IR 05000293/1998203

Insp Rept 50-293/98-203 on 980928-1023.No Violations Noted. Major Areas Inspected:Capability of Selected Sys to Perform Safety Functions Required by Design Bases,Adherence of Sys to Design & Licensing Bases & Consistency of Configuration

ML20196F783
Person / Time
Site:	Pilgrim
Issue date:	11/24/1998
From:	NRC (Affiliation Not Assigned)
To:
Shared Package
ML20196F769	List: IR 05000293/1998203 ML20196F763
References
50-293-98-203, NUDOCS 9812070122
Download: ML20196F783 (40)

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U.S. NUCLEAR REGULATORY COMMISSION  !

OFFICE OF NUCLEAR REACTOR REGULATION

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i Docket No.: 50-293

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License No.: DPR-35 l

l - Report No.: 50-293/98-203 I

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Licensee: Boston Edison Company 800 Boylston Street Boston, MA 02199 Facility: Pilgrim Nuclear Power Station l

l Location: Pilgrim Site t

Plymouth, MA Dates: September 28 through October 23,1998 inspectors: Morris Branch, Team Leader, PIPB, NRR Edmund Kleeh, Electrical Engineer, PIPB, NRR l Roy Mathew, Electrical Engineer, PIPB, NRR

! Robert Najuch, Lead Contractor Engineer *

l Douglas Schuler, I&C Engineer *

Dennis Vandeputte, Mechanical Engineer *

Craig Baron, Mechanical Engineer"

• Contractors from Stone & Webster Engineering Corporation

" Contractor from Beckman Associates i

! Approved by: Donald P. Norkin, Section Chief Operating Reactor inspection Support Division of Inspection and Support Programs Office of Nuclear Reactor Regulation l

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9812070122 981124  ?

PDR ADOCK 05000293 G PDR a

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) Table of Contents l

EXECUTIVE SUMMARY . . . . . . ......................... .....................i i

E1 CONDUCT OF ENGINEERING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 E Insoection Scoce and Methodoloav . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 E Residual Heat Removal (RHR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1 E1.2.1 Mechanical Desian Review . . . . . . . . . . . . . . . . . . . . . . . . ...1 E1.2.2 Electrical Desian Review . . . . . . . . . . . . . . . . . ... .. . . . . 10 E1.2.3 Instrumentation and Controls (l&C) Desian review . . . . . . . . 19 E1.2.4 System lnterfaces . . . . . . . . . . .............. .. .... 21 i E UFSAR Review . . . . . . ..................................28 E Desian Control . . ...... ......................... ...... 29 t

X1 Exit M eeting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Appendix A - List of Open items . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . A-1 Appendix B - Exit Meeting Attendees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

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Appendix C - List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1 i

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l EXECUTIVE SUMMARY From September 28 through October 23,1998, the staff of the U.S. Nuclear Regulatory l Commission (NRC), Office of Nuclear Reactor Regulation (NRR), inspection Program Branch, i conducted a design inspection at Pilgrim Nuclear Power Station, (PNPS). The inspection team 1 l consisted of a team leader and two inspectors from NRR, three contractor engineers from Stone

& Webster Engineering Corporation (SWEC) and one contractor engineer from Beckman Associate The purpose of the inspection was to evaluate the capability of the selected system to perform the safety functions required by its design bases, the adherence of the system to the design and licensing bases, and the consistency of the as-built configuration and system operations with the updated final safety analysis report (UFSAR). For the purpose of this inspection, the team selected the Residual Heat Removal (RHR) system, on the basis of its importance in mitigating design-basis accidents (DBAs) at PNPS. In particular, the inspection focused on the safety functions of this system and its interfaces with other systems. For guidance in performing the inspection, the team followed the applicable engineering design and configuration control

! portions of Inspection Procedure (IP) 93801, Safety System Functional inspection (SSFI). The team reviewed portions of the station's UFSAR, Technical Specifications (TS), drawings, calculations, modification packages, surveillance procedures, and other documents pertaining to l the selected syste Overall, the team found that the RHR system was capable of performing its design and licensing l

basis functions under all design basis conditions, including loss of off-site power and single active failure. The support systems, such as reactor building closed cooling water (RBCCW) l and electrical distribution, provided adequate margin to ensure short-term and long-term RHR '

system emergency core cooling performance objective l The PNPS efforts, to assemble, verify, and correct design basis documentation have generally resulted in new calculations of good quality and a consolidated design basis document (DBD)

that was useful for the team's review. These same documents, when completed for other systems, should provide useful design information for future activities. In the electrical area, many of the calculations that support the design basis of the system have not been completed and are still being revise Emergency operating procedure (EOP) mitigation strategy for a design basis loss of coolant accident (LOCA) airects the operators to flood the containment, although this action is not i necessary for short or long term core cooling. The radiological consequences, equipment i l

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demands, and environmental qualification associated with containment flooding are more severe than that assumed in the UFSAR and used to form the basis for equipment design. PNPS's plant specific 10CFR50.59 evaluations for EOP implementation did not identify the consequences of containment flooding as a potential unreviewed safety question (USQ). This

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potential generic issue is currently being reviewed by the NRC and additional followup actions may resul RHR pump surveillance test acceptance criteria and RHR system LOCA hydraulic analysis do not appear to adequately account for instrument uncertainties. PNPS is planning to address instrument uncertainty on a graded and programmatic basis. However, PNPS staff does not believe that there is a design or licensing requirement to specifically account for instrument

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uncertainty in testing or analyzing variables used in the LOCA analysis. This same AE team identified issue is being reviewed by the NRR staff for another facility and the results from that review will be applied to followup at PNPS as well. Additionally, LOCA analysis inputs and results currently contained in the UFSAR do not reflect the impact of delaying LPCI injection flows due to the increase in the swing bus transfer tim Equipment drains supporting the ECCS rooms may subject the ECCS equipment to common mode flooding concerns. PNPS staff is currently evaluating the basis and design of this equipment to ensure adequate protection from floodin Several ASME Vill heat exchangers did not have overpressure protective devices installed as specified in the original specifications and for compliance with ASME Code, Section Vill requirement The potential for RHR shutdown cooling line thermal overpressurization and for waterhammer and two-phase flow conditions in RBCCW are being addressed through the NRC's review of Generic Letter 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Condition Electrical system concerns associated with electrical penetration single device protection, station battery TS testing, and control of electrical loads through the use of calculation comment sheets were identified. During the exit meeting, PNPS staff described their plans to test the electrical penetration single protective device on an approximate 4 year schedule. This increased testing should provide additional assurance as to the reliability of the single protective devic Regarding battery testing, it is the NRC's understanding that PNPS plans to review the current TS requirements and modify them if necessary, after verifying the new testing method is technically acceptable to the battery vendo Other issues regarding Design Control, Calculation Control, and UFSAR inconsistencies are included within the report. During the course of the inspection the licensee documented many of the issues in their corrective action program. The number and nature of the items documented on problem report (prs) demonstrated good sensitivity for problem identificatio :

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l 111. Engineering i

! E1 CONDUCT OF ENGINEERING  !

E Insoection Scoce and Methodoloav The primary objectives of the design inspection at Pilgrim Nuclear Power Station (PNPS), were to evaluate the capability of the selected system to perform its safety functions required by )

design bases and to verify whether the licensee, Boston Edison Company (BECo), has maintained the station in compliance with its design and licensing bases. This inspection concentrated on the RHR system because of its importance in mitigating design basis accidents (DBA) at PNPS. In particular, this inspection focused on the safety functions of the selected

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system and its interfaces with other systems throughout the station. For guidance in performing I the inspection, the team followed the applicable engineering design and configuration control l portions of IP 93801, Safety System Functional Inspection (SSFI).

The team's review of the RHR system utilized the licensee's initial results of their DBD effort These draft DBDs were used as roadmaps for the team to ensure that the latest design basis information was being used. The licensee had compiled these DBDs for the RHR and several of '

its support systems as part of their supplemental response to the NRC 10 CFR 50.54(f) letter titled " Adequacy and Availability of Design Basis information." The team selected the RHR system because it was one of the three systems whose DBD was almost complete and the team wanted to review a system which had been through the DBD proces Prior to the inspection, the licensee contracted a third party to perform an SSFI and calculation reviews to evaluate the design basis of the systems being reviewed. Issues identified during this third party review were entered into the PNPS corrective action system. The licensee's '

calculation review project identified several configuration controlissues. These were also entered into their corrective action system. The licensee is presently reviewing almost all design basis calculations as part of their calculation upgrade progra Appendix ,, identifies the open items and issues resulting from this inspection, while Appendix B lists the individuals who attended the exit meeting on October 23,1998. Appendix C defines the various acronyms used in this repor l E Residual Heat Removal (RHR) 1 E1.2.1 Mechanical Desian Review l

E1.2.1.1 Scone of Review The mechanical design review of the RHR system included design and licensing documentation reviews, system walkdowns, and discussions with cognizant system and design engineers. The

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team reviewed applicable portions of the UFSAR and TSs; flow and process diagrams and other

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system drawings; calculations; design change documentation; system operating, inservice and surveillance test procedures and results; emergency operating procedures (EOP); problem reports (PR); and operating experience reviews. The scope of the review included verification of the appropriateness and correctness of design assumptions, boundary conditions, and system

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models; confirmation that design bases were consistent with the licensing bases; and verification of the adequacy of testing requirements. The team a!so examined installation of the RHR system components during plant walkdown Specific topical areas covered during the mechanical design review included system thermal / hydraulic performance requirements (e.g., system capacity, pump net positive suction head (NPSH), and pump minimum flow); system design pressure and temperature; overpressure protection; component safety and seismic classifications; component and piping design codes and standards; and single failure vulnerabilit E1.2. Findinas a. Low Pressure Coolant injection (LPCI) with Heat Rejection Operating Mode Following a Loss Of Coolant Accident (LOCA), long-term containment heat removal is accomplished by operation of the RHR system. For Boiling Water Reactors (BWRs) of Pilgrim's vintage, the containment analysis typically assumes that this function is performed by operating the RHR system in the suppression pool (torus) cooling mode (SPC), whereby one or more RHR pumps are manually aligned to pump water from the torus, through an RHR heat exchanger, and then directly back to the torus. An RHR pump so-aligned would no longer perform a LPCI functio At PNPS, a new mode of RHR system operation, LPCI with heat rejection, has been define The latest post-LOCA long-term containment heatup analysis prepared in support of License Amendment No.173, (General Electric (GE) report GE-NE-T23-00749-01, Pilgrim Nuclear Power Station Containment Heatup Analysis with ANS 5.1 + 20 Decay Heat, dated December 1997) assumes that at 10 minutes into the event, two RHR pumps in one loop continue injecting to the reactor vessel, and Reactor Building Closed Cooling Water (RBCCW) flow to the RHR heat exchanger is manually initiated. in this configuration, torus water, partially cooled by the RHR heat exchanger, is injected into the reactor vessel, spills out of the pipe break into the drywell, and retums to the torus through the drywell-to-wetwell vent system. This configuration maximizes injection flow to the reactor vessel for core cooling, but does not provide rated containment heat removal because approximately 65% of the two-pump LPCI flow bypasses the RHR heat exchanger through the full-open bypass valve (MO-1001-16A or B). At 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> into the event, the containment heatup analysis assumes that rated containment heat removal from one RHR heat exchanger is obtained by operator actions to manually secure one RHR pump, close the heat exchanger bypass valve (thereby directing all RHR pump flow through the heat l exchanger), and throttle the single RHR pump flow rate to 5,100 gpm. This single RHR pump !

flow continues to be injected to the vessel rather than retumed directly to the toru The team considered the LPCI with heat removal mode of RHR system operation to be a positive aspect of the long-term containment heatup analysis. The licensee recognized that the l EOPs (EOP-01, RPV Control, Revision 5) would direct the operator to maximize injection flow to the reactor vessel for large liquid line breaks for which reactor water level could not be restored to top of active fuel (TAF). Incorporation of this operating mode into the containment heatup analysis supports the injection objective while minimizing the impact on containment heat removal capability during the 10-minute to 2-hour time period. The LPCI with heat rejection mode is briefly described in UFSAR Section 4.8.5.4.1 but is not currently depicted on the RHR l system process diagram (drawing No. M1H 4-4, Rev. E6, which also represents UFSAR Figure

