IR 05000382/1999201

Insp Rept 50-382/99-201 on 990511-0619.No Violations Noted Major Areas Inspected:Engineering

ML20211P973
Person / Time
Site:	Waterford
Issue date:	07/27/1998
From:	NRC (Affiliation Not Assigned)
To:
Shared Package
ML20211P001	List: IR 05000382/1998201 IR 05000382/1999201
References
50-382-99-201, NUDOCS 9909140150
Download: ML20211P973 (46)

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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION Docket No.:

50-382 License No.:

NPF-38 Report No.:

50-382/98-201 Licensee:

Entergy Operations, Inc.

Facility:

Waterford Steam Electric Station, Unit 3 Location:

Hwy.18 Killona, Louisiana 70066 Dates:

May 11 through June 19,1998 Inspectors:

Roy K. Mathew, Team Leader, NRR Paul Bienick, Contractor *

Robert Najuch, Contractor *

Dough. Schuler, Contractor *

Dennis Vandeputte, Contractor *

Maty Yeminy, Contractor *

• Contractors from Stone & Webster Engineering Corporation Approved by:

Donald P. Norkin, Chief Operating Reactor inspection Support Section i

Inspection Program Branch Division of Inspection and Support Programs Office of Nuclear Reactor Regulation l

l 9909140150 980727 PDR ADOCK 050003 2 i

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SUMMARY

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i On May 11 through June 19,1998, the staff of the U.S. Nuclear Regulatory Commission (NRC),

l Office of Nuclear Reactor Regulation (NRR), inspection Program Branch, conducted a design inspection at Waterford Steam Electric Station, Unit 3. The inspection team consisted of a team leader from NRR and five contractor engineers from Stone and Webster Engineering

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' Corporation (SWEC).

The purpose of the inspection was to evaluate the capability of the selected systems to perform the safety functions required by their design bases, the adherence of the systems to their design and licensing bases, and the consistency of the as-built configuration and system r-l operations with the final safety analysis report (FSAR). For this inspection, the team selected the low pressure safety injection / shutdown cooling (LPSI/SDC) systems, and the emergency feedwater (EFW) system, as well as their support-interface systems because of the importance i

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of these systems in mitigating design-basis accidents at Waterford 3. The team followed the engineering design and configuration control section of inspection Procedure (IP) 93801 for this

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inspection. For the selected systems, the team reviewed the FSAR, Technical Specifications j

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(TS), drawings, calculations, modification packages, surveillance procedures, and other

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Except as noted below, the team determined that the selected systems were capable of performing their design-basis safety functions and that design and licensing bases were j

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. adequately adhered to. The licensee implemented appropriate measures to resolve the

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immediate concems identified by the team, and no immediate operability concems exist. For i

other issues, the licensee initiated appropriate reviews and evaluations using the corrective i

action. process.

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The team identified examples where actions to identify and correct conditions that are adverse i

to quality were not adequate. Failure of a nonsafety-related pressure regulator in the nitrogen system could affect the safety functions of both trains of EFW system flow control and isolation valves, as well as both trains of several other safety-related systems, because the relief valve to protect the safety systems did not meet safety, code and size requirements. Although this was an original design oeficiency, the licensee had several opportunities to identify and correct

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this issue. During this inspection, the licensee replaced the undersized relief valve. There are programmatic concems in evaluating 10 CFR Part 21 reports for conditions adverse to quality at Waterford 3. The team identified that a 10 CFR Part 21 notification issued in 1994 on

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Agastat relays was not evaluated to determine if the condition was adverse to quality at Waterford 3. During the inspection, the licensee identified 13 other 10 CFR Part 21 reviews

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l The team identified deficiencies in 10 CFR 50.59 evaluations. For example, the FSAR was revised to reflect a deviation from Regulatory Guide (RG) 1.9. However, the safety evaluation failed to identify an unreviewed safety question conceming potential overlapping of emergency diesel generator loads and frequency response less than specified in RG 1.9. In addition, the

. safety evaluation conceming battery replacements did not identify the effect on the Technical

' Specifications, nor the reductions in battery duty cycle time and battery charger charging time.

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Furthermore, the team noted that NRC (Inspection Report 50-382/97-25 ) has recently identified a violation of 10 CFR 50.59 requirements for a USQ issue regarding the reduction of

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EFW flow values.

The analyses to support the design and licensing bases did not always consider the limiting worst-case effects of potential single active failures and, in some cases, the bases were not established by analyses. For example: (1) The bases of TS surveillance requirements for LPSI pump performance were not established, resulting in questions regarding whether the safety analysis assumptions for LPSI performance were preserved by the TS surveillance; (2) Containment flooding analyses did not consider the failure of a containment sump isolation valve to open upon receipt of recirculation actuation signal. This could cause one safety injection train to continue drawing water from the reactor water storage pool (RWSP) until the RWSP was empty, thereby causing flooding; (3) Failure of the LPSI throttle valves that would allow increased flow to the reactor coolant system was not considered in the large break loss-of-coolant accident (LOCA) evaluation; (4) A minimum water level of 5 percent in the RWSP to prevent vortexing did not consider the single failure of an LPSI pump to trip until the sump isolation valves are opened; and (5) Failure of one steam generator level transmitter could

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cause the EFW flow control valves to open fully and overfill the steam generator. There was no

' basis for the high alarm setpoint of the steam generator level transmitter.

