IR 05000298/1997201

Insp Repts 50-298/97-201 on 971027-1121 & 1201-04.No Violations Noted.Major Areas Inspected:Rhr Sys & REC Sys

ML20203E029
Person / Time
Site:	Cooper
Issue date:	02/05/1998
From:	NRC (Affiliation Not Assigned)
To:
Shared Package
ML20203E011	List: IR 05000298/1997201 ML20203E005
References
50-298-97-201, NUDOCS 9802260235
Download: ML20203E029 (44)

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[ U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION

Docket No.: 50-298 ,

License No: DPR-46 4- Report No.: 50-298/97 201 Licensee: Nebraska Public Power District -

Facihty: Cooper Nuclear Station

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Location:~ . Brownville, NE Dates: October 27 - November 7,1997, November 17-21,1997, and December 1-4,1997 f

Inspectors: S.K. Malur, Team Leader, NRR R. Najuch, Contractor *

'R. Hogenmilier, Contractor *

c- M. Yeminy, Contractor *

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D. Vandeputte, Contractor *

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A. Varma, Contractor *

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(* Contractors from Stone & Webster Engineering Corp.)

Approved by: Donald P. Norkin, Chief

. Special Inspection Section Events Assessment, Generic Communications,

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and Special Inspection Branch Division of Reactor Program Management Office of Nuclear Reactor Regulation

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9002260235 900205 PDR ADOCK 05000298 G PDR

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Table of Contents Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 E Conduct of Engineering . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

E1.1 Inspection Scope and Methodology . . . . . . , . . . . . . ... ...........5 E1.2 Residual Heat Removal System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . 5 E1. Mechanical Design Review ........ ... ... ........5 E1.2.2 . Electrical Design Review . . . . . . . .. ... .......... 14 E1. Instrumentation and Control Design Review . . . . . . . . . . . . . 17 E1. *" "* m Interfaces . . . . . . . . . . . . . . . . . . . . . .

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.. . 18 E1. * 'Nalk d own . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . 2 3 E1. , .ad Safety Analysis Report / Technical Specifications . . 23

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E1.3 Reactor Equipmeru Cooling System , . . . . . . . . . . . . . . . . . . . . . . . 26 E1. Mechanical Design Review . , . . . . . . . . . . . . .. . . . . . . . . . 26 E1. Electrical Design Review . , , . . . . . . . . . . . . . . . . . . . . . . 31 E1. Instrumentation and Control Design Review . . . . . . . . . . . . . . 31 E1. System lnterfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 E1. System Walkdown , . . . . . . . . . . . . ................35 E1. Updated Safety Analysis Report . . ....,..........,...,. 35 X1 Exit Meeting . . . . . . . . . .

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' APPENDIX / Cpen items . . . . . . .... .... ......... .............. . . . . A-1 APPENDIX B Exit Meeting Attendees .. .. ...... ..... ............ . . . . . . . . _ B-1 APPENDIX C List of Acronyms . . .. . . . . . . . .

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EXECUTIVE SUMMARY A design inspection Cooper Nuclear Station (CNS) was performed by the Special Inspection -

Section of the Office of Nuclear Reactor Regulation (NRR) during the period October 6,1997, through December 4,1997, including on-site inspections during October 27-November 7,1997, November 17 21,1997, and December 1-4,1997. The inspection team consisted of a team leader from NRR and five contractors from the Stone & Webster Engineering Corporatio The team selected for inspection the residual heat removal (RHR) system and the reactor equipment cooling (REC) system. The purpose of the inspection was to evaluate the capability of the systems to perform safety functions required by their design bases, the adherence to the design and licensing bases, and the consistency of the as-built configuration with the updated safety analysis report (USAR). The engineering design and configuration control section of inspection procedure IP 93801 was followed for this inspection. The team selected and reviewed relevant portions of the USAR, technical specifications (TS), calculations, design criteria documents, drawings, modification packages, surveillance procsdures, and other plant document In response to the team's questions regarding the 200 gallons per day leakage from the REC

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system, the licensee investigated the sources of the leak and identified that about 600 cc/ min was being lost because the manual sampling valves at the filter demineralizer skid had been left open since the installation of the skid in 1991. Considering that the makeup to the REC system is non safety related, the minimum available volume of water in the surge tank would be depleted within a day and the REC system would be unable to support its long-term post-accident cooling functions. The design change that installed the filter demineralizer, the associated safety analysis, and the operating procedure did not address the importance of maintaining water inventory in the closed REC system. The licensee isolated the sampling valves, notified the NRC of the condition, and issued LER 97-014 on December 12,1997, which identified the cause as a failure to understand the design basis functions of the syste Although many calculations reviewed by the team were satisfactory, the team noted significant weaknesses in assumptions ard design inputs in the following calculations:

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The calculation for estimating the RHR pump room temperature (NEDC 93-C00, Revision 1) nonconservatively assumed the heat load from one RHR pump instead of from two pumps that would start after initiation of a low pressure coolant injection signa On the basis of this calculation, the operability requirements for the RHR room cooling fan coil units were removed from the TS. The licensee issued a night order to secure one of the RHR pumps if the fan coilin that room became inoperabl .

Calculation NEDC 97-074, Revision 1 for verifying the capability of the service water (SW) system to provide adequate back-up cooling for ssfety-related equipment in the REC system included nonconservative assumptions and inputs such as, operation of one RHR pump instead of two, flow distribution among the system equipment without considering the available test data, and SW temperatures without consideration of instrument uncertaintie _ . _ _

The 10 CFR 50.59 safety evaluation that was performed for the USAR revision to increase the RHRSW booster pump room temperature limit to 13f'F did not address operator actions and the consequences of such actions required during post accident conditions to prevent exceeding this temperature limit. Because the calculation for estimating the room temperature assumed operation of only one RHRSW pump and no other heat loads, the operator was required to open

- doors and remove hatch covers to establish natural convection cc9ing in the room, and secure all other equiprrent (all RHRSW booster pumps except one, air compressors, air dryers, and lighting) The safety evaluation also did not address conflicts within existing procedures that may not allow these steps to be performed. The licensee revised the safety evaluation and '

submitted it to the station operations resw committee for further revie The licensee informed the team that instrument uncertainties had not been taken into account for instruments used for surveillance tests. Previous NRC inspections had identified this issue in reports IR 96-26, IR 96 31, and IR 97-07. The team noted that the SW temperature indicating instrument uncertainty had not been considered for TS compliance or in several calculations that use this temperature as a design input. The licensee issued a night order to require certain operator actions when the SW temperature reaches 87F. The team also noted that the flow recorder and local pressure indicator uncertainties were not considered in determining RHR -

pump surveillance test compliance with the minimum flow specified in the TS. The actual test flow could be lower than the RHR flow value used in accident analysis. However, the team reviewed the latest test results of the RHR pumps and concluded that the current pump performance was acceptable considering instrument uncertaintie Because of oesign limitations of the minimum flow line, RHR pump flow was estimated at 1450 gpm per pump when both pumps are operating in parallel. The pump vendor agreed that although this flow was less than the recommended minimum flow of 1800 gpm, operation at this lower flow for 15 minutes for vitally important operation was acceptable. The vendor had also recommended minimum flow limitations for other pump operational conditions. However, the RHR operating procedures did not include these limitations. The team also noted that the evaluation of pump-to-pump interactions during parallel operation of the RHR pumps did not consider the allowed pump degradatio The effects of failure of air pressure regulators in the instrument air system on air operated valves has not been evaluated. The licensee initiated an evaluation of the impact of application of full air system pressure on 96 air operators in the plant. The team urged the licensee to expedite this investigation and promptly perform operability evaluations as require The team's review of the test results end performance evaluation of the RHR and REC system heat exchangers indicated that the test data and evaluation of several tests performed in 1996 and 1997 were in error. The calculated heat loads for one side of each heat exchanger were significantly higher than the other side and the fouling fectors calculated for the REC heat exchangers were negative. The licensee corrected errors identified by the team and established revised acceptance criteria for the heat exchangers, Because the SW temperature is unlikely to be near the design maximum value before the summer of 1998 &nd because some recent tests results were acceptable, the team had no immediate concerns regarding the performance of the heat exchangers.

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s The second level undervoltage relay setting for the emergency buses specified in TS Table 3.2.B. allowed a lower voltage than the analytical limit in the setpoint calculations (NEDC 88-0688, Revision 7). The licensee initiated revisions to relay calibration procedures to include the analytical limi The team noted that the reactor building sump pumps automr'ically start when sump lavels rise and during post accident conditions pump out potentially contaminated emergency core cooling system (ECCS) leakage collected in the sump to the radwaste system outside the reactor building. The licensee stated that these discharges had not been considered in the offsite and control room dose calculations. The team also noted that leakage through closed check valves and isolation valves from ECCS system to other interfacing systems had not been properly evaluated for dose consequence In condition adverse to quality report CAO 96-0634, the licensee incorrectly concluded that the inadequate original design in not providing diverse power sources for RHR heat exchanger vent valves which also have containment isolation functions was not reportable. However, this document also quoted a design requirement for the torus penetration that required that the valves be powered from diverse sources. The valves were closed and deenergized In' July 1996. In response to the team's questions, the licensee further reviewed the condition and issued LER 97-017, dated December 31,1997 to document that the condition was outside the design basis of the plan The team identified several discrepancies in the USAR, TS, and system design criteria documents, The team identified severalincorrect statements in the design criteria document (DCD-13) fo the RHR system that were inconsistent with the current system desig The team referred the following issues to the NRR staff for evaluation: the inability of the RHR system to recover from the suppression pool cooling mode and realign itself into the injection mode considering a single failure ; consideration of ECCS pump seal failure during long-term recovery from a loss of coolant accident (LOCA); consistency of the REC system with the licensing basis regarding independence of the two loops in the system; and consideration of LOCA-induced piping failures in the PsEC system desig The licensee implemented corrective or compensato;y actions, as appropriate, to resolve the immediate concerns identified by the team. For other issues, the licensee initiated problem identification reports to address required corrective actions. Taking into consideration the licensee's immediate actions, the team concluded at the end of the inspection, that both systems were capable of performing their safety function e o

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E Conduct of Engineering E1,1 inspection Scope and Methodology The purpose of this inspection was to evaluate the capability of the selected systems to perform the safety functions required by their design basis, to assess adherence to the design and licensing basis, and to evaluate consistency of the as-built configuration with the updated safety analysis report (USAR). The systems selected for inspection were the residual heat removal (RHR) system and the reactor equipment cooling (REC) system. These systems were selected on the basis of their importance la mitigating design basis accidents at the Cooper Nuclear SNtion (CNS).

The inspection was performed in accordance with NRC Inspection Procedure 93801, " Safety System Functional Inspection." The engineering design and configuration control section of the procedure was the primary focus of the inspection.

The open items resulting from this inspection are included in Appendix A. The acronyms used in this report are listed in Appendix C.

E Residual Heat Removal System E1. Mechanical Design Review E1.2. Scope 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 team reviewed: applicable portions of the USAR and Technical Specifications (TS), the design criteria documents (DCDs), ficw diagrams, piping and instrumentation diagrams (P&lD), and other system drawings, calculations; design change documentation, operating procedures, inservice and surveillance test procedures and results, emergency operating procedures (EOPs), and corrective action program documents. The scope of the review included:

verification of the appropriateness and correctness of design assumptions, boundary conditions, and system models; confirmation that design bases were consistent with the licensing bases; and verification of the adequacy of testing requirements. Systems interfacing with the RHR system were reviewed to verify that the interfaces were consistent with the RHR system design and licensing bases.

