IR 05000272/1997016

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Insp Repts 50-272/97-16 & 50-311/97-16 on 970609-0725. Violations Noted.Major Areas Inspected:Operations, Engineering & Plant Support
ML18102B579
Person / Time
Site: Salem  PSEG icon.png
Issue date: 09/17/1997
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
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Shared Package
ML18102B577 List:
References
50-272-97-16, 50-311-97-16, NUDOCS 9709220140
Download: ML18102B579 (29)
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Text

U. S. NUCLEAR REGULATORY COMMISSION Docket Nos:

License Nos:

Report Nos:

Licensee:

Facility:

Location:

Dates:

Inspectors:

Approved by:

9709220140 970917 PDR ADOCK 05000272 G

PDR

REGION I

50-272, 50-311 DPR-70, DPR-75 50-272/97-16, 50-311 /97-16 Public Service Electric and Gas Company Salem Nuclear Generating Station, Units 1 and 2 Hancocks Bridge, NJ June 9 - July 25, 1997 A. Della Greca, Sr. Reactor Engineer, EEB, DRS R. Fuhrmeister, Sr. Reactor Engineer, EEB, DRS R. Quirk, NRC Contract Engineer J. Shedlosky, Sr. Reactor Analyst, DRS William H. Ruland, Chief Electrical Engineering Branch Division of Reactor Safety

SUMMARY Salem Inspection Reports 50-272; 311 /97-08 March 31, 1997 - June 6, 1997 This inspection included aspects of licensee engineering and plant support. The report covers 7 weeks of inspection related to equipment and engineering performance issue The inspection also evaluated PSE&G's resolution of a variety of unresolved items, inspection followup items, and violations identified previousl Operations

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Overspeed trip testing of the turbine-driven auxiliary feedwater pump was well-

.controlled, in spite of apparent format and content problems with the infrequently used procedure. (Section 01.1)

Engineering

The analysis to address the inspector-identified cable separation deviations inside relay cabinets TP 25-1 and TP 28-1 was incomplete in that it did not specifically address failure modes of affected components. In addition, the resolution of the cable designation discrepancies was incomplete, in that a thorough evaluation of the circuits had not been done. (Section E1.1)

A violation was identified when testing of the Advanced Digital Feedwater Control System was not conducted in accordance with the controlling procedures. This is a recurring problem. (Section E1.3)

The control room ventilation system design basis for non-redundant dampers for the Salem units was reviewed and found acceptable. (Section E8.8)

The root cause analysis of the MCCB test procedure deficiencies was found to be detailed, well written, and with good insight. The conclusions were reasonable and the recommendations appropriate. (Section E8.4)

The licensee took acceptable actions to improve the quality and accuracy of safety evaluations. As in the case of the molded-case circuit breaker test discrepancies, the inspector found the root cause.analysis to be comprehensive and well don (Section E8.6)

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  • Report Details Plant Status 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 evaluate resolution of these concerns by Public Service Electric and Gas Company (PSE&G) and to observe testing activities related to the restart of Salem Unit 2. Except as noted, the review was conducted in accordance with Inspection Procedure 9290 I. OPERATIONS

Conduct of Operations 0 Auxiliary Feedwater Pump Turbine Overspeed Trip Test (70438) Inspection Scope On June 19, 1997, the inspector observed the pre-test briefing and performance-of S2.0P-PT.AF-0004(Q), Rev. 8, "No. 23 AF Pump Overspeeed Trip Test." On June 29, 1997, the inspector observed portions of a re-performance of S2.0P-PT.AF-0004(Q), Revision 10 uNo. 23 AF Pump Overspeed Trip Test." The inspector reviewed completed test procedures for portions of the test not actually observed. On July 1, 1997, the inspector observed the performance of S2.0P-SO.AF-0001 (Q), Auxiliary Feedwater System Operatio Observations and Findings The purpose of S2.0P-PT.AF-0004(Q) was to ensure the auxiliary feedwater (AF)

pump turbine mechanical overspeed device tripped the steam supply valve 2MS52 between 4900 and 5100 revolutions per minute (RPM). The pump was uncoupled, and a temporary cooling water supply was installe The pre-test briefing conducted on June 19 was thorough and detailed, with special emphasis placed on test termination criteria and test personnel responsibilities. The turbine vendor representative in attendance provided advice on how to proceed with the testing based on his prior experience running this type of turbine after a long shutdow During the test that was performed on June 19, 1997, using Revision 8 of the procedure, the turbine did not reach the overspeed condition on the first three run The overspeed trip test device vvas adjusted, using the instructions in the procedure, to increase turhlrie -RPM on the overspeed trip test. * On the fourth run,

  • the turbine did not trip before reaching 5100 RPM, and the turbine yvas manually
  • tripped. The testing was suspended to perform corrective maintenance to adjust the overspeed trip device. The inspector noted excellent communication between the control room operator and the personnel at the pump, including the use of

"3-point communications," and excellent procedure use by control room personne The overspeed trip setpoint was adjusted and the test was re-performed on June 20, 1997, and the licensee reported the turbine tripped within specification at 5060 RPM on the first retest, but failed the second retest and the turbine was manually tripped at 5117 RPM. PSE&G exercised the overspeed mechanical trip.

mechanism and returned it to the overspeed setting which existed prior to the adjustments on June 19, 1997. The test was re-commenced again, but was terminatea because of procedure problems. The procedure was revised twice before being used agai On June 29, 1997, the inspector observed the re-test pre-test briefing conducted by the Operations department test manager with personnel from Operations, Mechanical Maintenance, and System Engineering. The briefing was thorough, and included a detailed review of the procedure. Emphasis was placed on test termination criteria and communications between the Nuclear Control Operator (NCO) in the control room and the Nuclear Equipment Operator (NEO) at the turbin The main body of the procedure was clear, but there was some confusion of how the 4 attachments were to be used. These issues were discussed, and resolve Before proceeding with the test, the NEO completed a thorough walkdown of the area, and was convinced he understood the intent of the procedure. He did notice at least two instances where components were labeled differently in the field than in the procedure. These problems were reported in conformance with site procedures, and as the intent of the procedure was clear, testing continue The procedure was closely followed by the NCO and NEO, with the Test Manager also verifying procedural compliance several times. Precautions concerning minimizing time at < 500 RPM as well as at critical turbine speeds were followe Expectations were for the governor to engage between 1775 and 1975 RPM. This did not happen, and speed was slowly increased to 2200 RPM at which point, the Nuclear Shift Supervisor (NSS) and NCO were notified as reqllired by procedur A decision was made to decrease speed to 2100 RPM, and after a discussion between the test manager, mechanical maintenance, and control room personnel, a decision was made to slowly increase speed to determine if the governor would engage before reaching 3500 RPM. That speed was reached, and the governor was not engaged. The speed was decreased again, and after further consultations between the Test Manager, NCO, NSS, Mechanical Maintenance, and System Engineering, a decision was made to increase speed up to 4200 RPM. If the governor had not engaged by that point, there would be further discussion The lice*nsee reported that at.. 4050 RPM,. the governor engaged, and 23 AFP speed decreased to 1850 RPM. The procedure was followed to increase turbine speed and there were two successful tests of the turbine* overspeed mechanism. The NEO required an "On-The-Spot-Change" to the procedure when securing the turbine after LI r

