IR 05000272/1996020

Insp Repts 50-272/96-20 & 50-311/96-20 on 961118-1231.No Violations Noted.Major Areas Inspected:Licensee Engineering & Plant Support

ML18102A860
Person / Time
Site:	Salem
Issue date:	02/12/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18102A859	List: IR 05000272/1996020 ML18102A858
References
50-272-96-20, 50-311-96-20, NUDOCS 9702200196
Download: ML18102A860 (47)

Text

I **

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket Nos:

50-272, 50-311 License Nos:

DPR-70, DPR-75 Report Nos:

50-272/96-20, 50-311 /96-20

"Licensee:

Public Service Electric and Gas Company Facility:

Salem Nuclear Generating Station, Units 1 and 2 Location:

,. Hancocks Bridge,. Dates:

November 18 - December 31, 1996 Inspector:

A. Della Greca, Sr. R~actor Engineer, EEB, DRS R. Bhatia, Reactor Engineer, EEB, DRS s. Chaudhary, Sr. Reactor Engineer, 'MEB, DRS D. Dempsey, Reactor Engineer, SEB, DRS L. Harrison, Reactor Engineer, EEB, DRS T. Kenny, Sr. Reactor Engineer, SEB, DRS B. Smith,* NRC Contract Engineer -

Approved by:

William H. Ruland, Chief, Electrical Engineering Branch Division of Reactor Safety 9702200196 970212 PDR ADOCK 05000272 G

PDR

I*

.*

SUMMARY Salem Inspection Reports 50-272; 311/96-20 November 18~ l996 - December 31, 1996 This inspection included aspects of licensee engineerir:ig and plant.support. The report covers an 8-week period of inspection related to equipment and engineering performance issues that require resolution prior to Salem restart. The~e issues are included in Checklists II and Ill.a of the NRC restart action pla Engineering Based on their review of eleven closure packages and nine unresolvec;:I items and violations, the inspectors concluded that (Section E8.10):

The actions to address most issues were acceptable and the packages prepared to close the NRC restart items were in the most part complete and of good qualit *

Analyses, calculations, and modification packages, as applicable, were typicall a.cceptable, complete and had received the required review *

Reso~ution of programmatic weaknesses, while still incomplete, had received the attention necessary to *provide reasonable assurance of successful result Recommendations from self-assessments had been properly evaluated and implemente *

The IST Program Manual was treated as a controlled document under the Quality Assurance Program. The manual and the IST program basis da.ta sheets exceeded Code requirements and were an excellent initiativ *

Engineering evaluations were not always satisfactory. For instance, engineering failed to:

recognize that the auxiliary spray water was being heated while passing through the regenerative heat exchanger and that thermal shock of the pressurizer spray nozzle was never a concern; evaluate the NRC underlying concerns regarding the operating temperature of the Hagan modules. Therefore, some of the analytical work regarding this issue had to be redone;.

recognize the potential impact on fuel loading of several valves that had been improperly excluded from the IST program. Therefore, an evaluation was not initiated unti.1 fuel loading was ongoing and the NRC specifically requested such evaluation.

iv

.:'*"*

The Quality Assurance organization perfor.med a comprehensive and self-critical audit of the. Salem IST program. The stop work order indicated a willingness to

• .. *

force change to ensure quality and evidenced a sound safety perspective. PSE&G's root cause evaluation accurately identified the causes of the IST program deficiencies. *

Plant Support

The licensee effectively improved the collection capabilities for each Unit 2 RCP motor and provided reasonable assurance that a fire would not occur. The installed configurations met the requirements of 10 CFR Part 50, Appendix v

• Report Details Ill. Engineering E 1 Conduct of Engineering E1.1 Introduction E1.2 On February 23, 1996, the NRC issued the restart action plan for Salem Units 1 and 2. Restart Issue Checklists II and Ill.a include the technical and programmatic *

issues that require resolution. These issues, related to NRC concerns regarding equipment performance problems and plant personnel issues, involved previously identified unresolved items and violations as well as generic concerns. The,purpose of the current inspection was to review the closure packages prepared by the license.a to address these issues. Except as noted, the review was conducted in accordance with inspection procedure 9290 NRC Restart Issue 11.19 - Configuration Control of Piping and Pipe Supports !Closed Unit 2 Only)

Inspection Scope In 1979, the NRC issued bulletins 79-07 and 79-14, with several supplements an*d revisions, which created the need to verify the design, as-built configuration, and structural adequacy of safety-related piping and pipe supports in nuclear power plants. To respond to the bulletin requirements, the licensee retained severer consultants to verify and create, if necessary, design-basis calculation Due to the urgency of the respon~e and the magnitude of the undertaking, the work was started and carried but before procedures were created and/or implemented to administer and maintain calculation design bases and history of evolution of the revisions of design documents. Prior to 1987, four distinct organizational groups were involved in verifying and* generating stress calculations. These groups maintained their own administrative controls on the documents and calculations generated by them. As a result, the licensee did not have a single consolidated source of information and revision history of stress document In 1987, the licensee initiated acceptability reviews of existing stress document This task was part of the Salem recovery project and was initiated primarily in response to the documentation problems identified by the NRC (IR 50-272/86-07 and 50-311 /86-07). As a result of this review, the licensee initiated 145 7 discrepancy evaluation forms (DEFs), involving unchecked/unapproved calculations; unimplemented modifications; lost/unavailable calculations; incorrect thermal analyses; and unsupported/undocumented engineering judgement In response to NRC concerns, the licensee committed to resolve the identified

. discrepancies and issued Procedure NC.DE-AP.ZZ-0018(0) to control and expedite their resolution. However, the low priority placed on this effort did not produce a significant reduction in open DEFs. Hence, the licensee established a dedicated project grou. 2 The scope of this inspection was to determine the adequacy and effectiveness of the s*alem pipe support configuration control program and to review the licensee's progress in DEF backlog reduction since the last.inspection (IR 95-06). To determine the adequacy of the corrective actions, the inspector reviewed the modification packages for five support Observations and Findings The inspector's review focused on the methodology of the stress analyses, e.g.,

piping modeling, computer code, inputs, and the results. He determined that the output of these analyses were used to modify the affected supports and that the design changes were issued as revisions to the original support drawing. The inspector performed a walkthrough inspection.of the auxiliary feedwater (AFW)

system and the control air system (CAS) to visually examine the modified and/or new supports, and compared them with the applicable as-built drawing for form, fit, and functio The results of the above documentation review and visual examination of supports are indicated as follows:

The* design packages were complete with valid engineering calculations, safety evaluation, operability evaluation, and design output drawings.

The modification packages were complete with all pertinent information, such as drawings,* bills of material, welding and NOE requirement, and the acceptance criteria..

The modified or new supports in the plant appeared to meet the form, function, and fit indicated on design drawing *

Post-modification/erection documentation, like as-build drawings, were

. complete, reviewed, and accepte The inspector, however, noted that the pipe supports were not individually and/or clearly identified on the item itself. A similar observation regarding the absence of on-item identification was made also by the licensee's organization in the summer of 1996. The licensee stated that at Salem, there was no requirement to place any identification mark (tags, labels, markings) on the structure itself. Supports are identified by the location-shown on the support drawing relative to structures (walls, columns, and beams), and by the piping isometric drawings used for construction. The inspector was also informed that the supports included in the ASME Code,Section XI ISi program, were identified by the ISi people who controlled and tracked the status of those supports. This support identification was part of the approved ISi progra Although there is no specific.NRG requirement to identify supports by tag, labels, or*

markings on the support structure itself, this manner of identification is an industry practice. It contributes to the effectiveness and efficiency in identifying

nonconforming supports during walkthrough inspections by engineering, maintenance, and operation personnel; it also ensures a rapid response during and after a seismic, other design basis event, or an unanticipated operational even The inspector considered this lack of on-item identification to be a weakness in the licensee's pipe support configuration control progra The inspector also reviewed th~ pipe support DEFs identified during the period between Maren 1995 and November 15, 1996, to determine the extent and type of.

nonconformances identified and the timeliness of these resolution. Of approximately 82 Unit 2 and 75 Unit 1 pipe support incident reports (IRs), only three I Rs for Unit 2 were of significance Level "1 ". These deficiencies were dispositioned acceptably and in a timely manner. An asse~sment of all the other IRs was performed to determine the operability of the affected supports. All supports were found operable. The inspector concluded that the licensee resolution of this item was acceptable for Unit 2 restar The inspector also concluded 'that the licensee's dispositioning of DEFs from the 1 S87 review was not timely. As a result of this effort, the licensee initiated approximately 1457 DEFs. Although duririg the period between March 1995 and November 1996 they had reviewed and evaluated approximately 1270 old DEFs, by the spring of l995, they had dispositioned only a fe *

The failure of the Salem staff to evaluate and disposition the *identified piping and piping support DEFs in a timely manner is a violation of the requirements in 10 CFR 50, Appendix 8, Criterion XVI, Corrective Action. Since the NRC has taken significant enforcement action for Scilem's failure to identify and correct conditions adverse to quality, and since PSE&G voluntarily maintained both Salem units shut down to address equipment and enforcement deficiencies, the NRC will not take additional enforcement action in this cas The licensee's review and evaluation of 103 Unit 1 supports have not been performed. These reviews to determine the operability of supports are scheduled for the spring of 1997 and all deficiencies scheduled to be resolved before Unit 1 restart. The acceptability of the resolution of Unit 1 pipe support issues remains open and will be reviewed in a subsequent inspectio Conclusions Based on the above observations, the inspector concluded that although the licensee's resolution of identified deficiencies was slow, the pipe support *

configuration control program was comprehensive and effective and tnat the licensee had acceptably addressed identified Unit 2 pipe support deficiencies. For Unit 1, the identified deficiencies are scheduled for future resolution.

E1.3. NRC Restart Issue 11.35 - Verify Adequate Protection for Safety Injection Pump Runout !Closed) Inspection Scope Runout protection for the charging/safety injection (CHG/SI) pumps and the intermediate head safety injection llHSI) pumps are provided by hot leg and cold leg

• throttle valves. A concern was raised by INPO firs.t and Westinghouse later that the high pressure drop across these valves during a*1arge break loss of coolant accident (LOCA) might ca.use cavitation and erosion within the v.alves and prevent them from providing the required pump runout protection. Also the licensee had discovered that during the recirculation phase of a postulated accident some throttle valves might not be opened suffic_iently to prevent debris blocking the discharge flo The NRC reviewed this issue previously, NRC IR 50-272/96-10 and 50-311/96-1 During that review the inspector determined that acceptable actions had.been taken to resolve the pump runout concerns. The i~em was left open, however, pending the NRC review of the post-modification test results.. The purpose of this inspection was to evaluate the results of those test Observations and Findings The inspector's review of the Unit 2 post-modification and system flow balance tests determined that:

The valves {four SJ16's, four SJ143's a.nd four SJ138's) were now opened beyond the minimum calculated to prevent plugging and cavi~ation.~

To achieve the required pressure drop, PSE&G had to set the valves throttling position (opening) to values less than what they had determined in their orifice sizing calculations. PSE&G engineering attributed the difference partly to lack of reliable information regarding the flow coefficient of the valve *

With both safety injection pumps running and the throttle valves in the as-left position, no cavitation was evident _either in the orifice assemblies or in the valve *