E1.2. Findings RHR Pump Surveillance Test Technical Specification (TS) Section 4.5.A.3.d. for the low pressure coolant injection (LPCI)

subsystem requires that the RHR pump be tested once every 3 months to demonstrate that a single pump is capable of delivering a flow rate of at least 7700 gpm but no more than 8400 gpm against a system head equivalent to a reactor vessel pressure of 20 psid above drywell pressure with water level below the jet pumps. Under the same conditions, two-pump flow (in a single

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loop) must be at least 15,000 gpm. Testing of the RHR pumps is performed in accordance with surveillance procedures 6.1RHR.101, Revision 4C3 (Division 1) and 6.2RHR.101, Revision 4C3 (Division 2). The team reviewed these procedures and determined that test measurements were taken using existing process instrumentation, including control room RHR flow recorder FR 143, local plunp suction pressure indicators Pl-106A through -106D, and local pump discharge pressure indicators PI-107A through 107D. No formai calculations that documented the instrument uncertainties were available. However, informal calculations performed by the licensee indicated that the flow recorder had a total uncertainty of about +/- 500 gpm, and the local pressure indicators had a measurement uncertainty of about 1% of range based on original General Electric (GE) instrument data sheet 234A9307NS, Revision 2. The surveillance procedure specified the minimum TS flow rate for one pump as one of the acceptance criteria for the RHR pump test and did not account for any instrument uncertainties. Therefore, the actual RHR pump flow rate could be less than the 7700 gpm minimum value required by the TS for one pum Safety analyses presented in USAR Section VI and Section X!V-6.3 were performed using the minimum single RHR pump flow rate of 7700 gpm as an input assumption (USAR Table XIV-6-3b), with no allowance for surveillance test instrument uncertainties. Licensee calculation NEDC 94 230, Revision 3, " Vessel Head-Over-Drywell Capacity Curve for input into ECCS Analysis,"

also is br. sed on the 7700 gpm per RHR pump flow rate. If actual RHR flow rates were less than 7700 gpm, then the available safety margins could have been reduced or eliminated. The desipa bases for the RHR pump flow were not property translated into test procedures as required by 10 CFR 50, Appendix B, Criterion !:1, " Design Control." (URI 50-298/97-201-01)

The team reviewed the most recent pump surveillance test results and determined that ths RHR

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pump performance currently is acceptable taking into consideration instrument uncertaintie The licensee initiated SCAO 97-1407 to address the generic issue regarding failure to account for instrument uncertainties when determining compliance with TS and equipment operability requirement RHR Pump Suction Strainer in response to NRC Bulletin 96-03, " Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors," dated May 6,1996, the licensee replaced the original RHR pump suppression pool suction strainers with larger capacity passive strainers via modification package MP 96-132, " Emergency Core Cooling Systems Suction Strainers Modification." In the modification package, it was stated that the new strainers satisfied existing plant design and licensing bases, and increased the available net positive suction head (NPSH)

margin. In Section 6.3.1 of the original plant safety evaluation report (SER) dated February 14, 1973, the Atomic Energy Commission (AEC) stated that the RHR pump NPSH analysis showed that at least 3 psi margin existed between the containment pressure and the pressure required for minimum NPSH at the RHR pump. The AEC accepted the consideration of containment overpressure for the RHR pump NPSH evaluation although it did not fully meet Safety Guide 1.1, and concluded that the RHR pump NPSH analysis was conservative and there should be adequate NPSH to the pump The sizing of the replacement RHR strainers was based on an allowable strainer head loss

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margin that war established to ensure that adequate NPSH was available for the RHR pump The modification package and calculations NEDC 97-041 and NEDC 97-042 for the sizing of the new suction strainer and NPSH evaluation for the RHR and core spray pumps, did not explicitly specify or consider the 3 psi margin assumed in the SE The licensee initiated PIR No. 2 20641 to address this concern, and also provided a preliminary evaluation that concluded that the 3 psi margin was maintained for the replacement strainers if a dynamic velocity head loss term was removed from the available NPSH calculation for the replacement strainer. A letter from GE to NPPD dated December 15,1997 confirmed that the dynamic velocity head loss term was not included in the existing licensing basis NPSH determination that is shown in USAR Figure VI 5-15. (IFl 50-298/97-201-02)

In addition, the licensee noted that the replacement strainer dizing was based on a combined 50 percent debris generation and transport factor. A final determination of NPSH margin will be dependent on NRC approval of a final value for this factor, which impacts strainer head loss due to cebris accumulatio Strainer Replacement Modification Package The team reviewed modification package MP 96-132 and noted the following discrepancies:

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The modification package did not mention the sizing criteria for the suction strainer openings. An important design requirement for the strainers is that they must exclude particles larger than a certain size to prevent clogging of small passages in the RHR system flow stream, such as spray nozzles. Original GE design specification data sheet 257HA422AC, Revision 0, " Residual Heat Removal System (With Steam Condensing),"

identified spray nozzle maximum free passage diameters of 9/64 inch for the drywell spray nozzles, and 7/32 inch for the suppression chamber spray nozzles. The team f verified that the replacement strainers have been acceptably designed to allow debris of 1/8 inch maximum allowable size to pass through in Section 4.3.7 of design specification 24A5822, Revision 2, "ECCS Suction Strainers." The licensee initiated PIR No. 2-19709 to address this discrepanc .

The notes on drawing 729E11BB make numerous references to two strainers per LPCI suction line, and have not been revised to reflect the replacement of the dual strainers with a single new strainer. This drawing is reproduced in the USAR as Figures IV-8-1 and VI-4-3. The licensee initiated PIR No. 2-19708 to address this discrepanc .

The team identified discrepancies in calculation NEDC 97-044, Revision 0, " Review of GE report GENE E12-00147-04, Revision 1, Net Positive Suction Head (NPSH)

Evelustion," a document referenced in MP 96-132. The discrepancies included: an incorrect and non-conservative value of required NPSH for the RHR pump (23 ft instead of 26 ft at a flow rate of 7700 gpm); failure to justify whether the pressure drop for the auction line to RHR pump A was the bounding case; and the use of reference numbers that were not identified in the reference list contained within the document. The licensee initiated PIR No. 2-20628 to document these discrepancie _

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None of the above discrepancies had any adverse impact on the analyses performed in support of modification MP 96-132 or on the replacement strainer design; however, they were indicative of weaknesses in completeness and thoroughness in the preparation and review of the .

modification documen RHR Pump NPSH During Fire Events Report GE NE-T23-00742-01, " Fire Event Analyses for Cooper Nuclear Station," dated March 1997, criculated peak post-event suppression pool temperatures as high as 218.5 F after an Appendix R fire event. Because the RHR system is required to operate during a safe shutdown, the team questioned whether the RHR pump NPSH requirements at these elevated pool temperature conditions had been evaluated. The licensee initiated PIR No. 2-20629 to address this concern. Preliminary evaluations performed by the licensee, documented in Engineering Evaluation EE 97-335 dated December 1,1997, concluded that adequate RHR pump NPSH would exist when credit for containment pressure was taken. However, the containment pressure values credited in the evaluation were not conservatively calculated using assumptions that minimize the calculated pres.ure. The licensee stated that in a telephone conversation on December 2,1997, GE indicated that based on GE's experience, the containment pressures calculated using assumptions that minimize the pressure would be about 3-4 psi less than the values presented in report GE NE-T23-00742-01, Even with this lower containment pressure, since pt np NPSH requirements are less at the lower RHR flow rates, it appeared that RHR pump NPSH would be acceptable. However, the licensee recognized that a more rigorous evaluation was appropriate. (IFl 50-298/97-201-03) RHR Pump Minimum Flow The original design minimum flow bypass capacity of approximately 400 gpm for the RHR pump was increased through removal of orifices in the minimum flow lines by design changes DC 86-125, " Removal of RHR Minimum Flow Orifices," and DC 86-125, Revision 1, " Removal of RHR Minimum Flow Orifices / Flanges " Bingham International Inc., the pump vendor, had advised on September 10,1986, that for the RHR pumps the continuous minimum flow was 2800 gpm for a period greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in ai,y 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, and startup minimum flow was 1800 gpm for less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. Calculation NEDC 86-214, " Removal of RHR Orifices (Calculates min-flow rates for one and two pump operation)," documented the licensee's review of a GE analysis which predicted a single pump minimum flow capability of 1862 gpm, and 1450 gpm per pump minimum flow for two pump parallel operation, after removal of the minimum flow bypass line orifices. In letter AER-86-70, GE advised that the maximum duration that LPCI pump may operate in the minimum flow mode for the spectrum of hypotheticalloss-of-coolant accidents (LOCAs) was less than 15 minute In letter NLS 8800347, dated July 8,1988, addressed to the NRC, the licensee stated that the four RHR pumps had been shown, by actual test results, to have adequate minimum flow capacities and to not have adverse pump-to-pump interactions. The letter concluded these pumps were not adversely affected by the problems suggested in NRC Bulletin 88-04, " Potential Safety-Related Pump Loss."

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In response to questions posed by the NRC regard ng the licensee's response to NRC Bulletin 88-04, the licensee documented a re-evaluation of all safety-related pumps in letter NLS940141, dated December 29,1994, addressed to the NRC. Within this supplemental response, the licensee identified that the manufacturer concurred with the previous conclusion that minimum flow capacities were adequate, and parallel RHR pump operation on minimum flow for a duration of 15 minutes will not stress the pumps to the point of imminent failure. In a telefax dated August 24,1994, the pump vendor agreed that parallel operation of the pumps for 15 minutes or less at a flowrate of 1450 gpm, which was below the recommended flow for short duration, was acceptable if operation at this flow was vitally importan The team reviewed procedure 2.2.t.4, ' Residual Heat Removal System," and procedure 2.2.69.1, "RHR LPCI Mode," to determine how the minimum flow restrictions were addresse Both procedures did not specify operational limitations for the RHR pumps as stated by the vendor recommended minimum flow rates during both short term and long-term operation. The team concluded that design bases for RHR pump minimum flow requirements were not correctly translated into procedures and instructions as required by 10 CFR 50, Appendix B, Criterion 111,

" Design Control." (URI 50-298/97-201 04)

The licensee issued PIR No. 2 20626 to identify that RHR operating and off normal procedures l were not clear regarding maximum run time on minimum flow for the RHR pumps. The licensee issued Night Order 97-035 specifying pump minimum flow restrictions in compliance with pump i vendor recommendations. No specific directions had been provided on how to maintain the minimum flow or what actions are needed if the RHR pumps are to be shutdown because of minimum flow time limitations. Also, these instructions do not consider the potential flow instrument uncertainty discussed in E1.2.1.2.a of this repor The team considered that the temporary restrictions imposed by Night Order 97-035 were

{ inconsistent with USAR Section Vil-4.5.5.4, which indicated that a normally open minimum flow bypass line was provided to protect the pumps from overheating at low flow rates. No operator intervention to overcome a design deficiency and protect the RHR pumps is described in the USA Licensee responses in letters NLS 8800347 and NLS940141 were based on vibration tests performed in support of modification DC 86-125 and an analysis of 1987-1988 IST test data, which indicated the differential pressure between the A and C pumps was less than the differential pressure between the B and D pumps. The team reviewed calculation NEDC 94-258, " Tech. Spec. Acceptance Criteria for LPCI Pumps Flowing at 7800 gpm," and noted that the RHR pump surveillance test criteria would allow acceptance of pump performance combinations with one pump head degraded by about 100 ft more than the other pump. The team was concerned such a condition could result in a pump-to-pump interaction due to a

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ratatively flat pump performance curve at low flows. The licensee issued PIR No. 2-08280 to evaluate pump-to-pump interaction based on the worst case degradation allowed under the surveillance test program. (IFl 50-298/97-201-05)

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_ _ - _ - _ _ _ _ _ _ _ _ _-- RHR Heat Exchanger Performance Monitoring The team identified errors and questionable input parameters in calculation NEDC 93-08, "RHR Heat Exchanger Fouling Factor Determination for Mode C2," Revision 0. The errors included incorrect service water (SW) temperature, and incorrect heat transfer area, and input parameters based on test data that showed a considerable heat Icad mismatch between the two sides of the heat exchanger. The licens3e issued PIR No. 2-19713 to document this concem. The team questioned the validity of the conclusions in the calculation because of these erroneous input parameters. For example, the team noted from Sheet 3 of Attachment B to the calculation r rerformed in accordance with procedure 13.17, " Residual Heat Removal Heat Exchanger Performance Evaluation,' that during a test of RHR Heat Exchanger A on October 5,1991, a heat load of 800x10' Btu /hr was being removed from the RHR side of the heat exchanger while a heat load of 61x10' Btu /hr was entering the SW side. This heat load mismatch demonstrated that inaccurate measurements were used for evaluation of the heat removal ca.pability of the RHR haat exchangers. A review of condition adverse to quality (CAQ) report CAQ 97-0831 indicated that RHR HX-A had not been tested since March 1993 and had not been cleaned for four years between November 1991 and November 1995, it also induated that RHR HX B had not been cleaned for four years between April 1993 and April 1997 and was not tested since October 1995. Neither RHR heat exchanger was tested during the April 1997 outag Performance evaluation procedure 13.17, " Residual Heat Removal Heat Exchanger Performance Evaluation,' specifies an acceptance cnterion of 222 Btu /hr-F-ft2 for the heat transfer coefficient for the RHR heat exchangers. This value was based on the heat exchanger's capability to remove the accident heat load at a service water (SW) temperature of 85 F. The design basis service water temperature was increased to 90 F in 1990, and therefore, the team noted that the acceptance criterion for the heat exchanger should have been established taking into consideration the higher SW temperature. To resolve these concerns, l

the licensee stated that the method of evaluation would be changed and the acceptance criterion would be established based on heat removal capability projected to accident condition The acceptance limit in the test procedure and the evaluation of the test results were not adequate to demonstrate that the heat exchanger would perform satisfactorily in service as required by 10 CFR 50, Appendix B, Criterion XI, " Test Control." (URI 50-298/97-201-06) RHR System - Suppression Pool Cooling Mode of Operation The design of the RHR system is such that if during normal plant operation the system is operating in the suppression pool cooling (SPC) mode or in other secondary modes, the system cannot automatically be realigned into the LPCI mode to provide reactor cooling in the event of a LOCA assuming a single failure. Considering the worst case scenario, the flow from the operating RHR pumps would either be f!owing out of the break or be returned to the suppression pool through the failed open valve in the return line, and little or no LPCI flow may reach the reactor. Only one core spray pomp would be available for core cooling, and this was acceptable in the original design. However, to meet 10 CFR 50.46 and 10 CFR 50, Appendix K, analysis requirements, CS and LPCI pumps must operate to mitigate recirculation line breaks, assuming the loss of one emergency diesel generato _ _ _ _ _ _ _ _ _ _ _ _ _ ____ ________ __ _ _ _ _ _