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  • the first trip. When the 23 AFP was restarted for the second overspeed test, the governor engaged properly. Action Request (AR) 970630268 was initiated to address the governor not engaging between 1800-2000 RPM. The licensee surmised that the governor was not engaging because the NEO was increasing the speed too slowly. The vendor was consulted who said the acceleration rate was likely not the reason, and the problem was probably caused by a small corrosion particle in the governor oil. The vendor said if the problem continues then the governor oil should be changed. The 23 AFP was retested on July 1, 1997, using a normal startup procedure, and the governor properly engaged at 1825 RPM. The vendor was consulted who recommended no action be taken because the governor was responding properly. The vendor said that if the problem repeats frequently then the governor oil should be changed after turbine run Conclusions E1 E1.1 The testing was conducted in a controlled manner using approved procedure When the equipment was determined to not be functioning properly, appropriate actions were taken. This was an important test on critical path to plant heatup, and personnel used conservative judgment The 23 AFP turbine is a safety-related component. The number of procedure deficiencies which were resolved by two procedure revisions, an OTSC, and generation of ARs for labeling deficiencies, coupled with confusion regarding the use of procedure attachments, may be indicative of problems with the content of procedures which are not routinely used. The inspector will check for similar problems with infrequently performed Operations Department procedures in the future. (IFI 50-311/97-16-01).

Ill. Engineering Conduct of Engineering Inside-Panel Cable Separation Inspection Scope In addressing cable separation within *panels, Section 8.1.4.2.5 of the FSAR states that redundant safety-related components/wiring are generally located in physically separated panels and racks. In those cases where redundant components are located within the same panel, the design, material and wiring arrangement of the component is such that the propagation of an electrical fault from one separation group to the other is minimized. The FSAR section further states that redundant cables carrying redundant functions are separated by 6 inches, conduit, or suitable barrier. During walkdowns to address NRC Restart Item 11.21, Wiring Separation &

Redundancy Concerns with RG 1.97 Instruments and Cable Separation, the inspector observed apparent cable separation deviations inside relay cabinets. The purpose of this inspection was to evaluate the acceptability of such deviations.

Observations and Findings To address the NRC observations, PSE&G provided an analysis prepared in June 1990 by a licensee consultant. This analysis, No. S-C-VAR-CEE-0389, Revision 0, "Engineering Evaluation of Salem Generating Station Units 1 and 2 Physical Separation and Electrical Isolation Requirements," evaluated the design bases and licensing commitments of the plant relative to cable separation and electrical isolation and provided the criteria to be used in the development of a Salem-specific technical standard. In the evaluation, the licensee concluded that the physical separation and electrical isolation criteria used at Salem were acceptable to ensure physical independence of Class 1 E power and instrumentation and control systems. The licensee also concluded that the criteria complied with the requirement of IEEE Standard 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations," and IEEE Standard 308-1971, "Class 1 E Electric Systems for Nuclear Power Generating Stations."

The inspector review of the evaluation identified no areas of concern. The document provided a historical perspective of cable separation requirements and Salem commitments, but because it was not supported by physical plant walkdowns, it did not provide any insight as to the plant conformance to the criteria that had been established. The document cautioned that, in those areas where deviations existed between actual field conditions and the separation criteria,

"analyses must be performed to assure that the single failure criterion is not violated." The document also contained several recommendations, including revision of the FSAR to clarify separation criteria used, development of a standard to meet the criteria, and the development of evaluations to address. issues such as Regulatory Guide 1.97 and Safety Parameter Display System computer-related cable Although clarifications were provided in the FSAR regarding separation criteria, it was not immediately evident that actions had been taken to implement all other recommendations. For instance, although the document contained an analysis, dated October 10, 1973, to address some cable deviations that had been identified, no other analyses had been prepared to document other.deviations, such as those identified by the inspecto /

Regarding the specific deviations identified by the inspector, the licensee prepared engineering evaluation No. S-2-VAR-EEE-1228,. Revision 0, "Cable Separation Evaluation inside the Cabinets TP 25-1 and TP 28-1." This evaluation provided a description of the functions of the cables questioned by the inspector and concluded that the deviations were acceptable because either the functions of applicable cables were not safety-related or were not redundant and, therefore, were in compliance with IEEE Standard 27 The inspector's review of the engineering evaluation and other documents, including a distribution panel list, did not identify specific concerns with the conclusions reached by the licensee. The licensee's analysis itself, however, was limited in that it focused strictly on showing that the cables in question did not involve

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components and circuits performing redundant functions. An analysis of failure modes (e.g., hot shorts, protective device failure, or similar condition) and of their effect on associated components and systems was not prepared to show that the interaction between cables from* redundant divisions did not also impact redundant functions. A single failure analysis, including the use of the guidance of IEEE Standard 379 and IEEE Standard 352, is recommended by Section 2.6 of Technical Standard DE-TS.ZZ-1023(0), Revision 0, "SGS Physical Separation and Electrical Isolation Requirements (l&C)."

The inspector's review of the engineering evaluation of two cable designation discrepancies: cables 2F8D7-FQ and 2RP382-ET carried solid blue and solid gray color code markings, respectively. However, based on their cable designations (F and E, respectively) they should have carried blue and white (striped) and gray and white (striped) color code markings. At Salem, cables having solid color makings are considered to be vital; cables with striped color markings are considered to be associated cable An action request (AR), No. 00970716174, was issued by PSE&G to address the

  • inspector's identified discrepancies. A review of this AR and subsequent discussions with the licensee indicated that they planned to change the color code makings from solid to striped, but the inspector expressed a concern that the label change might be.inappropriate in at least one case. For instance, one of three wires in the gray cable provides the return path to the power supply for indication circuits that the licensee has designated as non-vital. The same wire also provides the return path to the power supply to several relays that, based on their description, appear to perform vital functions. No isolation device exists between the vital and nonvital portions of the circuit. The significance of this observation is that, at Salem, nonvital cables from different channels can run together after they become associated with a vital cabl Conclusions The analysis prepared by the licensee to address the inspector-identified cable separation deviations inside relay cabinets TP 25-1 and TP 28-1 was incomplete in that it did not specifically address failure modes of affected components as recommended by the licensee's procedure. In addition, the resolution of the cable designation discrepancies identified by the inspector was incomplete in that a thorough evaluation of the circuits had not been done. This issue remains open pending the licensee verification of the analysis result and resolution of the color coding discrepancies. (Unresolved Item 50-311/97-16-02)

Based on the inspector's preliminary review of applicable documents neither of these issues is a plant restart condition. In the case of the analysis, the inspector's conclusions were based on the following: (1) less thari ten cables are involved; (2) the-cables are within cabinets and, therefore, not subject to external hazards;

