Unit 2 master time response procedure, No. S2.IC-TR.ZZ-0002(Q), Revision 0, to evaluate the impact of approximately 0.7 seconds delay on the actuation signals that receive their input from the main steam line flow transmitters. The inspectors determined that the licensee calculated the loop response using the arithmetic sum of the worst.response time measured for the individual component This sum was then compared to the required time to establish its acceptability. The inspectors found that the response of the applicable loops was within the required time with sufficient margi However, this review also determined that four of the eight flow transmitters had response times ranging from 740 to 870 milliseconds, therefore, well above the 700 milliseconds specified in the calibration procedur The other four had measured response times of 675 to 100*
milliseconds, i.e., within 25 millisecond from the upper limit, using the licensee's ramp metho The additional delay, if measured
accurately (see "Transmitter Response Time Measurement," above), would not increase the response time of the loop beyond its required tim The inspectors, nonetheless, expressed a concern that four transmitters had been calibrated outside their required response band and the discrepancies had not been observed or questioned by supervisory personnel in maintenance and plant operations. The licensee initiated an investigatio This item is unresolved pending completion of the licensee investigation and review of its results by the NR (50-272&311/96-07-08)
E (Closed) Violation 50-272; 311/94-18-01 Nonconservative 125 Vdc Battery Acceptance Criteri This issue pertains to the inadequate battery acceptance criteria identified by the NRC during a followup inspection of the electrical distribution syste It is identified as Item II.15 of the NRC restart action plan for Sale The NRC conducted a review of the licensee's actions to address this issue and found them acceptable. *The details of the NRC review of this item are included in an attachment to Inspection Report No. 50-272; 311/96-06. This item is closed.
. E (Updated) Unresolved Item 50-272; 311/95-06-01 Configuration Control of Pipe Support Poor process for *
This item, identified as Item II.19 of the NRC restart action plan for Salem, was opened to track the licensee's efforts in the follow-up and resolution of concerns in regard to errors in.stress calculations and to the technical and procedural validity of a modification in the containment spray syste The inspectors verified that the licensee's investigations had been completed and that the results of the investigation had been submitted to the NR The investigation was performed by an outside independent agency and appeared to be broad and thoroug The investigation, however, disclosed some weaknesses in the licensee's process and procedures for handling such issue The licensee's letter to the NRC included their proposed, and in some cases implemented corrective actions to resolve these inadequacie This item remains open pending the NRC review and verification of implementation of these corrective action E (Updated) Unresolved Item 50-272; 311/94-32-05 Adequacy of the calculation for the new Pressurizer Overpressure Protection System (POPS) design basis transients. The POPS ability to mitigate overpressure events under 312°F is Item II.20 of the NRC restart action pl an..
Background The POPS uses two pressurizer power-operated relief valves
{PORVs) to mitigate overpressure transients at low temperature {<312°F)
and to keep the peak pressure below the limits of 10 CFR 50, Appendix G,
"Fracture Toughness Requirements," for brittle fracture protection. The Appendix G limits are incorporated in *technical specifications {TS) as pressure-temperature {P/T) curves specific to each unit's reactor vessel. The original design-basis mass addition transient for the POPS was based on the start of a safety injection pump {780 gpm) and its injection into a water solid reactor coolant system {RCS).