A number of design and configuration controlissues were identified. For example: (1) Analyses of post-LOCA offsite and control room doses resulting from back-leakage to the RWSP took -

credit for operation of the nonsafety-related and nonseismic reactor auxiliary building (RAB)

normal ventilation system to clean up the RAB atmosphere; (2) Nonsafety loads are automatically sequenced td the safety bus and certain nonsafety loads are connected to the safety buses. These are not in accordance with the existing design and licensing bases; (3) Condensate storage pool level instrumentation did not consider dynamic flow induced effects, such as velocity head losses and friction head losses including entrance losses;

- (4) During degraded bus voltage conditions, input voltages available for battery chargers and inverters are less than the manufacturer's input voltage requirements; and (5) The turbine-driven emergency feedwater pump stack and the steam lines are not protected from tomado missiles.

The team identified a number of deficiencies in surveillance testing. For example: (1) No procedures specifying test parameters and acceptance criteria for containment sump isolation valve seat leakage limits to prevent pump damage from potential air accumulation in

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emergency core cooling system (ECCS) pump suction lines from the sump; (2) Inservice tests of the EFW discharge check valves did not verify absence of reverse flow leakage to ensure that the valves fully close and preclude a recirculation flow path; (3) TS Section 6.8.4.a required reduction of radioactive leakage from the systems outside the containment. However, the test did not measure as-found leakage of ECCS. Instead, the procedure allowed repairs to reduce the leakage before the leakage rate was measured; this was not consistent with Section 1.9.37 of the FSAR; and (4) Two-percent accurate instruments were not used when performing

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pump tests, as required by ASME.

Other issues regarding~ design control, calculation, and FSAR discrepancies are included within the report.

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a lit. Engineering

. E1.0 CONDUCT OF ENGINEERING E1.1 : Insoection smaa and Mathedr.:cgv

.The purpose of the inspection was to evaluate the capability of the selected systems to perform safety functions required by their design bases, the adherence of the systems to their design

and licensing bases, and the consistency of the as-built configuration with the final safety analysis report (FSAR). The systems selected for inspection were the low pressure ~ safety l

l-injection / shutdown cooling systems, the emergency feedwater system, as well as support-interface systems. :These systems were selected on the baris of their importance in mitigating design-basis accidents at Waterford 3.

l The inspection was performed in accordance with NRC Inspection Procedure (IP) 93801,

" Safety System Functional Inspection.". The engineering design and configuration control

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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.

E1.2. Mechanical Design Review E1.2.1 Low Pressure Safety injection / Shutdown Cooling (LPSI/SDC) Systems

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! nspection Scope I

The mechanical design review of the LPSI/SDC systems included design and licensing documentation reviews, system walkdowns, and discussions with cognizant system and design engineers. The team reviewed applicable portions of the FSAR and Technical Specifications

'(TS); flow and process diagrams and other system drawings; calculations; design change documeritation; system operating, inservice and surveillance test procedures and results; emergency operating procedures (EOPs); engineering requests (ER); condition reports (CR);

and operating experience reviews. The review included the verification of the appropriateness and correctness of design assumptions, boundary conditions, and system models; confirmation that the design bases were consistent with the licensing bases; and verification of the adequacy of testing requirements. The team also examined the installation of the LPSI/SDC system components during a plant walkdown. The team also reviewed the results of recent design basis reviews performed by the licensee for the LPSI/SDC systems.

Specific areas covered during the mechanical design review included system thermal / hydraulic l

performance requirements (e.g., system capacity, pump net positive suction head (NPSH), and

= pump minimum flow); system design pressure and temperature; overpressure protection; component safety and seismic classifications; component and piping design codes and standards; and single failure vulnerability.

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E1.2.1.2 Observations and Findings I

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On the basis of the review of the design and licensing documentation noted above, the team verified that the.LPSI and SDC systems were capable of performing their design and safety

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functions. Those functions include the injection of borated water to flood and cool the reactor l

core following a lossef-coolant accident (LOCA), and removal of heat from the reactor coolant

system (RCS)in the shutdown cooling mode. The systems have adequate flow and heat transfer capabilities. ' Component safety and seismic classifications and specified codes and j

standards were appropriate. Design pressures and temperatures specified for piping and

components, and the overpressure protection features provided, were adequate. The material condition of the plant areas for these systems was good. The system design documents reviewed by the team adequately supported the design and licensing bases, except for the discrepancies and open items discussed in the following paragraphs.

a.