(3) the relay room itself is defined as a limited hazard area, according to IEEE Standard 384-1992; (4) safety systems were originally designed to withstand the failure of a single relay cabinet; (5) a preliminary review of a distribution panel load list appeared to support the licensee's conclusion; (6) for the potential interaction between two cables to exist, an electrical fault concurrent with the failure of the protective device would have to occur; and (7) cables and protective devices are safety-related. In the case of the cable color coding discrepancies, the conclusions were based on the fact that the current cable installation is conservative in that the cables in questions are treated and routed as vital cable E1.2 Control Room Ventilation Testing (37828) Inspection Scope Design Change Package (DCP) 1 EC-3505 made extensive modifications to the control.area ventilation (CAV) system. The inspector compared the testing completed as part of the design change process and recently completed surveillance tests (ST), and compared these to related Tech Spec surveillance requirement This inspection is a continuation of work from inspection report 50-311/97-1 Observations and Findings Technical Specification section 4. 7.6 identifies control room envelope emergency ventilation surveillance tests. The inspector compared these to several recently completed DCP 1 EC-3505 post-modification test results and ST procedures. All associated Tech Spec surveillance requirements (SR) were met by successful completion of STs except for 4. 7.6.1.d(5) which requires the demonstration of the Control Room Emergency Air Conditioning System (CREACS) design heat load removal capability. PSE&G stated this requirement was met by testing associated with DCP 1 EC-350 PSE&G stated that in the future S1.RA-ST.CAV-0004(0) "Unit 1 Control Room Emergency Air Conditioning System Surveillance, and S2.RA-ST.CAV..;0003{Q)

"Unit 2 Control Room Emergency Air Conditioning System Surveillance," will be used to verify compliance with Tech Spec 4.7.6.1.d{5). These STs verify the air side of the cooling coils are not fouled by using a visual inspection, the chill water sides are not fouled by performing a system flush, and chill water flow is verified by performance of chilled water system lnservice Test (IST) rather than by actually measuring the chill water flow to the cooler. Engineering chill water flow hydraulic analysis, CRE heat loads, and CREACS chiller heat transfer calculations were used to demonstrate the chiller would be able to remove the design heat load. PSE&G indicated this was consistent with guidance in Generic Letter {GL) 89-13, Service Water System Problems Affecting Safety Related Equipment. The inspector identified several discrepancies with this approac..

The PSE&G response to GL 89-13 included service water and component cooling heat exchangers but it did not include chill wate *

  • Neither the CREACS ST nor the chilled water inservice inspection include a chill water flow and temperature measurement for the CREACS chillers nor require efficiency tests as required by GL 89-13 Enclosure 2 Section I and Il e S-C-CAV-MDC-1569, the design control room heat load calculation used to determine CREACS chiller loads, had incorrect assumptions. One assumption was the maximum makeup air would be 2000 SCFM; Tech Specs permit up to 2200 SCFM makeup air, and actual values measured during performance of 1 EC-3505-11 STP-11 were 2087 SCFM. Another assumption is the heat generated in control room panels 1 (2)RP3 and 1 (2)RP4 is removed by the Control Room Area Air Conditioning system (CAACS). As a result of changes made by 1 EC-3505-11, the heat load is removed by CREACS, not CAAC The licensee indicated ST-and/or ISTprocedures will be modified to ensure they meet the requirements of Tech Spec 4.7.6.1.d(5). As a minimum, the modifications will include measuring CREACS chilled water flows and temperature PSE&G agreed that some of the assumptions in S-C-CAV-MDC-1569 are not correct. If the Technical Specification allowable value of 2200 SCFM makeup air is used, the design heat load would increase approximately 2 %. PSE&G also stated changes with RP3 and RP4 heat removal were evaluated as part of DCP 1 EC-3505-11 and found to be acceptable because they add approximately 1 % more heat load for the CREACS chiller. The licensee stated there was approximately 22% margin in the heat removal capability, and these changes will be incorporated in the associated calculations as part of DCP 1 EC-3505 Part B closur Conclusions TS 4. 7.6.1.d(5) is a new Salem Tech Spec, and is consistent with standardized Westinghouse Tech Spec Surveillance Requirement (SR) 3.7.11.1. The basis for this SR includes the statement the SR "consists of a combination of testing and calculations." The inspector concluded the recent post-modification testing, coupled with chill water flushing completed in July 1996, met the 18-month Tech Spec requiremen The existing surveillance tests do not verify the ability to remove the assumed heat load. PSE&G stated they came to a similar conclusion as part of their investigation of Violation 50-311/97-10-001, and stated procedures will be revised to include verification that the CREACS chill water flow and temperatures meet design requirements. PSE&G also stated they would revise design calculations. When issued, the inspector will review the calculations and procedures to ensure they are adequate to demonstrate compliance with Tech Spec 4.7.6.1.d(5). (IFI 50-311/97-16-03).
  • E1.3 Advanced Digital Feedwater Control System Testing (70448) Inspection Scope Design Change Package 2EC-31 78 installed an advanced digital feedwater control system (ADFCS), and 2EC-3306 added an automatic turbine runback on loss of a Steam Generator Feed Pump (SGFP), modified the automatic Auxiliary Feedwater start circuits on loss of both SGFPs, and installed a digital SGFP governor syste The inspector observed several tests associated with these modifications. These tests included portions of the standard post-modification testing referred to as Workbook 6 Section 10 testing as well as Special Test Procedures (STPs). Observations and Findings In general, tests were conducted by properly trained individuals who were very knowledgeable of the modified equipment, in accordance with the proper revision
  • level of approved procedures, and with calibrated test equipment. The inspector attended several pre-tests briefs conducted by the Test Engineers. These briefs included personnel from Operations, Engineering, Shift Test Engineer, and test technicians. The briefers were well prepared, understood the test procedure, and

,.resolved questions before proceeding with the*tests. In general, the results wer properly documented and reviewed, and test deviations were resolved in a prompt and correct manner. Some deficiencies were noted by the inspecto The most significant problem was a failure to ensure all 2EC-3178 STP-2, "Power Ascension Test, pre-requisites were completed before beginning the tes SH.Pl-AP.ZZ-0012(0), Rev. 0, "Modification Test Program," Section 5.2.1.1 states that the Test Engineer is responsible for verifying that prerequisites are complete

  • prior to testing. Procedure SH.Pl-AP.ZZ-0012(0), Section 5.2.2 states that test performers are responsible for performing test steps and making appropriate data entrie None of the five pre-requisites were signed off before performing 2EC-3178 STP-2 Section 5.5.1, "Mode 5 Signal Sampling." One of the pre-requisites was, "All pre-operational testing has been completed in accordance with test sections 10. 1 through 10.9 and [2EC-3178] STP-001." Most of 2EC-3178 STP-1, "Site Acceptance Testing," was completed, but portions,.including some testing by the Digital Systems Group, were not. After test equipment was installed for the 2EC- *

3178, Section 5.5.2, "MS10 Dynamic Tuning," on June 15, 1997, the inspector identified the lack of completing 2EC-3178-1 STP-1 to the test engineer, who stated the pre-requisite would be deleted using the Modification Concerns/Resolution (MCR) process later that da *

At the June 15, 1997, pre-test brief for 2EC-3178 Section 5.5.2, the test engineer signed off prerequisites 5.2.1 and 5.2.2. Prerequisites 5.2.3, 5.2.4, and 5. could more appropriately be called precautions for testing at power. During the pre-test brief on June 16, 1997, the oncoming operations shift noted the three remaining prerequisites were not signed, and required the steps to be signed off before proceeding. This failure to ensure pre-requisites are completed and the appropriate steps signed off is a violation of the requirements in SH.Pl-AP.ZZ-0012(0), "Modification Test Program." {VIO 50-311/97-16-04).