A licensee's analysis of the test results confirmed that at the valves as-left position no cavitation would occur. The analysis evaluated possible pump combination both for the safety injection and the recirculating phas To further assure that no cavitation potential existed, the licensee removed the most limiting Unit 1 throttle valve. An examination of that valve showed no signs of degradation. The valve had operated through approximately eight years of surveillance testing. The licensee estimated that the flow through the valve was equivalent to at least eighty hours of recirculating fl~w under actual operating conditions. Based on their observation that the original settings had not caused any

valve degradation for SO hours.of service, the licensee* deduced that the valves, at the improved flow conditions, would operate effectively for.the 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />, as required by the design basi Regarding the concerns expressed in the above NRC report about attention to detail and quality of design reviews by both* the contractor and the licensee, the licensee counseled the contractor and conducted training of PSE&G engineering on how to perform peer reviews of calculations.* Based on the documentation reviewed, the training addressed reviewer responsibilities, depth and method of review, documentation of the review, and conflicts resolutio Conclusions Based on his review of test results, post-test analyses, and photographs *of the Unit 1 valve, the inspector concluded that *the installed orifices were effective in increasing the opening of the throttle valves and correcting the debris blocking concern. Further, the testing demonstrated that neither the orifices nor the thro~tled valves would cavitate, erode and cause pump runout. Regarding the calculation verification process, the inspector concluded PSE&G had adqressed the NRC cone.ems in an appropriate manner. This restart issue is closed for Unit E1.4 NRC Restart Issue 11-.24 - Gate Valves Identified Susceptible to Pressure Lock*and Thermal Bindirig (Closed Unit* 2) *

Pressure locking and thermal binding of wedge-type gate valves concerns were.

originally expresse~ in Inspection Report (IR) 50-272; 50-311193-26. The status of the licensee's action to address those concerns, unresolved item 93-26-01, was reviewed and updated in NRC IR 50-272; 50-311196-07. At that time some of the valve-related issues were closed. The items described below were left open *

pending licensee actio *

Four valves (2PR6 and 7, pressure operated relief valve block valves, and 21 and 22CC16, residual heat removal heat exchanger outlet isolation valves)

required a recalculation of the thrust limits and a change of the motor controls from torque to position control. The inspector reviewed the thrust-limit calculation for the four valves and found it acceptable, as documented in IR 50-272; 50-311/96-07. The motor controls had not been change During this review, the inspector confirmed that the installation and testing of the Unit 2 modifications (design change package No. 2EC3467) had been completed. He determined that the licensee had replaced the motor pinion set and the spring pack and had modified the motor control wiring from torque to position control. He identified no installation discrepancies. He further determined that the motor operated valve (MOV) baseline testing for VOTES had also been completed. However, due to the current plant configuration, the stroke time testing of the valves had been scheduled, but not completed. For Unit 1, work was still incomplet.:*:"::*'**

Valves 21 and 22CC16 are solid wedge gate valves. Due to expansion of the valve stem after closure, these valves could be subject to thermal binding*. They are not, however, subject to pressure locking since they are solid wedge gate valves. The licensee, using the results of appropriate calculations, tested the valves under degraded voltage conditions. The measured thrust values showed that a positive margin* existed. Therefore, no change to the installed valves was necessary. These valves are also

. discussed in.NRC IR 50-311 /96-81.

• .

To continuously r~lieve the pressure in the bonnet cavity between the disks, the licensee drilled holes in the disk of valves 1 and 2SJ 1 ; 1 and 2SJ2; 11, 12, 21 and 22SJ113; 2SJ12 and 2SJ13. The inspector reviewed design change packages (DCPs) 1 EC3540 and 2EC3467 and determined that work had been completed for both unit *

For valves 11, 12, 21 and 22CS2 the surveillance procedures were revised to require the opening and closing of the valve after pump shutdown. This was done to relieve t~e pressure after the pump has stopped, following the surveillance test. For Unit 2 all procedures were changed. For Unit 1, two procedures, 51.O_P-ST.CS-0004/0007/0009 and 51. OP.ST.SSP-0002/0004

• were yet to be changed. These updates were being tracked under CR

1. 96011020 *

Valves 11 and 12CC16 and 21 and 22CC16 thermal binding cor:isiderations

were corrected by procedure changes. These changes are delineated in NRC Inspection Report 50-311 /96-81.

Based on the above review, the inspector concluded that the licensee had properly addressed all issues regarding thermal binding and pressure locking of the Unit 2 valves, but that licensee action was still required for some Unit l valves. Therefore, this item is closed for Unit 2 onl E1.5 NRC Restart Issue 11.13 - Gas Turbine Batteries Degrading (Closed) lnsoection Scope The licensee had completely discharged the Unit 3 (gas turbine) battery three times between 1988 and 1994. The discharge events in 1988, 1991 and 1994 led to individual cell reversals and complete battery replacements. The 125 *vdc battery is

• .not safety-related and is used for reactor startup onl Despite the safeguards that the licensee had put in place to prevent recurrence, on June 7, 1995, the incident occurred again. This time the voltage reached 60 volts and no cell reversal took place. This item was opened to review the licensee's actions regar~ing *the latest even *

• The inspector reviewed the testing conducted to prove operability of the battery, after the last discharge, and the actions taken by the licensee to prevent further recurrences *of the inciden Observations and Findings The licensee's root cause analysis of the latest battery discharge inCident concluded that:* (1) the procedure guidance for a partial loss of off-site power was insufficient to prevent battery discharge due to component loading; (2) the operators had failed to investigate the low voltage readings and take required compensatory measures to prevent battery discharge; (3) the low voltage alarms were noted, but not resolve in a timely manner; (4) the remedial actions in the alarm response procedure were less than adequate; and (5) previous licensee corrective actions had been ineffective *

in preventing recurrence of the battery discharg Because t~e battery is *not safety-related, it does not fall under the licensee's 1 dCFR 50, Appendix B program requirements. However, the results of the root.cause analysis question the quality of procedures, procedure adherence, and effectiveness of corrective actions. The adequacy of PSE&G's revised correction action program

. is item 111.a.10 of the NRC *restart action plan for Salem and is being reviewed separately and generiCally by the NRC. Therefore, the inspector did not perform a detailed review of this progra Regarding_ the adequacy of the actions related to the operability* of the gas turbine battery, the inspector reviewed engineering analysis BP 96062619.3. In this.

analysis, that received concurrence by the battery vendor, the licensee stated that a cell reversal ha.d not taken place and that damage to the battery had not occurre The analysis conclusions were based on the short time the battery voltage had been at 60 Vdc and on the consistent cell voltages and specific gravity readings obtained during surveillance activities in the weeks that followed the discharge and subsequent equalizi,ng charge of the battery. For the analysis the licensee used the guidance of vendor technical manuals and industry standard Calculation ES-4.007, performed to show the adequacy of the Unit 3 battery capacity, pointed out the need for maintaining the temperature of the battery electrolyte above 65°F, consistent with other Salem battery design. The inspector's review of DCP 3EE-0004 determined that a heater and controls had been added to the battery compartment to maintain its temperature between 75 and 79°F. No concerns were identified during this revie The inspector toured the battery area and found it to be clean. He also found the battery electrolyte levels to be within the proper band. The inspector's review of the last four weekly surveillance records determined that the tests had been successful and th_at the battery was in good working condition.

. 8 The inspector reviewed changes to 14 applicable procedures, including 2-EOP-LOPA-1 "Loss of ALL AC Power." These changes, when compared to those made in 1994, were more extensive, clearer, and included the operator steps to be followed in the event of a gas turbine battery low voltage alar Personnel performarice issues identified during the licensee's investigation were discussed directly with the individuals involved. Further, an information directive was issued to all operators.informing them of the problems associated with the even Conclusions The inspector concluded that the battery for Unit 3 was fully operational, that the procedures had been changed to reflect the concerns identified in the licensee's root*

cause analysis; and that licensee management had properly informed the operators about the event and the negative effects of a complete battery discharge. This restart issue is *close E1.6 NRC Restart Issue 11-25 - Inadvertent Auxiliary Spray (Closed) lnsoection Scope On June 7 ~ 1995, during a Technical Specification (TS) 3.0.3 required shutdown of Salem Unit 2, complications resulted in a reactor trip and a loss of reactor coolant pump~ (RCPs) 23 and 24~ With RCPs 23 and 24 not in operation, auxiliary spray was used to control pressurizer pressure. According to control room logs, the auxiliary spray was in service for approximately 1 2 minutes during which* the temperature ~ifterence between the spray fluid and the pressurizer reached a maximum* of 520°F. TS 3.4.10.2 limits this temperature difference to a maximum of 320° The NRC first reviewed the licensee resolution of this* issue in September 1996 (IR 50-311196-13). As a result of this inspection, five items required further-resolution by the licensee: (1) evaluation of the effect on the pressurizer arid spray

• nozzle of the longer than analyzed auxiliary spray duration;. (2) confirmation* that instrument error did not appreciably impact the maximum delta-T (520°F) measured during the event; (3) conduct* of a visual inspection of the pressurizer spray nozzle and associated piping; (4) performance of a missed in-service inspection of the pressurizer spray nozzle inner radius; and (5) finalization of the necessary emergency procedures revisions. The purpose of the inspection was to evaluate the licensee's. resolution of the above item **

.*

..

9 Observations and Findings During the current review, the inspector. determined that:

.,

Westinghouse had evaluated the effect of the longer than analyzed duration of the inadvertent auxiliary spray on the pressurizer spray nozzle and.

concluded the additional -spray time had negligibie impact on the nozzle. The basis provided by Westinghouse for their con.clusion was that, within a few minutes from the initial spray, the nozzle metals temperature begins to equalize and additional spray time at constant tempe~ature water has minimal effect on the nozzle. The inspector discussed the analysis results with both licensee and Westinghouse engineerin *

The peak delta-T measured during the event remained below the maximum value of 560°F analyzed by Westinghouse.. To confirm this value, the inspector reviewed the actual logs taken prior to and after the event. and *

verified the licensees delta-T computation.

.

In reviewing this issue, the inspector determined that the 520°F delta-T used in the calculation of the thermal shock event was apparently based on.the volume.control tank temperature of approximately 100°F. In reality, the auxiliary spray water, before entering the pressurizer *spray noz.zle, passed through the regenerative heat exchanger that elevated the water temperature to a much higher level. For instanc~, based on the last recorded reading (4:00 PM on June 7, 1995), the temperature at the outlet of the regenerative

. heat exchange~ was 594".'F. *At midnight of the same day the measured temperature was 349.6°F. The auxiliary spray of the pressurizer had occurred at 11 :05 P Based on the above, the inspector concluded that instrument error was not a concern, albeit he confirmed that the applicable instrument loops had been calibrated in accordance with approved procedures. The inspector also concluded that the nozzle had not undergone a thermal shock, because the delta-T never reached the TS maximum of 330°.

As a result of concerns raised during the original inspection, the licensee had conducted a visual inspection and, on September 5, 1996, the missed ASME Section XI, 1986 *Edition, inspection of the pressurizer spray nozzle and associated piping. The inspector reviewed the 96RF examination ~ummary record of the longitudinal weld and the inside radius section of the pressurizer spray nozzle. This examination identified no concerns in the examined portions of the spray nozzle..