The licensee inoicated that a TS Limiting Condition for Operation (LCO) is not entered when RHR system is in suppression pool cooling or in other secondary modes of operation. Licensee memos NLS960191 and NLS960208 indicate that the existing design basis for LPCI assumes that the system is aligned in the standby mode when a LOCA occurs and if LPCI is capable of performing this function from the standby mode, it can be considered operable. The memos cite report NEDC-32513, " Suppression Pool Cooling and Water Hammer," prepared for the BWR Owner's Group as the basis that realignment from the suppression pool cooling mode to the LPCI injection mode was not required as part of the design basis, because of the low probability of a design basis LOCA concurrent with the RHR System being in the suppression pool cooling mode. The memos conclude that if LPCI is capable of injecting from the standby mode, it is not required to be declared inoperable during suppression pool coolin The team noted that report NEDC 32513, Section 2, " Introduction," indicates that NRC Information Notice No. 87-10 stated that the design basis assumed that total SPC mode duration considering the coincident LOCA/ LOOP was one percent (90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> /per year) and Section 3.0,

" Original Design Basis," states that operation of the RHR system in the SPC mode was expected to be an infrequent occurrence during normal power operation, and therefore, not considered mechanistically in the ECCS design or analysis. Control room logs for the month of July 1997 indicated that the RHR system was in suppression pool cooling or other modes of operation for approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. The licensee stated that no limits on permissible durations in suppression pool cooling are imposed if it was necessary to maintain pool temperature limits in accordance with TS requirements. This issue has been referred to NRR staff for further evaluation. (IFl 50-298/97-201-07)

Licensee memo NLS960208 provides the position that if operations to transfer the torus water to radwaste occurs during the suppression pool cooling mode, and does not result in an extension of the normal time in the suppression pool cooling mode, then LPCI can be assumed operable.

l However, procedure 2.2.69.3, "RHR Suppression Peot Cooling and Containment Spray," and procedure 2.2.69, " Residual Heat Removal System," do not include any such restriction on suppression pool water transfer for cleanup to ensure it is coincident with normal suppression pool cooling. Control room logs for the month of July 1997 indicate the RHR system was in operation for approximately four hours apparently dedicated to support torus cleanup activities with transfer of torus water to the radwaste system. (IFl 50-289/97-201-08)

Design change DC 87-170 modified the stroke time of RHR system suppression chamber cooling throttle valves (also referred to as RHR pump test line isolation valves) RHR-MO-M034A&B from 24 seconds to 39 seconds. In the justification section of DC 87-170, it is stated that considering the recirculation discharge valve closure time, full LPCI injection will take place at 49.9 seconds following a LOCA, and valves RHR-MO-34A&B will close prior to the recirculation discharge valves. The safety evaluation for the modification also confirmed that with the longer stroke time the valve would successfully close prior to the start of LPCI injection. The timing requirement for the RHR system test return line isolation valves has been deleted from the USAR. This change was initiated by licensing change request (LCR) 94-0049 submitted on December 5,1994, which cited condition report CR 94-0297 as a basis. CR 94-0297 states that, if initially open, valves RHR-MO-34A&L' close automatically in response to a LPCI signal arid a closure time of 90 seconds would be acceptable based on a standard valve specificatior,.

Section 4.2.7.5 of GE Specification 22A1472, Revision 0, issued on May 20,1969, which

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specified that the closing speeds of the valves in the system test lines need not be greater than the manufacturers standard speed, was cited as a basis. The specification further states that this shall be based on the fact that the emergency core cooling system (ECCS) is not designed to recover from secondary modes of operation, such as testing, because the period of time that the ECCS is in these modes of operation is so short that the effects on overall reliability is insignificant. The surveillance procedure 6.1 RHR.201 "RHR Power Operated Valve Operability Test-Division I," specified an operability limit of 45 seconds for valve RHR-MO-34A.

The team noted that in addition to stating that the 90-second standard closure time in the valve specification was acceptable for valves RHR-MO 34A&B, CR 94-0297 stated that plant safety analysis for a LOCA demonstrated acceptable performance without LPCI operation for justifying a closure time of 90 seconds for torus cooling outboard valves RHR-MO-39A&B. These statements conflict with the requirement for the valves to close prior to start of LPCI injection and with the requirement that LPCI and core spray systems are required to provide reactor core cooling, following some accident scenarios. The team requested the 10 CFR 50.59 safety evaluation for LCR 94-0049 which deleted timing requirements for RHR test line isolation va!ves, The licensee indicated that a 10 CFR 50.59 evaluation for the USAR change had not been completed. This is documented in PIR 2-01693 dated December 2,1996. However, the safety evaluation has still not been completed for USAR changes associated with LCR 94-0049. (URI 50-298/97-201-09) RHR System - Steam Condensing Mode of Operation The team noted that PIR No. 2 01582 dated July 24,1996 indicated that tM motors and operators for outboard primary containment isolation valves (PCIV) RHR-MOV-M0166A/B at torus penetration X-214 are classified as non-essential. The MOVs are used to vent noncondensable gases from the RHR heat exchanger during the steam condensing mode of operation, and were de-energized in the closed position in July 1996. Valves RHR-MOV-MO166A/B are powered from the same source as the inboard containment isolation valves and are manually controlled from the control room.

The condition evaluation for this PIR contained in CAQ 96-0634 indicated that torus penetration X-214 was evaluated as a Class B penetration, and required two diversely powered isolation valves located on the line outside primary containment (PC) that close automatically on a containment isolation signal. The apparent root cause of the design deficiency was identified as an original plant design feature which did not consider the PC isolation requirements during the design development. In particular, the requirement for diverse pi ver sources for containment isolation valves in the same line was overlooked.

The licensee determined in CAQ 96-0634 dated August 6,1996, that this condition was not reportable and indicated that the valves are remote manual, not automatic PCIVs and therefore diversity of power supplies was unnecessary to preclude a single active failure since the penetration was isolated when PC integrity was required. Section 2.1, " Mitigating Factors of Condition Evaluation for CAQ 96-0634," states that the steam condensing mode is placed in service when the condenser is unavailable and the MSIVs are closed. The licensee concluded that since the condenser is unavailable and the MSIVs are closed, the plant is already in an event, and to consider another event such as a LOCA which requires containment isolation is

_ _ _ . _______ _-______ _ _ _ _ __

beyond the design basis and both valves on the same line would never be open when containment isolation is required. However, the team noted that in Section 1.4 of GE specification 22A1472, " Residual Heat Removal System (With Steam Condensing)," Revision 0, it is stated that during reactor core isolation cooling (RCIC) system operation, the RHR heat exchangers shall be used to condense reac'or steam and to cool the suppression pool, and that the pool temperature shall be maintained at a value such that in the event of a design basis accident the temperature will not exceed 176F when reactor pressure is above 135 psi Section 4.1.4.2 of the specification also states that incorporation of this mode of operation shall not affect LPCI initiation or operatio The licensee's evaluation in CAQ 96-0634 credited that the RHR steam condensing mode had never been placed in operation at CNS. However, the team noted that for about 23 years the required equipment was operational and procedures had been in place to support operation in the steam condensing mode. Procedural guidance for this mode of operation was deleted in May 1997, and the associated equipment was abandcoed in plac *

The team identified that although the plant was not operated in the steam condensing mode, the inaaequate design of power sources to the containment isolation valves should have been reported. The licensee further reviewed CAO 96-0634, determined that the reportability analysis for CAQ 96-0634 incorrectly concluded that the lack of power supply diversity for primary containment isolation valves RHR-MOV-MO166A(B) and RHR-MOV-M0167A(B) was not reportable, and issued LER 97-017, dated December 31,1997. in accordance with 10 CFR 50.73. (URI 50-298/97 201-10) Documentation Discrepancies l The team identified the following discrepancies in the reviewed documents:

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Design Criteria Document DCD-13. " Residual Heat Removal System," Appendix M, System Design Basis Requirements Matrix, items 27,29, 30,33, and 35, contained requirements that are based on the RHR loop selection logic and on Section 3.3 of NEDO 10139, " Compliance of Protection Systems to Industry Criteria," dated June 197 Also, it is stated in Appendix M that the LPCI ar.d core spray (CS) systems are redundant. These are inconsistent with TS Bases 3.5, which describes both core spray and LPCI as two distinct sub-systems which work in combination to provide core coolin The loop selection logic was eliminated by modification DC 76-2 completed in 1977. The licensee issued PIR No. 2-19695 dated October 31,1997 to document that 10 CFR 50 Appendix K was the current licensing basis and that NEDO-10139 should not be referenced as a basis for the current system desig *

Training lesson, " Residual Heat Removal \COR002-23-02," Revision 12, incorrectly states that a minimum of three RHR pumps are required for increasing the reactor vessel water levet after a design basis LOCA. As stated earlier, the core spray pump is required to operate in conjunction with the RHR pumps to perform the core reflood functio *

Design criteria document for the RHR system DCD-13, Section 5.2.2 states that the ccadensata storage tank (CST) and transfer system were not needed to supply water to

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the RHR syt.em for any safety related function. However, USAR Section VI-4.4, TS 3.5.F.5.c, and TS 3.10.F require a certain minimum water storage in the CST and alignment of LPCl or core spray pump suction to the CST to provide reactor core cooling when certain operations are performed with the suppression pool drained. The licensee issued PIR 219715 to resolve this discrepanc E1.2. Conclusions The team concluded that the RHR system was capable of performing its safety functioris assuming a loss of offsite powa and a single active failure. The team identified a concern regarding fbw instrument uncertainties not being considered in the RHR pump surveillance test acceptance criteria, which could result in actual pump flow that is less than the salue assumed in l plant safety analyses. Manufacturer'a recommendations for RHR pump minimum flow were not l

properly reflected in plant operating procedures, and pump-to-pump interactios:s based on allowed pump degradation had not been evaluated. The team noted deficiencies in l performance monitoring of RHR hest exchangers. The team identified that an LCO was not l entered when an RHR subsystem was operating in the SPC mode and that the operating time in

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the SPC mode was not administratively controlled, in recognition of single failure vulnerabilities of the systi.m when aligned for suppression pool cooling. The issues regarding SPC mode of l operation have been referred to the NRR staff for evaluation. The licensee issued an LER to l

' document the inadequate original design of the power sources to the RHR heat excha'1ger vent valve E1. Electrical Design Review I

E i.2. Scope of Review For ti;e electrical design review, the team focused on the critical power supplies to the RHR and

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REC systems. The areas examined, such as emergency diesel generators,4160 Vac (Emergency Service) Swituhgear,480 Vac (Emergency Service) Load Centers,250 Vdc power batteries,125 Vdc control batteries and battery chargers were common to both system Therefore, a separate discussion of the inspection of electrical aspects of the REC system is not included in the repor The team reviewed USAR Chapter Vill, TS Section 3/4.9, design criteria documents, electricai calculations and drawings, surveillance procedures and test data, design modification packages, problem identification reports, and other miscellaneous electrical design document The team assessed portions, si the following that are applicable to the RHR and REC systems:

critical power systems including switchgears, transformers, motors, raceways, panels, cables; cable separation; voltage drops and degraded voltages; protective device setpoints; field instaHations; modifications; drawings and record changes; and battery surveillance and test dat _ _ _ - - - _ _ _