POPS was designed to meet the single failure criterion, with either PORV having sufficient relief capacity to limit the peak pressure to less than the P/T curve limi An NRC safety evaluation report, dated February 21, 1980, associated with Amendment No. 24 to the Unit 1 TS, approved the Salem POPS setpoint of 375 pounds per square inch gage {psig), based on the calculated peak transient pressure of 446 psig and a 14 psi margin {at that time) below the Unit 1 Appendix G limit of 460 psig. Requirements for the Unit 2 POPS were incorporated into the unit's TS prior to initial startup and were approved based on the Unit 1 POPS safety evaluatio The P/T limits for all reactor vessels decrease with successive operating cycles due to irradiation effects on the vessel material Therefore, margin between the peak transient pressure and the P/T limit change as subsequent revisions of P/T curves are reviewed and approved by the NR The Salem Unit 1 P/T curves were revised in February 1990 in TS Amendment No. 108, which established a more restrictive limit of 450 psig at low temperatures. The Unit 2 P/T curves were approved {at the same time) in TS Amendment No. 86, which established a limit of 475 psig. These curves are valid for up to 15 effective full power years of operatio Subsequent to the TS amendmerits, in 1993, Westinghouse informed PSE&G of a condition that potentially could cause the automatic start of a second safety injection pum The starting of a second pump with a solid reactor coolant system would, in turn, result in a pressure spike that could exceed the 10 CFR 50, Appendix G criteria for the POPS relief valves setpoint and put the plant outside the design base The NRC review of this issue (Inspection Report 50-272;311/94-32) resulted in the identification of four apparent violations, as described below, and the initiation of escalated enforcement actio *
EEI 94-32-01 Failure to report an unanalyzed condition, as required by 10 CFR 50.72 and 7 When PSE&G became aware that the TS margins were no longer available and that the Appendix G limits of both units could be exceeded at low temperature (below 312°F), a reportable condition existe PSE&G failed to make the required repor EEI 94-32-01 Failure to request an exemption and obtain NRC pre-approval for using ASME code case N-514, as required by 10 CFR 50.6 To address the POPS issue, initially PSE&G decided to use ASME code case N-514 that adds 10% margin to the Appendix G criteri *
EEI 94-32-03 Failure to initiate corrective actions for a condition adverse to quality, as required by 10 CFR 50, Appendix B, Criterion XV When PSE&G recognized that the ASME code case could not be used without prior NRC approval they sought to credit the capacity of residual heat removal relief valve (RH3) to augment the analyzed POPS relief capacit A subsequent PSE&G analysis confirmed that, with RH3 available, the peak pressure would remain below the Appendix G limit. The crediting of RH3 (without either a safety evaluation or prior NRC approval of the POPS TS
- change) was, however, under consideration from mid-January to mid-April 1994, when a discrepancy evaluation form (DEF 94-0060) was written. This form documented that relief valve RH3 was not credited in the original POPS analysis or in the existing licensing -and design basis for Sale EEI 94-32-04 Failure to perform a safety evaluation in accordance with 10 CFR 50.59 to determine whether the change in POPS design-basis transient had created an unreviewed safety question. Since March 1993, PSE&G had initiated several corrective action programs to resolve the POPS issu PSE&G Actions To address the concerns of EEI 01 and 03, PSE&G rewrote their procedures that delineate the operability/reportability and corrective.action program The inspectors e~aluated the process to resolve all identified issues (procedures "Action Request Process" and "Corrective Action Program") and concluded that the new program improved the ability for correcting conditions adverse to quality. Specifically, the new program maintains close control of all aspects of the problem through its correction, with all responsible parties having input to the solutio The inspectors also determined that PSE&G conducted two surveys to evaluate engineering products and services. The surveys, performed by an independent contractor, pointed out the need for engineering to strengthen its communications, responsiveness, support, and quality of the engineering deliverables for the other department PSE&G also performed self assessments and had an outside agency also perform an assessment of the quality of the engineering departmen The assessments concurred with the results of the survey PSE&G engineering management has conveyed the results of the surveys and self assessments to the engineering staf The inspectors verified that the training program had been upgraded to strengthen the identified weaknesses and, through discussions with the engineering staff as well as document reviews, verified that PSE&G engineering were aware of the department weaknesses and were working to resolve the Regarding EEI 02 and 04, PSE&G requested the NRC for an exemption to use ASME code Case N-514 in a letter dated December 22, 199 The NRC granted the exemption by letter dated February 13,* 199 In addition,
PSE&G performed 50.59 reviews for the changes in the Units 1&2 design bases. Specifically, they evaluated a new pump configuration for the POPS and, as a result, they were preparing changes to the Final Safety Analysis Report (FSAR} and to the TS bases. A letter delineating the TS basis change was submitted to the NRC on May 31, 199 The inspector's review of the revised design basis determined that: the mass addition considered the start of a second safety injection pump; the revised transient is bounded by the 780 gpm flow used in the
.