The licensee had finalized the necessary emergency. procedures revision The inspector's review* of procedure 2-EOP-TRIP-2 "Reactor Trip Response*"

determined that the changes give the operator explicit guidelines regarding use of pressurizer spray. This review also determined that the licensee had also added substeps to set priorities for the use of pressurizer power operated relief valves versus auxiliary spray based on the status of the letdown flo c. '

Conclusions Based on the above review, the inspector* concluded. that PSE&G had taken proper actions to evaluate the effect of the inadvertent auxiliary spray and to prevent recurrence. Therefore, item 11.25 is close The inspector also concluded that PSE&G had displayed a narrowly focus approach in resolving the NRC thermal shock concern in that they addressed the perceived problem rather conducting a full evaluation of the issue. A clea.r understanding of the pressurizer spray system would have resolved the NRC concern before it became a restart item. A understanding of the system also was not evident during subsequent opportunities to resolve the issu E1. 7 NRC Restart Issue 11.39 - Review Corrective Action$.to Resolve Numerous Switchyard Failures (Closed)

a. *

Inspection Scope This i~sue developed. as a result of three separate events that occurred within *a

• two-month period in 1994. These events involving: (1) loss of one of the off-site power sources to Unit 1, on November 18, 1994, due to circui.t switcher 4T60 opening unexpectedly; (2) total loss of off-site power to Unit 2, on November 28, 1994, due to multiple relay trips and isolation of station power transformer.2 from the 500 kV ring bus; and (3) loss of power to the technical support center, on November 28, 1994, due to a failure of the 13 kV auxiliary loop substation #5; were discuss.ad at length in NRC inspection reports No 50-272; 311/94-31 and 50-272; 311/94-33. At that time, the NRC found PSE&G's actions to address the events appropriate and likely to. prevent similar occurrences. The

• purpose of this inspection was to review PSE&G's further actions to address potential generic implications resulting from the above event Observations and Findings In May 1995, a significant event review team (SERT) performed an extensive review of the events to identify potential common threads between the events. The inspector's review of the SERT report determined that they had found similarities in the events, such as multiple jobs taking place within the switchyard with key

11.

equipment out of service. They, therefore, recommended improvements to the oversight and control of switchyard work, improvements to the electrical systems preventative maintenance program, and the repla*cement of all of the 3X and 89/0X relay To address the SERT findings, he inspector verified that the new procedures put in place, SC.OP-DD.ZZ-0008 "Switchyard Rules _and *Regulations," and NC.NA-AP.ZZ-0009 "Work Control Process," did aid the operator in the performance of switchyard work and in the outage risk analysis prior to the work release. The inspector also verified that additional training had been given to maintenance personnel, such as on the methods for detecting and clearing DC ground Existing procedures (S1 & 52.0P-S0.125-0004) had been revised to verify the operability of redundant equipment prior to removing 1 25 Vdc control power to any circuit supplying ESF equipment. The relays had been replaced using approved procedure The inspector's revi~w.further determined that PSE&G had made other improvements to the switchyard equipment and processes, including a requirement

• to check the*motor-operator cam switch alignment after closure <;>f the 4T60.

disconnect switch, the replacement of the pressure switches on all the 500kV gas breakers, and the replacement of under-designed insulators on all substation~.

Another switchyard. improvement, involving the addition of four new transformers (3&4 500/13kV" and 13& 14 13/4kV), added two new off site sources to the vital b_uses. These new sources will increase voltage recovery on all vital and group buses during bus transfer, provide load growth capacity, improve plant voltages, provide margin for short circuit capacity, and improve plant reliability. The inspector verified that these improvements to the switchyard, DCP #1 SC-2269, had been implemente The licensee has further improved the Root Cause Analysis and Corrective Action Programs (Restart Items 111-10. 1-6), and has implemented the Maintenance Rule Program that is designed to better track system failures and enhance the availability and operability of system * Conclusions Based on the results of the previous NRC inspec~ions (IRs 50-272; 311 /94-31 and 50-272; 311 /94-33, and the implementation of the _above improvements, the inspector concluded that PSE&G had taken sufficient actions to enhance the reliability of the switchyard. Therefore, NRC restart issue 11.39 is closed.

. 12 E1.8 NRC Restart Issue 11.30 - RHR Min-Flow Valve IRH29):Failures on *Salem Unit 2,

!Closed Unit 2 Only) Inspection Scope The inspector reviewed PSE&G's corrective actions to address failure of the Residual Heat Removal (RHR) minimum flow valves (21 RH-29 and 22RH-29) at sa'1em Unit 2. This effort involved performing walkdowns of RHR system piping, reviewing preventive.maintenance documents, and evaluating the conclusions of a SERT report that examined PSE&G's operability assessment of the RHR minimum flow valves.before the June 7, 1995, plant shutdown. The inspector's review of this item also examined PSE&G's corrective actions to address the hardware deficiencies associated with the RHR minimum flow valves, but did not evaluate the adequacy of the corrective action program implemented by PSE&G to address generic training or cultural weaknesses in this area. These issues are the subject of NRC restart item 111.a.10, Corrective Action Progra *

Observations and Findings Background The RHR minimum flow valves at Salem Unit 2 are designed to ensure that the RHR pumps are not operateq in a no-fl_ow condition.. Accordingly, when the RHR pump

flow decreases to a predetermined level, the minimum flow valves open to

.

• recirculate some of the pump discharge flow back to the RHR pump suctio Similarly, when the RHR system flow increases above the predetermined level, the

. minimum flow valves close to ensure full RHR system flow to the reactor vesse On June 7, 1995, PSE&G determined that RHR minimum flow valves 21 RH-29 and 22RH-29 were inoperable and commenced a shutdown of Salem Unit 2. Before the

. shutdown, both valves had failed to open automatically as designed, during

. surveillance testing. Details concerning the RHR system testing and subsequent plant shutdown were outlined in.NRC IR 50-272; 311/95-10, dated July 14, 199 On October 16, 1995, the NRC issued a Notice of Violation (NOV) with Civil Penalty to PSE&G for their failure, in part, to determine the cause of and initiate actions to correct multiple failures associated with the RHR minimum flow valves. In their December 15, 1995, response to the NOV, PSE&G stated the mostprobable cause for the valves failure to operate as designed was a defective relay (RHR Low Flow 63LX) in the valve opening circuit. Relay 63LX is designed to energize and open the RHR minimum flow valves when a low flow condition occurs in the RHR system. The licensee's conclusion was based on an examination of the 21 RH-29 valve relay. This examination showed high relay contact resistance, excessive corrosion, and that the relay internals were covered with a fine brown non-conductive * filr:t *

Troubleshooting Activities To identify the RHR minimum flow valves failure mechanism, PSE&G developed temporary procedure TS2.0P-PT.RHR-0001, "Residual Heat Removal 21 RH29 and 22RH29 2FT641 A/B Transmitter Test." Using the *procedure, PSE&G functionally tested the automatic open/close functions of the RHR minimum flow valves through at a range of RHR flow conditions. The inspector performed a qualitative review of procedure TS2.0P-PT.RHR-0001 and verified PSE&G's troubleshooting approach was appropriat Corrective Action PSE&G corrective action included replacing all Struthers-Dunn relays in-both RHR trains, calibrating the flow transmitters, and ensuring the minimum flow valves were operational by injecting a signal at the flow sensor while verifying the minimum flow valves opened and closed. To ensure the Struthers-Dunn relays in other.plant systems were reliable, the PSE&G engineering department with the assistance of the relay vendor developed and implemented relay inspections using procedure SC.MD-PM.ZZ-02040~ "Bailey Relay Inspection.".

The inspectors reviewed procedure SC.MD-PM.ZZ-02040, and performed a walkdown of the RHR system where 21 RH29 minimum flow valve is locate During the walkdown, the inspector verified that housekeeping in the area of the RHR minimum flow valves was adequate and that pipe and valve conditions were acceptabl *

'

Procedure SC.MD-PM.ZZ-02040 contained a series of qualitative and quantitative acceptance criteria to assess relay performance. The inspector's review of this procedure concluded that the procedure adequately tested the Struthers-Dunn relays and was useful in detecting relay degradatio At the close of the inspection *report period, 90% of the Struthers-Dunn relays in Unit 2 had* been inspected. * PSE&G intend.ad to use the results of the relay inspections to evaluate the need for a periodic relay preventive maintenance inspection program~ Conclusions The inspectors concluded PSE&G's troubleshooting plan was adequate to diagnose the RHR minimum flow valve failures. PSE&G's corrective actions were adequate to address hardware deficiencies associated with the failure of the RHR minimum flow *

valves. Therefore, this item is closed for Unit 2.

E1.9 NRC Restart Issue 11.14 - Hagan Module Replacement Project (Open) lnsoection Scope NRC Inspection Report 50-272, 31'1/96-06, documented a concern with respect to the ability of the Hagan modules to perform their intended safety function under.

installed conditions. During a review of the closure package for this issue, the inspector determined that PSE&G had failed to consider the differences between the Westinghouse qualification test anc;I Salem's "worst case" rack configuration. The purpose of the inspection was to evaluate PSE&G's review and resolution of the NRC concer Observations and Findings PSE&G's documented review of the module. temperature issue included: 1) a review of the ".Summary Report of Hagan Temperature Analysis and Testing in Support of the Hagan Module Replacement & Refurbishment Project," dated April 11,.1996; 2) an evaluation of the completed design changes that will reduce the power consumption of the H~gan cabinets; 3) a review of the Wes1inghouse

"Temperature.Test on Racks & Modules of the NPS for PSE&G," dated February 1971; and 4) a review of the normal and worst-case room temperatures*

for the control equipment room. From this review, PSE&G concluded that for continuous operation, the modules would be operated within.the design basis. For the elevated temperature conditions (worst-case) during a station blackout (Sl;JO),

PSE&G concluded that the modules would be *capable of performing their safety function at the calculated temperature and for the SBO duration. The EO Programs Analysis Group (PAG) reviewed the test reports and agreed with these conclusion PSE&G also conducted a sampling inspection of each type of Hagan module for signs of accelerated aging and degradation due to excessive heating effects. Signs o*f localized heat-related degradation to module wiring insulation was documented for comparator, isolator, and summator modules. These. problems were corrected during the*refurbishment process. The remainder of the module types were satisfactor The inspector determined that the calculated power consumption for Salem's post restart "worst-case" rack loading (Rack #11) would be approximately 484 watts. In contrast, the measured power consumption for the three racks used in the Westinghouse test was 230, 190, and 260 watts, respectively. Based on the significant difference between the calculated value of Salem's "worst-case" rack and the measured values for the Westinghouse tested racks, the inspector concluded that PSE&G had still not provided assurance that the Hagan modules were not subject to heat related concerns. The inspector requested PSE&G to provide assurance that:*

the internal temperature of the Hagan modules in Rack #11 would not exceed the maximum temperature of 150° F measured in the Westinghouse test;

- - -

___

..

• with the control equipment room ambient temperature at. 85° F (highest normal* operating te1T1perature), the maximum rack ambient temperature would not exceed the 122° F design limit of the NU~ modules;

• *

all* modules would cominue to perform their safety function during an,SBO event, when PSE&G's analysis has shown that the control equipment room could reach 114.8° F for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, before ventilation is restored;

modules unable to operate reliably during an SBO are not required to mitigate the SB PSE&G conducted power consumption measurement testing on a mockup of Rack. #11. The measured power consumption was determ*ined to be approximately 219 watts, with all modules set up for maximum power output. The inspector verified that the mockup was in agreement with the Rack #11 post restart configuration and that the wattmeter was within its required calibration frequenc He also witnessed the performance of the test.