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4.8-2). The licensee had previously identified the need to update this drawing, as documented in PR 97.910 b. RHR Flow Measurement Uncertainties TS Section 4.5.A.3.b requires that each LPCI (RHR) pump delivers 4,800 gpm at a head across the pump of at least 380 ft. Periodic testing of the RHR pumps is performed in accordance with surveillance procedures 8.5.2.2.1 and 8.5.2.2.2, Revision 11, LPCI System Loop A (B) Pump

! and Valve Quarterly Operability. The team reviewed these procedures and determined that test flow measurements are taken using installed process instrumentation. Pump flow rate is read from computer points (RHR022 and RHR024) that are derived from flow transmitters FT-1051 A,B. Licensee's calculation I-N1-215, Revision 0, Uncertainty Calculation - RHR Flow Computer Points RHR022 & RHR024, determined that at an indicated RHR flow rate of 4,800 gpm, the actual flow under normal test conditions could be as low as 4,556 gpm. The i surveillance procedures did not appear to account for this instrument uncertainty; therefore, the l actual RHR pump flow rate could be less than the 4,800 gpm minimum value required by the l

T The team reviewed the licensing basis LOCA analyses documented in GE report NEDC-31852P, Revision 1, Pilgrim Nuclear Power Station SAFER /GESTR-LOCA Loss-of-Coolant l

Accident Analysis dated April 1992, which is referenced in UFSAR Section 6.5. These analyses were performed assuming minimum two-pump LPCI flow rates of 9,100 gpm at 20 psig reactor pressure and 9,500 gpm at 0 psig reactor pressure. If actual LPCI flow rates were less than these minimum values, then the consequences of the LOCA analyses could be more severe (i.e., higher peak clad temperature -(PCT)). To confirm that the minimum assumed LPCI flow rates could be achieved, the licensee performed calculation M667, Revision 2, RHR System Hydraulic Analysis Using PROTO-FLO Version 1.02. This calculation used as input a RHR pump performance curve that was reduced by 5% (in pump head) below the minimum pump performance required by the TS, resulting in a curve that was 89% of the pump manufacturer's certified test curve. The calculation stated that the assumed 5% reduction accounts for potentia errors associated with the actual in-service testing (IST); however, the team noted that it does not bound the flow measurement uncertainty (+253, -244 gpm) identified in calculation I-N1-21 To account for this calculated flow measurement uncertainty, the pump curve would need to be reduced to approximately 84% of the manufacturer's certified test curv The licensee stated that inclusion of Emergency Core Cooling System (ECCS) flow measurement uncertainties was not required by the PNPS licensing basis because the existing l

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LOCA analysis were performed using models developed in accordance with 10CFR50, Appendix K, ECCS Evaluation Models. Neither Appendix K nor 10CFR50.46(a)(1)(ii) specifically 4 address the inclusion of ECCS flow uncertainty in the inputs to these models. However, the i licensee subsequently performed an additional PROTO-FLO run that calculated LPCI flow rates in excess of the minimum LOCA analysis values assuming the RHR pumps operate at 83% of the manufacturer's certified pump curve. Based on these calculated results, the team's review of recent pump surveillance test data, and the fact that the calculated worst case LOCA PCT l

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occurs for the case where no LPCI flow reaches the core (single failure of the LPCI injection

valve to open), the team had no immediate operability concem ,

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Not adequately accounting for instrument uncertainties in the RHR pump surveillance test

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acceptance criteria or in the LOCA analysis appears to be a generic issue at Pilgrim and at other

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BWRs of the same vintage. The licensee's third party (DUKE) calculation review identified several areas, including procedure acceptance criteria values, where PNPS does not have a clear documented basis. The licensee discussed their program plans to establish and document the basis for uncertainty in instruments and how this information will be applied to analysis and operation of the Pilgrim Station. Based on AE team findings at other facilities the NRC's NRR staff is reviewing whether the design and licensing basis requires instrument uncertainties to be specifically accounted for in TS values or the LOCA analysis. Resolution of this apparent generic item at Pilgrim is identified as IFl 50-293/98-203-01 (Instrument Uncertainty Control and Application).

c. Changes to LOCA Analysis inputs and Results in Safety Evaluation (SE) No. 2989 dated September 9,1997, the licensee evaluated the impact of increasing overall LPCl injection delay time from 49.7 to 54.6 seconds for the design basis LOCA analysis. The additional delay time (4.9 seconds) is for transfer of 480V swing bus B6 from the preferred power source (train A) to the backup power source (train B) assuming single failure of the train A supply (e.g., train A battery failure). Swing bus B6 powers the LPCI injection valves (MO-1001-28A,B and MO-1001-29A,B) and the reactor recirculation pump suction and discharge isolation valves (MO-202-4A,B and MO-202-5A,B). The SE concluded that the PCT increased from 1694*F to about 1744*F for the assumed single failure of a station battery, but remained less than the worst case calculated PCT of 1821 *F for the LPCI injection valve single failure case. The team reviewed the SE and related documents and identified two concem . The SE did not identify any needed changes to UFSAR Section 6.5. This section l currently provides only a reference to GE report NEDC-31852P, Revision 1, for the licensing basis LOCA analysis inputs and results. This singular reference is not l completely accurate since the analysis inputs and results were modified by SE N !

2989. The team was also concemed that the level of detail provided in the UFSAR '

for description of the LOCA analysis inputs and results (i.e., only a reference to the GE report) was not appropriate. The licensee noted that a UFSAR review effort had been initiated as part of their 10CFR50.54(f) response to the NRC, and provided a copy of PR 98.0507 (initiated in March 1998) which identified a number of UFSAR discrepancies in various UFSAR sections, including Section 6.5. Completion of j revisions to UFSAR Section 6.5 to appropriately incorporate the effects of SE N should be assured by resolution of PR 98.0507 An important design input to the licensing basis LOCA analysis (swing bus transfer time), and the resulting impact on the PCT, were developed in SE No. 2989 but were l not documented in an engineering calculation; therefore, although the SE was I reviewed, independent verification was not documented. The licensee initiated PR 98.2667 to document and resolve this conce The team identified the above concems as IFl 50-293/98-203-02 (Control of LOCA Analysis inputs and UFSAR Update)

d. Containment Flooding as DBA LOCA Mitigation Strategy UFSAR Section 6.5 indicates that conformance to 10CFR50.46 and Appendix K is supported by Pilgrim Nuclea! Power Station SAFER /GESTR-LOCA Loss of Coolant Accident Analysis,

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NEDC-31852P Revision 1 dated April 1992 and General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10CFR50 Appendix K, NEDO-20566A, September 1986. NEDC-31852P states that the bases and demonstration of compliance with Criterion 5 of 10CFR50.46 for long term cooling are documented in NEDO-20566A and remain unchanged by application of SAFER /GESTR-LOCA. NEDO-20566A indicates that with one core spray (CS)

pump, the upper third of the core will remain wetted by the spray and no further perforations or metal water reactions result. If a CS system is not available, LPCI injection into the recirculation piping will result in the upper third of the core being cooled by convection to steam generated in the lower core portio EOP-01, RPV Level Control directs the operator to EOP-09, Primary Containment Flooding to restore the water level above TAF. A DBA LOCA would result in an indicated water level below l

TAF and would drive the operator to flood containment in accordance with the EOPs. Within EOP-09, venting the RPV is directed to allow the water level to rise to TAF. Venting is accomplished either to the condenser resulting in a ground level release, or to the reactor building, which would result in a filtered elevated stack release via the Standby Gas Treatment System (SGTS). This action appeared inconsistent with the accident analysis as presented in i UFSAR Section 6.5 and its references and with the LOCA radiological consequences as

presented in UFSAR Section 14.5.3. The licensee indicated that the existing EOPs are based on Emergency Procedure Guidelines (EPGs) Revision 4 and envelope beyond design basis events. For beyond design basis events, adequate core cooling is only assured when the RPV level is above TAF. The licensee confirmed that flooding is not required for adequate long term cooling to meet 10CFR50.46 i requirements nor is it required for the design or licensing basi The team was concerned that the EOP action to flood the containment could affect the design l and licensing basis in areas such as equipment availability and capability, equipment environmental conditions and qualification, and on and off-site radiological consequences. The licensee issued PR 98.9519 which indicates that the effects of containment flooding on

! equipment qualification, offsite dose, operator dose, and equipment availability were not considered when EPG Revision 4 was implemented and that neither the NRC Safety Evaluation Report (SER) or the Boiling Water Reactor Owners Group (BWROG) evaluated these issue i Subsequently the licensee issued PR 98.9541 which indicates that several issues (including but I not limited to equipment capability, radiological consequences, impact of flooding) may not have been fully considered upon implementation of EPG Revision The team reviewed various documentation related to the implementation of EPG Revision 4 as follows:

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On August 4,1987 BECo and NRR met and discussed the EOP program. Meeting l notes indicate that staff approval of Revision 4 of the EPGs had not yet been issued, l but review had progressed sufficiently that the NRC endorsed the effort by BECo.

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SE 87-154 dated August 26,1987 identified that a new procedure directs flooding of the containment to keep the core covered and maintain adequate core cooling. The SE concludes that the change does not involve an unreviewed safety question (USO), identifies that this flooding capability is identified within the UFSAR as an accident recovery method and the NRC has previously reviewed and approved the

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l concept in the SERs of EPGs Revision 3 and .

SE 2248 dated October 27,1987, evaluates the creation of the PNPS EOP Plant Specific Technical Guidelines (PSTGs). The SE identifies that the NRC had not yet issued a SER for Revision 4AF of the EPGs and in lieu of an NRC SER, the General Electric Design Review of the Revision 4 EPGs would provide the basis for the design adequacy of the EPGs and PSTGs to satisfy the provisions of 10CFR50.5 The summary emphasizes that the NRC endorses implementation of EPG Revision 4, based on the August 4,1987 Boston Edison Company /NRC meeting, PSTGs had been developed in strict conformance with Revision 4AF and differences have been documented in Appendix A and justified in Appendix B of the PSTGs. Based on the NRC involvement, and this implementation, the SE concludes that the change does

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SE 87-170 dated November 11,1987, evaluates implementation of the new EOPs based on EPGs Revision 4AF. The evaluation concludes that the proposed change does increase the possibility for an accident or malfunction of a different type than any evaluated previously in the UFSAR, however the approval indicates that the change does not involve an USQ, nor does in involve a change to the FSA Although not explicitly stated within the SE, the licensee indicated that SE 87-170 approval was based on an understanding that NRC approval of EPGs was necessary prior to implementatio .

NRC letter dated June 6,1988, provides the staff's safety evaluation of the Pilgrim Procedures Generation Package. The SER documents that the PSTGs were

reviewed and no major deviations from the EPG, Revision 4 guidelines were I

identified. The review concluded that the Pilgrim plant-specific guidelines were acceptable for near term implementation, however in the longer term, the licensee would be subject to the findings of the staff's final safety review of the EPG l

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September 12,1988, the NRC issued the staff safety evaluation of BWR Owners j Group - Emergency Procedure Guidelines, Revision 4, NEDO-31331 dated March J 1987. Although the review found the EPGs generally acceptable for implementation, 4 the NRC advised that each licensee should verify that the EPGs were consistent with !

its licensing basis analysis. Plant specific procedures consistent with the safety i analysis were to be implemented, or staff involvement to remedy such deviations was require SE 2630, dated September 16,1991 was issued to incorporate improvements and l changes resulting from an NRC EOP inspection. The SE states that SE 87-170, l which established the technical correctness of EOPs based on BWROG EPG l Revision 4, remains valid. The technical guidance is still in accordance with the BWROG EPG Revision 4 which was approved by the NRC in a safety evaluation dated September 12,198 On September 17,1991, the BWROG met with the NRC regarding the process for identifying and resolving differences between the EOPs and licensing basis. The resolution process required review of UFSAR events, assessment of EOP actions and consequences, and update of the UFSAR if within the licensing basis. If the J