2EC-3178 STP-2 Section 5.1. 1, "Special Equipment," identified the Westrac data acquisition system as the required special test equipment. This equipment will be used when testing steam generator level transients performed in mode 2 and 1.

Neither the equipment used for the mode 5 signal sampling nor the equipment used for the MS 10 valve testing in mode 4 was included in the list of special test equipment, although this was required by procedure used to develop the test, NC.DE-AP.ZZ-0012(0), Test Program. This test procedure was written before PSE&G increased their awareness of the need for compliance with this procedure, and the licensee corrected this problem during mode 4 testing. As the problem was corrected, the equipment used was appropriate for the test, and the equipment is not safety-related, this matter is not being cited for enforcement actio There were technical problems encountered while performing the atmospheric steam dump valve test. On June 15, 1997, the MS10 test cables connectors associated with the 21MS10 valve and 24MS 10 valves shorted out, resulting in signals to one valve actually operating two valves. This problem was the result of using uninsulated coax cable connectors. The testing was stopped, Condition Report 970616179 was initiated, the problem was rapidly diagnosed, the connectors were insulated, and testing was resumed. PSE&G stated that if the test had been on safety-related equipment, steps to ensure proper separation between the test cables would have been included in the procedur The CR resolution did not include an evaluation that the shorts did not damage the sensitive digital control system equipment. The test engineer indicated his understanding of the system was the ADFCS card input impedance was high enough to preclude damage. However, the test engineer stated an evaluation of this type would have to be completed by the design engineer, who was not

  • informed of the*problem *before testing was resume Additionally, there was evidence that cable shorting also occurred on the previous shift, but was not included in the test engineer watch turnove There was no apparent violation of procedure when the sensitive digital equipment was not thoroughly evaluated for damage before returning the system to servic Some PSE&G personnel were aware of potential problems associated with digital equipmer:it damage, but it was not obvious that this knowledge is widespread. The normal approach to analog systems is to do a rapid evaluation for obvious damage,
  • and then re-energize the equipment. There is a higher risk with doing this with certain digital equipment, and this is an area for potential improvemen On July 22, 1997, the inspector observed the MS 10 valve dynamic testing conducted as part of DCP 2EC-3178-01 Special Test Procedure (STP) -2. This testing was conducted at close to normal operating pressure, and was a continuation of valve controller dynamic tuning which began on June 15 when the plant entered mode 4. Observations were made in the Unit 2 control room (CR) as well as in the Unit 2 Electrical Equipment Room (EEU).

The purpose of this testing was to ensure the new digital controllers for the MS 10 valves operate properly at steam generator normal operating pressures.. At the direction of the Test Review Board the licensee conducted this portion of the STP on the Salem plant specific control room simulator to validate the test procedur There were several lessons learned from this pre-test investigation, including a decision to use a smaller step change and change the acceptance criteria from

. quarter wave tuning to controlling pressure within 5 pounds of the setpoint. These issues were discussed in a well prepared pre-test brief. Use of the simulator to validate the test prior to conducting the test was considered a strengt The test was well designed, and required one MS 10 valve to be in automatic while the other three were in manual.. Stable initial conditions were established, a ste decrease in pressure setpoint was introduced, followed.by a step increase. After both transients, the controller returned the plant to a stable condition, within one *

pound of the setpoint, in approximately one minut There was a failure. by the test engineer to follow the instructions in the procedur After each MS10 valve was tested, the procedure called for stopping the recorder, and annotating the recorder output with the test procedure and step number, test engineer, time, and date. On July 22, 1997, this was not done for the first three transients until. the NRC inspector pointed this out. At that point, the test engineer properly. marked the test recorder output. This is a failure to comply with the requirements of SC.SE-AP.ZZ-0002(0), Conduct of Testing, section 5.2.2, which requires test instructions to be followed. This NRC identified violation is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Policy due to its minor nature and lack of safety consequences. (NCV 50-311/97-16-06) Conclusions This test was the first special test executed after entering mode 4, and had high visibility. In general personnel performance during the test was adequate. The p~oblems identified are not major from a technical standpoint, and the ADFCS system, automatic runback circuits, and digital governors are not safety-relate However, procedure non-compliance has been a problem in the past at PSE&G. The inspector discussed these and other minor observations with the engineers involved as well as with PSE&G startup an.d test management personne [

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The licensee acknowledged the prerequisites were not completed, but stated that all the important portions of the prerequisite test STP-1 were completed. Additionally, STP-1 was modified so it could be completed. Appropri~te actions were taken by the licensee, including removing STP-1 as a prerequisite for STP-The licensee initiated an AR when the MS 10 valves were not operating properl The evaluation of the cable short consequences was somewhat superficial before testing was resume E1.4 Main Steam Generator Feed Pump (SGFP) Testing (70400)

- Inspection Scope The inspector observed SGFP testing and related trouble shooting associated with

. DCP 2EC-3306-1. The testing included standard post-modification testing, referred to as Workbook 6 Section 10, and STP testing. Procedure 2EC-3306 STP-3 tested the electrical and mechanical overspeed trip device Observations and Findings Numerous problems were encountered during these tests. Some, such as defective relays and solenoids; could be classified as routine maintenance issues. However, most were the result of design errors. Testing was conducted with the SGFP turbine and pump uncoupled. The problems observed included the following items:

Inability to Latch 22 SGFP turbine trip valve because of defective relays and solenoid. These problems were not identified during system readiness review walkdown *

Valve lineup problems. Two control oil vent valves were open, although this was in accordance with valve line-up procedures. Additionally, a steam flow transmitter vent valve was ope *

Speed Demand Indicator Errors. There were at least two design errors with the steam demand signal which required several days to resolve. One error was the control room indicator was scaled from 0 to 7500 RPM; the correct range was 1100 - 5500 RPM. The other error was the result of grounding the signal shield in the floating ground Woodward Governor cabine False indication of SGFP eccentricity. The new SGFP vibration monitoring

. system relocated eccentricity probes. The new location near the end of the

  • shaft also sensed turbine* shaft runout, but this was not expected,* and higher than expected "eccentricity" values were observe *

Mechanical Overspeed Trip Device Failures. The mechanical oversp-eed trip*

devices on both 21 and 22 SGFP would not operate in a repeatable manne The problem appears to be caused by excessive oil flow resulting from SGFP vibration probe **

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_ Most of the SGFP problems could have been resolved in mode 6, or prior to fuel load. Several of the test procedures were written to be performed prior to fuel load using the site auxiliary boiler. Due to problems with systems required for earlier mode transitions, resources were diverted from the nonsafety-related feedwater problems to the more pressing mode restraint system problems. PSE&G understood the risks associated with this approach, and has now taken corrective action Conclusions The SGFPs are not required for safe shutdown,.cooldown, or minimizing the release of radiation to the general public. As such, they are not safety-related. However, feedpumps and feedwater control problems are the leading cause for unplanned trips in Westinghouse plants. The SGFPs will be required shortly after entry into mode 1. PSE&G's actions to resolve the various problems appeared to be appropriate, and are continuin E7