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E1.2.2 2 Findings The team reviewed the emergency diesel generator (EDG) design criteria document, capacity calculations, elementary diagrams, protective relay setpoints, and electrical equipment. The calculations showed that EDG loading was properly estimated and the EDGs had adequate capacity margin. The electricalloads including ECCS loads were sequenced onto the EDG within the required time, and the drop in output voltage and frequency and their recovery were acceptabl The team reviewed the design criteria document for the AC electrical distribution system, drawings, protective relay setpoints and coordination calculations, and other aspects of the

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4160-volt and 480-volt AC systems with emphasis on undervoltage setpoints. These setpoints were adequate for proper operation of the electricalloads and for shedding loads in the event of a loss of off site power, except as noted belo The team reviewed the design criteria document for the DC electrical distribution system, capacity calculations, drawings, and surveillance test data. The team identified several concerns regarding battery operability and capacity margin, as discussed below.

l Undervoltage Relay Setpoint Technical Specification l'able 3.2.0, page 3, specifies e second level undervoltage relay setting limit of 3880 +/ 52 volts for the cmergency buses. Calculation NEDC 88-0868,"Setpoint Determination of Second Level Undervolta0e Relays," Revision 7, specifies an analyticallimit of 3847 volts for the degraded voltage, which is above the lower TS limit of 3828 volts. The current TS allows second level undervoltage relay settings to be less than the analyticallimit for the j emergency bus degraded voltage. Therefore, it is possible for a relay to drift below the analytical limit and still be considered operable by current TS limits. The design basis in the calculation was not correctly translated into the technical specifications. (URI 50 289/97 201 11)

The team reviewed the undervoltage relay test and calibration procedures 6.1EE.303 and 6.2EE.303 and determined uiat the lower calibration limit is sat at 3866 volts, which was above the analyticallimit of 3847 volts and was acceptabl The licensee issued PIR No. 219696 to resolve the discrepancy and initiated an instant procedure change for procedures 6.1EE.303 and 6.2EE.303 for undervoltage relay testing and calibration to identify 3847 volts as the lower an>lytical limit and the threshold at which the buses should be declared inoperable in lieu of the lower TS limit of 3828 volts. Additionally the licensee also issued Technical Specification Interpretation (TSI) Request No.97-016 to revise the TS setting limit for the emergency bus undervoltage relays to 3880 +52/ 33 volt V Battery Load Profile The team followed up on licensee actions to resolve operability concerns on the 125 Vdc battery load profile ioentified during a previous NRC inspection (see NRC inspection report 50-298/97-18). The team reviewed the licensee's operability assessment that concluded that the battery

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had adequate capacity to perform its intended function and meet the load profile except for the last minute of the revised station blackout (SBO) load profile. The service test performed on 125V battery 1B in 1995 did not envelop the last minute of the revised SBO load profile. The test service load was 165A and the load according to the revised load profile was 186A. The team accepted the licensee's justification for the battery's capability to meet the loading during the last minute, because the required battery voltage taking into consideration the revised load profile was less than the available battery minimum voltage. The licensee issued SCAQ 971425 to capture all discrepancies identifited in the previous inspection. This issue will be followed up as 3 part of the open items in inspection report 50 298/971 Battery Surveillance Test Data l

The team identified the following weaknesses so the battery test procedures:

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The team noted that the battery discharge tests for 125V and 250V batteries performed in accordancs with procedures 6.EE.07 and 6.EE.08 incorrectly calculated battery l :apacity. The calculated capacity included a 2 minute time interval with a discharge

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current of 100 amps which was less than the required value of 225 amps. The impact of this error on battery capacity was not significant. The licensee init!sted PIR No. 219733 to address this discrepanc .

The service test for 250V batteries 1 A and 1B were performed during October 1995 in accordance with procedure 6.EE.605. The load profile for 250V battery 1 A was 500 amps during 0 to 8 seconds and 280 amps during 8 to 60 seconds. The load profile for 250V t'attery 1B was 640 amps during 0 to 20 seconds and 900 amps during 180 to 183 seconds. The team could not verify that the specified Icad profile was applied during the test, because the test program did not record data for such short time intervals. The licensee stated that the test engineer and the quality control personnel witnessed the tests and signed the test procedure documents indicating that the tests (including the application of the load profile) were performed in accordance with the procedure requirements. The team had no further questions on the test result Battery Charger Maintenance Procedure During walkdown the team noted that 250 Vdc charger 1 A was tagged out and spare charger 1C was in service. The licensee indicated that charger 1 A had tripped on October 27,1997 due to DC overvoltage, because the time delay for the high voltage shutdown relay K3 was not set properly. The relay setting data sheet E-150 specified the setting, but the associated maintenance procedure MP 7.3.1.6, * Protection Relay Testing and Calibration Manual," did not specify time delay adjustment requirements. The licensee issued PIR No. 2-19138 datad October 30,1997 to revise procedure MP 7.3.1.6 wi.h additional instructions and data points to set the K3 time delay rela E1.2. Conclusions The team concluded that the critical power supplies for the RHR and REC systems were capable of performing the safety functions required by their design bases. Calculations for

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protective relay setpoints, electrical coordination, voltage drops, EDG loading, battery loading and others were conservative in approach, used appropriate methodology, produced reasonable results, and were consistent with the design bases. Some weaknesses in surveil!ance test procederes and test records and in battery charger maintenance procedures were identifie The adequacy of the 125Vdc profile calculation is an unresolved item that will be followed up as part of IR 50 298/971 E1. Instrumentation and Control Design Review E1.2.? ! Scope of Review l

The scope of the instrumentation and control desi0n assessment consisted of a review of RHR design criteria documents, USAR, technical specifications, P&lDs, loop diagrams, schematics / control logic diagrams, setpoint calculations and loop uncertainty analysis, setpoint data sheets, surveillance data sheets, design change packages and surveillance and operating -

procedures. The sistem components, instrumentation and controls, main control room, auxiliary relay and cable sprei. ding rooms and alternate shutdown control room were walked dow E1.2. Findings The instrumentation and controls of the RHR system were reviewed to verify their ability to perform the safety functions of the system. It was concluded that the design was adequate to support the system functions. The review included the system controllogic for startup control, injection flow permissives, RHR minimum flow protection, ADG initiation permissives for LPCI pumps, heat exchanger bypass permissives, protection from water hammer, and load sequencing onto the safety related buses. Several setpoints were reviewed to verify whether sufficient margins wem prn,lded to ensure safe operation of the RHR systam without exceeding analyticallimits. These included the high drywell pressure, low reactor vessellevel, low pressure piping protection from high reactor pressures (i ;ection and suction lines), pump minimum flow protection, ADS initiation permissives, heat exchanger bypass control, and REC to RHR differentml pressure control. The RHR system was reviewed for Appendix R provisions for auxiliary relay room and control room fire scenarios. Provisions for alternate shutdown were adquate. The control room instrumentation was reviewed and was considered sufficient to support operations. Instrument installations for field instrumentation were reviewed and determined to be in accordance with the desig Instrument Uncertainties Previous NRC inspections (Inspection Reports IR 96 26, IR 96 31, and IR 97-07) had identified concerns regarding inadequate concideration of instrument uncertainties. During this inspection, the licensee noted that possible deficiencies existed in accounting for instrument uncertainties in determining compliance with technical specificatiora requirements. This was documented by the licensee in PIR 213393, dated October 20,1997. The licensee investigated these problems in parallel with this inspection, and issued report SCAQ 97-1407 on Cecember 4,1997. In this report the licensee acknowledged that instrument uncertainties had not been taken into account when establishing the acceptance criteria for surveillance tests. During this inspection the team identified that instrument uncertairity had not been considered for RHR flow recorder FR_143_

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and SW temperature indicator Ml TR 3020 (see sections E1.2.1.2.a and E1.3.1.1.a). (IFl 50-298/97 201 12) RHR Heat Exchanger Bypass Technical Specification Table 3.2.8 lists the setting limits for the RHR heat exchanger bypass tirna delay relays RHR REL K93A&B as 2 min +/ 0.2 min. These time delay relays prevent manual closure of bypass valves RHR MOV-66A&B during a LOCA until a specified amount of time had passed after LPCIinnlation signal. Calculation NEDC 92 050BH, *RHR REL K93A&B Setpoint Calculations," Revision 0, determined the setpoint uncertainty to be +/- O sec. In the conclusion section, the maximum allowable stroke time for the bypass valve opening was established as 100 seconds as a result of this calculation. T he team pointed out tnat the valve stroke time did not depend on the time delay. The licensee agreed with the team, but could not provide a basis for the 2 min time delay setpoint. The licensee indicated that the TS would be revised to delete the setting limits for these relays. (IFl 50 298/97 201 13)

E 1.2. Conclusions The team concluded that the instrumentation and control design for the RHR system was adequate. Instrument setpoints for automat'c actuations had adequate margins, and TS limits were met. Instrument uncertainties were not considered for instruments used for surveillance tests, for plant monitoring, or for emergency operating procedure criteria. The setpoint calculation did not properly evaluate the technical specification timing requirement for the RHR heat exchanger bypass valve time delay and the analyticallimit information was not availabl E1. System Interfaces E1.2. Scope of Review The team selected the condensate system, RHR service water (RkR$W) system, and radioactive equipment drainage system, that interface with the RHR system and verified that the interfacing system design information for supporting the function of the RHR system was appropriately considered. The team examined inrtallation of the interfaces during the RHR system walkdown E1.2. Findings Condensate Storage Tank Technical Specification Requirements USAR Section VI-4.4 states that refueling operations can be conducted with '.:.e suppression pool drained, provided an operable CS or LPCI subsystem is aligned to take suction on CST 1A, which must contain at least 150,000 gallons of water. TS 3.5.F.5.C reqv;res that 230,000 gallons be available in the CST with one control rod drive housing open while the suppression pool chamber is completely drained. "3 3.10.F requires that 150,000 gallons be available in the CST when suppression pool chamber is completely drained. TS Br.ses 3.5 states that, under worst-case leak conditions, water inventory in the reactor well, spent fuel pool, and condensat6 storage tank is required to provide approximately 60 minutes of core cooling and sufficient water

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inventory to permit the water which has drained from the ecLet to fill the torus to a level above the CS and LPCI suction strainer No supporting calculations were available to confirm that the 150,000 gallon and 230,000 gallon requirements will satisfy the TS bases. The licensee informally estimated a volume of about 169,000 gallons would have i Mn required to flood the torus with the old RHR suction strainers and about 281,000 gallons w.'ai the new suction strainer design. The volume of water trapped on the containment floor and the permissible spent fuel pool drawdown would require further evaluation. The licensee indicated that the 150,000 gallon requirement was from NUREG-0123,

• Standard Technical Specifications for GE Boiling Water Reactors," and was consistent with NUREG 1433, ' Standard Technical Specifications for General Electric Plants, BWR/4." (IFl 50-298/97 201 14)

Notwithstanding the lack of a defined basis for the 230,000 gallon requirement, the licensee indicated that in the proposed CNS Improved Technical Specifications (ITS) the 230,000 gallon requirement had been changed to 150,000 gallons consistent with NUREG 1433. The licensee also indicated that similar questions regarding the CST volume requirements were received from the NRC in the letter requesting additional information on the IT ECCS Leakage into Interfacing Systems Valves RHR V 98 and RHR V 99 provide isolation between the RHR system and the CST as depicted on USAR Figure IV-8 2, Sheets 1 and 2. The inservice testing (IST) basis document indicates tiiat the normally locked closed valves RHR V 98 and 99 have a passive safety function in the closed position to prevent diversion of suppression pool water, However, the IbT basis document identifies no testing requirements for these valves. The team noted there might be instances where, due to containment pressure increase as a result of a LOCA, pressure would be higher on the RHR side of the normally closed valves with the potential for leakage of post accident suppression pool water to the condensate syste Check valves RHR CV-19 and RHR CV 25 provide the interface between the RHR system and the pressure maintenance system as depicted on USAR Figure IV 8 2, Sheets 1 and 2. The IST basis document indicates that these check valves have an active safety function in the closed position to prevent diversion of RHR/LPCI flow. The check valves are IST leak tested in accordance with procedure G.1RHR.101 and Procedure 6.2RHR.101 with a leakage rate test acceptance criteria up to 0.75 gpm per valve. The licensee identified these valves in the evaluation of Information Notice 91-56, " Potential Radioactive Leakage to Tanh Vented to :

Atmosphere,' and concluded that the probability of a significant amount of contaminated torus coolant reaching the cendensate system was very low because of the path it must take through the piping upstream of the interface boundary. The team noted that the information notice indicated that a leakage of 0.1 gpm from similar sources in some cases had resulted in estimated doses to control room personnel exceeding the limit The licensee issued PIR 219728 to document this issue and stated that the previous evaluation might not have been comprehensive. (IFl 50 298/97 201 15)

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-_ ______ _____ ____-___ _ _ _ ECCS Leakage into Reactor Building Sumpo USAR Section X 14.3.3 states that during a design basis LOCA, ECCS component leakage is routed directly or indirectly by the radioactive drainage system to the reactor building sump The reactor building floor drain sumps will operate ,*or the duration of the LOCA to maintain sump level, and pump collected drains from ECCS component leakage and other reactor building sources. The sump pumps are powered by emergency power sources and are available during post accident conditions. Alarm procedure 2.3.2.20 indicates that the sump pumps start automatically on increase in sump level, and directs operators to enter EOPs and to manually start any sump pump that is not operating. With area water level above the maximum normal operating level as a entry condition, EOP flowchart SA directs the operator to operate available sump pumps to restore and maintain the water level below its maxirnum normal operating level. The licensee indicated the sumps would be iso!ated by the operator (operator action 4.5.1 of emergency procedure 5.3.1)in response to a high radiation alarm. The team noted that emergency procedure 5.3.1 instructions conflict with procedure 2.3.2.20 for sump

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level alarms, and with emergency procedure 5.8 flowchart SA .