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consequences were outside the licensing basis, the resolution process required re-l evaluation of EOP consequences using realistic analysis, notification to the NRC of USQs and update of the licensing basis upon NRC approval. Meeting notes indicate l

that NRC representatives concluded that the process was not difficult to apply, I

brought issues to the surface, and provided a good procedure to resolve difference The team concluded that PNPS relied on programmatic involvement by the BWROG and NRC to address plant specific issues and used BWROG and NRC review and approval as a basis for PNPS plant specific 50.59 evaluations as reflected in SE 87-154,2248,87-170, and 263 Further, PNPS did not recognize that NRC approval of the PSTGs was subject to the findings of the staff's final safety review of the EPGs. Within the staff EPG safety evaluation, the NRC advised that plant specific procedures consistent with the safety analysis were to be implemented, or staff involvement to remedy such deviations was required. Last, the BWROG process for identification and resolution of differences between the EPGs and specific plant licensing basis as presented to the NRC in 1991, has not been implemented at PNP Concems with proper reconciliation of EOP actions and UFSAR assumptions appear to be generic. Another BWR of this vintage reported a similar issue to the NRC and Region 1 requested that the NRC's NRR technical staff review this issue to determine if it was a potential i unreviewed safety question (USQ). At the exit meeting, the team discussed the licensee's plans i

to review the PNPS 10CFR50.59 review and USQ determinations that approved implementation of the EOPs in light of new information. Differences in the required actions and assumptions in the UFSAR and other design basis information should be reconciled. Resolution of this potential generic item is identified as URI 50-293/98-203-03 (Reconciliation of EOP Actions and UFSAR Assumptions Associated With Containment Flooding)

l RHR Shutdown Cooling Line - Potential Thermal Overpressurization l NRC Generic Letter (GL) 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions, dated September 30,1996 addressed the potential for thermally induced overpressurization of isolated water-filled piping sections in containmen The licensee's 120-day response to GL 96-06, BECo Letter 2.97-006, dated January 28,1997, l stated that a review had identified six drywell penetrations subject to thermal pressurization effects. One of the penetrations identified was the RHR shutdown cooling suction line (Penetration X-12). This 20-inch line was insulated and was normally isolated between the inboard isolation valve, MO 1001-50, and the outboard isolation valve, MO-1001-47. The line had approximately 5 feet of exposed piping within the containment to absorb the thermal energy from the containment atmosphere and approximately 40 feet of piping outside the containment to dissipate the pressure energy. The licensee's letter stated that, assuming the insulation inside the containment was removed during the event, the pressure in the line would remain below the maximum operating pressure of the piping during postulated design basis LOCA and MSLB events, and that no corrective actions were required for this penetration.

t The team reviewed the analysis that formed the basis of the licensee's GL 96-06 response, Altran Technical Report Number 96249-TP,-01, Piping System Assessment of isolated Lines Across Primary Containment Boundary Subjected to Drywell DBA Event, Revision 0. This analysis determined that the peak pressure and temperature in this piping would be reached approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> after the accident initiation. The team identified two concems with the heat transfer calculations included in this analysis. First, the heat transfer coefficient used to l 7 i

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calculate the amount of heat transferred from the piping to the water inside the pipe appeared to l

be non-conservative. Second, the analysis assumed that the piping outside of containment was l

thermally isolated from the piping inside containment. This assumption also appeared non-

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conservativ I The licensee issued PR 98.9535 to review this analysis. On October 19,1998 the licensee notified NRC of a condition outside the design basis of the plant in accordance with 10 CFR 50.72, Event Number 34933. The licensee stated that the calculated intemal pressure l exceeded the maximum code pressure piping pressure based on a revised heat transfer l l

coefficient. The licensee stated that they would prepare a justification for continued operation l and planned to perform a detailed evaluation to determine if overpressure protection of the piping was require During the inspection the licensee provided a new calculation, Altran Calculation Number 98232-C-01, Parameter Sensitivity Assessment for GL 96-06 Thermal Over-Pressurization Evaluation of RHR/SDC, Revision 0. This calculation was performed to determine the impact of the team's concems on the calculated peak pressure and temperature in the shutdown cooling suction piping. This calculation used Altran's application, PIPEPRESS, to calculate the thermal and pressure response of this piping. The calculation concluded that results presented in Altran Technical Report Number 96249-TR-01 were conservative and boundin The team also reviewed Altran Calculation Number 98232-C-01 during the period of the inspection and identified a concem regarding the method used by Altran's application, PIPEPRESS, to calculate pressure in the piping. Specifically, the team questioned whether the correct fluid density values were being used in Section 3.3 of the calculation to determine the thermal expansion of the isolated fluid. The calculation determined the thermal expansion of the

isolated fluid from the initial conditions, then determined the pressure that would be required to compress the fluid into the available piping volume. The thermal expansion of the fluid was calculated by dividing the initial fluid density into the density of the heated fluid. The calculated change in the fluid volume, due to thermal expansion, was then multiplied by the fluid bulk modulus to calculate the pressure change in the piping from the initial pressure. The team's concern was that the density of the heated fluid was being determined based on the pressure in the heated / pressurized piping (calculated for the previous time step) rather than being based on the initial pressure in the piping. It appeared that this method could result in the thermal expansion being under-calculated and the calculated pressure being lower than the actual pressure in the piping. The licensee and their vendor, Altran, had not completed their evaluation of this concem during the inspection period.

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Resolution of the potentially non-conservative calculation methods in support of the licensee's GL 96-06 response, is identified as IFl 50-293/98-203-04. The technical acceptability of the licensee's resolution of the penetration overpressure protection is deferred to the NRC's review of the Pilgrim GL 96-06 response.

l f. Torus Cooling Mode - Single Failure Vulnerability

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During normal station operation with RHR operating in the torus cooling mode, the system cannot automatically be realigned into the LPCI mode in the event of a LOCA, assuming a single failure which results in the retum path valves to the torus remaining open. Because of train cross-connect valves, the flow from the operating RHR pumps in either loop would be returned

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to the torus through the failed open valves in the retum line. LPCI flow will be split based on line resistances between the reactor and the parallel torus discharge return path. Assuming an emergency diesel generator failure resulted in this condition, only the opposite train CS pump would be available for core cooling. Current 10CFR50 Appendix K analysis requires operation and injection of either both CS pumps or a combination of CS and LPCI pumps for mitigation of recirculation line breaks. RHR system operation in the torus cooling mode, exposes the system to this single failur GE Design Specification 22A1430, Revision 1, Residual Heat Removal System, dated August 19,1969, requirement 4.1.2.4 states that operation in the SPC shall not affect LPCl initiation or operation if required by a loss of coolant accident. UFSAR Section 7.4.3.5.4 LPCI Valve Control indicates that the normally closed RHR test line valves (torus retum valves) automatically close within a 30 second stroke time upon receipt of a LPCI initiation signal, which is consistent with the design specification requirement, however this would not preclude the single failure vulnerability. GE requirement 4.1.2.5 of specification 22A1430 identifies that anticipated operation in the SPC mode during normal operation was to be limited to 240 hours0.00278 days <br />0.0667 hours <br />3.968254e-4 weeks <br />9.132e-5 months <br /> consisting of 30 cycles at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> per cycle, based on a 40 year life. The licensee indicated that the operating hours in the SPC mode, based on RHR pump operating hours, all of which are assumed in SPC mode, were 370 hours0.00428 days <br />0.103 hours <br />6.117725e-4 weeks <br />1.40785e-4 months <br /> during 1997 and 159 hours0.00184 days <br />0.0442 hours <br />2.628968e-4 weeks <br />6.04995e-5 months <br /> through July 31,199 The licensee had identified this problem as part of the Maintenance Rule improvement Project and issued PR 98.9159, March 30,1998. Standing Order (SO) 98-04 was issued on March 31, 1998 to require that an active LCO be entered for the LPCI system being inoperable in accordar'ce with TS 3.5.A.4, whenever the system is aligned in the torus cooling mod Procedure 2.2.19, Residual Heat Removal, Revision 65, dated August 21,1998 incorporated the requirements of SO 98-0 LER 98-007 (Licensee Event Report) April 29,1998 addressed this single failure vulnerabilit During the inspection period, the licensee indicated that based on a iow probability of occurrence, a TS amendment and UFSAR change was being considered to resolve this issue and clarify system operability during this mode of operatio E1.2.1.3 . Conclusions The team concluded that the mechanical design of the RHR system was generally acceptable, and that the system was capable of performing its safety functions from its normal standby alignment, assuming a loss of offsite power and a single active failure. The team had some concerns regarding the consequences of EOP guidance that would direct the operator to flood the primary containment in response to a DBA LOCA event. Several design control concems were identified regarding changes to the LOCA analysis inputs and results, and assumptions made in the RHR shutdown cooling line thermal overpressurization analysis (GL 96-06). A test control concern was noted whereby the RHR pump surveillance test did not completely account for flow measurement uncertainty. The team also noted several positive attributes during the review, including LPCI operation with heat rejection mode being successfully integrated into the containment heatup analysis, and declaration of an LCO when operating in the SPC mode in recognition of RHR system single failure vulnerability when in this mod The licensee initiated actions to resolve RHR system issues identified during the inspection through their condition reporting and corrective action program. Two potentially generic items,

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associated with application of instrument uncertainty and EOP containment flooding actions are currently being evaluated by the NRC staff and any future corrective actions should also be addressed by the licensee's corrective action progra E1. Electrical Desian Review E1.2.2.1 Insoection Scone For the electrical design review, the team focused on the essential power supplies to the RHR, and support-interface systems. The following power supplies were chosen for review:

emergency diesel generators, the 4160 Vac system, the 480 Vac system, the 120 Vac system, and the 250 Vdc and 125 Vdc systems. The following attributes for the above areas of review were assessed by the team: equipment sizing; regulatory and standard compliance; electrical separation; voltage drops and available voltages; protective device sizing, coordination and setpoints; controls and interlocks; operating procedures; plant modifications; surveillance tests; and design and configuration contro The team reviewed UFSAR Section 8, technical specifications (TS) 3/4.9, system descriptions, electrical requirements, design change packages, surveillance test requirements, and other miscellaneous electrical documents related to the design basi E1.2.2.2 Observations and Findinas E1.2.2.2.1 AC System Review a. Emergency Diesel Generator The Pilgrim EDG ratings are as follows: 2600 kW- continuous; 2750 kW- 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />; 2860 kW- 2hr/24 hr period; and 3000 kW- 30 minutes ratings. Review of the EDG steady state loading calculation PS-79, " Emergency Diesel Generator Loading," Revision 4, determined that the "B' EDG loads under worst-case design basis event (failure of *A" EDG under accident conditions) were 2875 kW for period 10 minutes to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This loading remained within the 30 minute EDG rating of 3000 KW with approximate 77 kW of these loads from cyclic operation of motor operated valves (MOVs). The licensee's calculations determined that the worst-case EDG loading remained within the 2-hr rating as well. The acceptability of EDG loading was further assured by conservative procedure load restrictions during manualloading of the EDG The team had no concerns regarding the operability of the diesels because the estimated loads were within the overload ratings specified by the manufacturer (Coltec Industries).

The above EDG loading was based on calculation comment sheet (CCS) 21. This CCS attached engineering evaluation ( EE)98-031 to the above loading calculation to address several problem reports identifying potential overloading of diesels. The team evaluated power demands for pumps such as Core Spray, RHR, RBCCW and Service Water and verified that the loads were accurately identified in the calculation. The team noted that the licensee utilized a realistic (40-55'C) temperature instead of a (90'C) bounding temperature in assessing the cable heat loss when estimating potentialloads. The licensee initiated PR 98-1795 to review the impact of using a non-bounding temperature values for the loading analysi Procedure 3.05, " Design Calculations," Revision 23 and design guide EB12 requires that

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previous comment sheets be incorporated whenever a calculation is revised. However, the procedure does not require a mandatory calculation revision after information changes nor does it limit the use of comment sheets to supplement existing calculations. The use of comment sheets to supplement calculations makes it difficult to evaluate the cumulative effects of the l changes on the loading calculation. Presently, the licensee has neither established procedural I

requirements to keep a running total cf all steady state loads added to the diesel not any limiting criteria as to when the calculation should be revised when loads are added to the EDGs via comment sheets. The team considered this a weakness in the licensee's calculation cc t ol ,

program. During the inspection, the licensee was revising EDG steady state loading calcu'ation l ( PS-79) to incorporate all outstanding comments sheet '

l Review of recent EDG surveillance test reports for the "B " EDG (Procedure No. 8.9.1, Revision l 4, 8M 3-1, Revision 26 and 3.M.3-47, Revision 13) showed that electrical loads, including ECCS l loads, were sequenced onto the EDG within the required times and that the drop and recoverv ,

j in output voltage and frequency were acceptable. The licensee took prompt and effective

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measures to correct unacceptable conditions identified during the test via PR 98-9403. The team noted that the licensee's existing tests were not verifying the EDG's capability to carry worst-case loading conditions during an accident and the EDG steady state loading j requirements did not have much margins. The licensee had previously acknowledged that non- i worst case testing nor steady state calculations completely demonstrate EDG capability under !

l transient loading conditions. Therefore, the licensee is performing an EDG transient analysis to l verify the EDG's capab@y to carry worst case loading. This analysis was not complete at the l time of the inspection but is scheduled for completion by the end of 199 The team identified the NRC's redew of the licensee's EDG steady state loading and transient !

calculations as IFl 50-293/98-203-05 (Review of Revised EDG Loading Calculations).

b. Short Circuit Study and Protective Coordination

l The team reviewed Calculations PS-95, Short Circuit Study," Revision 2 and comment sheets,

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! PS 30, "480 voit Breaker Coordination / Protection ," Revision 0 and comments sheets, and various protective coordination curves developed as part of calculation PS-149, Revision 1, and PS-63, Revision 0. The buses and breakers were properly sized for the worst-case available fault currents. However, the team identified that in calculation PS 95, the licensee used incorrect l fault current for the 345 kV switchyard (16128 amperes instead of 17152 amperes). The l

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potentialimpact of this error on the calculation appear to be negligible. The licensee stated that they were performing a new calculation (AC load flow study including fault analysis) and this discrepancy would be addressed in the next revisio The team reviewed protective coordination for several train B safety related components at  ;

different voltage levels. Adequate coordination existed between the feeder breakers and the ,

down stream protective devices for the sample RHR, RBCCW, SW and other systems reviewe However, the team noted that the coordination curves did not show important information such as motor thermal limits, cable thermal limits and in some cases the locked rotor currents with available short circuit currents. Even though the licensee was able to retrieve most of this

information for the team's review, they were not available for all the circuits. The licensee stated i that a centralized coordination study under their calculation upgrade program was being l performed that would address this issue.