  • Quality Assurance in Engineering Activities E7.1 Rod Control Testing (70432) Inspection Scope The inspector observed rod control testing for the Individual Rod Position Indicator Calibration completed under procedure TS2.IC-SP.RCS-0001 (Q), and Rod Drop Time Measurement - Hot Full Flow, S2.IC-ST.RCS-0001 (Q). The rod drop timing test also included control rod dashpot entry data collectio Observations and Findings

.. On.July 11., 1.997, while establishing initial conditions for the TS2.IC-SP.RCS-0001 (Q), personnel were taking action to clear the URGENT FAILURE rod control alarm by following Rod Control System Operation, S2.0P-SO.RCS-0001 (Q) section 5.2 "Energize Rod Control System~" All control rods were fully inserted. While moving the ROD BANK SELECTOR SWITCH th.rough the AUTO position there were indications that rods stepped out, but no rod-motion was expected. PSE&G formed an investigation* team and concluded that a failed TAVE module created a TAVE IT REF mismatch, which caused the rods to step in.. S2.0P-SO.RCS-0001 (Q) was enhanced by adding a precaution concerning possible rod motion when the ROD BANK SELECTOR SWITCH moves through the AUTO position, and also relocated steps used to ~lear the rod control failure alarms to ensure alarms are cleared after shutting the reactor trip breakers, but before moving the *ROD BANK SELECTOR SWITCH. There was no actual rod motion, the plant was in a safe shutdown condition, the procedure deficiencies were quickly identified, and the procedure was revised before continuing testing. However, the TAVE module was known to be failed, and there was som*e* iack of -understancting of the full implication *

On July 17, 1 997, the control room shift identified a problem with several minimum shutdown margins calculated during rod testing. The preparers of the calculation did not take into account that rods were not all on the bottom. With all rods on the bottom the required boron concentration was ~ 2050 ppm boron, but with one or more rods off the bottom, the required concentration is ~ 21 50 ppm boron. The plant was in a safe condition because boron concentration was > 2400 ppm. The suspected cause was a complicated procedure used to calculate shutdown margi On July 16, 1997, S2.IC-ST.RCS-0001 (Q) testing was observed. This was an infrequently performed test, and was on critical path to startup. This was the first time this procedure was being performed by concurrently dropping an entire bank of rods. The Test Engineer prepared to brief it as a frequently performed test, but the NSS correctly canceled the briefing until a procedurally compliant infrequent test briefing was prepared. After the revised briefing was completed, testing commenced. After withdrawing *the first bank of shutdown rods, an unexpected *

HIGH SOURCE RANGE COUNTS AT SHUTDOWN alarm was received. Nuclear instruments were observed to be spiking, but not increasing, and all other rods were verified to be on the bottom. The SNSS directed that the rods be inserted, and a new RCS sample be analyzed for boro Conclusions In general, the control room personnel performance was adequate. Attention to reactivity management issues, with the exception of the incorrect shutdown margin calculation, was good. The apparent cause for this problem was inadequate procedures for infrequently performed evolutions. As noted in section 01. 1, this is a matter which will require further evaluation by NR E7.2 Control Loop Tuning (7044 7) Inspection Scope The inspector observed selected portions of procedures used to tune plant process controllers. These controllers were replaced as part of the Hagan Module projec The operation of other Hagan modules can be observed in a static condition, but it is necessary to demonstrate the new controller modules respond correctly during a transient. Observed tests included Chemical and Volume Control System (CVCS) *

letdown flow temperature and pressure control in TS2.SE-SU.RCP-0004(Q) and TS2.SE-SU.RCP-0005(Q), and pressurizer level control in TS2.SE-SU.RCP-0007(0).

Observations and Findings These tests were classified as infrequently performed tests, and were preceded by

.adequate pre-test briefs. Emphasis was placed on test termination criteria, acceptance criteria, communications,. and the $top, Think, Act, Review (ST AR)

  • .

principle. The acceptance criteria was the transient decay ratio should be 1 /4 or less. The decay ratio is defined as:

Decay Ratio = Second Peak Overshoot First Peak Overshoot Instrument maintenance personnel did a good job following the procedures, but were unable to meet the required decay ratio using the controller settings specified in the design change package. The transients were slow, and the setpoints were reached after one overshoot. A second overshoot meeting test requirements was not obtained. After several unsuccessful attempts at tuning each of the loops, the results were sent to Engineering for review. After some analysis, tuning was re-conducted using different parameters. Atthe end of the inspection period, none of these tests were completed_ successfull Conclusions The licensee has been unable to prove to themselves that the new controllers act as anticipated by the design organization. It is not clear if the problem is a result of hardware problems, tuning skill problems, or test requirements that are too restrictive. This issue remains unresolved pending the final test results review and approval. (URI 50-311/97-16-05)

ES Miscellaneous Engineering Issues E (Updated) Unresolved Item 50-272: 311 /96-01-09: CR205 Relays Used in Safety-Related Applications This item was opened as a result of Hope Creek engineering personnel identifying two issues with some Model CR205 machine tool relays manufactured by General Electric. The two issues involved the use of #16 AWG wires with terminal lugs

. designed for #14 AWG minimum wire, and the chattering and hanging-up of the relay auxiliary contacts. As stated in the original report, by the end of the inspection period, the licensee had determined that some CR205 relays were being used in safety-related applications and, although they believed that the auxiliary contacts were not being used, they were conducting a detailed revie Discussions with the licensee, during the current inspection, indicated that the review was completed shortly after the inspection in conjunction with another engineering effort *that addressed a General Electric service information letter, i.e., SIL No. 508, involving aging of the CR205 relays. However, the results of

. these efforts had apparently been lost and were not available for the inspector's review. Therefore, the item remains open.pending the licensee's recovery of the documentation and the NRC review-of the results of the licensee's evaluations, including their resolution of the SIL 508 issu j