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Tne existing ECCS leakage limit in procedure 13.1, 'ECCS Leakage Evaluation," is 602

) cc/ minute. This leakage could cause sump levels to rise, initiate automatic actuation of the sump pumps, and discharge sump water outside the secondary containment. If actuation were not automatic, alarm response and emergency procedures direct the operator to operate available sump pumps to restore and maintain the level below its maximum normal operating level. The licensee confirmed that such discharges from the pumps had not been considered in the offsite and control room dose calculations. This is a weakness in the design, evaluation and operation of the radioactive floor drain system and in toe offsite and control room dose calculations. (URI 50 298/97-201 16)

l In response to the team's questions, the licensee issued PIR No. 2 20905 which stated that the description within USAR Section X 14.3.3 was contrary to CNS's original design basis for the sump pumps and the pumps were not relied upon during post-accident conditions as inferred in the current USAR. As a part of the disposition of the PIR, the licensee proposed to reduce the maximum acceptable ECCS leakage rate from 602 cc/ min to 454 cc/ min to limit flooding to the maximum safe flood depths identified in the USAR. Although this change would protect ECCS equipment from flooding, the issue of pumping sump water to radwaste was not resolved, and requires evaluatio Regarding passive failure of en ECCS pump seal, Section 2D of SECY 77-439 stated that the current practice was to assume fluid leakage owing to gross failure of a pump or valve seal, but not pipe breaks, during the long-term cooling mode follow;ng a LOCA. The team questioned how the long-term passive failure of a seal was addressed in the ECCS design and sump pump operating requiremems for CNS. The licensee stated that ECCS pump seal failure was outside the CNS licensing basis as stated in answer to question 10.5b in FSAR amendment 11. This issue has been referred to NP.;l staff for further evaluation. (IFl 50-298/97 201 17)

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_ _ _ _ _ _ _ _ _ _ _ _ _ _ Reactor Building Sump Pump Seismic Qualification USAR Section X 14.3.3 states that the reactor building floor drain sump pumps have been designed to ' withstand a Class I seismic earthquake." The original AEC SER, Section 6.3.1, dated February 14,1973, states that the drainage system is designed to Class I (saismic)

str ndrards. This design basis requirement is confirmed in a Burns and Roe memorandum dated December 17,1970, which states that the sump pumps shall be designed and constructed to operate with seismic forces imposed. The licensee's review of selected procurement documents indicated that no requirements were specified for maintaining the original seismic qualification of the pumps. The licensee initiated PIR No. 219722 to address this concern. The licensee's review of sump pump maintenance history determined that the pumps had been overhauled but

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not totally replaced. Engineering Evaluation EE 97 327 dated November 21,1997 subsequently concluded that the replacement of component parts would not have a detrimental effect on seismic qualification of the pumps. The PIR also notes that seismic qualification of the sump pumps may have been overlooked because the pumps are classified as nonessential in the licensee's e :uipment database. The seismic design bases for the sump pumps had not been translated into the equipment data base to ensure that their seismic qualification is maintaine (URI 50 298/97 201 18) RHRSW Crosstie USAR Sections IV 8.5.1, VI 5.2.0, and X-8.2.5 state that a crosstie is provided from the RHRSW system to the RHR system (Loop A only) to provide emergency post-LOCA core and/or containment flooding in the unlikely event of loss of all ECCS functions. The original AEC SER, Section 9.3.4, dated February 14,1973 also mentions this capability. The crosstle is shown on I

the RHR system flow diagram No. 2040, Sheet 1, Revision N68, and on the service water system flow diagram No. 2006, Sheet 4 Revision N32. Instructions for initiating this beyond-design-basis emergency cooling function are outlined in emergency operating procedure 5.8.3,

'RPV Flooding Systems,' Revision 4C1. The team requested a copy of the hydraulic calculation or other documentation that demonstrated that the RHRSW system was capable of performing this function. The licensee could not locate such documentation, and initiated PIR No. 219698 to document this deficiency. As recommended in the PIR, preparation of a new calculation (NEDC 97 086) was initiated. This calculation was not available for review by the team prior to completion of the inspection. (IFl 50 298/97 201-19) RHRSW Booster Pump Room Cooling Licensing Change Request 93-0010 dated February 5,1993, initiated a revision of USAR Figure X-10-2 to specify a RHRSW booster pump room temperature limit of 131'F during abnormal conditions. This change was required because the room has no safety related ventilation system and the fan coil unit (FCU) p.ovided for the room is designed as non-essential equipment. The 10 CFR 50.59 reportability analysis dated October 29,1992, in sk prt of the USAR change concluded that there was no unreviewed safety question due to this change because there were no physical changes to the plan _

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Calculation NEDC 92 063, * Maximum SWBP Temperatures with No Cooling from Control building HVAC,' estimated that with natural ventilation the room temperature will reach 13CTF with one RHR booster pump running and all other major heat loads, such as air compressors, dryers, and lights, deenergized. Step 4.10 of Abnormal Procedure 2.4.8.4.9, ' Control Building Temperature Above or Below Temperature Limits," dated October 20,1997, requires the operator to open the room C 903 equipment hatch to the basement, open certain doors, and secure RHRSW pumps per procedure 2.2.70. This procedure also requires, .?.4 operator to secure instrument air compressors and dryers so that RHRSW booster pump room temperature does not exceed 130"F with one RHRSW booster pump or one air compressor runnin However, procedure 2.2.70, *RHR Service Water Booster Pump System," Revision 37, allows operation of both RHRSW booster pumps when required by emergency operating procedure Also, emergency procedure 5.2.5, * Loss of Normal AC Power - Use of Emergency AC Power,"

Revision 30, dated October 11,1997 specifically directs operators to start air compressors and air dryers. Furthermore, if LPCIis required concurrent with suppress'on pool cooling, RHR fiow will be established through two heat exchangers requiring two RHRSW pump operation. Also, operation of two RHRSW booster pumps is preferred for mitigation of the accident. The EOP flowcharts (Primary Containment Control) specifically direct the operators to use "all available suppression pool cooling." However, the plant's design basis requires only one RHRSW Booster l pump for accident mitigatio The 10 CFR 50.59 safety evaluation performed for the USAR change did not address the following:

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Assessment of the radiation dose to operator (s) while establishing natural ventilation in the RHRSW booster pump room during an acciden .

Loss of normal power to the overhead crane which was required to lift the hatch cover Emergency power is not supplied to the cran .

Introduction of potentially contaminated turbine building air into the control building during all accident scenarios requiring the RHRSW booster pumps. Calcu!Ption 92-063 estimates that an air flow rate of 3720 CFM from the turbine building is required if only one RHRSW bester pump is operating and if all other equipment are deenergized. If two booster pumps are operated, an air flow rate of 8193 CFM will be require .

The ability in provide air at a temperature not greater than 100 F from the turbine building to the RHRSW booster pump roo .

Not operating the instrument air system, which is being relied upon in operation and accident mitigation procedure .

Conflict between emergency operating procedures which require operating all available suppression pool cooling as well as starting of air compressors and air dryers, and the abnormal procedure which requires maintaining room temperature below limit As a result of these concerns, the licensee revised the affected 10 CFR 50.59 evaluation and

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submitted it for review by the Station Operations Review Committee (SORC). In addition, the licensee revised the procedure 2.4.8.4.9 to secure all equipment in the area except for one RHRSW booster pump. The licensee stated that a chain fall would be provided for hatch cover removal. The change to the USAR had not been adequately evaluated in accordance with 10 CFR 50.59 to conclude that the consequences of an accident or malfunction of equipment previously evaluated in the safety analysis report had not increased. (URI 50 298/97 20120) '

E1.2. Conclusions The design of the RHR system interfaces was generally satisfactory and supported performance of the RHR system safety functions; however, the team identified several concems. There was no documented basis for the TS limits on minimum volume in CST 1 A to provide an alternate suction source for the LPCI pumps. Post accident ECCS leakage through valves and post-accident ECCS room sump pump discharges were not included as source terms in offsite and control room dose calculations. Seismic qualification requirements of the reactor building floor drain sump pumps had not been specified the in the equirment database. The licenses also had not properly evaluated design and licensing basis changes associated with increasing the maximum allowable post accident temperature in the RHRSW booster pump roorr. The licensee initiated actions to resolve these issues through the problem reporting proces E1. System Walkdown The team puformed walkdowns of selected portions of the RHR system. Piping and mechanical components, piping interfaces with the condensate system and the RHRSW system, and installation of instrumentation and electrical components were examined to verify consistency with plant drawings. The team also examined the control room instrumentation for monitoring RHR system operation. The material condition of the system and general housekeeping appeared to be good, and no discrepancies or deficient conditions were observe E1. Updated Safety Analysis Report / Technical Specifications The team reviewed the applicable USAR and TS sections for the RHR system, interfacing systems, and the associated electrical and instrumentation and controls sections, to verify consistency between the USAR and TS descriptions, TS requirements, and design documentation. The following discrepancies were identified:

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TS Bases Section 3.5.6 states that if a water hammer were to occur at the time at which the RHR system was required, the system would still perform its design functions. This implies that the RHR/LPCI piping is designed to withstand water hammer load However, a procedure change request for procedure 2.4.2.4.1, Revision 16, "RHR Loss of Shutdown Cooling," and the referenced document CAQ 96 0748 noted that the RHR system piping was not analyzed for water hammer loads. The licensee initiated PIR N to address this discrepancy. The PIR noted that the inaccurate statement does not exist in the CNS Improved Technical Specifications (ITS), which are currently being reviewed by the NRC, and the affected RHR loop would be declared inoperable upon loss of pressure maintenance. The licensee has also initiated a licensing change

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request (LCR 97-008) to process a correction to the current TS Base .

USAR Figures IV 81 and VI 4 3 state in Note 3 that the minimum available RHR pump NPSH in Mode C2 (suppression pool cooling), Mode F (shutdown cooling), and Mode G (LPCI runout conditions) must be 4 ft. Greater than the pump requirements. RHR pump NPSH calculations reviewed by the team, as well as plant modification MP C6-132 for suction strainer replacement did not appear to reference or implement this requiremen The licensee initiated PIR No. 219688 to address this discrepancy. The licensee indicated that the note will be modified or deleted since the 4 ft margin was considered an original construction and equipment margin rather than a design requiremen .

USAR Section VI 4.4 incorrectly identifies that LPCI operation consists of using at least l three of the four RHR pumps taking suction from the suppression poo .

USAR Section Vll 4.5.5.3 incorrectly identifies that three of the four RHR pumps are required to proviel adequate flow to restore reactor vessel water level for the design

, basis LOCA.

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USAR Section IV 12.0 references FSAR Amendments ?0 and 25 for the analysis of high energy line breaks (HELBs). The team's review of the HELB analyses presented in these FSAR amendmants indicated that they did not reflect the current plant design, in that references are made to design features that were changed in past design modifications (e.g., DC 76-2). The licensee recognized that the HELB analyses required upgrading, and stated that existing corrective action documents and USAR update project open items should addr:ss these issue .

USAR Section VI, Table VI 31, states in a footnote that the most limiting single failure in the ECCS is a LDCI discharge pipe break. The team's leview of the design basis LOCA analysis results presented in USAR Section VI 5.0 indicated that a LPCI discharge pipe break was not one of the analyzed single failures. The licensee initiated PIR No. 2-18542 to address this discrepanc .