. Based on:. 1) the results of their mockup test; 2) a re-review of the results of the Westinghouse* rack temperature test; 3) additional module temperature information obtained from NUS, PSE&G concluded that the design temperature limits of the Westinghouse and NUS modules would not be exceeded during normal maximum temperature conditions in the control equipment room. PSE&G further.determined that, for entering the reactor modes 6 and 5, only nonsafety-related process control modules were required." Therefore, the ability of the modules to mitigate an SBO event for these modes was not a concern. The results of these evaluations had not

.been documented by PSE&G. T~e inspector, however, discussed in detail with PSE&G the bases for their conclusion Conclusions Based on the above review and discussions with responsible licensee engineering and supervisory personnel, the inspector concluded that PSE&G had provided sufficient assurance that safety-related reactor protection modules would perform reliably under normal operating conditions. The inspector further concluded that, for" the same modules, no concerns existed in the event of an SBO during reactor modes 6 and 5., the modes of interest. This item continues to remain open pending the NRC review of the licensee's documented analysis to address the

• . modules temperature issue E1.10 NRC Restart Issue 111.a.18 - Parts Availability and Bill of Material Accuracy (Open) Inspection Scope The NRC identified that adequate component parts were not available to maintenance department and that the managed maintenance information system

-~-----------<MMl~Ldatabase contained inaccurate classification codes f~r safety-related Bills of

'"

.

Material (BOM). As a results of these and other programmatic weaknesses,

.

.

.

.

....

...

.

.

.

.

.

..

.

maintenance activities were not being properly supported. The NRC concerns in these areas were detailed in inspection reports 50-272; 311/95-80 and 50-272; 311 /95-02. In addition, material concerns were part of a major enforcement action against the licensee as described in.item 06014 of NRC letter EA-94-112, dated October 5, 1994. The inspector assessed PSE&G's corrective actions to.address the above material availability and material management concerns by reviewing applicable documents and conducting personnel intervi~ws.. Observations and Findings To improve material availability and BOM accuracy, PSE&G implemented various corrective actions and p"erformed self-assessments of the material management p*rocess. The nuclear procurement engineering and material management (NP&MMl departments were reorganized and streamlined. At the same time,.efforts had been

• made and were ongoing to enhance communications among material users, design

engineering, and NP&MM personne *

Material Availability and Material Management Processes

.

.

.

In March.1996 PSE&G formed a material availability improvement team *. This team, consisting of experiericed personnel from NP&MM, maintenance, operations, *

planning, and design engineering,* froni both Salem and Hope Creek, recommended a variety of process improvements, including:.

Clarification of definitions and respo_nsibilities in the material management and administrative procedures (NAP-18, 19 and NP&MM internal

. procedures);

Integration of procuremeljlt and material processing organizations under a single manager;

Initiation of performance trends;

Enhanced commuriications to better understand the operation process;

Early planning and prioritization of work, schedules;

.

.

Establishment of better *criteria for stock items and order on demand; and

Integration of DCP material change and ordering processes into the work control and. material management processe By the end of the inspection period _all recommendations, except the last one which was under review, had been implemente In July_ 1996, PSE&G completed a root cause analysis (RCA) to evaluate the effectiveness of the material management process. PSE&G concluded that the overall process was satisfactory. However, when* complex materials or design were involved, the process did not consistently m~et the needs of the enc;i-use application or the requiren:ients of the design* and procurement. document As a result of this RCA, the licensee initiated actions to improve QA supplier hold points ~nd awareness of technical requirements when ordering material. The licensee also planned to conduct formal training of NP&MM and other personnel to convey the RCA results and process need Prioritization of work orders had been implemented. Planning and operation personnel were requested to identify required date and priority of parts as it became

. known and to support the 90-day look ahead cycle. Based on interviews of planning and procurement engineering personnel and a review of the database, the inspector determined that the added information was effective in assisting the NP&MM department in their prioritization and procurement of required components'.

.

-

'(he responsibilities of the-procurement manager were expa~ded to encompass all material management activities, including material coordination, inventory

.

maintenance, buying, expediting, and suppliers performance. This integration of function is expected to improve the. overall material management process and to foster communications within other departments. In addition, a full time

procurement analyst was ;;sssigned to the outage control center to ~ddress emergent material concern A review of the 1996 work order activities determined that the licensee's corrective actions in the area of material management had helped in reducing the number of o*n-hold maintenance work orders from 12.5% to 9.1 %. The inspector estimated

.

.

that approximately 140 of the 370 work orders were outage-relate The inspector verified that the licensee's guidelines and procedures for material management (NAP-18, 19, and procurement procedures) had been revised. Based on discussion with several staff and management personnel, responsible personnel were cognizant of the changes and of management expectations regarding the overall material management proces BOM Documentation Concerns The licensee conducted self-assessments three times since 1994 to review the problems associated with MMIS datalJase updating and to improve the accuracy of the BOM. A phase I assessment, completed in June 1994, recommended the:

. *

development of a comprehensive BOM user guideline for creating and updating BOMs and for resolving deficiencies;

• is preparation of training lessons addressing*proper use of guidelines, relationship between BOM and warehbuse automated management system (WAMMS), class codes and MMIS ownerships responsibilitie *

development of an electronic MMrS discrepancy form to facilitate changes in the MMIS database.*

assignment of a team to monitor the database improvement process and to.

. perform. a followup assessmen.

.

A followup assessment, completed in February 1995, found that the BOMs were

• not as inaccurate and incomplete as originally perceived to be; Nonetheless, minor process improvements were recommended. In April 1996, PSE&G's review of a

random sample of 125 BOMs for completeness and accuracy identified no safety concerns. The licensee was planning to use the results of the latter assessment as.

a benchmark for assessing the need for future enhancement The inspector's review of the results of April 1996 assessment determined that*

PSE&G had identified nine minor discrepancies. In one cas~, a BOM part description differed from that in the WAMMS portion of the MMIS. In the other eight cases the WAMMS database had not yet been revised to reflect part number changes by the vendor. All discrepancies had be.en corrected. The licensee had initiated an action request to perform* *a BOM assessment in 199 Nonsafety-Related Material Classification (PC4) in Safety-Related BOMs To address 'the NRC concerns regarding the use of nonsafety-related, PC4 classified

• material in BOMs for safety-related applications, the licensee performed two engineering evaluations intended to validate the adequacy of the BOM database and of the installed components.

. The first assessment, completed in December 1994, evaluated *500 PC4 class code materials randomly selected from approximately 4690 Salem 1 and 2 PC4 components. This initial evaluation, performed by the procurement engineering staff and validated by the quality assurance staff, identified approximately 35 issues

involving PC4 class code components in. safety-related BOMs. Of the 35, ten BOMs were issued to the station to be used in the *safety-related systems. These components, further evaluated by the licensee (and reviewed by the inspector)~.

satisfied the safety-related application requirement The remaini.ng twenty-five components, unacceptable for safety-related application, had not been installed. However, they had been included in safety-related BOMs without adequate dedication documentation. The inspector determined that the BOMs.had either been corrected or deleted from the database. He also determined that the majority of the problems occurre.d before the process enhancements of the procl,lrement engineering and configuration control groups (CCG) had taken place during the 1990.:1991 time fram *

• The inspector randomly selected three of the 35 issues for. his review (class codes 55-8771 - uninsulated copper compression terminal; X38-4106 -Cap screw; and *

X38-7870 - locking lug). He found that the licensee had properly identified the key characteristics of the components and justified their use in safety-related.

application The second assessment was initiated to review the remaining PC4 class code components. This review identified approximately 420 discrepancies. All discrepancies had been dispositioned. The licensee had also concluded that there 1 was no operability concern with the incorrectly classified components installed in the plant because all were commercial grade and all had satisfactory. passed post-installation testing. Furthermore, dedication testing of available components of the same material, part number, and manufacturer confirmed their acceptability for their safety-related functio For this review, the inspector randomly selected several corrective actions completed by the licensee to address applicable installed components consisting of pneumatic relays, tubing, fuses, resi~tors and potentiometers. He determined that the licensee's evaluation of the identified concerns and justification for the use of the components were acceptabl * Conclusions.

Based upon the above review, the inspector concluded that the licensee had _taken reasonable steps to address the material related concerns and to ensure the adequacy and availability of the material required, the accuracy of BOMs, and the proper use PC4 components in safety-related applications. However, because the material management improvemer:it process was ongoing, a definite assessment of the process could not be made. Therefore, this item remains open pending further NRC review of the effectiveness of implemented programmatic change E1.11 NRC Restart Item 11.6 - EOG Output Breakers Fail to Close (Closed)

This issue pertains to three 1995 events involving the failure of the emergency diesel generator (EOG) output breaker to close during scheduled tests. The NRC originally reviewed the actions taken to address the issue in August 1*996 (Inspection Report No. 50-272; 311/96-10). At that time, the inspector concluded that the licensee's assessment of the most probable cause for the three events was reasonable and that the recommendations to revise the surveillance procedure were also reasonabl Earlier in 1996, the licensee had experienced some maintenance-related breaker failures to close on demand and had conducted a root cause analysis. The generic issues pertaining to breaker maintenance were also reviewed by the NRC and were documented in Inspection Report 50-272; 311 /96-07. During that review, an NRC question regarding closure and opening speed of the breaker contacts was unresolved pending resolution by the licensee.

Because of. the unresolved breaker refurbishment issue, this item was left open pending resolution by PSE&G and NRC review of the results. As stated in Section E8.5 of this report, the unresolved issue regarding breaker opening and closing speed was closed. Therefore, this item is also close E1.12 NRC Restart Item 11.16 - NRC and QA Identified Numerous lnservice Test Program Deficiencies - Program Scope (Open) (See also E1.13. E1.14. E3.1, E6.1. E7.1). Inspection Scope The inspectors reviewed PSEG's lnservice Test (IST) Program documents, the Salem

• Unit 2 Updated Fihal Safety Analysis Report (UFSAR) and technical specifications, system drawings, and surveillance test procedures to verify that pumps and valves that perform a safety function were included in the* 1sT program. The inspection focused on components in the au.xiliary feedwater, safety injection (SI) and resrdual heat removal.(RHR) systems*.

• * Observations and Findings The inspectors reviewed. the IST program basis data sheets for the selected systems and noted that a large number of valves were identified as having active safety functions in one direction of travel and passive safety functions in the other direction. For example, a normally closed valve that was required to be closed during a design-basis a~cident would not be exercised periodically in the closure direction.Section XI, Subarticle IWV-21 Ob <?f the Code defines passive valves as valves that are not required to chang*e position to accomplish a specific function, while active valves are those that are *required to change position to accomplish the function. * The inspectors determined that several valves in the reviewed systems *

that were designated as having passive safety functions actually had active safety functions, and were active valves within the meaning of the Cod One example of an incorrectly classified safety function was valve 21 SJ 14, one of four reactor coolant system (RCS) cold leg injection check valves. The program basis data sheet stated that the valve had safety functions in both directions, but only the open direction was considered to be an active function and tested in accordance with Code requirements.* The basis sheet cited UFSAR 5.2.7.1.5, which describes the closed function as being required* to prevent inter-system leakage from the RCS to the SI system. The licensee stated that since the valve was not required to move froni its normally closed position during an accident, the close function was passive. However, the NRC's position, documented in Section 2.4 of NUREG 1482, "Guidelines for lnservice Testing at Nuclear Power Plants;" is that a valve that is routinely repositioned during power operation, or that has an active safety function, is an active valve. Therefore, periodic verification of

-*.

.. ::***.

.

. --*-*------*

the closure function is required for valves, whether normally open or closed, if they perform a safety function in the closed position. The. inspectors concluded that PSE&G had not interpreted the Code requirements correctly, and that several safety *

functions that were designated as passive were, in fact, active. The inspectors noted tha~ approximately 58 valves in the SI system alone were affected by the misinterpretatio The inspectors also.noted instances in which component safety functions were not identified in the licensee's program. The basis data sheets for RHR pump suction check valves 2RH75 and 2RH76 stated that the valves "... must be capable 9f closure to prevent diversion of flow and deadheading of one_ RHR pump when both RHR pumps are in operation. This is required in the unlikely event that one RHR *

pump develops a greater discharge head over the other inservice pump."