  • E (Closed) Violation 50-272: 311/96-01-10: Failure to Follow NAP-25 Procedure Regarding Combustibles E On January 24, 1996, a fire occurred at Salem involving demolition work of coal-tar lined service water (SW) piping. This fire occurred within a 24-inch diameter pipe located in the Unit 2 auxiliary building SW valve room no. 21, known as the mechanical penetration area. The inspector's review of the event determined that, although the hot work permit for this job had been appropriately posted and signed prior to commencement of actual work as required by NAP 25, Part 2 of the permit had not been adequately completed. Part 2 required validation by the job supervisor that the work area was safe and free from combustible and flammable materials within 35 feet. Flammables were observed by the inspector during the area walkdown. The inspector also determined that a firewatch failed to remain in a work area for a minimum of 30 minutes after hot work had been performe In their response, letter No. LR-N96105, dated April 25, 1996, PSE&G attributed the violation to personnel error and failure to follow procedure requirements. Based on their conclusions, they conducted meetings with contract personnel and supervisors emphasizing management expectations regarding compliance with the NAP 25 requirements. In addition the licensee directed the fire protection department to conduct inspection of selective hot work activities and to notify management of any procedural non compliance. To avoid further violations, supervisors involved in field activities where hot work may be included received firewatch and NAP 25 training. On July 17, 1997, in response to a NRC concern that PSE&G's letter had not addressed the root cause of why previous corrective actions had failed, the licensee supplemented the April 25 letter stating that those concerns had been addressed in their Salem Restart Action Pla The inspector reviewed the lesson plan and confirmed that supervisory personnel had received fire watch and NAP 25 training. The inspector also reviewed Nuclear Fire Protection Procedure ND.FP-DD.ZZ-0012(Z), Revision 1, "Hot Work Authorization." This revised procedure requires the nuclear fire protection supervisors or designees to conduct random inspections of hot work activities and provides the instruction on specific activities to be observed and documented. The inspector also verified that the activities in the Salem Restart Action Plan had been completed by PSE&G and reviewed and found acceptable by the NRC. Based on the above review, this item is close !Closed) Unresolved Items 50-272: 311 /96-13-04: Localized High Temperature in the Diesel Generator Room During the review of the thermography data recorded for #2A EOG Room during an extended run of 2A EOG on August 15, 1996, the inspector noted that the temperature of detector No. 4 had two recorded readings in excess of 120° F (141 and 130° F): This detector,- loc-ated several feet from the EOG exhaust manifold, had been previously relocated further away from the exhaust manifold due to overheating concerns (see item 3 above). Salem UFSAR, Revision 14, Section 9.4.5, Diesel Generator Area Ventilation, Paragraph 9.4.5.1, Design Bases,

states that, "The ventilation systems are designed to limit the temperature of each diesel generator compartment to 120° F and each control room to 110° F in the summer with equipment in the room operating." Since the UFSAR did not discuss localized high temperature areas, the inspector questioned the licensee about the acceptability of the high temperature reading The licensee's review of the issue determined that there was no equipment in the vicinity of the exhaust manifold that would be adversely affected by the higher temperature. The licensee also observed that the 120° F specified in the UFSAR referred to bulk room temperature. Therefore, they planned to clarify the UFSA The inspector's review of the area confirmed that there was no safety-related equipment in the immediate vicinity of sensor. Therefore, he considered the licensee's resolution of the issue acceptable. This item is close E (Closed) Violation 50- 272; 311/97-02-01: Failure to Replace Oversized Fuses and

. to Correct Discrepancies Between Calculation and MCC Test Procedure This violation involved two examples of inadequate corrective actions to address identified deficiencies. The bases for the violation and the licensee's actions to address each issue are described belo In the first example, the licensee had issued a Performance Improvement Request (PIR), No. 951230143, to address a concern that the 15A fuses used in the secondary circuit of control power transformers might be too large to protect the circuit. In their review and resolution of the PIR, they recognized that the fuses did not adequately protect No. 20 AWG wires, but failed to ensure that all circuits with No. 20 AWG received adequate overcurrent protectio In the second example, the licensee had issued several PIRs, including N, to address discrepancies they had identified between Calculation ES-13.005 and molded case circuit breaker (MCCB) test procedure SCMD-ST.ZZ-004(0). The actions to correct the PIR 960612148 had been apparently completed on July 26, 1996, yet two subsequent revisions of the procedure had failed to correct all discrepancies. In addition, other discrepancies were identified by the inspecto Regarding the fuse issue, in their letter, dated May 28, 1997, PSE&G attributed the violation to personnel error and to a less than adequate fuse control program. The licensee had previously developed Programmatic Standard SC.DE-PS.ZZ-0051 (Q),

"Fuse Control Program for Salem Generating Station Units 1, 2, and 3," dated May 2, 1996, and Technical Standard SH.DE-TS.ZZ-2037(0), "Fuse Selection Design Standard for Salem and Hope Creek Generating Stations," dated March 29, 1996. In addition, the licensee evaluated the use of oversized fuses. Based on the results of their evaluation indicating that no operability or safety concern existed, PSE&G planned to replace the* oversized fuses following the plant restar * CR 0096121 2235 was prepared to track completion of this effort currently scheduled for March 1998.

The NRC reviewed the Technical and Programmatic Standards during their review of NRC Restart Item 11.12, Review Adequacy of Fuse Control Program. The NRC also evaluated the impact on safety of oversized fuses. As a result of this review the restart item was closed. Closure of the restart item was documented in inspection report 50-272; 311 /97-0 Regarding the MCCB test procedure discrepancies, the licensee attributed the violation to programmatic deficiencies with the procedure revision process, in that this process did not require entry of the revision request into the corrective action program and, hence, the request could not be tracked. To address this issue, the licensee revised procedure NC.NA-AP.ZZ-0001 (Q), Nuclear Procedure System," to require preparation of an Action Request in conjunction with the procedure change request. In addition, PSE&G established a single point of contact within electrical engineering to coordinate MCCB testing and initiated a root cause analysis to determine whether additional actions would be required to prevent recurrence of the violation. An engineering evaluation to assist maintenance in the testing of the MCCBs had been previously issue The inspector confirmed that the procedure had been revised to track procedure change requests and evaluated the results of the root cause analysis. This root cause analysis team concurred with the licensee's conclusions, above, but also attributed the failure to identify and correct the discrepancies to other factors, such as: (1) *inadequate Quality Assurance audits in the past; (2) inadequate operating experience program; (3) human error caused in part by "Tunnel Vision" and "Time Pressure" and (4) inter-organization interface problems. The analysis team recognized that program* improvements had removed most causal factor Therefore, they made no additional recommendation for corrective actions except that they considered it beneficial to develop a MCCB testing and maintenance program in which responsibilities and ownership are clearly define The inspector review of the root cause analysis found it to be detailed, well written, and with good insight. The conclusions were reasonable and the recommendations appropriate. Based on the above review and the review of the two issues under the NRC restart plan (I Rs 50-272; 311 /97-02 and 97-08), the inspector concluded that acceptable actions had been taken to address the violation. This item is close E (Closed) Violation 50-311 /97-02-02: Failure to Test MCCBs in the Instantaneous

  • Region The NRC review of the MCCB test results determined that several electrical penetration protection circuit breakers (e.g., 2GP14X and 1 OX and 2EP2X and 3X)

had been tested in the thermal region, but not in the instantaneous region. Test Procedure SC.MD-ST.ZZ-0004(0) required that the licensee verify the setting of adjustable instantaneous trip devices of all thermal-magnetic and magnetic-only breakers in the program.