USAR Section Vil-4.5,4.4 states that the RHR and core spray systems are kept full by a header from the reactor building auxiliary condensate booster pump. This is inconsistent with descriptions contained in the RHR system design criteria document DCD-13, which states that the auxiliary condensate pump is a backup to the condensate system, which is the normal pressure maintenance source. The licensee initiated PIR No. 2-19702 to document this discrepanc .

USAR Section V:l, Figures Vil 4-7a, Vil-4 7biand Vil 4 7c are the functional control diagrams (FCD) for the RHR system. USAR Figure Vil 4 7a, Note 6 states that motive power for System I pumps (A and C) shall originate from a different AC bus than the pumps of System 11 (B and D). This note does not reflect deletion of the LPCIloop select logic that was incorporated vis modification DC 76-2. In the current design, RHR pumps A and B (Division 1) are powered from a different source than pumps C and D (Division ll). The licensee initiated PIR No. 2-19703 to address this discrepanc .

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USAR Section 1.7.1 states that a compliance comparist . . .. RPS and ECCS design with each design requirement of IEEE 279 is given in NEDO 10139. NEDO 10139 addresses the LPCI design concept in effect prior to implementation of design change 76-2. CNS issued USAR Rebaselining Project Item 97-432 to address this discrepanc .

Engineering Evaluation 97151 documents that a USAR change request was made to eliminate the RHR steam condensing mode at CNS. Components associated with the steam condensing mode have been operationally abandoned in place by turning breakers off, isolating instrument air supplies, and closing manual valves. Station procedures were modified to leave components in a safe position and eliminate their cperation. USAR changes, in large part, simply deleted discussion of the RHR steam condenuing mode. Figures were generally annotated to indicate the RHR steam l condent ing mode we ' no longer an operational mode. Considering the RHR steam l condensing mode equipment is physically installed in the plant, and is abandoned only l through administrative controls, the team considered that it would be more representative i

of the current plant configuration to incorporate those administrative restrictions within the USA .

USAR section X 6.5.3 includes calculations to show that the maximum time allowable for the area coolers in the HPCI room to start removing heat from the room as 20.7 minute This calculation was based on an initial room temperature of 104'F, but records showed that during normal operation the HPCI room temperature was often as high as 120" These temperatures could be three or more degrees higher considering instrument uncertainties. In additiori, the maximum allowable FCU start time was based on the room heating up to 148"F. However, the equipment quahfication data package for the HPCI turbine controls located in the HPCI room specifies an accident environment temperature of 135"F. In response to the team's questions, the licensee initiated a new calculation and a revision to an existing calculation to demonstrate that there was sufficient time to establish flow to the FCUs in the RHR and core spray pump quads before maximum allowable ambient temperatures were reache .

USAR Section X 6.5.2 states that at a design inlet water temperature of 95'F the design heat transfer for each REC heat exchanger is 33x10' Btu /hr. However, the specification data sheet fcr the heat exchanger specifies a SW temperature of 85'F for this heat removal capacity. At SW temperature of 90 F, the heat removal capacity of the heat exchanger would be lower. The heat removal capacity value stated in the USAR is incorrect for the current design tasis SW temperatur .

The RHR pump motor specification (GE document No. 21 A5790AM, Revision 7, *RHR Pump Data Sheet," dated December 31,1969), states that the maximum ambient temperature for an RHR pump is 148 F. However, the licensee requalified the pump motors to an ambient temperature of 155'F as documented in equipment qualification design input EQDIM40 dated May 28,199 '

The above examples indicate thnt the USAR had not been updated to include the latest material developed and the effects of all changes made to the facility or precedures, as required by 10 CFR 50.71(e). (URI 50 298/97 20121)

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E1.3 Reactor Equipment Cooling System E1. Mechanical Design Review E1.3. Scope of Review The mechanical design review of the reactor equipment cooling (REC) system included a design and licensing documentation review, system walkdowns, and discussion with system and design engineers. The team reviewed applicable portions of the USAR and TS, flow diagrams, physical drawings, vendor drawings, equipment specifications, the system DCD, calculations, operating and surycillance procedures, PiRs and CAQs. The scope of the review included the appropriateness of the design, bounding design conditions, validity of design assumptions, verification of design input, verification of heat loads and capability of heat exchangers, single failure vulnerability of components, and adequacy of system testin During the inspection, the team identified that although the system is electrically separated into two divisions, it is not separated mechanically. The redundancy is provided by means of aligning service water (SW) flow to essential portions of the REC system. Therefore, the team included review of some of those portions of the SW system that perform the ossential functions l of the REC syste Ei3. Findings SW Design Temperature According to design criteria document DCD 3 for the service water system, the current design basis temperature for service water is 90'F. SW temperature is indicated by Ml TR 3020 in the control room and is logged in procedure 6. LOG.601, " Daily Surveillance Log (Technical Specifications)." instrument loop uncertainties were not taken into account when the maximum allowable service water temperature was established. The team also noted that instrument uncertainties were not considered in procedures and thermal performance of heat exchangers cooled by SW. Discussions with operators indicated that they would have allowed SW temperature to rise up to 90'F (as read in the control room) while the actual temperature could have been higher. The licensee's preliminary estimate of the maximum value was 91.10 F, without taking into account drift, temperature effects, calibration effects and reading error. The actual maximum SW temperature is critical for the performance of safety-related functions of the REC system. On November 4,1997 the licensee issued night order No.97-030 to change the maximum SW temperature from 96F to 87 F in procedure 6. LOG.601. In addition, more restrictive values were specified in the night order for other parameters that did not consider instrument uncertainties, after these parameters were identified by the NRC resident inspector The licensee issued PIR Nos. 2 25013 and 2-19712 to address this issue. Because the SW temperature is nn ikely to reach the maximum design value before the summer of 1998, the team did not have any immediate concer.1s. The SW system design basis was not appropriately translated into procedures as required by 10 CFR 50, Appendix B, Criterion Ill, " Design Control."

(URI 50 298/97-20122) '

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. . . REC System Water Inventory in response to the team's question regarding adequacy of the surge tank to makeup the REC system leak rate, the licensee stated that the current leak rate was over 200 gallons per day. To determine the source of the leak, the licensee inspected the system for leaks and found that the bulk of the leakage (~600 cc/ min.) was due to continuous flow through the filter domineralizer sampling system. Three manual sample valves (REC-V 728, REC V 733, and REC V 737)

were apparently open since the time the filter demineralizer was installed six years ago. In the event of an accident, the inventury in the REC surge tank would have been depleted in less than l one day resulting in loss of REC, because the non safety related makeup would not be available. The REC system is required to be operable during the long term following an accident. The SW system can back up the REC system via crossties operated from the control l

room, but no credit is taken for this capability in the plant's current licensing basis, except j following a seismic even The licensee issued PIR 219617, isolated the sampling flow on November 4,1997, and found that the system leak rate was reduced to less than 4 gallons per day. This would allow the system to be operable for over 30 days (considering a tank low level volume of 120 gallons).

Procedure 2.5.3.7, * REC Filter Domineralizer Skid," was subsequently revised to change the position of valves REC 728, REC 733, and REC 737 from normally open to normally closed. On November 9,1997, the licensee notified the NRC of this condition as required under 10 CFR 50.72. and issued LER 97-014, dated December 12,1997, in the Design Change DC 90-085,

' REC Finer Domineralizer Skid Addition," and in the associated safety analysis there was no discussion of the requirement to maintain water inventory in the closed REC system or the need I

to revise procedures to keep the sampling system isc,;ated to prevent water inventory loss. The design was not adequately verified or checked, and the design bases for the system were not correctly translated into procedures, as required by 10 CFR 50, Appendix B, Criterion lil, ' Design Control." (URI 50 298/97 20123) RHR Pump Aria Cooling Calculation NEDC 93-093, Revision 0, " Analysis of STP 93 062 Data (RHR Quad Heatup) " and calculation NEDC 93-050, Revision 1, *RHR Quad Temperature," evaluated the test data that measured temperatures in the RHR pump area (also referred to as RHR quads) with one RHR pump running, and concluded that the ambient temperatures without operation of the fan coil unit would be acceptable. However, the team was concerned that a LPCI initiation signal would start both RHR pumps in the room, if emergency power was available. Operation of two RHR pumps with natural circulation in the pump area (assuming failure of the fan coil unit) would result in ambient temperature higher than the 155'F limit for the pump motor On the basis of this calculation, the licensee had processed a request for TS amendment in 1993 to delete explicit operability requirements for the room coolers in the RHR quads as well as those located in the HPCI and RCIC rooms from the TS. This was approved by the NRC in license amendment 16 During the inspection, the licensee also identified this concern with the calculation in problem

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report PIR 2 21090, dated October 29,1997. The licensee issued a night order on October 29,

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1997, to secure one of the RHR pumps in a quad if the fan coil unit in that quad became inoperable. The team was concemed that the design requirements were not translated into procedures or instructions as required by 10 CFR 50, Appendix B, Criterion lil, ' Design Control.'

(URI 50 298/97 20124)

The team questioned whether there were any instances, after license amendment 163, when the RHR quad fan coit units were inoperable and an LCO was not entered. After a preliminary review of plant records, the licensee identified four instances in October 1997 when the fan coil unit was inoperable. At the end of this inspection, the licensee was still evaluating these for reportability. The licensee also issued PIRs 219692,219746, and 2 20198 to address the issues identified by the team, REC System Design TS Bases 3.12 describes the REC system as consisting of two, distinct subsystems, each containing two pumps and one heat exchanger. This is consistent with USAR Section X-6.5.1,

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which states the REC system consists of two subsystems with independent loops for those I components wHch must function during postulated acc; dents and transients. The two independent loops have the capability to be interconnected through crosstles equipped with isolation valves. USAR Section X-6.6 states that two independent closed loops, each with full l heat transfer capability, are provided. USAR Section X-6.8.3, identifies that the system consists l

of two full capacity closed loops with provisions for cross connectio AEC safety evaluation dated February 14,1972, states that the reactor building closed loop cooling water system includes two independent closed loops each containing two pumps and :

one heat exchanger with crossties providing essential cooling services from two essential service headers. As originally submitted, the system could not support safe shutdown following an SSE considering a concurrent single failure of an active component in the Class I (Seismic)

piping system, or safe shutdown considering a single passive failure not concurrent with SSE or DBA. The system was upgraded to meet this requirement through seismic upgrades snd the provision of SWintertie Design change DC 93-57,"SW and REC System Modifications," modified the SW and REC systems to establish two electrically independent trains in each system. The REC system, as noted in DC 93-57, page 8,5 not mechanically redundant and separated because the critical REC loop retum headers are pysically cross connected and the cross-connect valves are required to remain open at all times to allow makeup inventory supply from a single surge tan The DC further identifies that SW REC intertie valves will be reclassified as essential to provide backup to the REC system for cooling criticalloads. The team quer** *d whether the REC system as described in the USAR and in the AEC safety evaluation wn e,asistent with the as-built system, which does not have two mechanically independent loops. This issue was referred to NRR staff for evaluation. (IFl 50 298/97 20125)

, The REC seismic class 11 piping inside the drywell is in close proximity with high energy piping such as, recirculation and RhR piping. In response to the team's questions the licensee stated that the RHR piping intermediate point pipe break stresses do not exceed twice the hot allowable stress (2.0 Ss) specified in USAS B31.1.0-1967, and therefore, no intermediate bieaks

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are postulated. The team pointed out the statement in the AEC safety evaluation Supplement 1, dated July 16,1973, which states that breaks were assumed to occur at all terminal points and at two or more intermediate points in each piping run. The licensee replied that based on an informal review even according to the NUREG 0800 criteria, no intermediate breaks would be postulated. With regard to the rec,iculation piping, the licensee stated that the pipe whip restraints are designed to prevent pipe whip due to a line break from damaging the 8" REC piping. The licensee also stated that jet impingement due to 1 longitudinal recirculation pipe split that could cause damage to the REC piping was highly unliensly.

Damage to REC piping within the drywell could result in the REC system becoming inoperable because of loss of water inventory. Although the SW tie in can be opened from the control room after operator recognition of the event, the use of SW is credited only for a seismic event. This '

issue has also been referred to the NRR staff for evaluation. (IFl 50 298/97 20126) Heat Removal Capability of the REC Heat Exchangers The team identified that calculation 94 021, * REC HX A/B Maximum Allowable Accident Case Fouling / Revision 2, used as inputs, indicated service water temperature without factoring instrument uncertainty and a lower than maximum heat load. The licensee revised the calculation and used additional margins to account for tube plugging and heat load due to two RHR pump operation, and concluded that the heat exchangers could still perform their heat removal functions during an accident. In addition, the acceptance criteria for the heat exchanger fouling factor was reduced to a more restrictive value.