Notwithstanding, the licensee concluded that the valves had no safety function in the closed position. *

Finally, the inspectors. identified valves that appeared to have safety functions that were not included in the Salem IST program:

Safety injection accumulator isolation valves 21-24SJ54 are described in UF$AR Sections 7.6.2 and 6.3.2.16 as being normally open and under administrative control with motive power locked out during normal power operation. The IST program basis data sheets state that the open safety function of the valves is passive. However, the valves. receive an SI

. initiation signal to open, and the licensee's Generic Letter 89-10 motor-operated valve program considers the valves to have a active open* safety

. function through manual SI initiation if a loss of coolant accident occurs during plant startu *

UFSAR Secti°on 6.3.2.16 states that the SI initiation signal was removed from the centrifugal charging pump (CCP) miniflow isolation valves, preventing automatic termination of miniflow. Manual valve CV197, which directs reactor coolant pump sealwater return flow to the suction of the CCP, was locked closed and manual valve CV130 was locked open to route sealwater return and CCP miniflow to the volume control tank (VCT).

Therefore during a safety injection initiation, the VCT will fill solid causing VCT relief valve CV241 to open, directing miniflow to the chemical and volume control system holdup tanks. Procedurally, the operator will be instructed to terminate miniflow below an RCS pressure of 1500 psig and to re-establish miniflow if RCS pressure rises again to 2000 psig.. The inspector noted that valves CV241 and CV130 were not included in the Salem IST program. The inspector also noted an apparent inconsistency in Section 6.3.2.17 of the UFSAR which states that no manual actions are required of the operator for proper operation of the emergency core cooling systems

.during the injection mode of operation.

-1

The inspectors did not review whether the above identified discrepancies were the result of inadequate evaluations during recent IST program revisions or whether they existed prior to the current shut<;town. This review will be completed by the NRC during a followup inspection of the program to be completed prior to the restart of Unit 2. The discrepancies were, nonetheless, discussed with the licensee who initiated a re-review of the incorrectly classified components to ensure that no IST of these components was required while fuel was being moved and with the reactor in modes 6 anp 5. This review identified no components for which IST was required. Additional reviews were ongoing for other* reactor mode Conclusion The inspectors identified several apparent IST program scope deficiencies that require PSE&G resolution prior to startup of Salem Unit 2. Several examples of incorrect classifications require further NRC review to determine the source of such discrepancie A PSE&G's evaluation of the potential impact on fuel loading of several valves that had been improperly excluded from the IST program was not initiated until fuel loading was ongoing and the NRC specifically questioned the need of such evaluatio E1.13 NRC Restart Item 11.16 - NRC and QA Identified Numerous lnservice Test Program Deficiencies - Pump Fixed Reference Values (Open) (See also E1.12. E1.14, E3.1, E6.1. E7.1) Inspection Scope The inspector reviewed Salem IST program technical position TP-4, "Pump Fixed Reference Value Variance, II to ascertain compliance with the requirements of Subarticles IWP-3100, IWP-3110, and Table IWP-4110-1 regarding testing of pump Observations and Findings PSE&G's IST program technical position TP-4 references NRC guidance contained in Section 5.3 of NUREG-1482 regarding the establishment of fixed reference values within +/- 2 % of the stated fixed reference value, and states that " *.. in no case will the total tolerance exceed +/- 2 % of the reference value without a corresponding adjustment to the associated acceptance criteria or an evaluation being performed to justify the greater tolerance." TP-4 also contains an example of an acceptable gage accuracy evaluation. Documentation for the flow instruments used to test the SI and component cooling water pumps was included in TP-4 and found by the inspector to be acceptabl Surveillance procedure S2.0P-ST.SW-0001 (Q), "lnservice* Testing - 21 Service Water Pump," did not appear to meet the requirements of Subarticles.IWV-3110 and IWV-4600, or of the NUREG, and was not discussed in position TP-4. Section

• 5.2.2 of the procedure instructs the operator to throttle valve SW458 until instrument 2PL 16017 reads 12 pounds per square inch differential (psid). A note in*

Section 5.2.1 indicates that the normal fluctuation of the gage is approximately +/- 1 Psid, and that 12 psid represents approximately [sic] 10,875 gallons per minute (gpm) of flow.. The allowed fluctuation in the gage reading is +/- 8.3% of the*

reference value. It was not clear to the inspector how the allowed fluctuation provided for a repeatable reference value. Also, there was no method describ~d in the procedure or in the IST.Program documents regarding how the flow rate of 10,875 gpm was de~ermined. By the end of the inspection, the inspector was not *

able to determine fro'm the documentation reviewed how the flow rate determined from the "conversion factor" is used to assess the pump's hydraulic performance against the acceptance criteria of the Code. This issue will be reviewed agaiff by the inspector during a followup inspection to address closure of the subject restart ite Conclusions The surveillance test procedure for the 21 service water,pump did not appear to satisfy the Code requirements for reference value repeatability. However I further review is required by the NRC to determine how the licensee assesses the hydraulic performance of the pum E1.14 NRC Restart Item 11.16 - NRC and QA Identified Numerous lnservice Test Program Deficiencies - Accumulator Discharge Check Valves (Open) (See also E1.12. E1.1 E3.1, E6.1. E7.1l Inspection Scope The inspector reviewed calculation S-2-SJ-MDC-1394, "Accumulator Pressure Decay During Discharge Test," and procedure 82.0P-ST.SJ-0006(0), "lnservice Testing Safety Injection Valves - Mode 6," used to satisfy the ASME Code periodic exercise requirements for the SI accumulator discharge check valve Observations and Findings In a safety evaluation dated April 15, 1994, the NRC granted relief from the Code test frequency requirements for SI accumulator check valves 11-14SJ55, 21-24SJ55, 11-14SJ56, and 21-24SJ56 (sixteen valves). Since then, the licensee redrafted the relief requests, now designated as V-24 and V-25, during its IST program upgrade effort. The inspector determined that the new relief requests also included a deviation from the Code test method requirements. The licensee performed a partial flow test to verify that each check valve disk was exercised to its full accident flow position. The licensee check valve program coordinator informed the inspector that a non-intrusive test method was used during the accumulator dump test, but only for preventive maintenance. purposes, and not for

IST acceptance. The inspector there.fore concluded that the test method did not conform to the guidance of Position 1 of Generic Letter 89-04, "Guidance On Developing Acceptable lnservice Test Programs," *and that NRC approval is required to use the current test metho N~C approval of the relief request will be needed prior to startup of Salem Ur:iit Conclusion PSE&G will need NRC approval of the IST method used to exercise the SI accumulator check valves at Salem Units 1 and 2. The relief from the Code test requirements will.be required prior to startup of Salem Unit E3 Engineering Procedures and Documentation E NRC Restart Item 11.16 - NRC and QA Identified Numerous lnservice Test Program Deficiencies - Program Procedures and Documents (Open) (See also E1.12, E1.13, E1.14, E6.1, E7.1 Inspection Scope The purpose of this portion of the inspection was to evaluate the procedures and other licensee documents that describe the implementation methods for the Salem IST program. The IST requirements are contained in Salem Unit 2 Technical Specification 4.0.5, which* requires *te.sting in accordance with 10 CFR 50.55a,

"Codes and Standards,_" and Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the Code). Administrative procedure NC.NA-AP.ZZ-0070(0), "lnservice Testing (IST) *and Valve Programs,"

establishes the general requirements for implementing the IST program.

. Observations and Findings

.

.

.

PSE&G currently tests safety...:related pumps and valves pursuant to Section XI, Subsections IWP and IWV of the Code ( 1983 Edition through the Summer 1 983 Addenda), with the exception of power-operated valves, for which the applicable portions of Part 10 (OM-10) of ASME/ANSI OMa-1988 recently have been adopte The inspectors found that the licensee's method of establishing initial valve stroke time reference values was appropriate,.and that the.provisions stated in Section 4.2. 7 of NUREG.1482 concerning the use of OM-10 in lieu of requirements of Section IWV of the Code were followe *

Administrative procedure NC.NA-AP.ZZ-0070(0) establishes an IST Program Manual containing: (1) a requirements section, referencing applicable sections of 10 CFR 50, NRC Regulatory Guides, the Salem Technical SpeCifications, ASME Code

• * Editions and Code Cases, and additional NRC commitments; (2) a copy of the latest program submitted to the NRC; (3) a copy of the N.RC Safety Evaluation for the latest program submittal; and '(4) a section identifying each. component, and a brief

.,

description of the evaluation that determined the applicable design and test

requirements. PSE&G maintains the program manual as a controlled document

.

.

/,

under its 10 CFR 50, Appendix 8, Quality Assurance Program. The inspector note.d *

that biennial reviews of the manual and of all IST program submittals to the NRC are called for to determine the need for an updated su~mittal to *the NRC. Maintenance of a centralized program document.exceeds Code requirements and was considered by the inspectors to be useful initiativ The inspectors found that each component in the IST program is described in an IST program basis data sheet. Each data sheet contains information such as component number and description, plant drawing number and grid coordinates, normal, safety, arid fail-safe valve positions, Code category, test requirements, a safety *function discussion,.and references. The references included the Salem UFSAR and technical specifications, design-basis documentation program documents, design calculations, 10 CFR 50.59 safety evaluations, and NSSS and vendor analyse The licensee stated that the documents were reviewed for comments and concurrence by operations and system and design engineering personnel as appropriate. Neither the program.manual nor the basis data sheets are reviewed per 10 CFR 50.59, "Changes, tests, and experiments." However, the inspector noted that surveillance procedure revisions* that may result from changes to these documents are evaluated by the licensee per.10 CFR ~0.59. As evidenced by the findings discussed in Section E1.1, some of the d~ta sheets reviewed were not entirely complete. However, the inspectors considered the documents t*o be good resource for design and _licensing basis information at the component level, consistent with Section 2.4.4 of NUREG 1482. The inspectors concluded that establishment of the data sheets was an excellent initiative that exceeded Code requirement Consistent with NRC findings previously documented in Inspection Report *

-1 50-272;311 /94-21, the inspectors found that the licensee's surveillance test

• ,,

procedures were of high quality, and contained clear, step-by-step instructions for performing the test~, documenting and evaluating post-maintenance test results, re-establishing baseline values, qispositioning unsatisfactory data, and taking the*

necessary actions for alert and required action range Conclusions The IST Program Manual was treated as a controlled document under' PSE&G's 10 CFR 50, Appendix B Quality Assurance Program. The manual and the IST program basis data sheets exceeded Code requirements and were an excellent initiative. Changes in IST scope, test frequency, and methodology were evaluated by the licensee in. accordance with 10 CFR 50.59.

E6 Engineering Organization and Administration E NRC Restart Item 11.16 - NRC and QA Identified Numerous lnservice Test Program Deficiencies -Program Administration (Open) (See also E1.12. E1.13. E1.14. E E7.1)

.

. Inspection Scope The inspectors reviewed and discussed with licensee pen:;onnel the administrative cQntrols and procedures that govern the conduct of IST at Salem in light of the weaknesses and deficiencies that *were identified previously during NRC inspections and PSE&G Quality Assurance audits (See Section E7.1 ). Observations and Findings.