In their response to the violation, letter No. LR-N970300, dated May 28, 1997, the licensee stated that some of the breakers had been tested using procedure M3Q-1,

"Containment Penetration Conductor Overcurrent Protection Device Test." This procedure, voided on July 30, 1993, apparently was ambiguous regarding testing of the instantaneous trip devices. Regarding procedure SC.MD-ST.ZZ-0004(0),

although it accurately reflected the testing requirements, it did not accurately specify the acceptance criterio To address the NRC finding, the licensee tested the instantaneous trip setpoint of the Salem Unit 2 breakers and revised procedure SC.MD-ST.ZZ-0004(0) to clarify the test requirements. In addition, they initiated a root cause analysis to determine whether additional actions would be required to prevent recurrence of the violatio As stated in inspection report 50-272; 311 /97-08, the inspector verified that the instantaneous trip setting of the circuit breakers had been tested and that the procedure had been revised. The results of the root cause analysis are described in Section E8.4, above, and were found reasonable and acceptable. This item is closed for Unit 2, only. For Unit 1, closure of the item is pending confirmation that the MCCBs have been teste E (Updated) Violation 50-272: 311 /97-05-01: Inadequate Safety Evaluation On June 3, 1997, the NRC issued a Notice of Violation for failure to provide adequate bases for plant design configurations that differed from the FSAR description. The NOV cited two examples. In the first example, PSE&G revised the FSAR to allow cables of redundant channels to be separated by a distance less than that previously accepted by the NRC. In the safety evaluation, S-C-ZZ-EEE-0841, Revision 1, dated July 22, 1996, PSE&G justified the acceptability of the reduced distance (or no separation) using criteria for fire protection/Appendix R instead of separation criteria contained in Regulatory Guide 1. 75, Revision 1. Section 8.1.4.2.4, Revision 11, dated July 22, 1991, specified "a minimal vertical and horizontal spacing between redundant trays of 18 and 1 2 inches, respectively... "

In the second example, PSE&G failed to prepare a safety evaluation (SE) for FSAR revisions that permitted cable separation configurations not allowed or not specifically allowed by the previous FSAR revision, as in the three examples belo *

~ew section 7.9.1 (1) allowed nonsafety-related cables associated with redundant channels to run together, after leaving the associated vital tra *

Revised section 8. 1.4.2.4 deleted a requirement that, when redundant trays cross each.other at less than 18 inches, a fire-resistant blanket be installed on the top of the lower tray, extending a minimum of 24 inches beyond each side of the crossover. In the containment annulus area, no fire-resistant blankets were provided where trays cross each othe *

Revised Section 8.1.4.2.5, added a requirement that a minimum separation of 6 inches be provided between redundant channels within panels and rack In their response to the NOV, Letter No. LR-N970402, dated June 27, 1997, PSE&G attributed the violation to personnel error and inadequate implementation of the 10 CFR 50.59 program. In the first example, they had erroneously assumed that no free air cable separation was required because of the availability of an alternative means of shutdown for the room under the 10 CFR 50, Appendix R, program. In the second example, they confirmed that their 1990 safety evaluation applicability review inappropriately concluded that a full SE was not required for the proposed FSAR revisio To address the NRC regarding the above issues and the SE process in general, the licensee:

issued a revised SE (S-C-ZZ-ESE-0841, Revision 2) addressing minimum separation distance between cables in free air. This safety evaluation was reviewed and approved by the Station Operations Review Committee and found acceptable by the NRC (Inspection Report 50-272; 311 /97-08).

  • developed an inspection program to inspect the plant areas with safety related cables and to gain reasonable assurance that Salem Unit conforms with the established cable separation criteria. The NRC reviewed the program and the actions taken to correct nonconformances and found them acceptable. Walkdowns to assess Unit 1 cable separation and correct deficiencies were still incomplet *

performed a root cause evaluation of this and other 10 CFR 50.59 violation The evaluation attributed the violations to: (1) Lack of clearly defined management expectations regarding the 50.59 program implementation; (2) Less than adequate program evaluation process; and (3) lack of commitment to program implementation. Based on the results of the root cause evaluation and in concurrence with the root cause evaluation recommendations, PSE&G proposed to:

Establish performance *standards and communicate expectations for performing SEs;

Periodically publish lessons learned from the critical review of SEs;

Formalize a feedback process to the preparer of the SE;

Establish grading criteria and performance indicators for SEs;

Establish an interdisciplinary engineering review team; and

Perform periodic self-assessments of the SE proces *

~-----------------------~--

On July 14, 1997, a memorandum was issued to all engineering personnel to communicate to the management expectations for 10 CFR 50.59 applicability reviews and the SE process. The remainder of the actions are schedule for implementation between July 31 and September 30, 1997. In the interim, the licensee established a Salem Engineering Independent Review Team, consisting of experienced individuals from different disciplines to provide an additional revie *

planned to re-evaluate the 1 990 FSAR cable separation issue in accordance with the revised 10 CFR 50.59 process and perform necessary change Based on the review of the above documents, the inspector concluded that the licensee had taken acceptable actions to improve the quality and accuracy of safety evaluations. However, considering that the walkdowns to address cable separation in Unit 1 and the implementation of all but one of the root cause analysis recommendations are ongoing, this item remains open pending completion of planned activities. As in the case of the molded-case circuit breaker test discrepancies, the inspector found the root cause analysis to be comprehensive and well-don ES. 7 Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the updated final safety analysis report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR descriptions. While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameter E Control Room Ventilation System Non-Redundant Dampers Scope of Inspection The inspector reviewed a condition report (CR) issued by PSE&G regarding the design basis of the. CAV system...Ihe inspector. reviewed the following documents to determine nature of the issue and the requirements and history for control room habitability:

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CR 970626080, Non-Redundant CAV Dampers

. Calculation PSBP 323135, 30 Day Control Room Dose following a LOCA with 2 hr Manual Operator Action to Pressurize CR, Realistic Containment Leakage and Annual Average CR Atmospheric Dispersion Factors, Rev~ 0, dated July 10, 1997

  • Calculation PSBP 321040, Radiological Dose Consequence at EAB/LPZ and Control Room due to a LOCA at Salem unit 1 or Unit 2 with updated CR design, Rev. 4, dated June 25, 1996

Standard Review Plan, Section *

NRC Confirmatory Order issued March 14, 1983

NRC Confirmatory Order issued July 10, 1981

PSE&G Letter, R.L. Mittl to A. Schwencer, dated August 13, 1980

PSE&G Letter, R.L. Mittl to A. Schwencer, dated July 1, 1980

PSE&G Letter LR-N97419, dated June 30, 1997, Control Area Air Conditioning System Licensing Basis Clarifications, Salem Generating Station Unit Nos. 1 and 2, Docket Nos. 50-272 and 50-311

NRC Letter, L. N. Olshan to L. R. Eliason, dated July 24, 1997 Observations and Findings During a review of the design basis of the CAV system, PSE&G identified that the license revision request submitted to NRC by PSE&G on June 10, 1996, contained information which did not appear to be supported by calculations. Specifically, the June 10, 1996, submittal stated "... Certain single failures... may result in control room doses exceeding GDC 19 limits. These include:... single failure of non-redundant dampers without manual repositioning." This.statement would seem to imply that a single failure of a non-redundant damper with manual repositioning would not result in doses exceeding GDC 19 limits. There were no calculations which supported this position. This finding was documented in CR 97062608 There are six non-redundant dampers in the control room ventilation system (3 in each unit) which automatically realign to enter the emergency pressurization mode of the system. These dampers receive redundant closure signals, and are designed so that they fail in the closed position on a loss of electrical control power or loss of control air. In addition, the dampers are subjected to functional tests on a monthly basi PSE&G clarified their licensing basis for the control room air conditioning system by letter to NRC dated June 30, J 997. They specifically stated their position that the non-redundant dampers "meet the intent of the Single Failure Criterion as it was applied* at the time the Salem units were licensed." PSE&G also stated that they had not done a separate dose assessment to support the June 1996 submitta Calculation PSBP 323135, issued July 10, 1997, evaluated control room post-accident.radiation doses. PSE&G had this analysis performed as a contingency in case NRC did not support the PSE&G position that the dampers were not required to be redundant. The calculation used realistic, rather than design basis inputs, for atmospheric dispersion factor and containment leakage. These Inputs included an average annual atmospheric dispersion factor, actual containment leakage rate obtained from testing (75% of the technical specification allowable value), and two hours to manually reposition the failed damper. This evaluation determined that, for

.the conditions specified, control room radiation doses would remain below the GDC 19 limits (5 Rem whole body, 30 Rem thyroid, or 30 Rem to the skin).