original design analysis; the calculated peak transient pressure remains 446 psig for the revised mass input, as originally evaluated; and the pressur~ increase resulting from the ope~ation of two additional reactor coolant pumps is 39 psig for a total of 485 psig. This value is below the new permissible pressure limits of 495 psig for Unit 1 and 544 psig for Unit 2, the new TS pressure limits based on approval to use the code cas PSE&G's operating procedures were amended to reflect the shutdown configuration of the intermediate and high head pumps as well as instructions for running the safety injection and reactor coolant pumps below 312°F, based on the new design basi The inspectors concluded that the NRC approval of the code case and the new pump configurations provided sufficient assurance that the 10 CFR, Appendix G criteria referred to in TS would not be exceede Additional Concern From NRC Inspection Report 50-272.311/94-32 On March 15, 1993, Westinghouse issued a Nuclear Safety Advisory Letter (NSAL-93-0058} informing PSE&G of nonconservatism in their setpoint methodology for POP Specifically, Westinghouse determined that the dynamic head, resulting from running reactor coolant pumps (RCPs}, and the static head, due to elevation of sensors relative to the reactor vessel midplane, had not been considered in the original setpoint methodolog *
The static head error for.Salem is relatively small, resulting in a 4.7 psi increase in the peak transient pressur The dynamic head error, however, is more significan For each operating RCP, the difference between the pressure at the reactor vessel midplane and that sensed by the POPS instrumentation increases by approximately 25 psi. Consequently, for a four-loop plant such as Salem, the sensed pressure (with all four RCPs running} could be as much as 100 psi less than the actual pressure at the reactor vessel midplane (the area of concern for P/T curves}. These errors are added to the original peak transient pressure since their effect is to offset the pressure at which POPS will actuat The pressure effects of running two reactor coolant pumps were included in the new design basis with the results identified abov These results and the associated calculations were sent to PSE&G by Westinghouse in a letter dated September 29, 199 *
Conclusions Acceptable actions were taken by the licensee to address the POPS issu The adequacy of the new design basis for POPS is currently under review by the NRC's Office of Nuclear Reactor Regulatio Pending NRC assessment of the PSE&G's proposed limiting design-basis transient for POPS, this issue remains unresolve E NRC Restart Issue II.37 - Concerns Over Service Water CSWl Piping Leaks (CLOSED) Inspection Scope SW piping leaks have been a problem at Salem since its constructio The purpose of this review was to evaluate PSE&G's resolution of the service water pipe erosio Findings and Observations The carbon-steel-lined pipe is susceptible to corrosion at locations where the steel is exposed to the river water, such as weld joint This corrosion is aggravated by the high biological activity in the river wate The resulting micro-biological influenced corrosion (MIC)
proved to be aggressive.
To address this issue, since 1986 PSE&G has been gradually replacing the existing piping with a more corrosion resistant piping made from AL6XN, a stainless material with 6% molybdenu Over the years, PSE&G has been inspecting the new piping at various opportunities with very good success; to date no leaks were identified in the new pipin During the current outage, PSE&G completed the SW piping changes for both units; all of the piping were replaced except for the underground piping and several through-wall penetrations. The underground piping of steel reinforced concrete and the supply headers of the pipe tunnel receive a 100% inspection, by divers, every other refueling outag No degradation has been observed in this piping to date. The through-wall penetrations received a 100% inspection this outage and only minor weld repairs to some pits and seal welds were require Both the underground and pipe penetration piping are scheduled to be inspected as indicated abov Rubber expansion joints will be replaced on their existing preventive maintenance frequency, which has been successful to dat Conclusions Based on his review of related documents, including a compiled graph showing a steady decrease from thirty leaks in 1991 to two leaks in 1995, the inspectors concluded that PSE&G had taken sufficient steps toward resolving the Salem SW system leak issues. This item is close *
E NRC Restart Issue II.29 - Reactor Head Vent Stroke Times CCLOSED) Inspection Scope On July 6, 1994, the Unit 2 safety-related reactor head vent valve 2RC40 failed to operate (stroke open) during testing. Unit 2 was in cold shutdow PSE&G speculated that the low reactor coolant system temperature may have promoted boric acid crystallization and adversely affect the valve operation. Subsequently, on July 10, 1994, upon increasing the reactor coolant system temperature and confirming the functionality of the valve, PSE&G returned the valve to normal servic They did not, however, perform a formal review or assessment of the failure relative to preventive maintenance, operability, actions to prevent recurrence, or generic implications, in accordance with the applicable "Work Control Process" procedur In addition, this failure of a safety-related component was never documente The purpose of this review was to evaluate PSE&G's resolution of the reactor head vent time Findings and Observations Following the issuance of a violation, PSE&G investigated the issue and found that the valve (2RC40) and others like it, used in the same application, were worn internally. The wearing of the valve caused the seat to start leaking and the boric acid to be presen PSE&G also determined that the reactor vent was the only place were these valves are used in boric acid system application PSE&G took the following steps to correct the situation and prevent recurrence:
They upgraded the corrective action program as described in paragraph ES-In addition the maintenance department established a group, with manager, dedicated to root cause investigation and corrective action determination. This group received level 1 root cause analysis training and was given -a lower threshold for analysis implementatio *
They replaced all the reactor head vent valves and instituted a surveillance program for the This program will involve disassembly and inspection of the valves every 54 months to check for wear, cycling of the valves every time the reactor is placed in cold shutdown, and flushing of the valves with demineralized water after cycling them for surveillance. The latter practice was started when the old valves began to lea The inspectors reviewed the statistics compiled by the maintenance department over the last seven months and observed an increase in self-identified problems in the areas of procedure, process, and field discrepancies.
34 Conclusions Based upon the above review and considering the increased attention to the department weaknesses, the actions taken regarding the physical hardware changes, and the surveillance program established for the valves the inspectors concluded that appropriate actions had been taken to address the reactor head vent issue and that improvements were being made in the maintenance area. This item is close E (Updated) Unresolved Item 50-272; 50-311/93-26-01 - Pressure Locking and Thermal Binding of Wedge Type Gate Valves PSE&G's resolution of the pressure locking and thermal binding of wedge type gate valves is Item I~.24 of the NRC restart action pla During a November 1993 NRC inspection, the NRC reviewed PSE&G's evaluation of the pressure locking and thermal binding potential for gate valves at the Salem plan PSE&G had originally conducted a study in 1984 in response to Significant Operating Event Report 84-0 Based on the results of this study, they concluded that all susceptible valves were equipped with either internal or external protection devices that would prevent the occurrence of pressure locking or thermal bindin Following Generic Letter (GL) 89-10, PSE&G reassessed the susceptibility of the motor operated valves (MOVs) identified in their original study.
They concluded that twelve additional valves should have been included in the original stud Of these, four appeared to require additional evaluation to determine their susceptibility and the need for additional actions. This item was left unresolved pending completion of PSE&G's evaluation (NRC Inspection Report Item No. 50-272/93-26-01 and 50-311/93-26-01).
Prior to the NRC's follow up to the above open item GL 95-07 was issued extending the concerns of GL 89-10, Supplement 6 to all gate valve PSE&G performed an assessment in accordance with GL 95-07 and identified a total of 22 valves for both units requiring corrective actions as follows:
Ten valves required the drilling of weep holes, a practice
.recognized by the GL; the holes were drille Four valves required procedural changes to request cycling of the valves after running their respective pumps to prevent pressure binding; this item was in the process of being don Four valves required recalculation of their thrust values to address the thermal binding concerns; the calculations had been complete Four valves required the change of the motor controls from torque to position control along with a recalculation of the thrust limits. The calculation were completed, but the new limit switches had not installe The inspectors reviewed the licensee's actions to address pressure locking and thermal binding of wedge type gate valves and concluded that acceptable actions had been take The inspectors also reviewed the supporting calculations and found them acceptable. This item remains open pending PSE&G revision of the above procedures and installation of the above modifications and the NRC review of the completed task *
E NRC Restart Issue II.28 - Reactor Coolant Pump CRCP) Seal Water Flow Problems (CLOSED) Inspection Scope On February 19, 1994, the Salem.Unit 2 control room operators shut the plant down from 47% power to remove No. 21 RCP from service because of a low seal water leakage flo This event, in conjunction with other related RCP seal events (Inspection Report Nos. 50-272; 311/94-32 and 95-11) prompted NRC review of these RCP seal failure The purpose of this review was to evaluate the licensee's root cause determination of the causes and their planned corrective actions to ~ddress the~e seal problem Findings and Observations PSE&G engineering hired a consultant with expertise in Westinghouse RCP seals and the pump manufacturer to work with them to perform a root cause analysis of the RCP seal failure The analysis determined that the primary cause of the failures was corrosion build up across the No. 1 seal. Seven recommendations resulted. These recommendations and the rationale for PSE&G resolution follow.*
Continue the program to reduce mesh size of the seal injection filter PSE&G considered this a "restart" activity and indicated that they will reduce the size of the filters mesh in the RCP seal injection and the reactor coolant ~ystem (RCS).