During a review of the Salem IST program, documented in Inspection Report 50-272;311/94-21; the NRC identified programmatic* shortcomings indicative of weak management oversight including: (1) unclear roles and responsibUities, (2)

inadequate resources, *(3) lack of effective* self-assessment, and (4) inad~quate corrective action.* T~e * 1sT Coordinator was unable to manage the program.due to

. the constraints imposed by day-to-day test activities, and was not linked formally*

with many of the activities (such as post-maintenance testing and procedure review and approval) that involve the IST progra PSE&G addressed the shortcomings by: ( 1) consolidating the IST and inservice inspection functions under a Manager of. Specialty Engineering (Reliability Assessment)~ creating a new supervisory position for the IST program group, and designating a full-tim~ IST Manager to oversee implementation of the test progra * IST-related activities previously assigned to other Salem organizations were transferred to the Manager of Specialty Engineering; (2) defining.and communicating management expectations, roles, and responsibilities throughout the Salem organization; and (3) strengthening the IST Manager position. For example; dur.ing.

the IST program stop work order that was in effect during 1995, written approval of the IST Manager,* on a case-by-case basis, *was required prior to conducting each surveillance test. All IST implementing procedures have been revised to require prompt review of applicable post-maintenance and inservice tests by the IST Manager. Operations, engineering, maintenance, and planning personnel with a role i_n IST have bee.n brief_ed on the program bases, requirements, and processe The inspector reviewed administrative procedures NC.NA-AP.ZZ-0070(Q),

"lnservice Testing (IST) and Valve Programs," and SH;RA-AP.ZZ~0105(Q), "IST Program Manager Activitie The.procedures clearly delineate the responsibilities of the Salem organizations involved in IST, and provide explicit and detailed guidance. for implementing the program. The inspector found that some of the provisions embodied good engineering practices that exceeded minimum Code

• requirements. For example, the inst.rum~ntation and.controls department is required to notify the IST Program Manager so that a *component evaluation can be performed whenever test instruments used in the IST program are found to be out of calibration. The inspectors verified that adequate measures were in place to ensure that IST results are reviewed promptly t>y the IST Manage PSE&G also retained the servic~s of an outside expert in IST programs to perform an on-going third-party review of pr~gram activities. The inspectors found the individual to be very ~nowledgeable regarding Code requirements and the NRC positions documented in NUREG-1.482, "Guidelines for lnservice Testing at Nuclear Power Plants," *and other generic NRC document * Conclusions PSE&G has established the organizational and administrative measures needed to implement an effective IST program. The licensee's corrective actions adequately addressed the programmatic weaknesses identified by the NRC and the PSE&G Quality Assurance organization in previous IST program review E7 Quality Assurance in Engineering Activities E NRC Restart Item 11.16 - NRC and QA Identified Numerous lnservice Test Program Deficiencies - Qu.ality Assurance of IST Program (Open) (See also E1.12. E1.1 E1.14. E3.1, E6.1l*

. *

a:

Inspection Scope The inspector reviewed the PSE&G Technical/Programmatic Restart Issue No. T-16 closure package, dated October 10, 1996. The package contained copies of Quality Assurance (QA) IST program Audit 95-012S, dated August 26, 1995, the Salem IST Program Stop Work Order, dated July 31, 1995, and the Root Cause Analysis Report associated with the stop work order. The purpose of the review was to assess PSE&G's evaluation of the root causes and corrective actions for the administrative and technical deficiencies identified in the QA audi The inspector also reviewed the ten Plant Improvement Requests (PRs) categorized by the licensee as plant startup items, and eight (approximately one third) of the post-startup items to: (1) verify that PSE&G properly categorized the items, (2)

confirm completion of the restart items, (3) ensure that corrective actions complied with Code requirements, and (4) assess the quality of the licensee's startup item closure proces *

Observations and Findings The PSE&G QA organization conducted a broad-based audit of the Salem IST program from July to August, 1995. The auditors identified significant problems in the areas of test scheduling and methods, program documentation, test instrumentation, and corrective action. The audit team cor:tcluded that the program

• .::-** -

was not being implemented effectively, did not meet regulatory requirements, and did not implement commitl'T)ents made to the NRC in response to Generic Letter 89-04, "Guidance in Developing Acceptable lnservice Testing Programs." The executive summary of the audit report stated that "... the IST Engineer lacked control and authority over th~ prog*ram. Inadequate management attention t,o previous NRG and Audit Findings resulted in long standing deficiencies in the IST program.... S.trong ownership by Engineering and the support of the Operations, Planning and Maintenance Depar:tments' management is necessary... to ensure that-changes are effective.... ". The inspector noted that many of the findings paralleled-those documented in NRC Inspection Report 50-272 & 311/94-21, dated November 30, 1994. (See Section E6. 1)

On July 31, 1995, QA issued a stop work order on IST at Salem, permitting testing to continue only wi~h written authorization, on a case-by-case basis. Several actions were required to be completed prior to removing the order, including: (1)

notifying the IST Engineer prior to conducting IST, (2) confirming that IST procedures adequately demonstrated equipment operability per technical specifications and the ASME Code, (3) validating acceptance criteria, (4) assuring IST Engineer review of procedure.and acceptance criteria changes, and (5) _

• establishing process controls adequate to ensure that test *equipment used ih IST met Co~e* range and accuracy requirements, and that all out of calibration

. -~ : -~~ instruments were reported to the IST Engi_neer for test evaluation. Lof"1g term

-

• -- action*s included verification that Generic Letter 89-04 commitments to the NRC

• were met, that the IST manual was reviewed and updated* to reflect NRC commitments, design-b.asis requirements, and program responsibilities, and establishment of an effective document control process for pump baseline data sheets. (The last two items are discussed in Sections E6.1 and E8.1, respectively,

• of this report.) QA lifted the stop work order on December 12, 199 The* inspector reviewed the audit report and the 37 action request items and observations contained therein. The inspector concluded that the audit was-comprehensive and self-critical, and that the technical findings were sound and accurate. All of the audit findings were entered into the licensee's corrective action program and tracked to resolution. The stop work order evidenced QA management's willing.ness to force change as needed to ensure qualit The inspector reviewed the root cause analysis performed by the licensee in response to the audit findings and the stop work order. The licensee attributed the

. _program deficiencies to: (1) lack of management commitment to establish and

• implement an IST program in accordance with regulatory requirements, commitments, and industry standards; (2) management failure to (a) recognize and emphasize the importance of the program, (b) establish and communicate expectations, responsibilities, and accountabilities, (c) provide adequate resources, and (d) implement_ adequate IST_program performance indicators; (3) lack of

• • ,_

coordination and teamwork between the technical and operations groups. The inspector concluded that the root cause evaluation accurately identified the basic causes of the program deficiencies identified during the 1994 NRC inspection arid the 1995 QA audit. As discussed in Sections E3.1 and E6. 1 of this -report, the licensee's corrective actions to add.ress the root causes appeared to have been effectiv The technical deficiencies identified by the licensee ultimately were captured,*

evaluated, resolved, and tracked in the PR system. Each PR contained several items or findings that were individually tracked. For example, PR 950807327, "ASME Section XI Criteria," contained nine corrective action items. Each item was categorized and prioritized as a startup or post-startup item. Only item CRCA 2 to incorporate baseline data sheets into Unit 2 IST procedures was a startup prerequisite. The inspector verified through review of the PRs that the items listed in the T-16 closure package w*ere categorized appropriately; that is, the inspector agreed that none of the post-startup items reviewed needed to be completed prior to startup of Salem Unit 2. The inspector noted that the QA department evaluators

.adopted a performance-based approach to item closure. After reviewing the technical department's response, the evaluators typically personally verified on a sampling basis that the required *actions actually were performed. For-example, item CRCA 3 of PR 950807308 required development of a programmatic standard describing the conduct of the IST program, including information on IST manual *

updating requirements. The technical department responded that administra~ive procedure SH.RA-AP.ZZ-0105(0), "IST Program Manager Activities," would be issued. The QA evaluator verified that the procedure, in fact, was-issued and contained the necessary information. The inspector concluded that the QA organization properly evaluated and verified the closure of PR startup item The inspector verified through review of IST program documents and procedures that seven of the ten Salem Unit 2 startup items listed in the T-1 6 closure package were completed, and that the* remaining items were in the. process of being implemented. The following items remained open at the end of the inspection:

PR 950807291 PR 950807301 PR 950807327 Complete revision of the 23 turbine-driven auxiliary feedwater pump surveillance procedure. PSE&G was tracking CRCA 11 as a Mode 3 prerequisit Review Unit 2 stroke time data to ensure "alert" range testing decisions were correct. This item was completed. However, CRCA 8 issued to revise all valve procedures to incorporate OM-10 requirements was not complete Incorporate pump baseline data sheets into procedures. This item was completed. However, CRCA 8 concerning a

.

surveillance procedure for 23 auxiliary feedwater pump was not d.one. This item, categorized the item as a Mode 3 prerequisite, did not appear in the T-26 startup list. *

PR 950721197 PR 950825284

Track work orders for MS46 valve torque values and revise procedures with new acceptance criteria (CRVR 2). The *

inspector was informed that the work was still in progres.

.

Incorporate alternate check valve test methods into pro.cedures (CRVR 2). The inspector was informed that new procedures were written and undergoing revie The inspector concluded that work on the startup items was substantially completed. However; several items, as described above, were not closed at the *

time of the inspection. Completion of these items was considered necessary for restart of Salem Unit Conclusions The PSE&G Quality Assurance organization performed a comprehensive and self-critical audit of the Salem iST program. The stop work order indicated a willingness to force change te ensure quality and evidenced a sound safety perspectiv PSE&G's root cause *evaluation accurately identified the basic causes of the IST

. program deficiencies, and corre~tive actions appeared to be effective. Technical ite!Tls appropriately were categorized as plant startup prerequisites, were properly tracked, and verified by QA evaluators for closure. Five Unit 2 startup items remained open at th_e_end o~ the inspectio ES Miscellaneous :Engineering Issues.

..

.

• ES. 1 (Closed) Unresolved Item 50-27 2 & 311 /94-21-01 : Review and approval of safety- *

related pump test.baseline data sheet *

PSE&G's administrative procedure for review and approval of changes to the IST

. acceptance criteria contained !i:i pump b~seline data sheets did not appear to conform to the technical specification requirements for review by a Station Qualified Reviewer (SQR).

This item was covered by i~em 2 of Performance Improvement Request (PIR)

.

950807327. Resolution of this PIR eliminated the pump test baseline data sheet Therefore, the issue is no longer a concern. The acceptance criteria for components in the IST program currently are contained in procedures that correspond *to each specific surveillance test procedure. The inspector verified on a sampling basis' that the new *procedures were reviewed by an SQR, that technical specification review and approval requirements are imposed appropriately by administrative procedures, and that 10 CFR 50.59 safety evaluations are performed for initial procedure issue and for subsequent revisions. The inspectors noted also that administrative procedure SC.RA-Tl.ZZ-0028(Q), "Pump And Valve *Reference And Acceptance Criteria Value!?," requires IST engineers to verify that new reference values do not

• conflict with the.values established in plant design and licensing document *

E (Closed) Unresolved Item 50-272 & 311 /94-21-02: Inadequate cold shutdown justification During the 1994 inspection, the inspectors were unable to conclude, on the basis of PSE&G's IST program documents alone, that certain power-operated valves could not be exercised at least once every three months as required by the ASME Cod The licensee subsequently revised its cold shutdown justifications to provide the requisite level of detail: The inspector reviewed justifications associated with the auxiliary feedwater, residual heat removal (RHR), safety injection, and containment spray systems (including justification CS-16 for RHR heat exchanger cross-connect valves 11, 12,21,22SJ45 and justification CS-38 for containment spray isolation valves 11, 12,21,22CS-36) and concluded that the revised documents were acceptable. The licensee co~cluded that no cold shutdown justification was required for safety injection accumulator outlet valves 11-14SJ54, because periodic valve exercising was not required by the Code. This test scope issue is discussed in Section *E1. E (Closed) Violation 50-272 & 311./94-21-03: Failure to test check valves in accordance with Section XI of the ASME Cod *

PSE&G did not exercise charging pump suction check valves 1 SJ3 and 2SJ3 at the periodicity required by the Code, and did not disassemble anµ inspect pressure relief tank check valves 1 PR25 and 2PR25 in accordance with the NRC safety evaluation that granted relief from the Code test method and frequency requirement.