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c. Cable Ampacity The team reviewed Calculations PS 65," Voltage Study," Revision 0, PS-58," Electrical Power Cable Ampacity and Conduit fill," Revision 0, and Calculation EG-1-1, " Cable Ampacity Calculation," Revision 0, to determine adequate cable sizing to withstand full load currents under design basis conditions. The team learned, that the typical industry practice of sizing the cables to withstand a continuous current of at least 125% of full load was used in the Pilgrim design as well. The RHR, RBCCW and SW system cables reviewed were found to be sized adequately, i

However, the team noted that 480 Vac feeder cables to motor control center (MCC) B-10 and MCC B-14 would carry 458 amperes and 546 amperes, respectively during worst-case design basis accident. But, these cables were rated for only 384 amperes and 546 amperes, respectively. The initial review of the existing condition under PR 98-2661 determined that this condition would not result in any short term physical damage to the cables in accordance with I the guidance provided in IEEE S-135 - IPCEA P-46-426, *lEEE-PCEA Power Cable Ampacities."

i The licensee is presently developing new, PNPS cable specific, calculations to reconfirm that all power cables have acceptable ampacities. The licensee expects 'o complete this review by the first Quarter of 1999.

l d. Preferred Source of Shutdown Operating Mode The licensee had used the 345 kV switchyard, back feeding through the main transformer, as the preferred off-site source during shutdown conditions. The 345 kV back feed feature is an attemate qualified offsite power source as discussed in Section 8.1 of UFSAR and Section 3.9 of TS Bases.

l The team requested the basis that demonstrates the adequacy of the backfecd source, and

) learned that no written basis existed to confirm backfeed adequacy as to required voltage, l loading, or short circuit protection requirements. The licensee plans to review this issue as part

of their calculation update program. The team identified this issue as IFl 50-293/98-203-06 l (Review of Backfeed Analysis).

e. Electrical Penetration Protection The team reviewed electrical penetration protection calculations PS-119, " Containment Electrical l Penetrations," Revision 3, and PS-124, * Adequacy of Electrical Penetrations Under LOCA i Condition, Revision 2, to determine the adequacy of electrical penetration protection. Neither l

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the UFSAR nor the TS including TS bases or the staff's safety evaluation report (SER) dated August 25,1971, specifically addressed the penetration protection design for the Pilgrim Statio However, the licensee's design bases requires the electrical system to meet the redundancy, independence and single failure criteria as defined in IEEE 308-1969," Class 1E Electric Systems l for Nuclear Power Generating Stations." Review of the calculations determined that the l electrical pene' rations were not designed to withstand a fault current assuming a single failure of the protective device. The team noted that the protective devices were sized properly to isolate the worst-case fault with one protective device (one breaker or fuse). Thir appeared to be the original design of the plant except this was not discussed in any licensing documents. The team's concem was that if the breaker fails to open during a fault, the containment pressure integrity could be lost. The team requested that the licensee describe the non-safety related -

circuits that were energized during an accident. The licensee provided a list of non-safety loads l (approximately twenty five 480 volt power circuits and one hundred 120 Vac/125 Vdc control

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circuits) that were either protected by safety-related protective devices or nonsafety-related protective devices. The team's review of the sample coordination curves for penetrations Q105 A-2, and 4, and Q101 B-1, and1 A circuits indicated that during a worst-case fault, assuming a failure of single protective device the penetration conductors and penetration would exceed their i

design values. The team noted that in 1996 the licensee had reported (LER 96-004) that a l

containment penetration integrity would have been jeopardized because of incorrect trip settings and failures of motor contactor In response to the team's concem, the licensee stated that penetration safety-related breakers that were tested presently at 6-year interval and nonsafety-related breakers at 8-year interval would be tested every four years to ensure that protective devices would operate properly when they are required to operate during a fault. The licensee also developed a licensing and regulatory history for this issue. The licensee's review also calculated that the probability of a LOCA and a resulting penetration breach because of a fault would be 1.57 E -7 per yea Because of potential unacceptable containment results caused by a single failure of a protective device, the team in consultation with NRR projects decided that this issue should be referred to l

' the NRR technical staff for further review. This item is identified as IFl 50-293/98-203-07 (Review of Electrical Penetration Protection).

f. Degraded Volta;je Protection

! 4160 Volts Level l

The team reviewed the degraded voltage protection on the Class 1E buses to ensure that emergency buses and loads would not be damaged during a sustained undervoltage conditio The team reviewed calculations PS 65A, * Degraded Voltage," Revision 0 and attachments 1-6; PS-163,setpoint calculation for degraded voltage relays for Bus B6," Revision 0; and loop l l

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accuracy calculations PS-148, " Degraded Voltage Alarm Relays- Revised Setpoint, " Revision 0; PS-147, " Degraded Voltage Trip Relays- Revised Setpoint," Revision 1; PS-146, " Degraded Voltage Alarm Relays -Setpoint for Time Delay," Revision 1; and PS 145, " Degraded voltage Trip Relays - Setpoint for Time Delay," Revision 1. The review indicated that the licensee had addressed a number of problems identified in calculation PS-65A. Regulating transformers were installed to ensure acceptable voltages at 1M volt level components. Corttrol power

! transformers were replaced and interposing m - were installed in 480 volt MCC control l circuits. Cables were replaced where caw , :arge voltage drops and motors that had less than 80% starting voltages were analyzed tur starting at the minimum available voltage of 75% ;

of rated voltage. The licensee had revised TS Table 3.2.B consistent with the degraded bus l setpoint accuracy calculations. The existing degraded voltage setpoint is approximately 93% of ;

normal voltage. The degraded voltage alarm setpoint on the bus is approximately 95% of  !

normal voltage. The licensee's calculations assumed approximately 92.5% normal voltage  !

(3849) as analytical limit to provide adequate voltages for all components. The allowable values I for the n tpoints were selected based on the methodologies provided in ISA standard 67.04 and RG 1.105. The licensee had taken corrective actions for specific components where the voltage rnargiris were negative.

i As noted above, the licensee had made several improvements to ensure reliable 4160 Vac power would be available. However, prior to the NRC inspection, the licensee note that timing of ;

the degraded bus relays to support the operation of 4160 voit buses from EDGs was not

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consistent with the accident analysis. Specifically, during a degraded voltage condition before l 13

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the degraded bus relay actuates to power the bus from the EDGs the core spray (CS) pump breakers could potentially trip due to locked rotor current during motor starting if that happened, !

operator action was needed during the automatic sequencing of loads to restore the CS pump l The licensee reported this issue in LER 98-015 stating that under these conditions, the 10 CFR ,

50.46 limits could be exceeded, and no evaluation of the peak clad temperature (PCT) was I performed. The licensee reported on the same day that during a degraded voltage condition i

, coincident with the LOCA, the EDG would not be available to support the accident loads in the l

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required time (14.4 seconds) assumed in the LOCA analysis. The actual time to restore power by the diesels would be approximately 21 seconds. The design discrepancy was reported by the licensee in LER 98-014. This delay was caused by a 10.2 second timer in the EDG closure circuit in addition to the 10.6 seconds time delay for the degraded bus relays. The team noted that the licensee did not fully understand the design basis for the 10.2 seconds timer. In both l

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cases, the licensee addressed the operability issue by implementing administrative controls by j maintaining the grid voltage above 342 kV (voltage above degraded alarm range). Procedure 2.4.1.4, * Degraded Voltage," Revision 14, Section 4.1 requires that if voltages at safety buses A5 and A6 are between 3879 and 3959 volts (voltages between trip setpoint and alarm l setpoint), then start the diesel generators and load them on to the bus. The team determined j that this was acceptable to address operability of the above concerns. The team reviewed 345 l

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kV and 23 kV grid voltage records for the last five years and noted that they were operating well above the minimum voltages assumed in the calculation. The licensee is presently reviewing their degraced voltage design as part of the design basis review effort. The licensee stated that their commitment to implement corrective actions (any modifications and/or analysis) would be completed prior to or during refueling outage (RF012). The review of licensee's corrective

actions is identified as IFl 50-293/98-203-08 (Review of Plant Modification to Resolve Degraded l

Bus Voltage Concems).

480 Volt fevel l The team reviewed modification package PDC-95-05 that added degraded bus protection for 480 volt swing bus B6. The licensee performed this modification because the existing degraded voltage scheme (which senses voltage on the startup source) was not single failure proof as it relates to the 480 volt swing bus. The swing bus is needed for proper operation of both trains of LPCI. The analytical limits established for the 480 volt system is consistent with 4160 volt system and was based on not causing any premature or delay in tripping and transferring to the attemate source for bus B6. As described in section E1.2.1.2.c of this report, the swing bus transfer modification resulted in an approximately 4.9 seconds delay in the LPCl flow injection

, time. The 4160 volts degraded and undervoltage relays including timing tolerances are

! specified in TS 3.2.B and 4.2.B. TS 4.2.B requires that these 4160 bus relays be calibrated on )

a refueling interval and functionally verified on a monthly basis. However, the licensee had not '

established similar tests for the new 480 volt relays and timer l l

The team noted that the licensee's safety evaluation for the modification did not discuss the effect on the TS. The licensee stated that the TS impact was reviewed as part of the modification process. The licensee's design cliteria specification stated that this modification did not affect the existing degraded voltage TS without providing any basis. The licensee's 10 CFR 50.59 safety evaluation Procedure P83E5 " Safety Review," Revision 12, did not require any l review for TS impact. It was not clear to the team tnat the licensee's review of this modification completely satisfied the TS impact review requirements specified in 10 CFR 50.59.

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The team's concem with the licensee's 10 CFR 50.59 determinations associated with TS impact and the failure to establish appropriate testing for the new 480 Vac relay is identified as IFl 50-293/98-203-09 (Adequacy of TS and Testing of the New 480Vac Relays).

E1.2.2.2.2 DC System Review I

a. Sizing of Station Batteries i

The team verified the 2550 amp-hour ratings of each of the three station batteries (redundant !