Starting with 2 microns they intend to decrease the mesh size to as low as is possible over the fuel cycle. During the cycle, they also intend to clean up the system to the optimum cl~anliness possibl PSE&G polled the industry and determined that, by using this approach, other utilities had attained good results in lowering corrosion buildup throughout the RCS and in particular in the No. 1 seal *
Review operating procedures to ensure seal injection is maintained during shutdown, outage and startup, and especially during reactor coolant fill operations. This recommendation was intended to keep the reactor coolant from going through the seal during the above modes of operatio The procedures implementation was confirmed via procedure review by the inspector~.
Review operations of the boron system and boration practices to determine whether the RCP seals are being exposed to unnecessarily harsh and avoidable chemistry transient The licensee completed this task and found that no operation of the boric acid system fell outside the system desig Engineering, however, issued an action request (AR) No. 960603249) to research this further and to ensure that the addition of boron does not affect the overall system chemistr *
Examine the particulate downstream of the seals to ensure that sizes are not greater than the seal filters allo The intent of
r--------------------------------------
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this recommendation was* to ensure that the seal filters were not being bypassed and that there was no source of crud downstream of the PSE&G Engineering stated that with both units shut down for more than one year there were no reliable sources (old filters) to examine and that all of the old filters had been crated for offsite shipment and burial. Therefore, no action could be presently taken to satisfy this recommendatio Test the boric acid system for high levels of corrosion products as a result of high boric acid level PSE&G stated that the system already had filtration for particles greater than 2 microns. Therefore, significant particles would not enter the RCS or the charging and letdown system CVC Also, PSE&G stated that they operated the RCS within the chemistry guidelines of EPRI and Westinghouse. Therefore, no action was required at this tim Review the seal injection system especially downstream of the seal injection filters for components that have the potential for exposing carbon steel or other corrodible m~terials to the borated reactor coolan PSE&G considered this recommendation a post~
restart item. Therefore, they issued an AR (No. 960603249) to continue an already existing program*to look for potential carbon steel or corrodible mat~rials in the RCS.
Flush the seal injection system at high flow rat PSE&G stated that this was not practical because the RCS, CVCS and the seal injection systems operate in a clos~d loop and that all systems would have to be flushed for effective results. Also, the seal injection lines are flushed during the RCS fill, when the seal injection is operated and the seals are bypa-sse Therefore, no further action was require Further, in their effort to resolve the RCP seal difficulties PSE&G also reviewed 139 records from the Nuclear Plant Reliability and Data System (NPRDS).