PSE&G in their letter LR-N95001, dated January 16, 1995, attributed the violation to personnel error and *inadequate attention to detail. Regarding valves 1 SJ3 and 2SJ3, PSE&G submitted relief request V-18 to partially stroke the valve~ open during cold shutdowns and to full stroke exercise the valves each refueling outag The NRC approved.the request in August 1995. The inspector verified that closed safety function of th.e valves i.s verified as specified by the Code. For valves 1 PR25 and 2PR25 PSE&G submitted. relief request V-16. The valves are full-flow tested quarterly, and reverse flow tested each refueling outage during performance of a local leak rate test per 10 CFR 50, Appendix J. The NRC gr~nted generic relief to*

use this approach in Section 4.1.4 of NUREG-1482, "Guidelines For lnservice Testing* At Nuclear Power Plants." The inspector verified that the information contained in relief request V-16 satisfied the NUREG guidelines, and that a recurring maintenance task properly scheduled the Appendix J tests. To prevent recurrence, the licensee augmented the plant IST staff and strengthened administrative processes to provide additional assurance that IST is performed in accordance with Code requirements. (See Section E3.1) The inspector concluded that the licensee's corrective actions were acceptable.

• I

..,

E (Closed) Violation 50-27 2/94-21-04:. Failure to identify and correct conditions adverse to qualit This violation involved: (1) repetitive failures to establish new pump reference values following maintenance, and *(2) ineffective corrective action for leakage through safety injection pump discharge relief valve 22SJ39. As stated in PSE&G letter* LR-N95001, dated January* 16, 1995, the violation was caused by inadequate administrative controls to ensure that the IST engineering staff was promptly informed regarding maintenance and test activities affecting components in the IST program. This weakness was reconfirmed by the PSE&G quality assurance organization in 1995 and documented in IST program audit 95-1 25 and performance improvement request 95071924 The licensee revised* its implementing procedures to require IST engineer signoff of all test data following pump maintenance. Also, new system engineering division procedure SH.RA-AP.22-0105(0), "IST Program Manager Activities," contains provisions to ensure timely review of all IST results. Based on his review of these procedures, the inspector concluded. that the new administrative measures adequately addressed the cause of the violation.

The licensee also strengthened the technical guidance for rebaselining component

. reference values contained in procedure SC.RA-Tl.ZZ-0028(0), "Pump and Valve Reference and Acceptance Criteria Values." The inspector found that the procedure contained a number of commendable attributes including: ( 1 ) a section evaluating the need to rebaseline a component; (2) appropriate references to the ASME Code for component testing; (3) references to other 'industry standards, such as ASTM-E29-93a, for properly rounding off recorded test data to appropriate signific~nt.

digits; and (4) an individual li~ting of each pump in the IST program with th~

specific data sheet required to rebaseline the pump. The inspector noted also that PSE&G conducts full flow tests of a number of pumps in the IST program during refueling outages. The augmented pump tests exceed Code requirements and were

. considered to be a program strength. The inspector concluded that the procedure provided an excellent. means to determine. and document the need to. re baseline IST component.

.

E (Closed) lnsoection Followup Items 50-272: 311 /96-07-03: Breaker Closing Spee During a followup inspection of refurbishment issues related to General Electric 4 kV Magne-Blast circuit breakers, the NRC determined that PSE&G, after making all

adjustments, conducted func;tional tests and captured the mechanism motion on

• * *

film to obtain GE concurrence for breaker operability. As a result of these tests, PSE&G had measured contact opening times. However, because of methodology differences, the time measurement could not be immediately compared with GE closing* and opening speed requirements. This issue was an inspection followup item pending NRC verification that contact closing and opening speeds were not

. outside the GE specification *

• To address the NRC question, PSE&G iss.ued a perform*ance improvement request (PIR), No. 96031.5194. Resolution of this PIR initiaUy involved submittal to General Electric of appropriate recorded test data~ GE's evaluation of timing data submitted by PSE&G confirmed that the ve.locity of the breaker contacts, following PSE&G adjustments, was greater than the minimum specified for opening and closing in GE instruction book No. GEH-230A Subsequently, PSE&G developed a method to measure the contact travel distanc Using travel distance and contact closing time measurements taken with the high speed camera, PSE&G was able to -calculate the contact velocity and verify its compliance with GE specifications. PSE&G included this measurement method in their maintenance procedure No. SC.MD.IS.4kV-0001 (0), Revision 13, "4kV and 13kV Magne-Blast Circuit Breakers Inspection and Test." *

The inspector reviewed PSE&G's evaluation and testing as well as correspondence with GE and tl:te revised maintenance procedure. Based on this review, he concluded that the actions take to address the breaker closing and opening velocity were acceptable. This Item is close E (Closed) Unresolved Item 50-272; 311195-06-01: Safety concerns regarding piping and pfpe* supports Inspection Scope This item pertains to the_ licensee's investigation and resolution of concerns raised by a former employee. Some of the employee concerns related -to the design adequacy of piping and pipe supports and to the licensee's handling of identified problems in this area. The licensee completed their investigation in the summer of 199 To evaluate the scope of the investigation, the validity *of findings, and the

. adequacy of the proposed programs, procedures, and schedules of the corrective actions, the inspector reviewed the investigation report of licensee's independent contractor; the records of the licensee's staff review of, and comments for the investigation findings and conclusions; the licensee's resolution of the concerns; and the planned corrective action Findings In the fall of 1994, the-licensee engaged a contractor to perform an independent investigation of concerns raised by a former employee. After the investigation, in 1995, the contractor submitted a comprehensive report of its finding to the licensee.

-*-*..

Pressurizer Safety and PORV Supports and Piping Outside Code Allowables In May 1990, the NRC issued a safety evaluation report (SER) in response the PSE&G's submittal regarding NUREG-0737, Item 11.D.1. The SER included two open items that required licensee reanalysis. PSE&G hired a contractor for the

.

.

'

required rea~alysis. In September 1991, the contractor concluded that the Safety Valve and PORV discharge piping, pipe.supports, and welded attachments exceeded ASME code allowable stress leve.ls after valv~ actuation for all valves~

The employee's concerns regarding this issue included:

The contractor analyses had identified problems in stress calculations which resulted in support redesign (including exceeding of code allowable stress).

• Once the analyses indicated that Salem was not in compliance* with the licensing basis and 1 OCFR 50.55a, the licensee had prepared no Justification for Continued Operation (JCO).

The 1994/1995 contractor review of the employee's concerns concluded that the concern with this issue was substantiated. Specifically, the investigation *

establislled that, as a result of inadequate stress calculations for piping and pipe supports in safety-related systems: 1) Salem had oeen neither in compliance with its licensing basis, nor with 10 CFR 50.55a; 2) no timely determination ha*d been made to continue plant operation; and 3) appropriate reporting and followup actions had not initiated in a timely *manner. Furthermore, the contractor determined that

• Units 1 *and 2 JCOs had been issued fourteen (November 1992) and ten months

• (July 1992), respectively, after the problem discovery, and that no licensee event report (LERI had been submi~ed to notify the NRC of the operability criteria used to justify continued operation and of the plans and schedules to bring piping and supports in compliance with licensing and Code requirements.

.The licensee acknowledged that, prior fo the issuance of the JCOs, there was lack of timeliness in operability review, inadequate consideration of reportability, and inadequate corrective action documentation. They attributed these deficiencies, in part, to lack of understanding of the regulatory significance of the issue, failure to follow formal corrective action process, insufficient management oversight, and excessive focus on the technical resolution of the issue.

. The failure of the Salem staff to evaluate and correct the identified piping and piping*

support deficiencies in a timely manner is a violation of the requirements in 10 CFR 50, Appendix 8, Criterion XVI, Corrective Action. Since the NRC has taken significant enforcement action for Salem's failure to identify and correct conditions adverse to quality, and since PSE&G voluntarily maintained both Salem units shut down to address. equipment and. enforcement deficiencies, the NRC will not take additional enforcement action iri this cas *

Regarding the status of required corrective actions, the inspector determined that plant modifications to.address the technical concerns had already been designed and installed at the time of the contractor's investigation. The *inspector also determined that the licensee had provided additional training to engineering and other technical* personnel to emphasize the management policy and expectation for timely evaluation and reporting of operational or design concerns. These messages were delivered in staff meetings and technical training sessions. for the staf * Records were made ayailable for inspectors' revie Regarding reportability, discussions with the licensee indicated that originally, when the contractor determined that the piping, piping supports, and welded attachments exceeded the code allowable stress levels, PSE&G had not concluded that the system was inoperable or seriously degraded. Therefore, the condition was not reportable in accordance with 10 CFR 50. 73. In developing the JCO, PSE&G determined that the components design met the operability criteria they had established and, hence, the *condition was not reportable. Subsequently,. the system was modified to bring the design into compliance with applicable code Therefore, reportability *was not longer an. issue. What was more a concern was the licensee's corrective action program and their timeliness in addressing safety

/i*

concern The adequacy and effectiveness of the corrective action and root cause analysis programs, in general, were evaluated during the NRC review of item 111.a.10 of the restart action plan for Salem and found acceptable. These programs are also included in the Salem restart readiness review checklist (IV.1.2), and are to be a_ssessed furt~er by the restart tea Containment Soray System Pieing Modifications Two other issues in the employee concern related to a piping modification in the containment spray (CS) system. The main technical and safety concern raised by the former employee focused on the licensee's failure.to leak-test a blank flange temporarily installed in the system to maintain containment integrity during modification. The work involved replacement of a section of CS piping that had developed.a through-wall leak. This piping was replaced with a spool piec The inspector's review of this concern determined that,* during modification planning, the licensee* appropriately recognized that the work would disable one train of'the CS system for longer than allowed by the technical specification (TS).