125 VDC batteries and 250 VDC battery) by reviewing the available worst case sizing analysi The most recent sizing analysis for station battery *A" was found in procurement specification E10A Revision E3, and its current 8-hour discharge curve in load flow analysis PS47G, "DC Loading Calculation for 125V "A" Battery with Type NCN35 Cells, Revision 1. As part of the licensee's calculation upgrade program, new sizing calculations are being generated for all of the present batteries that were installed in 1993 and 1994 under PDC 93-28, " Station Battery Replacement," Revision 0.1 he following discrepancies were identified during the team's review of the available data:

1. The field of EDG "A", which is flashed in the last minute of battery operation is not correctly depicte . Torus Vacuum Breaker solenoid valves SV5040A & B should be energized for periods 1-5 as well as period 6 as identified in PR 98.2565 3. Backup scram solenoid valves A & B should be modeled as energized for a total of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> but were not shown as energized at al . ADS logic and blowdown valves can be powered from either train but only the A battery analysis correctly modeled this potentialloa . Problem Report 98.2691 identified that new HPCI inverter resulted in increased loading that was not properly modeled in the B battery calculation. However, the effects ,

of increased loading on the A battery from the new RCIC inverter had not been addressed by the license The licensee determined the station batteries had sufficient margin in accordance with IEEE 485 even after accounting for the outstanding load discrepancie The licensee's resolution of the discrepancies found in the calculations is considered IFl 50-293/98-203-10 (Review of New Battery Sizing Calculations).

b. DC Fault Evaluation The team reviewed calculation PS-23, "DC Short Circuit Currents for Coordinated Review", Re O but it is for the previously installed batteries. There is no calculation that determines available fault currents for the new batteries installed by PDC 93-28 in 1993 and 1994. Engineering Evaluation EE96-083 in response to Problem Report 91.2241 predicted higher DC fault currents due to the lack of current-limiting capability of the fuses in the main battery leads. The licensee has since leamed that possibly five buses (D4, DS, D10, D16, and D17, in the DC distribution systems of the three station battaries, have to be replaced with ones with higher fault ratings since the fuses in question will not properly limit DC fault currents. Since the redundant 125 VDC buses are not connected during normal operation, this is not considered a common mode failure. However, it does demonstrate a lack of complete understanding of the fault limiting

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capability of the fuses in question. Verification of postulated fault currents and replacement of buses with low fault ratings is considered IFl 50-293/98-203-1 c. DC Load FlowNoltage Drop The team reviewed calculation PS47G regarding voltage available at DC components (end devices). In most cases, the licensee calculated the available voltage at the distribution panel level and not down to the DC end devices. The team selected a sample of end devices for which the licensee determined that all end devices were operable for worst-case battery A terminal voltages experienced during its discharge cycle. This review provided confidence that most end devices appear to be operable, but that will be confirmed with a greater degree of certainty when the new load flow analysis is completed as a result of the design basis upgrad The licensee did not determine, by analysis, what the minimum battery terminal voltage would be during a given station battery's discharge cycle. The service test acceptance criteria of 110 or 220 volts for the 125 and 250 VDC systems respectively, had no basis except that the licensee believed it to be conservative. The team noted that the licensee had made previous design changes to improve system performance by replacing feeder cables to DC distribution panels and MCCs along with replacing the DC operators of MOV The licensee is currently reverifying DC system and battery terminal voltage through their electrical calculation upgrade efforts. Followup review of the licensee's new calculations is identified as IFl 50-293/98-203-1 d. DC Load Control Procedure NE 3.20, * Preparation, Review, Approval, Revision, and Closeout of Modifications, Revision 1 and its predecester NE 3.02, with a similar title, require affected priority B documents, which include calculations, to be identified on e traveler to a PDC. However, the licensee documented in PR 98-2616 five instances where PDCs did not properly indicate affected documents to be revised. Procedures NE3.05, " Design Calculation," Revision 23, Step 7.0.3.d and design guide EB12, " Electrical Engineering Discipline Design Basis," Step 1 require a calculation to be revised as part of PDC preparation / engineering review. If the change is negligible, a calculation comment sheet can be issued. Procedure NOP83E1, " Control of Modifications at Pilgrim Station," Revision 20, Step 5.1.2.a dictates PDC preparation in accordance with good engineering practices and industry standards and codes with review and approval by Modification Team and Department Managers per Step 5.1.2.b. This design control guidance was not adhered to for the following cases:

1. Installation of the larger amp-hour batteries under PDC 93-28 required the determination of the magnitude of available fault currents from the battery and a reevaluation of protective devices credited with limiting fault currents. This was not adequately done per NOP83E1 for PDC 93-28 since the licensee subsequently discovered that available fault currents exceeded the nominal fault ratings at some DC buses. Controlled calculation PS23. for analysis of DC fault currents, was not revised per NE3.05 during the review and approval of PDC 93-28 due to an error in judgement that credited the fuses in station battery main leads with more current limiting capability than what they actually provide .) Existing controlled battery sizing calculations were not revised or new sizing

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calculations originated for the new batteries installed by PDC 93-28. The size of each station battery was not verified for DC load changes per NE3.05 subsequent to installation of present batteries since no controlled battery sizing calculations existe Only the operability of DC end devices was verified by tracking load changes in the form of outstanding calculation comment sheets against the load flow analyses. A sizing calculation determines amp-hours withdrawn from a battery or positive plates required whereas a load flow analysis verifies sufficient voltage at all DC end devices to ensure their operability. This is further supported by Problem Report 98.2616 which indicates that PDCs 93-37/93-38 did not evaluate the impact ofloading changes on DC system or of the adequacy of available voltage at buses since calculation comments were written against the wrong calculation .) Problem report 98.2691 determined that for installation of new RCIC and HPCI inverters that a calculation comment sheet improperly stated no load change was involve The significance of the above errors is that the licensee has no formal procedure for tracking and controlling DC loads other than the revision of the appropriate DC calculations or by l calculation comment sheets outstanding against those same calculations. The real-time load on a given DC bus or the battery itself during the interim between a calculation's revisions is obtained by summing all load changes on outstanding calculation comment sheets against that calculation. In addition, Tech Spec surveillance tests like the battery service test are updated only for calculation revisions. The licensee has not established any calculation revision criteria such as periodic time limit, number of outstanding calculation comment sheets, or a set value of DC load changes in kW, it is at the discretion of the cognizant engineer. Therefore, there is a ,

potential for not correctly performing Tech Spec surveillance tests because a calculatian wM not

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updated. In fact, this calculation update weakness appears to be the root cause of a tan w

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correctly test the "B" station battery as discussed in section E1.2.2.2(e) of this report. Similar design control weaknesses associated with controlling AC loads were discussed in section E1.2.2.1.a as well. This item is identified as URI 50-293/98-203-13 (Adequacy of Design Control and Acceptability of TS Surveillance Test).

e. Surveillance tests TS 4.9.A.2.c and d require a service test (accident load profile) to be performed every refueling l outage for each battery and allows the performance test (capacity test) to be substituted for a i service test for each Class 1E battery every five years. The licensee currently performs the l service test and performance test for each battery on an attemating basis every two years. The l performance test allows the battery to discharge at a constant current of 319 amps for an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> i period; it is conducted for both the redundant 125 VDC batteries and the 250 VDC battery.

! However, the team identified that, although allowed by TS the performance test does not envelope the service tests for any of the three batteries for the first minute of loading. The A train 125 VDC battery and the 250 VDC battery have the most severe first minute current peaks, of 644 amps and 898 amps, respectively. The adequacy of the present approved TS is questionable since the performance test does not envelope the service test. Neither the NRC i

nor the licensee question the operability of the batteries since they are oversized and relatively

new. The licensee indicated that they plan to correct the TS requirements for battery testing

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after reviewing with the battery vendor the acceptability of performing overlapping tes l

l l DC Loading Calculation PS47H for 125 VDC "B" Battery, Revision 01, was revised to update load profile for "B" Battery on 9/27/97. However, surveillance test procedure 8.9.8.2, "B" 125 VDC Battery Acceptance, Performance, or Service Test," Revision 8 was not modified to include this change prior to performance of a service test for "B" battery on 11/24/97. The test performed was not conservative because "B" battery's first minute calculated load should have been specified at 449 amperes. The test procedure used, specified a first minute load that was 22 amperes lower. The 11/24/97 service test could not be considered a valid test since the

actualload profile was not verified acceptable by testing. BECo wrote PR 98.9536 to document i I

the team's concern and to evaluate battery operability. The licensee's review determined that the last valid test, a TS allowed substituted performance test, was performed successfully on 9/29/95. The licensee considered that the 9/25/95 test was valid until March 1999, if the 25%

l allowed grace period was applied (i.e. 9/29/95 plus 2 years surveillance interval plus 6 month grace). At the conclusion of the inspection the licensee was considering several options to resolve this issue. Since the test would require the plant to be shutdown the licensee was considering scheduling the test for an outage window of opportunity prior to March 1999. The licensee was also reviewing the calculation that added the load to determine if margins could be reevaluated to make the 11/24/97 test valid. Additionally, the licensee was considering the option of requesting a one-time TS change or enforcement discretion in order to perform a valid service test for Battery B during RFO-11 starting in April or May of 1999. Adequacy of TS battery surveillance test and design control weaknesses which allowed this event to occur were l

previously identified as URI 50-293/98/203-13 in section E1.2.2.2.2.d abov f. Ground Detection Schemes and Ampacity of DC Cables The licensee did not have a formal calculation for sizing the ampacity of existing DC cables and was not generating ampacity calculations to support new cables for PDCs. However even with this lack of documentation to support the ampacity ratings of existing and new DC cables, the l

licensee was able to verify the ampacitics of the samples of DC cables selected by the tea The team reviewed the ground detection schemes for the station batteries. The one for each station battery is a solid state ground detection scheme. The team reviewed past problem reports and determined that several grounds had been reported in both of the 125 VDC redundant distribution systems. The licensee was either able to determine the problem and correct it or the ground never occurred again. The ground system is sensitive enough to detect even high resistance ground g. Coordination and Selectivity of DC Protective Devices The team reviewed calculation PS31,DC System Overcurrent Protection Coordination Study,"

Revision 1. The results show that coordination is achieved between most distribution panel l branch circuit breakers and their main feeder breakers even for the new fault currents for the present batteries. Coordination will not be achieved between protective devices in main battery feeds and the feeder breakers to DC distribution panels but this is within the single failure criteria of loss of one train. The licensee replaced some protective devices in order to achieve selectivity between protective devices as much as possible. The team did not identify any cases where the lack of coordination would present a problem. The licensee has not updated the time-current plots or calculation PS31 itself for the new fault currents available from the present station batteries. The licensee plans to revise the calculation as part of the calculation improvement progra l I

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E1.2.2.3 Conclusions  !

I The team concluded that the essential power supplies for the RHR and its support systems were capable of performing their safety functions as required by their design beces. The material condition of the systems and general house-keeping appeared to be good. The team identified I severalissues such as deficiencies in surveillance testing and load control of batteries; l nonconsevative TS for battery surveillance tests; potentialloss of pressure integrity of containment electrical penetrations assuming a single failure of the protective device; incomplete analysis to demonstrate the capability of the EDGs under a worst-case design basis accident j condition ; electrical backfeed mode of operation when the plant is in shutdown conditions was

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not analyzed; times assumed to restore power by the EDGs and to the swing bus were

! inconsistent with accident analysis; swing bus degraded bus relays and timers are not tested as frequent as 4160 degraded bus relays and timers; and weaknesses in licensee's procedures for i l 10 CFR 50.59 evaluation and guidance for revising calculations when loads are added. The self l assessments in the electrical area were useful in identifying issues conceming the

! design / licensing bases.

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E1.2.3 Instrumentation and Controls O&C) Desian review E1.2. Scone of Review

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The team evaluated the ability of the instrumentation and controls for the RHR system and the i supporting RBCCW system to perform their safety functions during normal power operation and accident conditions. Documentation reviewed included the UFSAR, TS, applicable analyses l and calculations, operating procedures, and plant modifications. System walkdowns l supplemented the document reviews. The team concentrated on reviewing setpoint bases

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documents, uncertainty calculations, and commitments to Regulatory Guide (RG) 1.97, instrumentation for Light-Water-Cooled Nuclear Power Plants to Access Plant and Environs Conditions During and Following an Acciden E1.2. Findinas a. General findings l

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Post-accident monitoring instrumentation design was consistent with the guidance of RG 1.9 Modification packages reviewed were generally of good quality, consistent with the design bases, and associated 10CFR50.59 evaluations were acceptable. Various uncertainty calculations such as for the engineered safety feature setpoints were generally acceptable and consistent with plant design. Equipment inspected during plant walkdowns was generally in conformance with design documentatio b. Calculations Quality and Control

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Generally the team's review found that l&C calculations developed for TS values associated with the RHR and its support systems were of good quality and provided acceptable results.