With the non-critical REC loop isolated, REC temperature cannot be monitored from the control room. To assure that REC temperature does not exceed 95'F, the operators would have to establish a flow cf 4CJ gpm, as determined by calculation NEDC 94-021. The team noted that considering instrument uncertainties, and establishing an ind!cated flow of 400 opm os directed by steps 8.8.11.3 and 8.8.12.3 of procedure 2.2.65.1, * REC Operation,* the flow might not be sufficient to maintain REC temperature at or below 950F.

The REC heat exchangers are tested under tha licensee commitment to implement the requirements of GL 8913," Service Water System Problems Affecting Safety-Related Equipment," Although some of the test results were acceptable, data documented in data sheets in procedure 13.15.1, * Reactor Equipment Cooling Heat Exchanger Performance Analysis / for several tests of the REC heat exchangers were inaccurate, and the test results had been analyzed using incorrect data. The team identified that the process instruments used in the tests were apparently not providing correct readings. Specially calibrated test instruments were not used during the test. The team identified the following deficiencies in test data collection and analysis:

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The team's evaluation of the 1996 and 1997 test results for both REC heat exchangers identified a substantial mismatch in heat load between the REC system side and the SW system side of the heat exchanger in some of the test results. For example: a test of heat exchanger B on January 6,1997 showed that the heat removed from REC system was 2.65 times the heat added to SW system; a test of heat exchanger B on July 19, 1996 showed that the heat removed from REC system was 1.38 times the heat added to

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SW system; a test of heat exchanger A on July 24,1996 showed that the heat removed from REC system was 0.59 times the heat added to SW sjstem; and a test of heat exchanger A on September 16,1997 showed that the heat removed from REC was times the heat added to SW system.

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The licensee evaluated test results and calculated negative fouling factors in several cases. For example: evaluation of test results of heat exchanger A tests conducted on February 9,1996, May 3,1996, July 24,1996, and January 6,1997, and heat exchanger B tests on January 29,1996, July 19,1996, and January 6,1997 concluded that the fouiing factors were negative.

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Instrument uncertainties of the instruments used for the tests were not taken into account in determining the heat removal capability of the heat exchangers. This resulted in the evaluation of test results being potentially nonconservative.

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Attachment 3 to Procedure 13.15.1, * Reactor Equipment Cooling Heat Exchanger Performance Analysis,' Revision 8, page 16, included an incorrect formula for log mean temperature difference. The licens% identified this error during the inspection and ,

initiated a procedure revision to correct the discrepancy.

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During the test, the service water flow to the heat exchangers was continuously changing due to modulation of the temperature control valves (SW TCV-451 A/B). The licensee initiated a procedure change to place the valve controller (REC TIC-451 A/B) in manual control prior to the test to avoid fluctuating SW flow, in response to the team's concerns, the licensee revised the acceptance criteria used in the evaluation of test results of the REC heat exchangers. The licensee issued PIR Nos. 24M79, 2-23190,219747, and 2 ,'0640 to document and resolve the above deficiencies. Because the SW temperature is unlikely to increase to the maximum value before the summer of 1998, and because some of the recent tests were acceptable, the team had no immediate concerns regarding the performance of the heat exchangers. Test procedures for the REC heat exchangers were not adequate in assuring that adequate test instrumentation was used and that test results were ovaluated to verify that test requirements were satisfied as required by 10 CFR 50, Aopendix B, Criterion XI, " Test Control.' (URI 50-298/97 20127)

E 1.3. Conclusions The team identified that the two REC loops were not mechanically indep?ndent and referred this issue to the NRR staff for evaluation. Because the maximum allowable SW temperature of 90F did not account for instrument unce enties, the licensee reduced the maximum allowable SW temperature to 87 F. The REC ' stem inventory was being depleted continuously because sampling valves were left open. The licensee closed the valves and revised operating procedures. Because of incorrect calculations, the room coolers in the RHR quads were incorrectly determined to be not required to support RHR pump operation. The team referred to the NRR staff the issue regarding the acceptability of not considering the impact of a high energy line break on the REC system piping inside containment. The team identified errors in the thermal performance testing and evaluation of the REC heat exchangers. The design of the

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. .. REC system with the capability to take manual operator actions from the control room to align service water to critical equipment that need cooling, er,sured that the system can perform its safety function E1. Electrical Design Review The discussion in Section E1.2.3 of this report covers the electrical design review of the REC syste E1. Instrumentation and Control Design Review E 1.3. Scope of Review The scope of the instrumentation J.'d control design assessment consisted of a review of REC system design criteria documenti., USAR, technical specifications, P&lDs, loop diagrams, schematics /controllogic diagrams, setpoint calculations and loop uncertainty analysis, setpoint data sheets, surveillance data sheets, design change packages, and surveillance and operating procedures. Walkdowns were performed of the system components, instrumentation end controls, main control room, relay and cable spreading rooms and the alternate shutdown control room.

l E1.3. Findings The team reviewed the instrumentation and controls of the REC system to venfy their ability to perform the safety functions of the system. The review included the system controllogic, equipment lineup to support critical and non-critical loads, provisions for inventory control and makeup, and the cross connect to the service water system. Operation under normal and accident conditions was in accordance with the intended design. The team reviewed selected setpoints to verify that sufficient margins had been provided to ensure safe operation of the REC system without exceeding the analyticallimits. These included pump discharge pressure alarms, flow and temperature alarms, surge tank level control and alarms, process radiation monitoring, fast transfer on loss of power, and loss of pressure due to loss of system pressure boundary in the non-criticalloops. The team reviewed the REC system for Appendix R provisions for reW room and control room fire scenarios, and noted that the system was adequately protected from shorts and grounds. The design was verified to be in accordance with the separation criteria except as noted below. Divisional powering of equipment was appropriate to meet electrical redundancy requirements. Installation of system pressure, flow, and temperature instrumentation was in accordance with the desig Electrical Separation Design criteria document DCD-34, * Electrical Separatien System Document," provides criteria for the design of cable and wiring systems that are protected from single failures. The team noted that this document did not specify design methods for associated cables. The team also noted that the document did not provide any guidelines defining acceptable methods for separation of circuits, such as use of circuit breakers. fuses, contact-to-coil or contact-to-contact separation for relays and switches, transformers, and optical devices. Design change 93-057,

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'SW and REC System Modification,' modified the interconnection between the REC system and the SW system to provide control of the interconnecting valves from intertie switches in the control room. The Division 11 intertie switch operates valves REC MOV 714, REC MOV-698 SW MOV 887 and SW MOV 889. These valves are powered from a Division ll MCC except for valve REC MOV 698 which is powered from a Division l MCC. The valve control circuit wiring for Divisions I and ll are terminated on the Division ll intertie switch. The licensee was unable to verify whether a failure analysis was per'ormed for possible wiring faults that could affect both division circuits. The licensee issued PIR 219735 to document the lack of guidance in the DCD regarding associated cables and separation methods. (IFl 50 298/97 20128)

b, Safe Shutdown Analysis While reviewing the valve lineups for alternate shutdown (ASD) capability, the team noted that Appendix E of the safe shutdown analysis report showed incorrect positions for some of the

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valves for the SW intertie to REC Valve REC MOV 695 was shown as being required to be open when it should have been shown as closed. Valves SW MOV 887 and SW MOV 889 were shown as being required to be closed when they should have been open. The corresponding valve positions shown in the analysis summary report were correct. The licensee issued PIR No. 2 20915 to correct these e'rors. The licensee identified after further review, that the analysis that describes the equipment lineups had not been documented in the repor c.- REC Heat Exchanger Outlet Header Low Pressure Switch Calculation NEDC 92 050X determined the setpoint for pressure switches REC PS-452A, REC-PS-452B1 and REC-PS 452B2 that isolate the non criticalloads from the REC system on loss of pressure in the system header. The calculation stated that the 55 psig setpoint for the pressure switches was given in USAR Section 6.5.3; however, this information was not found in the USAR. The liceasee was not able to provide any documented basis for the 55 psig setpoint -

value that would ensure that the safety related REC portions would be isolated and the system insentory would be maintained to avoid the system pumps becoming inoperable. For relays REC REL PS452AX, REC REL PS452B1X and REC REL PS452B2, calculation NEDC 92 050AC determined the time delay from the occurrence of a low pressure condition to the initiation of the closure of the isolation valves The relays are set at 40 seconds. Calculation NEDC 92-050AC indicated in the conclusion section that the 40 second time delay adjusted for an uncertainty of +/ 30 percent was acceptable because it was within the allowable time of minutes for loss of REC, as stated in USAR Section X-6.5.3. The team noted that the 40 second time delay setting does not depend on the 5.1 minute limit. The licensen issued PIR No. 20635

. to document these concerns. (IFl 50 296/97 20129).

E1.3. Conclusions The team concluded that the instrumentation and control design for the REC system was adequate. Setpoints reviewed had adequate margins, except that no analyticallimit or setpoint bases information was available for the REC discharge header pressure switch. The Appendix R instrumentation and control design was adequate except for some documentation discrepancies. No evaluation had been performed to determine the acceptability of terminating

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__ control wiring from both divicione on the control room SW intertie switc _ - -

E1. System lnterfaces E1.3. Scope The team selected portions of SW and instrument air systems that support the operation of the REC system, and reviewed the interface desig E1.3. cindings SW Interface witn REC Calculation NEDC 97 074 Revision 1," Evaluation of the Service Water System to Provide Direct Back up Cooling to the REC System's Critical Loops," establishes the capability of the SW system to provide cooling to safety related equipment in the REC system. The licensee stated that no testing was done to verify actual service water flow to the safety related equipment in the REC system to avoid introducing river water into the REC system. Calculation NEDC 97-074 concluded that the SW system was capable of providing a'l essential coolin The team identified the following concerns with the calculation:

.

The calculation did not take into account increases in SW temperature due to instrument uncertaintie .

The calculation used room heat loads taken from another calculation which assumed

[ only one RHR pump operating instoad of two.- In addition, one RHR pump motor was replaced with a new motor whose efficiency is 1% lower than the other RHR pump moto This lower efficiency for a 1250 HP motor increased the heat rejected into the RHR qua .

The calculation did not use REC system surveillance test data for flow to each connected equipment to determine the percentage of tota! flow to each equipment, and appropriately use that data to calculate the SW flow distribution, in response to the team's concerns, the licensee revised calculation NEDC 97-074 to consider the following: a higher heat duty for the reactor building fan coil units (FCUs) using a conservative fouling factor of 0.005; new performance curves provided by the manufacturer that established greater heat removal capabiSty of the FCUs; flow rates to the FCus based on suC/111ance test data; increased heat loading due to operation of RCIC and both CRD pumps; an( ' ' W maximum temperature of 900F, The team noted that because operational restrictions to in : oW temperature to 87 F to account for instrument uncertainties had been imposed during the inspection, use of SW temperature of 90F in the calculation was acceptable. The team concluded that the revised calculation NEDC 97 074 demonstrated the capability of SW to cool the safety-related equipment in the REC syste The licensee issued PIR Nos. 219692,2-19746, and 2-20200 during the inspection to address and resolve these issues. The design bases for the SW back up to the REC system were not correctly translated into the design input for calculation NEDC 97-074. (URI 50-298/97-20130)

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_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ Instrument Air System Interface Paragraph 3.2.17 of f' 1, " Service Water (SW) and Residual Heat Removal Service Water (RHRSW) Booster * mn,' Revision 1, stated that valves SW AO-TCV451 A & B were analyzed for loss of air. The tw 1 questioned whether the valves had ber analyzed for full air header pressure which may be 7 plied to the valve's actuator and po..uoner upon failure of the upstream air pressure regulator. The licensee stated that this scenario had not been analyzed, and investigated the potential failure modes of ti is valve. The licensee determined that it was possible for the valve to fail in the non safe position, but expected plant operators to recognize the failure when REC temperature exceeded 95'F and take compensatory action by venting the air from the solenoid to open the valv The licensee initiated an investigation of the possibility and consequences of other similar l failures in the instrument air system. Preliminary results indicated that:

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There ware potentially 96 essential air operators of different sizes, pressure ratings, and types that could be affected by air pressure regulator failure .

Six valves were found to have diaphragm type operators with a maximum allowable pressure less than the normalinstrument air pressure of 125 psig. Exceeding the pressure rating may cause operator case and stem damage such that the valves may fail in the non-safe positio .