Using the results of their root cause analysis and the information derived from the other sources, PSE&G developed a program that is comparable with those of other Westinghouse utilitie In addition, PSE&G issued a PR, No. 9590818341, to investigate the possibility of changing two of the No.1 seals.every outage, a program that has become a standard practice at several other utilities having relatively few problems with their RCP seal Conclusions The inspectors concluded that PSE&G had conducted the required reviews and had developed the most up-to-date information available regarding RCP seal Even though the licensee had not accepted every recommendation from their consultant, taken as a whole, their actions appear appropriate to correct their program weaknesses. This item is close *
E (Closed) Unresolved Item 50-272 & 311/92-01-04 The containment spray motor operated valve operability concern is Item II.1 of the NRC restart action pla During a refueling outage, in January 1992, PSE&G engineering identified a concern regarding the operating capability of the containment spray discharge isolation valves of both Salem units (ll,12,21,22CS2). The source of their concern was the difference between the originally specified (200 psid) differential pressure against which the valve motor operators were required to function and the one they had preliminarily calculated (241 psid) in response to Generic Letter 89-1 PSE&G took compensatory measures to continue operating the units, as delineated in NRC combined Inspection Report 50-272; 311; 354/92-01 and informed the NRC that they would replace the motors during the next outage of sufficient length to perform the replacement Due to switchyard problems Salem was experiencing, PSE&G replaced some -
transformers with ones of larger capacity. This change increased the degraded grid voltage available at the plant component With the higher grid voltages PSE&G reevaluated their MOV progra New calculations for the above MOVs showed that, with appropriate thermal overloads in the motor control circuits, the installed motor could still be use The new overloads were installed and the motors tested both statically and dynamically with satisfactory result The inspectors reviewed the calculations and test results and concluded that sufficient bases existed to ensure the operability of the valve This item close ES.10 Conclusions and General Comments The inspectors review of the issues described in Sections E8.l through EB.9 concluded that PSE&G's action to resolve five outstanding issues were sufficient for their closure. One additional issue, pertaining to pressure locking and thermal binding of safety related valves, remained open pending the licensee's completion of scheduled activities to resolve it. Further, resolution of the pipe support configuration control and of the POPS issues remained open pending the NRC completion of inspection activitie However, PSE&G's actions to resolve the NRC concern regarding potential safety injection signals caused by spurious high steam flow signals were insufficient for closure of the issue. The NRC review of this issue concluded that the design changes performed in 1994 to dampen the response of the steam flow transmitters and delay the injection signal were narrowly focused in that they did not fully evaluate the impact of the *change In addition, the justifications to address the inspectors questions and comments were insufficient to close the issue. As a result of this review, the NRC identified four specific concerns that require the licensee's resolutio..
The quality of the licensee's packages to resolve the above items was adequate with improvements noted in packages developed later in the inspection period. These improvements were primarily due to the detailed review of closure packages by the system readiness review committee and by the management review boar For instance, the inspectors had reviewed the package for item II.28 (Section 8.8) prior to PSE&G's review process taking plac The inspectors found that the package had not thoroughly addressed all of the recommendations of the root cause analysi The package was also rejected by PSE&G during their first step of the review process. After the package was reworked and PSE&G completed their review, the inspectors found that all issues had been addressed in sufficient detail to warrant closure of the issu ES.11 Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR descriptions.'
While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspecte Except as described in Section 02.1.b and E8. of this report, the inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters~
IV. Plant Support Rl Radiological Protection and Chemistry (RP&C) Controls Rl.l Ammonia Leak in Unit 2 Turbine Building Inspection Scope The inspectors observed licensee response to an ammonia leak in the turbine building of Unit Observations and Findings On June 7, 1996, ammonia leaked into the basement of the Unit 2 turbine buildin The leak resulted from two separate activitie On June 4, plant staff opened a pipe union to flush and drain a section of the ammonia feed syste The workers relied on normally closed valves to provide isolation from the ammonia storage tank while the union was ope They did not apply safety blocking tags to these valves, and, therefore, did not ensure the open piping remained isolated from the ammonia storage tank. Subsequently, a chemist, not knowing other workers had opened the union, opened the normally closed valves to fill bottles from the ammonia storage tan As a result, about five gallons of ammonia leaked from the tank through the open union and into the *
turbine building basement before operators stopped the spil *
I
- "'
The inspectors reviewed the tagging boundary for the drain and flush evolution, and NC.NA-AP.ZZ-0015(Q), Rev. 4, Safety Tagging Program (NAP-15).