However, calculation comments associated with vendor calculations were not controlled as wel Specifically, calculation 1N1-136, Setpoint Calculation for PS 1001-89A-2, B-2, C-2 and D-2, Drywell Pressure RHR Initiate, Revision 0, dated June 11,1993 determined the setpoint and

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allowable values for the pressure switches to support TS changes required for a 24-month fuel t

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cycle. Primary containment (drywell) high pressure causes an immediate LPCI initiation signal to the RHR pump timers.

l Within the body of the calculation the Notify Watch Engineer (NWE) allowable value was 2.44

! psig. The calculation, performed by an outside vendor, was reviewed by BECo as required by l Pilgrim Nuclear Engineering Services Department, Procedure No. 3.01, Review l Evaluation, and l Acceptance of Supplier Design Documents, Revision 13. BECo comments were attached to the l supplier design documents (SUDDS) comment form. The comments stated that the TS setpoint allowable value was to be chsnged to 2.22 psig from 2.44 psig. The allowable value is the limiting value the trip setpoint can have when tested periodically. The team found that the 2.22 psig recommended by the licensee was not incorporated within the body of the calculation. The l calculation was accepted into the BECo system and was made available as a design bases

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document. In response to the team's concem, the licensee stated that the change to the )

allowable value should have been incorporated within the text of the calculatio The team was concemed that the proposed change documented in the comments, but not incorporated within the body of the calculation, may not have become part of the design. Failure to have consistent design inputs could yield inadequate design bases. The licensee further stated there were no operability issues with this calculation inconsistency. The licensee verified l the revised 2.22 psig allowable value was consistently applied to the TS, UFSAR and surveillance procedures and was appropriately used in licensing and plant document base They also stated the plant had previously addressed this issue with PR 97.3606 after finding two other calculations,1N1-146, "Setpoint Calculation for PlS 263-49A, B: Reactor Pressure RHR Permissive, Revision 0, Dated September 9,1993 and 1N1-147, "Setpoint Calculation for PIS l 263-50A, B: Reactor Pressure RHR Permissive, Revision 0, Dated September 9,1993 with l

similar concems. Based on the team's finding, the licensee issued PR 98.2540 to resolve this concern. Design control problems were also noted in section E1.2.2.2.2.d of this report and identified as URI 50-293/98-203-13. The control of comments on vendor calculations is identified for resolution as part of that URI.

l c. Condensate Storage Tank (CST) to Team !nwrlocks

' i The team reviewed the condensate storage tank level switch interlocks. Pressure switches PS-2390A and B were reviewed for adequacy of design. Two pressure switches installed in the i

suction piping to the High Pressure Coolant injection (HPCI) pump monitor CST level. The switches cause the HPCI suction valve from the CST (MO-2301-6) to close and the HPCI l suction valves (MO 2301-35 and 36) from the torus to ope l The pressure switches are safety-related devices, installed b '.iw suction piping of the HPCI system per instrumerd installation detail M-263. Switch ir;sta 'athn is not directly off of a static l line of the CST, but in a 18-inch line a distance away 'r the tu tor building. The team was concemed that the use of pressure switches instalvd in o nne ihat would have flow, to measure t level would need corrections in the design for vehty %duccJ bia i

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l Calculation E634-3, Setpoints for PS-2390 A&B d the HPOl System, Revision 1, dated

November 18,1987, established the current somd af 31.8 inches decreasing above tank bottom. Effects of velocity head loss and pipe trymon losses were not addressed within the

calculation. Based en the team's concem, the licensee evaluated the velocity head loss and

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pipe friction losses and found that the fluid velocity and friction head losses would decrease the measured head below its actual value. For the HPCI design flow rate of 4250 gpm, the measured head was decreased by approximately 6 inches due to velocity head and approximately 2 feet due to piping friction losses, fittings, etc. This pressure reduction would tend to cause the switches to actuate before the required level setpoint. A 2.5 foot pressure drop error was equivalent to approximately 19,000 gallons of water in the CST and would potentially strand this volume if the pressure switches were actuated at the specified flow rat The licensee considered the effect of transferring from the CST to the suppression pool at a higher than anthipated level and found that this was more conservative and did not affect HPCI l system operability. TS Table 3.2.B stated that the required trip level setting was to be 18 inches above tank zero. The licensee stated that the condensate transfer system would be used post- I accident, if available, and that it was not entical to mitigating a design bases accident. The team agreed with this analysi I In response to the team's concem, the licensee investigated other instrument designs for possible extent of conditions and they concluded that this was the only application where !

pressure switches installed remotely away from a tank were utilized to measure tank level. The licensee issued PR 98.2605 to address the effect of velocity induced biases and revise various

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engineering procedures as require d. Salt Service Water (SSW) Instrumentation Installation Service water to the RBCCW heat exchanger flow transmitter FT-624 appeared not to meet the ;

1 inch per foot slope requirements specified on the instrument installation detail drawing M263, for high and low side instrument tubing near the 18 inch service water pipe. This instrument is ;

classified as safety related. The team was concemed that with the present installed  !

configuration air could become entrained affecting the flow reading. The licensee confirmed the !

inadequacy of the installation and checked the maintenance database for possible past I calibration problems, but no items were identified. Based on the team's concem, maintenance request MR 19802377 was issued to address this issu E1.2.3.3 Conclusigns The team concluded that the design of the instrumentation and controls for the RHR and l

RBCCW systerns was adequate to support the safety functions of the systems and was consistent with the licensing bases. Post-accident monitoring instrumentation design was consistent with the guidance of RG 1.97. Modification packages reviewed were generally of good quality, consistent with the design bases, and associated 10CFR50.59 evaluations were acceptable. Various uncertainty calculations such as for the engineered safety feature setpoints were generally acceptable and consistent with plant design. Equipment inspected during plant walkdowns was generally in conformance with design documentatio The team identified several design control weaknesses including inadequate consideration of piping losses in the calculation that determined the CST to torus switchover setpoints; not incorporating design review comments into the body of a vendor uncertainty calculation; and instrument slope deviations from installation specification. The licensee initiated actions to resolve these items through their condition reporting and corrective action progra E1.2.4 System Interfaces 21 i

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E1.2. Scoce of Review The team selected the following systems that interface with the RHR system to verify that the interfacing system design appropriately supported the function of the RHR system:

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The RBCCW system, which provides cooling water to the RHR heat exchangers as well as other essential equipmen The SSW system, which provides cooling water to dissipate RHR system heat from the RBCCW system heat exchanger The reactor building floor drain and equipment drain systems, which collect drainage from the reactor building; and

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The reactor building room coolers, which maintain room temperatures within acceptable limit In addition to reviewing design information for the interfacing systems identified above, the team examined installation of the interfacing systems during the RHR system walkdow ,

E1.2.4.2 Eindinos Potential Common Mode ECCS Failure Due to Flooding The quad rooms house various safety related components for the following systems: Northwest quad - RHR and CS train B; Northeast quad - control rod drive (CRD); Southeast quad - RHR and CS train A; and Southwest quad - RCIC (Reactor Core isolation Cooling). Adjacent to the Northwest quad is a compartment housing HPCI components. The floor drain lines for these rooms are piped to a common Reactor Building floor drain sump located in the HPCI compartment. The individual floor drain line from each quad room contains a normally closed, fail-closed, air-operated isolation valve to prevent a flooding event in one room from affecting the other rooms. However, there also exists a Reactor Building equipment drain system that serves the Reactor Building, the quad rooms, and the reactor auxiliary bay. The equipment drain lines are piped to a common sump also located in the HPCI compartmert. There are no isolation or check valves to prevent reverse flow in these equipment drain lines; therefore, the potential exists for a common flooding event whereby multiple ECCS equipment rnoms could be impacted by a single flooding event. NRC concem for events of this type was identified in IE Circular N , Potential Common Mode Flooding of ECCS Equipment Rooms at BWR Facihties, dated May 31,197 A review of the analysis of the consequences of high energy piping failures outside the primary containment (UFSAR Appendix O) indicated that there are no high energy lines in the quad rooms whose rupture could cause flooding. The only flooding source identified by the licensee was normal system leakage of 1 gpm from the ECCS for a 30-day period following a design basis LOCA. As stated in calculation S&SA-60, Revision 0, Flooding Due to ECCS Leakage Outside Containment, this leakage was limited to valve packing, bonnet to bonnet gasketed l joints, pump packing glands and seals, and bolted flanges. The resulting common flood in the

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quad rooms (excluding the CRD quad, in which the equipment drain lines were capped) and the HPCI compartment was 21.2 inches. The team reviewed calculation S&SA-60 and questioned whether all possible sources of water to the Reactor Building sumps had been considered. In particular, the team noted that credit was being taken for operator actions to isolate leakage sources based on non-safety related tank or sump level alarms. The licensee initiated PR 98.9537 to perform a comprehensive review of all possible inputs to the reactor building sumps to assure that resulting flood levels in the interconnected ECCS equipment rooms are acceptable. The licensee also indicated that the WNP-2 ECCS room flooding event caused by a fire water pipe rupture (Information Notice 98-31, Fire Protection Design Deficiencies and Common-Mode Flooding of Emergency Core Cooling System Rooms at Washington Nuclear Project Unit 2, dated August 18,1998) was under review for applicability to PNPS under their operating experience review progra Completion of a comprehensive review of all possible sources of leakage and flooding to assure that multiple ECCS equipment rooms are not adversely impacted by a single flooding event is identified as URI 50-293/98-203-14 (Adequacy of Design Controls Associated With ECCS Room Potential Flooding).

b. RBCCW System ISI Boundaries The basis for the RBCCW system classification was described in Memorandum NED 90-300, ISI Safety Class P&lDs, dated May 4,1990, and is documented on Inservice inspection drawings ISIM215, Sheet 1, Revision E7; ISIM215, Sheet 2, Revision E6: ISIM215, Sheet 3, Revision E6; and ISIM215, Sheet 4, Revision E6. ASME Section XI refers to 10CFR50 for the classification criteria. Footnote 9 of 10 CFR 50.55a stated that guidance for classifications may be found in RG 1.26, Quality Group Classifications and Standards for Water, Steam and Radiological Waste Containing Components of Nuclear Power Plants and Section 3.2.2 of NUREG-0800, Standard Review Plan (SRP) for Review of Safety Analysis Reports for Nuclear Power Plants. The memorandum stated that PNPS was designed and constructed prior to the issuance of the RGs; therefore, systems and components were not classified under the quality group classifications defined in RG 1.26. It also stated that PNPS is not required to meet the SRP requirement Section 6.2 of the memorandum, addressing the RBCCW system, indicated; This system has been classified ISI Class 3 in accordance with RG 1.26, Section C. with the exception of the items listed in b. below (UFSAR Article 10.5.3). Piping and components between valves MO4085A and MO4085B (recirculation motor

generator set equipment), from MO4009A to MO4002 (cleanup demineralizer heat exchanger, fuel pool heat exchanger), 30-CK-432 (supply piping to containment) and MO4009B (retum piping from containment), and between primary containment penetrations X-23 and X-24 (piping and equipment within containment) are not classified as they service equipment that is not safety related (UFSAR Article 10.5.5.1, Q-List). Piping and components between 30-CK-432 and X-23 and between X-24 and MO4002 have been classified as ISI Class 2 in accordance with RG 1.26 and ANSI /ANS 56.2-1984, Containment isolation Provisions for Fluid Systems After a LOCA). l l

The team questioned the basis of the ISI classification boundaries located at the normally open i I

RBCCW non-essential loop isolation valves (MO4085A/B, MO4009A/B) and at the primary

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containment penetrations (30-CK 432 to X-23, X-24 to MO4002). The non-essential loop isolation valves and containment isolation valve MO4002 are motor operated valves requiring operator action to close. However, it did not appear that a failure in a non-classified portion of the system would be isolated in time to prevent a loss of the inventory from the affected RBCCW loo The licensee initiated PR 98.9531 which stated that it is necessary that a final determination be made as to the appropriate classification of the RBCCW non-essential piping and component Engineering Evaluation (EE) 98-0081 prepared during the inspection, determined that the non-classified portion of the system should either be included in the ISI program, or be included in a similar inspection progra Resolution of the appropriate ISI Class 3 test boundaries, consistent with the pressure boundary design basis to ensure RBCCW inventory is maintained, is identified as IFl 50-293/98-203-15 (Review of RBCCW ISI Boundary).