Nineteen valves have diaphragm type operators with no specific manufacturer information on pressure rating. The licensee determined that these operators might not I withstand the 125 psig instrument air pressure. The effect of valve damage on valve position is being investigate .

Thirty-nine valves have cylinder type operators. These operators might be able to withstand an air pressure of 125 psi .

No design information was available for eighteen valve At the conclusion of the inspection, the investigation was stillin progress. The team urged the licensee to expedite the investigation and promptly nerform appropriate operability assessments as needed. The licensee issued PIR No. 2-20632 uuring the inspection to document this issu (IFl 50-298/97-20131)

E1.3. Conclusion 5 The team concluded that after revising the analysis to resolve the team's comments, the licensee was able to demonstrate that manualinitiation of SW to REC system components would provide adequate cooling water flow. Failure of air regulators in the instrument air system could cause failure of a OW temperature control valve in the closed position, and would require operator action to open the valve. Similar failures of air regulators in the instrument air system and their affects on other air operated valves are being investigated by the license ,

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E1. System Walkdown E 1.3. Scope The team walked down selected portions of the REC system including system instrumentation and control equipment located in the main control room. The walkdown also included portions of the SW system, the RHRSW booster pump room, and REC supply to RHR pumps and the ECCS room cooler E1.3. Findings The team noted that the following adverse conditions had not been promptly corrected. (IFl 50-298/97 201-32): RHRSW Booster Pun a Pressure Gauges The team noted that pressure gauges SW PI 385A through -385D in the RHRSW booster pump suction piping were pegged high. The system engineer stated that this issue had been identified

) in condition report No. 96-0311, dated April 8,1996. He also stated that this condition was due l to high river water level and the range of the pressure gauges was inadequate to indicate the system operating pressures. However, this problem had not yet been corrected, Valve SW V 1265 The team observed that the safety related, normally closed, manually operated service water valve SW V 1265 was leaking around the stem. The licensee stated that the valve had been leaking for about four years, and agreed to expedite repairs to the valv E1.3. Conclusions The material condition of the system and general house keeping appeared to be good. The team identified that prompt actions had not been taken to address the inadequate range of the SW pressure gauges and the needed repairs to valvs SW V-126 E1. Updated Safety Analysis Report The team reviewed applicable portions of the USAR and TS for the REC system, interfacing systems, and the associated electrical and instrumer,tation and control sections, to venfy consistency between these documents and the design documentation. The discrepancies identified by the team in these documents are included in Section 1.2.6 of this repor . . . . , , . . . . .

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X1 Exit Meeting After completing the on-site inspection, the team conducted an exit meeting wP.n the licensee on :

December 4,1997, that was open to public observation, During the meeting, the team leader presented the results of the inspection. A list of persons who attended the exit meeting is . !

contained in Appendix B. The team reviewed licensee provided proprietary information during the inspection, but such proprietary information is not contained in this report,

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APPENDIX A OPEN ITEMS This report categorizes the laspection findings as unresolved items and inspection follow up items in accordance with the NRC Inspection Manual, Manual Chapter 0610. An unresolved

' item (URI) is a matter about which more hformation is required to determine whether the issue in question is an acceptable item, a deviation, a nonconformance, or a violation. The NRC Region IV office will issue any enforcement action resulting from the review of the identified unresolved items. An inspection follow-up item (IFI) is a matter that requires further inspection because of a potential problem, because specific licensee or NRC action is pending, or because additionalinformation is needed that was not available at the time of the inspectio Item Numhet Einfag Iltle IX9a 50-298/97 201 01 URI RHR Pump Test Acceptance Criteria (Section E1.2.1.2.a.)

50 298/97 201 02 IFl RHR Pump NPSH Margin (Section E1.2.1.2.b.)

50-298/97 201 03 IFl RHR Pump NPSH for Fire Events (Section E1.2.1.2.d.)

50-298/97 201-04 URI RHR Pump Minimum Flow (Section E1.2.1.2.e.)

50-298/97 201-05 IFl RHR Pump to-Pump Interaction (Section E1.2.1.2.e.)

50 298/97 201-06 URI RHR Heat Exchanger Performance Testing (Section E 1.2.1.2.f.)

50 298/97 201 07 IFl Suppression Pool Cooling Mode of Operation (Section E1.2.1.2.g.)

50-298/97 201-08 IFl Suppression Pool Transfer to Radwaste (Section E1.2.1.2.g.)

50-298/97 201 09 URI RHR System Suppression Chamber Cooling Throttle Valve Stroke Time (Section E1.2.1.2.g.)

50-298/97 201 10 URI Reportable Condition of Containment isolation Valves (Section E1.2.1.2.h.)

50-298/97 201 11 URI TS Setting Limit for Undervoltage Relays (Section E1.2.2.2.a.)

50 298/97 201-12 IFl Instrument Uncertainties (Section E1.2.3.2.a.)

50-298/97 201 13 IFl RHR Heat Exchanger Bypass Relay A1 s .

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50-298/97 201 14 IFl TS Bases foi CST Storage Requirements (Section E1.2.4.2.a.)

50 238/97 201 15 IFl ECCS Leakage Through Valves (section E.1.2.4.2.b.)

50-298/97-201 18 URI ECCS Leake into Reactor Building Sumps

(E1.2.4.2.c.)

l 50 298/97-201 17 IFl ECCS Pump Seal Failure (Section E1.2.4.2.c.)

50-298/97 201 18 URI Seismic Qualification for Reactor Building Sump Pumps (Section E1.2.4.2.d.)

50 298/97-201 19 IFl Hydraulic Analysis for RHRSW Crosst4 (Section E1.2.4.2.e.)

50 298/97 201 20 URI Post Accident Temperature Control of RHRSW Booster Pump Room (Section E1.2.4.2.f.)

50-298/97 201 21 URI USAR / TS Discrepancies (Section E1.2.8)

50 298/97 201 22 URI SW Design Temperature (Section E1.3.1.2.a.)

50 298/97 201 23 URI REC System inventory Loss (Section E1.3.1.2.b)

50-298/97 201 24 URI RHR Pump Area Cooling (Section E1.3.1.2.c.)

50 298/97 201 25 IFl REC System Design (E1.3.1.2.d.)

50-298/97-201 28 IFl Effect of LOCA Induced Piping Failure of REC System Piping (Section E1.3.1.2.d.)

50-298/97-201 27 URI REC Heat Exchanger Testing (Section E1.3.1.2.e.)

50 298/97-201 28 IFl Electrical Separation Criteria (Section E1.3.3.2.a.) -

50 298/97 201 29 IFl REC System Discharge Header Pressure Switch Setpoint (Section E1.3.3.2.c.)

50-298/97-201 30 URI SW Interface with REC System (Section E1.3.4.2.a.)

.50-298/97 201-31 IFl Instrument Air Pressure Regulator Failure (Section E1.3.4.2.b.)

50-298/97 201 32 IFl Corrective Actions (Section E1.3.5.2.)

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APPENDIX B EXIT MEETING ATTENDEES NAME ORGANIZATION UPPD P. Graham VP - Nuclear D.Buman AE Response Team Leader J. Pelletier Sr. Manager, Engineering M. Bennet Licensing Supervisor L Newman Operations Manager M. Peckham Plant Mar iger D. Weed Board of Directors L Taylor Board Of Directors R. Sessoms Sr. Manager, QA G. Horn Sr. VP, Energy Supply E. Mace Assistant to Sr. Eng. Manager M. Spencer Engineering Programs Supervisor R. Wachowiak Reliability Engineering Supervisor J.Long Engineering Support Manager T. Hough Sr. Staff Engineer L. Church RHR System Engineer K. Billesbach Engineer N. Haskell Consultant S. Freeoorg Maintenance Engineering Supervisor J. Gausman Executive Assistant B. Seidl Operawns Support Engineer J. Cass REC System Engineer M. Gillan Acting Performance Analysis Manager T. Hottovy Operations Support Eng. SLpervisor S. Stiers Admin. Services Mrnager R. Wenzl Project Manager N. Armstrong Site Communication Specialist C. Gaines Maintenance Manager T. Chard Assistant Radiation Protection Manager B. Toline OA Audit Supervisor M. Tackett Control Room Supervisor D. Nelson Director B. Newell Assistant Maintenance Manager D. Hal Records Analyst J. Sayer Employee Concerns Program R. Tanderup Shift Supervisor B1

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NRG K. Brockman Deputy ; s.ctor DRP, Region IV E. Collins Chief, Reactor Projects Branch *C', Region IV D. Norkin Chief Specialinspection Section, NRR T. Stetka Acting Chief, Eng. Branch, Region IV S. Malur Team Leader, NRR r

J. Hall (

Project Manager, NRR C. Skinner Resident inspector R. Najuch Contractor, SWEC R. Hogenmiller Contractor, SWEC M. Yeminy Contractor, SWEC (

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l D. Vandeputte Contractor, SWEC l

A. Varma (

Contractor, SWEC \

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Olhef

l R. Stoddard Chief Engineer, Lincoln Electric System

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APPENDIX C List of Acronyms AC,ac Alternating Current AEC Atomic Energy Commission AH Ampere Hour ASD Alternate Shutdown Stu British Thermal Unit BWR Doiling Water Reactor CAQ Condition Adverse to Quality CFR Code of Federal Regulations CNS Cooper Nuclear Station CR Condition Report CRD Control Rod Drive CS Core Spray CSCS Core Standby Cooling Systems CST Condensate Storage Tank DBA Design Basis Axident DC, de Direct Current DC Design Change DCD Design Criteria Document ECCS Emergency Core Cooling System EDG Emergency Jiesel Generator EDSFl Electrical Distribution System Functional Inspection EE Engineering Evaluation EOP Emergency Operating Procedure EODP Equipment Qualification Data Package FCD Functional Control Diagram j FCU Fan Coil Unit FSAR Final Safety Analysis Report GDC General Design Criterion GE General Electric C GL Generic Letter gpm gallons per minute HELB High Energy Line Break HPCI High Pressure Coolant injection Hr hour I&C Instrumentation and Control lA Instrument Air IFl Inspection Followup Item IR inspection Report IST Inservice Test ITS Improved Technical Specifications kV kilovolts C-1

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p LCO Limiting Condition for Operation LCR Licensing Change Request LER Licensee Event Report LOCA Loss-of-Coolant Accident LOOP Loss of Offsite Power LPCI Low Pressure Coolant injection MCC Motor Control Center MOV Motor-Operated Valve MP Modification Package MSIV Main Steam Isolation Valve NCR Nonconformance Report NEDC Nuclear Engineering Design Calculation NEMA National Electrical Manufacturers Association NPPD Nebraska Public Power District *

NPSH Net Positive Suction Head NRC US Nuclear Regulatory Commission NRR Nuclear Regulatory Regulation, Office of (NRC)

P&lD Piping and instrumentation Diagram PC Primary Containment PCiV Primary Containment isolation Valve PCR Procedure Change Request PCT Peak Clad Temperature PIR Problem Identification Report Psid Pounds per square inch, differential Psig Pounds per square inch, gage

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QA Quality Assurance RBCCW Reactor Building Closed Cooling Water RCIC Reactor Core Isolation Cooling l

REC Reactor Equipment Cooling

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RG Regulatory Guide RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RPV Reactor Pressure Vessel SAR Safety Analysis Report SBO Station Blackout SCAQ Significant Ccndition Adverse to Quality SER Safety Evaluation Report -

SORC Station Operations Review Committee SPC Suppression Poo! Cooling SRV Safety Relief Valve SSE Safe Shutdown Earthquake SSFl Safety System FunctionalInspection

. SW Service Water

SWEC Stone & Webster Engineering Corporation

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TS Technical Specification (s)

TSI Technical Specification interpretation UPS Uninterruptable Power Supply C-2

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URI Unr& solved Itam USAR Updated Safety A:ialysis Report USQ Unreviewed Safety Question

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DISTRIBUTION FOR COOPER NUCLEAR STATION DESIGN INSPECTION RCPORT:

DATED Februarv11998 Dockst File (50 298)

PUBLIC PECB R/F BShoron JRoe SRichards DNorkin CRossi, AEOD EA6ensam

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JHannon CHawes HMillar, RI

)

r LReyas, Ril '

ABrach, Rlll i

EWMershoff, RIV CHehl, RI JWiggins, RI JJohnson, Ril JJaudon, Ril GGrant, Rlli CPedsrson, Ril TGwynn, RIV AHowell, RIV JEDyer, DRA, RIV ACRS (3)

OGC (3)

JHall SMalur 11S Distribution JRosenthal, AEOD l

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