The procedure requires that plant staff establish tagging boundaries to isolate energy sources from personne The ammonia leak demonstrated that plant staff did not adequately isolate the ammonia tank from plant staff wdrking in the turbine building. (Section 04.3 has additional details)
c. Conclusions The inspectors concluded plant staff did not comply with the tagging procedure requirement The procedure non-compliance did not violate regulatory requirements since the work on the union was not a regulated activity. The inspectors noted, however, that plant staff failed to recognize the need to apply red blocking tags to ensure isolation of the ammonia storage tank from open portions of system pipin As a result, they failed to protect other workers in the plan Had the work involved higher energy systems or safety-related equipment, or if the storage tank isolation valves remained open longer, the staff's inadequate performance could have resulted in more serious consequence S4 Security and Safeguards Staff Knowledge and Performance S4.l Security Awareness Inspection Scope C71707)
The inspector conducted frequent tours of the plant and periodically assessed physical security control Observations and Findings On May 27, 1996, the inspector discovered a security guard, seated and inattentive, in a secluded area of the Unit 2 auxiliary building. The inspector discussed the guard's inattentiveness with security supervisio Security supervision talked to the guard and determined that the guard had been alert and within his assigned area.. Security supervisors instructed the guard that although he was alert, he should also appear alert. The inspector independently requested, received, and reviewed recorded information that indicated that the guard remained seated for 21 minutes until disturbed by the inspecto The inspector discussed this observation with security managemen Based on the guard's good performance record, Security management counseled the guar In addition, Security management reinforced its standards and expectations concerning attention to duty to the security force organizatio Conclusions A security guard did not patrol his assigned area continuousl Security supervision follow up did not thoroughly assess the guard's
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inattention to dut They limited the thoroughness of their followup action because of previous good performance of the guar During the exit meeting, the general manager noted this as a poor practice and provided the proper guidance and direction to the security organizatio V. Management Meetings Xl Exit Meeting Sununary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 3, 199 The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietar No proprietary information was identifie X3 Management Meeting Summary From June 25 through June 28, Mr. H. Miller, NRC Regional Administrator, Region III, visited Salem and Hope Creek to tour.the plants and meet with various PSE&G managers and supervisors.
X4 Management Changes Public Service Electric and Gas announced the following management changes:
Charlie Munzenmaier assumed the position of General Manager, Steam Generator Replacements, effective June Dave Garchow assumed the Salem General Manager position effective June 1 Mark Reddemann.assumed the position of Director, Steam Generator Projects, effective June 1 Marty Trum assumed the position of Director, Nuclear Operations Services, effective June 1 INSPECTION PROCEDURES USED IP 61726:
IP 62703:
IP 71707:
Surveillance Observations Maintenance Observations Plant Operations IP 92903:
Follow up - Engineering Opened 50-272&311/96-07-01 50-272&311/96-07-02 50-272&311/96-07-03 50-272&311/96-07-04 ITEMS OPENED, CLOSED, AND DISCUSSED URI UFSAR and licensing basis nonconformances VIO procedure noncompliance IFI switchgear testing VIO reporting guidelines
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CAP CR CRI DCP DFOST EDG EMIS FHB I&C IST LER N/A NAP NRC OE OEF PDR PMT PSE&G QA RP RP&C RV LIS SAC SFP SNSS SPT SRO TS UFSAR URI UT VIO WO LIST OF ACRONYMS USED Corrective Action Program Condition Report Control Room Indicator Design Change Package Diesel Fuel Oil Storage Tank Emergency Diesel Generator Equipment Malfunction Information System Fuel Handling Building Instrumentation and Controls In-service Testing Licensee Event Report
- Not App 1 i cab 1 e Nuclear Administrative Procedures Nuclear Regulatory Commission Operating Experience Operating Experience Feedback Public Document Room Post-Maintenance Testing Public Service Electric and Gas Quality Assurance Radiation Protection Radiological Protection and Chemistry Reactor Vessel Indication System Station Air Compressor Spent Fuel Pool Senior Nuclear Shift Supervisor Station Power Transformer Senior Reactor Operator Technical Specification Updated Final Safety Analysis Report Unresolved Item Ultrasonic Violation Work Order