c. Potential Loss of RBCCW System Function or Containment Integrity Due to a HELB inside Containment NRC Information Notice 89-55, Degradation of Containment isolation Capability by a High Energy Line Break, dated June 30,1989 addressed the potential for a High Energy Line Break (HELB) inside containment causing the failure of piping in a closed system inside containment, thereby negating one containment isolation barrier and leaving the plant with only a single containment isolation valve to mitigate potential radiological releases. ESR Response Memorandum (ERM) 89-1158, dated December 14,1989 determined that RBCCW piping inside containment would not be damaged by pipe whip, and that only the portions of the RBCCW system supplying four of the drywell coolers could be exposed to the jet impingement effects of HELBs. The ERM also stated that the system piping configuration and operator action to close RBCCW isolation valves in response to low RBCCW surge tank level would prevent loss of containment integrity. This ERM concluded that there was a low risk of the specific events occurring that would compromise containment integrity, and that containment integrity would still be provided by a water sealin the RBCCW system if the containment isolation valve failed to close. The licensee concluded that further protection against this event was not require The team observed that the ERM did not evaluate the potential effects of losing RBCCW i inventory before the failure could be isolated by the operators. It appeared that the "B" loop system inventory could be pumped out through a failure prior to the operators identifying the failure location and closing the associated motor operated valves. Loss of system inventory could potentially result in a loss of function of the system loop or create a vent path from the primary containment through the surge tank vent to the reactor buildin The licensee initiated PR 98.9532 which stated that no analysis of record could be located to

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address this issue. The licensee performed EE 98-0082, Revision 1 during the inspection and I

determined that the likelihood of losing of the RBCCW "B" loop due to a HELB in the drywellin conjunction with losing of the "A" RBCCW loop due to a random single failure would be extremely low, and that loss of RBCCW cooling capacity as a result of a HELB was not a credible even EE 98-0082, Revision 1 also stated that a vent path from the primary containment to the reactor

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building could be established if a RBCCW pump continued to operate and the isolation valves were not closed. The conclusion of the EE judged that the flow rate through this vent path would be well within the capacity of the SGTS, and that the radiological consequences of this potential scenario would not have any significant irnpact on the previously evaluated release to the environmen The design and protection of the RBCCW system inside containment was not well documente This vulnerability of the system to high energy lines within the drywellis similar to a concem identified at another BWR of thie Vntage, which is currently being reviewed by the NRR technical staff. NRC resolution of this issue and the licensee's " low probability approach" to address the potential for a HELB nside contailment causing the failure of piping in a closed system inside containment, is identified as IFl 00-293/98-203-16 (Vulnerability of RBCCW System to Damage From a HELB).

d. Potential Loss of RBCCW Function or Containment Integrity Due to a Waterhammer Induced Failure inside Containment NRC Generic Letter (GL) 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions, dated September 30,1996, addressed the potential for waterhammer and two-phase flow conditions in containment air cooling water systems. The licensee's 120-day response to GL 96-06, BECo Letter 2.97-006, dated January 28,1997, stated that the RBCCW system would not be susceptible to waterhammer or two-phase flow that would degrade the pressure boundary integrity or RBCCW safety related heat removal performance, and that the system was operable and corrective actions were not required. This conclusion was based on RBCCW flow to the drywell coolers being automatically restored in less than approximately 94 seconds after a design basis LOCA with a concurrent loss of off-site power (LOOP).

The licensee's response to NRC's Request for Additional Information (RAI) dated July 14,1998 for Resolution of GL 96-06 issues at PNPS, BECo Letter 2.98-123, dated October 1,1998, addressed a single active failure scenario that could result in RBCCW flow to the drywell coolers being interrupted for more than approximately 94 seconds after a LOCA. This letter stated that the potential waterhammer from a delayed RBCCW pump restart may damage the pressure boundary of the drywell cooler due to its copper tube construction. However, primary containment integrity and operability is assured by the system isolation valves outside containment. Additionally, to further their argument, the licensee calculated the probability of a LOCA followed within 600 seconds by a LOOP with a concurrent diesel generator failure to be 2.9 x 104 per year. The licensee concluded that this low probability coupled with the isolation valves ensures containment integrity would not be credibly challenged by the postulated scenario. This response was being reviewed by NRC at the time of the inspectio The team identified an additional single active failure scenario that could result in RBCCW flow to the drywell coolers being interrupted for more than approximately 94 seconds after a LOC RBCCW system TS 3/4.5.B.3, Amendment 176, only required two of the three RBCCW pumps to be operable for the subsystem to be operable and a second pump could fail to start due to a single active failure. Therefore, it appeared that RBCCW flow to the drywell coolers may not be restored for over 100 seconds, potentially resulting in a waterhammer. The licensee evaluated this scenario during the inspection and concluded that it had a probability of 9.1 x 10" per year and was less probable than the scenario addressed in the GL 96-06 response. The licensee

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also stated that the LOOP probability values were based on the historical record of the complete l loss of the 345kV and 24kV off-site power sources and did not consider degraded voltage i condition The team also observed that the GL 96-06 responses did not evaluate the potential effects of

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losing RBCCW inventory due to a waterhammer induced failure before the primary containment l RBCCW piping could be isolated by the operators. It appeared that the "B" loop system l inventory could be pumped out through a damaged drywell cooler or piping prior to the operators l identifying the failure location and closing the associated motor operated valves. Loss of system l inventory could potentially result in a vent path from the primary containment through the surge

! tank vent to the reac'or building. The licensee included this scenario in PR 98.9532 and EE 98-0082, Revision 1.

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The team discussed with the NRR technical reviewer the details of the licensee's proposed probability approach to resolve the GL 96-06 concem. Resolution of this specific GL 96-06 concem will be tracked as part of IFl 50-293/98-203-04 (Resolution of GL 96-06 Concems).

l e. RBCCW System Overpressure Protection ASME Code, Section Vill, Division 1, Paragraph UG-125 required that pressure vessels be provided with overpressure protective devices in accordance with the requirements of l Paragraphs UG-125 through UG-136. Based on review of drawings M215, Sheet 5, RBCCW l Composite P&lD, Revision E5 and M212, Sheet 1, Service Water System P&lD, Revision E73, and on system walkdowns, the team observed several ASME Vill heat exchangers that did not have overpressure protective devices installed on the equipment or on the adjacent pipin These heat exchangers were the RBCCW Heat Exchangers (E-209A & E-209B), Fuel Pool Cooling Heat Exchangers (E-206A & E-206B), Recirculation Pump MG Set Oil Coolers (E-211A

& E-211B), and CRD Pump Oil Coolers (E-212A & E-2128).

The licensee determined that the original Bechtel Specification M-11, Cooling Water and Fuel Pool Cooling Heat Exchangers, Revision 1 had required that the seller fumish shell and channel l relief valves on these heat exchangers. The licensee stated that when the RBCCW and SSW l systems are in their normal lineups there is no potential for overpressure to occur. However, during maintenance the heat exchanger may be isolated, resulting in the potential for thermal pressurization. The licensee concluded that this potential could be eliminated with procedural controls, i in response to this issue, the licensee initiated PR 98.2644 to determine corrective actions to l address operational issues, review ASME Vill code requirements, include precautions for any active work packages on the affected equipment, and conduct a reportability revie Resolution of compliance with the ASME Vill code for overpressure protection of heat exchangers is identified as IFl 50-293/98-203-17 (Review of Overpressure Protection For Heat Exchangers in the RBCCW System).

t f. IST of SSW System Manual Backwash Valves PNPS IST program was presented in Procedure Number 8.l.1.1, inservice Pump and Valve Testing Program, Revision 9. This procedure identified the scope of components (pumps and

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valves) and testing requirements for compliance with 10CFR50.55a(f) IST requirements. Section

6.3 of the procedure included a list of the valves included v/ithin the program scope.

1 The team noted that the following 12 manual SSW system valves, periodically operated to

- backwash the RBCCW heat exchangers (valves 29-HO-3823, 24, 37, 38, 39,42) and TBCCW

heat exchangers (valves 29-HO-3827, 28, 29, 32, 33, 34) were not included in the IST program

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and asked if these were active manual valves requiring testin !

j The licensee stated tunhe RBCCW and TBCCW heat exchanges were backwashed on a '

weekly basis, or more frequently as required, the heat exchangers were not declared inoperable

! during backwashing operations, and that in the event of an accident the operators would be

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,i in response to this issue, the licensee initiated PR 98.2677 during the inspection which stated j that these valves most probably need to be included in the IST program because they are >

! manipulated weekly and cannot be classified as " passive," and therefore should be subject to i  ;

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g. RHR/CS Cooling Water Flow Distribution \

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1 Calculation M-784, Revision 0, RBCCW Flow Test Evaluation dated April 21,1998, evaluates i RBCCW flow distribution test results based on a calculated system hydraulic gradient to project I the emergency LOCA flow distributionc Test data for the RHR seal coolers (B&D) and CS pump .

B motor thrust bearing indicated a combined flow through the three parallel units of 108 gpm at a l differential pressure of 44.7 psi. With the CS pump motor thrust bearing cooler valved out a '

combined flow of 106 gpm at 44.3 psi was recorded through the two parallel RHR seal cooler The analysis concluded that after adjustment for anticipated hydraulic grades, the RHR pump seat coolers and CS pump motor thrust bearing cooler, as a combined load, receive a total flow that is greater than the design flow under emergency LOCA conditions and therefore there is good agreement between the flow model and the flow test. Evaluation to demonstrate the flow

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distribution to each of the three parallel flow paths was not evident. GE Design Specification 22A1281 AF Revision 4, Closed Cooling Water System for Reactor Service dated June 28,1972, specified a 20 gpm flow rate for each RHR pump seal cooler and a 4 gpm flow rate to the CS pump motor thrust bearing resulting in a design flow of 44 gpm for the three parallel cooler arrangement. The team was concemed that the different resistance characteristics for the seal coolers compared to the thrust bearing cooler may result in little flow margin for the thrust bearing coole The licensee indicated that the original test data was to benchmark the hydraulic model and this was accomplished based on larger model of three parallel flow paths. The additional test data with the thrust bearing cooler isolated was not used to benchmark the flow model. Re-evaluation of this data using the same hydraulic model could not validate the model for verification of flows to individual components. PR 98.9516 was issued to recommend that further testing be performed to establish the actual flow through and resistance of the thrust bearing coole E1.2.4.3 Conclusions The design of the RHR system interfaces were acceptable and supported performance of the

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I RHR system safety functions. In general, the engineering analysis associated with the RHR !

interface systems were of high quality and consistent with the design and licensing basi However, the team identified several design and test control concern I Design control issues identified include use cf probability as a design basis to address effects of high energy line breaks within containment, potential common mode ECCS room flooding due to interaction through equipment drains, and ASME Section Vill code compliance for overpressure protection of code stamped heat exchangers. Test control issues include definition of ISI test boundaries inconsistent with Pressure Boundary Only design bases of RBCCW system, and incomplete evaluation of RBCCW flow test results for parallel path RHR and CS component The potential loss of RBCCW function or containment integrity due to a waterhammer failure inside containment was being reviewed by NRC in conjunction with GL 96-06 at the time of the inspection and is deferred to that revie The licensee has initiated actions to resolve these concems through their problem report program, as require E1.3 UFSAR Review l

The team reviewed the applicable UFSAR sections for the RHR system, interfacing systems, ;

and the associated electrical and instrumentation and controls sections, to verify consistency '

between the UFSAR descriptions and design documentatio I The following discrepancies were noted during review of the RHR and supporting UFSAR Chapters:

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UFSAR Table 4.8-1 lists the RHR pump shutoff head as 600 ft. This value was originally specified in GE design specification 22A1430AB, Revision 3, Residual Heat Removal l System; however, review of the manufacturer's certified test curves for the four RHR l pumps indicates that the actual shutoff head is 740-750 ft. The licensee initiated PR i 98.2542 to correct this discrepanc l l

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UFSAR Section 7.4.3.5.3, LPCI Pump Control, states that only three of the four RHR pumps are required to provide adequate flow to restore reactor vessel level water for the design basis LOCA. The licensee indicated that this statement reflects original requirements for individual system performance when PCT limits were higher and certain mooeling characteristics were less conservative. Original requirements were that three LPCI pumps alone provide adequate core cooling, and that each CS loop also be capable of providing adequate core cooling. The current licensing basis Appendix K core cooling analysis GE NEDC-31852P, Pilgrim Nuclear Power Station SAFER /GESTAR-LOCA Loss of Coolant Accident Analysis, Revision 1, April 1992 does not verify the ability of three LPCI pumps alone to perform adequate core cooling. The

! licensee initiated PR 98.2566 to determine if this RHR capability still exists or to modify the UFSAR accordingl The licensee is addressing these UFSAR discrepancies through their corrective action progra I Additionally, the above discrepancies are typical of those items being found by tne licensee's UFSAR update efforts.