On March 4, 1989, the NRC granted enforcement discretion for the conditio Because a through-wall leak on the. containment side of an outboard isolation valve

. is technically the same as an inoperable outboard isolation valve, Section 3.6.3 of the TS applies. The action statement of this section requires that, with a containment isolation valve _inoperable, at least one isolation valve must remain

"operable" for the affected penetration. Further, TS Section 3.6.3.c action statement allows the use a blind flange and one closed isolation valve to meet the co.ntainment isolation requirements. In conformance with these requirements, the

licensee did not subject the containment spray system penetration to Type "B" leak-tests. The inspector considered the licensee's decision not to perform a type "B" leak-test following the installation of the flange, but while.the modification was ongoing, acceptabl Following completion of the modification and before returning the system to service, the licensee should have performed a leak-test of the installation. The plant UFSAR, Table 6.2-12, Rev. 6, dated February 15, 1987, indicates the CS system valves to be subject to Type "C" tests. The licensee's submittal indicated that a post-maintenance Type "C" test to determine the acceptability of the modification was not_ performed before the system was returned to operatio Containment Spray Initiation Another issue of the employee concern pertained to the containment spray header occasionally not being* filled and a causing potential containment_ spray initiation delay. To determine th~ technical validity of this concern, the inspector reviewed operating procedures, held discussions with the licensee personnel and reviewed the contractor's independent assessment report. The inspector observed that Procedure S1/S1 - SO.CS-0001 (Q), used to fill and vent the containment spray system, requires the operators to ensure the reactor water storage tank (RWST)

level to be at a minimum level of 40 feet-6 inches prior to beginning the filling and venting process.* This level is above the technical specification. minimum level in the RWST and ensures that sufficient level is available to fill the CS system without going below the technical specification minimum valu *

The procedure further requires that, after the level is confirmed~ the operators open the valves in the containment spray discha.rge and suction. patf:l. This allows water to fill the CS piping to a level equal to the level in the RWST. The level is then verified and system vented by opening vent valves on the header until a solid

• stream of water comes out. Once the system has been filled to the correct level per procedure, the only way level can be changed is to open a vent or drain valve located below the valves. used to initially verify level. The containment spray delay*

(85 seconds) calculated by Westinghouse was based on the header being filled to the minimum RWST level. The delay calculation took into account the anticipated containment pressur A keyword search was made by the licensee of incident reports to determine whether CS had ever been found drained or not filled to the correct level. No incidents could be found; however, Incident Report 94-437 documented a water hammer event that occurred during the eighth refueling outage on Unit 2. In this case, the normal fill and vent procedure was used in conjunction with Pro~edure S2.0P-ST.CS-0010(0), Revision 1, to fill and vent the CS in preparation for a full flow test.. Also, the flow path was different from normal in that water was sent through valve*-21 CS36 and. 21RH18 to the residual. heat removal (RHR) system instead of out the spray nozzles. This flow path had not been used before and was

inadequately vented by the normal vent and fill procedure.* As a result, when CS

• .

pump 21 was started, a water hammer occurre Failure to fill the piping between 21 CS36 and 21RH18 did not affect the ability of

. CS to spray the containment during accident conditions. The piping is normally isolated and would be used only if_a*complete failure. of CS occurred.* RHR would then be used to spray containment. Based on the above observations, the inspector determined that this concern was not substantiate Conclusions Based on the above review, the inspector concluded that PSE&G's investigation of*

the employee concerns was thorough: The investigation was independent and covered broadly the related areas. This item is close During the above investigation, the licensee found that their review of piping and piping support concerns identified in.1991 lacked timeliness and thoroughness of review. The corrective actions were, nonetheless acceptable. The root cause and corrective action programs underwent extensive revamping in recent months. Their effectiveness was evaluated as a part of the NRC restart action plan for Salem (item 111.a.10) and found acceptabl *

ES. 7 (Closed) Unresolved Item 50-311193-26-01: Pressure locking and thermal binding of wedge type gate* valve Pressure locking and thermal binding of wedge-type gate valves concerns were originally expressed. in Inspection Report (IR) 50-272; 50-311 /93-26. The status of the licensee's action to address those concerns, unresolved item 93,.26-01, was reviewed and updated in NRC IR 50-272; 50-311/96-07. At that time some of the valve. related issues were closed. The remaining issues pertaining this unresolved item were evaluated in Section E1.4 of this report and found acceptable for Unit For Unit 1, some of the actions are still incomplete. This item is closed for Unit 2 only..

E (Closed) Unresolved Item No. *s0-311 /94-33-01: Reactor Coolant Pump (RCP) Oil Collection System Deficiencies Resolution of reactor coolant pump oil collection system deficiencies were originally

. reviewed in August 1996. At that time, the NRC found the program. for addressing the identified deficiencies acceptable. However, the required hardware changes had not been implemented. As stated in Section F.8.1 of this report, the required Unit 2 modifications have been completed and the NRC has found the installation of the plant changes acceptable. For Unit 1, the modifications had not been implemente This item is closed for Unit E8.9 * (Closed) Violation No. 50-311195-117-01: RHR Recirculation Valve Failed to Open on Low Flow On June 7, 1995, Salem operators commenced a reactor shutdown due to the inoperability of.both trains of the RHR. The circumstances leading to PSE&G declaring both RHR loops inoperable are described in Inspection Report 50-272; 311/95-10. This event resulted in escalated enforcement and civil penalty, as stated in NRC letter EA 94-112, dated, Octo~er_ 16, 199 As discussed in Section E. 1.8 of this report, the actions taken by PSE&G to ad~ress the technical issues relating to the failure of the recirculation valve to open as designed were acceptable. The adequacy of the corrective action program is *

currently being reviewed separately and generically under NRC Restart Item 111.a.1 Based on the conclusions of section E.1.8, this item is close E8.10 General Conclusions Based on their review of the above engineering packages and corrective actions, the inspectors concluded that:

the acti"ons to address most issues were acceptable and the packages prepared to close the NRC restart items were in the most part complete and of good quality;.

analyses, calculations,. and modification packages, as applicable, were typically acceptabJe, complete and* had received the required reviews;

resolution of programmatic weaknesses, while still incomplete, had received the attention necessary to provide reasonable assurance. of successful results;

recommendations from self-assessments had been properiy evaluated and implemented;

• the IST Program Manual was treated as a controlled document under the Quality Assurance Program; the manual and the IST program basis data sheets exceeded Code requirements and were an excellent initiative;

Engineering evaluations were not always satisfactory. For instance, engineering failed to:

recognize that the auxiliary spray water was being heated while passing through the regenerative heat exchanger and that thermal shock of the pressurizer spray nozzle was never a concern; *

evaluate the NRC underlying concerns regarding the operating temperature of the Hagan modules. Therefore, some of the analytical work regarding this issue had to be redone;

r 3~

recognize th~ potential *impact on fuel loading of several valves that had been improperly excluded from the IST program. Therefore, an evaluation was not initiated until fuel loading was ongoing and. the NRC spedfically requested such evaluation..

The Quality Assurance organization performed a comprehensive and self-critical audit of the Salem IST program. *The stop work order indicated a willingness to force change to ensure quality and evidenced a sound safety perspective. PSE&G's root cause evaluation accurately identified the causes of the IST program deficiencie *

E.8.11 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 *revi~wed the applicable portions of the UFSAR that related to.

the areas insp~cted. The. inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameter IV. Plant Support FS

, Miscellaneous Fire Protection Issues F NRC Restart Issue 11.27 - Rector Coolant Pump Oil Collection System Deficiencies (Closed for Unit 2 Only) Inspection Scope (92903-05)

As discussed in NRC inspection reports 50-311 /94-33 and 96-10, this issue remained open pending the completion of Unit 2 design change package (DCP) 2EC-3379 to resolve RCP oil collection system hardware deficiencies and NRC walkdown of all four Unit 2 RCPs to verify the adequacy of the installed oil collection system Observations and Findings The inspector performed a walkdown of each of the four Unit 2 RCP oil c_ollection systems and found that the changes designated by DCP.2EC-3379 had been appropriately implemented. The inspector determined that the installed configurations were well-designed to ensure that alt potential leakage sites were

. protected and any oil would be collected and drained appropriately, as required by

• 10 CFR Part 50, Appendix R, Section 11.

.

As discussed in NRC inspection report 50-272; 311 /94-33, a conc~rn was identified regarding the lack of a collection* device for iii certain plug and flange. At that time, further NRC review was required to determine if the design was in full compliance with the requirements of 10 CFR Part 50, Appendix R, Section 111.0. Based on additional review of this concern,* the NRC determined that the design was not in compliance with the regulatory requirements. 'However, this issue is being treated as a non-cited violation in accordance with Section Vll.B.1 of NUREG 1600,

"General Statement of Policy and Procedure for NRC Enforcement Action." The bases for this non-cited violation also include:

The f aill,lre to provide collection devices for the subject plug and flange was identified by the licensee;

the noncompliance could not have been prevented by corrective actions taken for a previous violation that occurred over the past two years;

the non -compliance was corrected within a reasonable time by means of a well designed and implemented modification of all Unit 2 RCP oil collectic;>n systems; and

the failure *to provide collection devices for the* subject plug* and flange was not determined to be willfu The inspector noted that the-drawings and instructions established for personnel tasked with reassembly and inspection of the oil collection -components were of very good quality. Specifically, the drawing details were clearly presented and instructions clearly stated the review.requirements for verifying* installation adequac Conclusions The inspector concluded that the licensee had improved the oil collection

• * capabilities of the Unit 2 RCP motors and provided reasonable assurance that a fire would not occur. The inspector verified that the installed configurations.met the

• requirements of 10 CFR Part 50, Appendix R. This restart issue is closed for Unit V. Management Meetings XI Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on January 10, 1996. The licensee acknowledged the findings presente The inspector asked the licensee whether any material examined during the inspection should be considered proprietary. No proprietary information was identifie.*.,

PARTIAL LIST OF ATTENDEES Public Service Electric and Gas Company G. Cranston C. Fricker A. Giardino P. Koppel L. Lake D. Lyons M. McGough S. Michigan G. Overbeck M. Rencheck S. Robitzski G. Salamon J. Schubert A. Spivak

• B Thomi:is E. Villar Manager, Nuclear Electrical Engineering Salem Quality Assurance Salem Projects System Engineer lnsetvice Test Group Supervisor (Salem/Hope* Creek)

Salem_ lnservice Test Manager Director Design Engineering and Projects Technical Assistant to Director Design Engineering Director System Engineering Manager Salem System Engineering *

Technical Engineer Licensing and Resolution System Engineer Maintenance Engineering Supervisor Licensing Engineer Licensing Engineer U. S. Nuclear Regulatory Commission *

T. Fish R. Fuhrmeister R. Quirk Resident Inspector*

Senior Reactor Engineer NRC Contract Engineer W. Ruland*

K. Youn!;J AFW AR CAG

. CAP CA/QS CCHX CROM CRs eve ECAC EOG EOPs ERG FME.

. HDI l&C INPO Ctiief Electrical Engineering Branch Reactor Engineer LIST OF ACRONYMS USED Auxiliary Feedwater Action Request Corrective Action Group Corrective Action Program Corrective Action and Quality Services Component Cooling Heat Exchanger Control Rod Drive Mechanisms Condition Reports Centrifugal Charging Emergency Control Air Compressor Emergency Diesel Generator Emergency Operating Procedures

• Emergency Response Guideline Foreign Material Exclus_ion Hilti Drop-In.

Instrumentation and Controls Institute of Nuclear Power Operations

ISi LER MRC MSIVs

. N/ NBU NRC NTOC OD OEF OTSC PDR PMT PSE&G PWSCC RCP RCS RHR RVLIS SERT SI SIRA SNSS SORC SRG SRO SW TOR TR Gs TRIS TS UFSAR

lnservice Inspection Licensee Event Report Management Review Commirtee Main Steam Isolation Valves Not Applicable Nuclear Business Unit Nuclear Regulatory Commission Nuclear Training Oversight Committee Operability Determinations Operating Experience Feedback

. On-The-Spot Change Public Document Room Post-Maintenance T.esting Public Service Electric and Gas Primary Water Stress Corrosion Cracking Reactor Coolant Pump Reactor Coolant System Residual Heat Removal Reactor Vessel Level rndicating System Significant Event Response Team Safety Injection

.

Salem Integrated Readiness Assessment

• Senior Nuclear Shift Supervisor Station Operations Review Committee Safety Review Group Senior Reactor Operator Service Water Technical Document Room*

Training Review Group Tagging Request Inquiry.System Technical Specification

Updated Final Safety Analyses Report