  • XI

As part of the response to the Accident at Three Mile Island, the NRC required all license and construction permit holders for nuclear power generating stations to make certain modifications and upgrades to their facilities. These were subsequently clarified in NUREG-0737, "TMI Action Plan Clarification." One portion of the action plan, 111.D.3.4, addressed control room habitability post-accident, and in the event of a chemical spill on the site or in the immediate vicinity. Action Item 111.D.3.4, "Control Room Habitability," required facilities to review their designs against Sections 2.2.1, 2.2.3, and 6.4 of the Standard Review Plan (SRP). Section 6.4 of the SRP states, among other things, that.the control room ventilation systems be single-failure proo PSE&G performed an evaluation of control room habitability in response to FSAR Question 14. 16, as documented in their letter of July 1, 1980. PSE&G also contended that their analysis met the requirements of Action Item 111.D.3.4. The results of this evaluation were provided to NRC in a letter dated August 13, 198 That letter stated, "We have concluded that the design of the Salem 2 Control Room is such as to assure that operators in the Control Room will be adequately protected against exposure to unacceptable levels of radiation during and after a design basis accident and unacceptable levels of hazardous *chemicals released on or in the vicinity of the site. On this basis, no design modifications are necessary."

NRC imposed the commitment to complete the evaluations by Confirmatory Order dated July 10, 1981. A subsequent Confirmatory Order, issued March 14, 1983, shows Action Item 111.D.3.4 as being close Conclusions NRC accepted PSE&G's position by letter dated July 24, 1997. The control room ventilation system non-redundant dampers meet the Salem licensing basis. We found no evidence that PSE&G was implying that a single failure of a non-redundant damper with manual repositioning would not result in doses above GDC limit PSE&G's completed actions to resolve the CR were appropriat V. MANAGEMENT MEETINGS Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 23, 1997. *The licensee acknowledged the findings presente Some of the documents reviewed *during-the *inspection were marked as proprietary information. Those documents were returned to PSE&G when they were no longer neede I, I

I l,

j

PARTIAL LIST OF PERSONS CONTACTED Public Service Electric and Gas Company J. Barnes G. Boerschig J. Broadwater M. Dobson P. Morakinyo D. Nealon J. O'Connor R. Villar L. Haley T. Hawkins J. Alexander J. Chwastyk Project Manager System Readiness Manager, Nuclear Electrical Engineering Projects Test Projects Test Senior Engineer Senior Staff Engineer Supervisor, Design Electrical Engineering Licensing Engineer Startup Shift Test Engineer Startup Shift Test Engineer Startup Shift Test Engineer Startup Shift Test Engineer U. S. Nuclear Regulatory Commission M. Evans C. Marschall W. Ruland R. Lorson L. Olshan State of New Jersey D. Vann Opened 50-311197-16-01 Senior Resident Inspector Senior Resident Inspector Chief, Electrical Engineering Branch Resident Inspector Licensing Project Manager Nuclear Engineer ITEMS OPENED, CLOSED, AND DISCUSSED IFI Accuracy of Infrequently Performed Procedures 50-272; 311/97-16-02 URI Cable Separation within Panels and Cabinets 50-311197-16-03 IFI 50-311197-16-04 VIO 50-311197-16-05 URI Conformance of Calculations and Procedures with TS 4. 7.6.1.d(5)

Failure to Follow Post-Modification Test Procedures Control-Loop Tuning Problems

Closed 50-27 2; 311 /96-13-04 50-272; 311/96-01-10 50-311197-02-02 50- 272; 311 /97-02-01 Discussed 50-272; 311/96-01-09 50-311197-05-01

URI Localized High Temperature in the Diesel Generator Room VIO Failure to Follow NAP-25 Procedure RE: Combustibles VIO Failure to Test MCCBs in the Instantaneous Region VIO Failure to Replace Oversized Fuses and to Correct Discrepancies Between Calculation and MCC Test Procedure URI CR205 Relays Used in Safety-Related Applications VIO Inadequate Safety Evaluation

AFW AFP AR AWG CAG CAP CA/QS CAV CCHX CROM CRs eves EAB ECAC EOG EOPs ERG FME FSAR GDC HDI l&C INPO ISi LER LPZ MCCB MRC MS IVs N/A NBU NCO NEO NRC NSS NTOC OD OEF OTSC PDR PMT PPM PSE&G

LIST OF ACRONYMS USED Auxiliary Feedwater Auxiliary Feedwater Pump Action Request American Wire Gage Corrective Action Group Corrective Action Program Corrective Action and Quality Services Control Area Ventilation Component Cooling Heat Exchanger Control Rod Drive Mechanisms Condition Reports Chemical and Volume Control System Exclision Area Boundary Emergency Control Air Compressor Emergency Diesel Generator Emergency Operating Procedures Emergency Response Guideline Foreign Material Exclusion Final Safety Analysis Report General Design Criterion Hilti Drop-In Instrumentation and Controls Institute of Nuclear Power Operations lnservice Inspection Licensee Event Report

.Low Population Zone Molded Case Circuit Breaker Management Review Committee Main Steam Isolation Valves Not Applicable Nuclear Business Unit Nuclear Control Operator Nuclear Equipment Operator Nuclear Regulatory Commission Nuclear Shift Supervisor Nuclear Training Oversight Committee Operability Determinations Operating Experience Feedback On-The-Spot Change Public Document Room Post-Maintenance Testing Parts Per Million Public Service Electric and *Gas Primary Water Stress Corrosion Cracking Quality Assurance I

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...t

RCP RCS REM RHR

.RPM RVLIS SCFM SERT SI SIL SIRA SNSS SORC SRG SRO SRP SW TOR TRB TR Gs TRIS TS UFSAR Reactor Coolant Pump Reactor Coolant System Roentgen Equivalent Man Residual Heat Removal Revolutions Per Minute

Reactor Vessel Level Indicating System Standard Cubic Feet Per Minute Significant Event Response Team Safety Injection Service information Letter Salem Integrated Readiness Assessment Senior Nuclear Shift Supervisor Station Operations Review Committee Safety Review Group Senior Reactor Operator Standard Review Plan Service Water Technical Document Room Test Review Board Training Review Group Tagging Request Inquiry System Technical Specification Updated Final Safety Analysis Report

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