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E Desian Control

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E.1.4.1 Scone of Review l

The team reviewed engineering and design documentation (drawings, calculations, specifications, etc.) for the RHR system as discussed in previous sections of this report. During these reviews, the team assessed the effectiveness of the licensee's design control processe The team identified a number of document discrepancies and inconsistencies, as itemized belo E.1. Findinos a. Controlof Calculations

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Calculation M408, Revision 0, RHR Pump Suction System - Pressure increase Analysis dated December 28,1989 analyzed a deviation between the design pressure (80 psig) of the RHR suction lines as documented in Specification M300 for Piping and the potential actual pressure of 122 psig as documented in PCAQ 89-116. The licensee had identified a similar problem during the RHR Design Bases Document development as documented in PR 98.0644, dated March 26,1998, wherein GE documentation specified a design pressure of 150 psig for this system portion, compared to piping specification M300 ratings of 80 psig. The results of PCAQ 89-116 had not been reflected in specification M300. PR 98.0644 was supplemented (PR 98.0644.02) to reconcile calculation M408 with the update of specification M30 .

Calculation S&SA 015 Single Failure ECCS Analysis dated April 2,1979 assessed the capability of the ECCS to perform its safety function assuming a single failure. The analysis was performed in response to GE letter WHH:78-46 Single-Failure Emergency Core Cooling (ECCS) System Analysis dated May 31,1978 to confirm that the loss-of coolant accident analysis is in conformance with 10CFR50 Appendix K. The team identified several concems with the analysis including: assumptions of effects of loss of cooling water systems, effects of a loss of instrument air, and operation in torus cooling mod The licensee issued PR 98.2516 to address the team's concem .

Calculation N-13, Revision 0, Calculation of Maximum Evaporative Cooling Pressure Drop From Containment Spray, dated August 24,1984 determines the maximum pressure difference between the drywell and the torus with spray into a dry containmen The calculation indicates that if the maximum evaporative cooling pressure drop is less than the design pressure differential for the torus to the drywell, the spray at rated flow is acceptable. The analysis indicates that the drywell to wetwell negative design pressure is 2 psi and concludes that an evaporative cooling differential pressure in excess of 4 psi could exist, however no evaluation of the maximum drywell spray rate flow limit was l include The licensee indicated that esiculation N-13 is no longer valid. Subsequent analysis indicates that a torus to the drywell differential over 8 psi is acceptable. Calculation S&SA 053, Revision 6, Data for PNPS Emergency Operating Procedures (EOP)

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Developed from EPG Revision 4, dated April 11,1997 used the higher limit to establish the Drywell Spray Initiation Limit pressure and temperature limits for initiation of drywell sprays. The licensee initiated PR 98.2692 to void calculation N-1 .

Calculation S&SA 036, SSW Degraded Flow, dated November 10,1980 evaluates post LOCA torus water temperature with SSW flow degraded to 3300 gpm, the RBCCW heat exchanger in a clean condition and service water at 6S'F. The calculation summary indicates that the torus water temperature does not exceed 200 The licensee indicated that the calculation was done to assess effects of flow blockage and fouling on heat exchanger performance discovered on October 9,1980. The

calculation does not represent the current licensing basis for SSW flow, heat exchanger performance, or torus water temperature limits. PR 98.2606 was issued to void calculation S&SA-03 b. Evaluation of Radiological Effects on Non-Electrical items in the Commercial Grade item Process The licensee stated that the flexible steel reinforced RBCCW hoses on the RHR pump area i cooling coils had been replaced with in-kind replacements under the Commercial Grade item l (CGI) Process. The team questioned if the new hoses had been evaluated for potential degradation from radiation under post accident conditions. The licensee investigated the replacement hose material and determined that it was suitable for the calculated worst case total integrated dose (TID) values in the reactor building. However, the licensee stated that the CGI process did not require an evaluation of the radiological effects on non-electricalitems outside the scope of the EQ program.

l in response to this issue, the licensee initiated PR 98.2647 during the inspection. This problem

! report stated that the CGI procedures would be reviewed to include evaluation of radiological effects as necessary.

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[ Elements of design control require that measures be established for the selection and review for

!- suitability of application of materials, parts, and equipment that are essential to the safety-related

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functions of the structures, systems and components. Identification of suitable environmental l

requirements for components outside the scope of the EQ program is identified as IFl 50-

293/98-203-18 (Design Controls for Replacement Parts).

c. Minor Documentation Discrepancies

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Drawing M241 Sh.1 & 2, P&lD - Residual Heat Removal System (UFSAR Figure 4.8-1)

contained several drawing errors. The Loop A pump minimum flow line was shown terminating on an instrument line rather than at the RHR retum line to the suppression pool. Also, the RHR pump discharge line interfaces with the condensate transfer system (keep-full feature) incorrectly referenced a Note 15, whereas the correct reference was Note 13. The licensee initiated PR 98.2459 to correct these drawing errors.

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A typographical error was found in PNPS Surveillance Procedure 8.M.2-2.10.2-5, Loop

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Selection Logic System A, performed March 30,1998. An incorrect time delay setting i associated with relay 10A-K40A was inadvertently recorded. The licensee issued PR

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98.2492 to resolve the discrepanc .

Calculation 1N1-61, Low Setpoint for RBCCW Header Discharge Pressure Switches Loop A (PS-4058) & (PS-4008), Revision 1, sheet 5, note 5 stated that the maximum static head per M-752 was 35.8 psig. The correct value should have been 38.5 psi The licensee stated that this was a typographical error and the results of the calculation remained valid. The licensee included this discrepancy in PR 98.2492.

,' E.1.4.3 Conclusions The licensee's calculation review and DBD efforts have resulted in a better documented design

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basis for systems that have received this level of review. The quality of recent calculations was

generally good. However, older calculations were sometimes not consistent with the current design basis or were not being adequately controlled, revised or supersede X1 Exit Meeting

After completing the on-site inspection, the team conducted an exit meeting with the licensee on October 23,1998. During the exit meeting, the team leader presented the results of the

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inspection. A partial list of persons who attended the exit meeting is contained in Appendix B.

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Appendix A - List of Open items i

This report categorizes the inspection findings as unresolved items (URIs) and inspection followup items (IFI) in accordance with Chapter 610 of the NRC Inspection Manual. A URI is a matter about which the Commission requires more information to determine whether the issue in question is acceptable or constitutes a deviation, nonconformance, or violation. The NRC may issue enforcement action resulting from its review of the identified URis. By contrast, an IFl is a i matter that requires further inspection because of a potential problem, because specific licensee or NRC action is pending, or because additional information is needed that was not available at the time of the inspectio Item Number Findina Ilt!g ISDt 50-293/98-203-01 IFl Instrument Uncertainty Control and Application (E1.2.1.2.b)

50-293/98-203-02 IFl Control of LOCA Analysis inputs and UFSAR Update (E1.2.1.2.c)

50-293/98-203-03 URI Reconciliation of EOP Actions and UFSAR Assumptions Associated With Containment Flooding (E1.2.1.2.d) l 50-293/98-203-04 IFl Review of Licensee's GL 96-06 Calculation and Review Method (E1.2.1.2.e and E1.2.4.2.d)

50-293/98-203-05 IFl Review of Ravised EDG Loading Calculations (E1.2.2.2.1.a)

50-293/98-203-06 IFl Review of Electrical Backfeed Analysis (E1.2.2.2.1.d)

50-293/98-203-07 IFl Review of Electrical Penetration Protection (E1.2.2.2.1.e)

50-293/98-203-08 IFl Review of Plant Modification to Resolve Degraded Bus Voltage Concerns (E1.2.2.2.1.f)

50-293/98-203-09 IFl Review of TS and Testing of New 480 Vac Relays (E1.2.2.2.1.f)

50-293/98-203-10 IFl Review of New Battery Sizing Calculations (E1.2.2.2.2.a)

50-293/98-203-11 IFl Verification of Postulated Fault Current and Replacement of Buses with Low Fault Current Ratings l (E1.2.2.2.2.b)

50-293/98-203-12 IFl Followup Review of DC System and Battery Terminal Voltage Calculations (E1.2.2.2.2.c)

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50-293/98-203-13 URI Adequacy of Design Controls Associated With Controlling Changes With Calculation Comment Sheets and Acceptability of TS Surveillance Test (E1.2.2.2.2.d, E1.2.2.2.2.e and E1.2.3.2.b)

50-293/98-203-14 URI Adequacy of Design Controls Associated With ECCS l Room Potential Flooding (E1.2.4.2.a) '

50-293/98-203-15 IFl Review of RBCCW ISI Boundary (E1.2.4.2.b)

50-293/98-203-16 IFl Vulnerability of RBCCW System to Damage From a -

HELB (E1.2.4.2.c)

l 50-293/98-203-17 IFl Review of Overpressure Protection for Heat '

l Exchangers in the RBCCW System (E1.2.4.2.e) l 50-293/98-203-18 IFl Design Control for Replacement Parts (E1.4.2.b)

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Appendix B - Exit Meeting Attendees

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NAME ORGANIZATION BECo

' T. Sullivan Vice President H. Oheim General Manager, Technical Support C. Goddard Plant Manager J. Garety NESG Manager

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B. Sheridan QA Manager

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N. Desmond Training Manager .

T. McElhinney Operations Department Manager F. Mogolesko Nuclear Project Manager, AE Team Leader C. Wilson AE Team Counterpart R. Pace AE Team Counterpart (Mechanical)

P. Harizi AE Team Counterpart (Mechanical) i S. Das AE Team Counterpart (Electrical)

J. Coughlin AE Team Counterpart Electrical)

B. Rancourt AE Team Counterpart (l&C)

P. Doody S&SA Engineer R. Kelley Engineering NEG J. Wiggins Director, DRS, RI  :

G. Kelly Branch Chief, DRS, RI D. Norkin Section Chief, DISP, NRR L. Prividy Engineer, DRS, RI R. Arrighi Resident inspector

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Appendix C - List of Acronyms L

ANS American Nuclear Society

, ' ANSI American National Standards institute ASME American Society of Mechanical Engineering

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..BECo Boston Edison Company  !

BW Boiling Water Reactor

BWROG Boiling Water Reactor Owners Group ]

CFR- Code of Federal Regulations

. CGI . Commercial Grade item CR Control Room

. CRD Control Rod Drive

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CS Core Spray 3 CST Condensate Storage Tank l DBA~ : Design Basis Accident :

ECCS Emergency Core Cooling System EE . Engineering Evaluation .

EOP Emergency Operating Procedure EPG Emergency Procedure Guideline EQ Environmental QuaEfication

, ERM ESR Response Memorandum .

L ESR Engineering Service Request -

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, FSAR Final Safety Analysis Report

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GE General Electric Company GL Generic Letter ,

gpm gallons per minute  !

l l HELB ' High Energy Line Break j

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HPCI High Pressure Coolant injection 4 l

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l 18C Instrumentation & Control

! IFl inspection Followup Item l- IP inspection Procedure '

ISI inservice inspection IST Inservice Testing LCO Limiting Condition for Operation LER Licensee Event Report  :

i LOCA Loss-of-Coolant Accident I LOOP Loss of Off-Site Power LPCI Low Pressure Coolant Injection MO Motor Operated Valve C-1 L

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NPSH Net Positive Suction Head i NRC U.S. Nuclear Regulatory Commission NRR Nuclear Reactor Regulation, Office of (NRC)

NWE Notify Watch Engineer l

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P&lD Piping & Instrumentation Diagram ,

PBO Pressure Boundary Only l

PCT Peak Cladding Temperature  !

PNPS Pilgrim Nuclear Power Station PR Problem Report PSTG Plant Specific Technical Guidelines i

l RAI Request for AdditionalInformation RBCCW Reactor Building Closed Cooling Water RCIC Reactor Core isolation Cooling l

RG Regulatory Guide 1

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RHR Residual Heat Removal I RPS Reactor Protection System i RPV Reactor Pressure Vessel l SE Safety Evaluation SER Safety Evaluation Report  ;

SGTS Standby Gas Treatment System '

SO Standing Order SPC Suppression Pool (Torus) Cooling SRP Standard Review Plan SSFI Safety System Functional Inspection SSW Salt Service Water SWEC Stone & Webster Engineering Corporation TAF Top of Active Fuel TBCCW Turbine Building Closed Cooling Water TID Total Integrated Dose TS Technical Specifications l I

UFSAR Updated Final Safety Analysis Report URI Unresolved item l USQ Unreviewed Safety Question  !

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