LPSI Injection Valve Limit Switch Failure

. FSAR Section 6.3.3 states that for a large-break LOCA, the most limiting case from the

'i standpoint of peak clad temperaturs (PCT)is the assumption that no single active failure will occur in the safety injection system (sis). This results in maximum safety injection flow spillage and minimum containment pressure, which consequently results in a lower core reflood rate.

Calculation EC-S96-004," Cycle 9 Safety Analysis Groundrules," Revision 2, compiled

> current / desired plant conditions as inputs for the Cycle 9 core design and safety analyses. In

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. Attachment 1 of this calculation, the maximum delivered LPSI pump flow rate (one pump) was specified as 5500 gpm. Footnote 59 of Attachment 1 stated that this value consisted of the actual measured flow during the last flow balance test (5100 gpm) plus an assumed flow measurement uncertainty of 400 gpm.

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The flow balance test is performed to satisfy the surveillance requirements specified in TS Section 4.5.2.g. The team's review of this TS section noted that the LPSI cold leg injection line throttle valves (SI-138A,B and SI-139A,B) each open to a throttled position upon receipt of a safety injection actuation signal (SlAS). The team questioned whether the impact of a single failure of a throttle valve limit switch was considered. This type of failure allows the throttle valve to open fully; thereby, increasing the LPSI flow rate. As indicated in FSAR Section 6.3.3, a higher SIS flow rate has the potential to negatively impact the maximum calculated PCT. The licensee determined that failure of a throttle valve to the full-open position was not previously

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considered in the design. The licensee prepared a new calculation (EC-M98-027, i

" Determination of LPSI Flowrates with Valves SI-138A/B and SI-139A/B Full Open," Revision 0)

and determined that, utilizing conservative assumptions, the rhaximum calculated LPSI flow

. rate with the throttle valves full open would not exceed the 5500 gpm value used in the current LOCA analyses.-

FSAR Section 6.3.1.4 states that the safety functions of the SIS must be accomplished assuming the failure of a single active component. This requirement is consistent with General

. Design Criterion 35, as defined in Appendix A to 10 CFR Part 50. To demonstrate this

. capability, a failure modes and effects analysis for the SIS was performed and presented in FSAR Table 6.3-1. This table did not adequately address the potential effects of the failure of a throttle valve to the full-open position since the table identified the symptoms and local effects

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of such a failure as "none". The failure to consider the potential impact of a credible single

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active failure on SIS operation is identified as URI 50-382/98-201-01a.

b. - LPSI Pump Failure to Trip on a Recirculation Actuation Signal (RAS)

During the injection mode of post-accident SIS operation, each train of SIS pumps, as well as

the containment spray system (CSS) pumps, take suction from the refueling water storage pool (RWSP).- Each SIS train consists of one high pressure safety injection (HPSI) pump and one LPSI pump. When the RWSP level has fallen to the low level setpoint (nominally 10 percent), a recirculation actuation signal (RAS) is generated. The RAS secures the LPSI pumps and opens the containment SI sump isolation valves (SI-602A,B). Maximum opening time for the

containment SI sump isolation valves is 35 seconds.

Calculation EC-M97-026, " Required Submergence to Prevent Vodexing in the RWSP," Revision 0, recommended that the minimum water level setpoint in the RWSP remain above 5 percent to prevent vortexing of the HPSI, LPSI, and CSS pumps before switchover to the recirculation mode of operation. This recommendation was predicated on the results of scale model testing.-

The calculation concluded that this 5 percent setpoint level was well below the RAS setpoint of

10 percent, plus instrument uncedainties. The team reviewed this calculation and questioned whether the impact of a single failure of an LPSI pump to trip upon receipt of the RAS was considered by the licensee. As stated in FSAR Section 6.3.2.5.4, this is a credible active failure. During the 35 seconds that the containment Si sump isolation valves are opening,

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continued operation of an LPSI pump would withdraw additional water from the RWSP causing the water level to fall below the minimum required level of 5 percent to prevent vortexing. The

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licensee determined that this postulated single failure was not previously considered. The licensee performed a preliminary eva!uation demonstrating that the RWSP water level would not reach 5 percent before the complete opening of the sump isolation valves; therefore, vortex formation is not expected to occur. The licensee intends to finalize and formally document this

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evaluation within the scope of a new calculation that will document royJeed RWSP volumes.

This is an additional example of the licensee failing to' consider the WAal impd of a credible single active failure on SIS operation and is URI 50-382/98-201-01b.

c.

Containment Flood Level Following a LOCA NRC Inspection Report 50-382/97-25 dated March 12,1998, discussed the impact of increased containment flooding. The licensee had re-calculated the maximum post-LOCA flood level in

' the containment. The licensee's analysis indicated certain Regulatory Guide (RG) 1.97 instrumentation subject to flooding that was not qualified for submergence, and the partial flooding of the cooling coils of a containment fan cooling unit. These concems were identified by the licensee in CR 97-1287 dated May 22,1997. To prevent flooding of this equipment, the licensee administratively imposed a 90 percent upper limit on the maximum RWSP water inventory. This requirement was implemented in procedure OP-903-001, " Technical Specification Surveillance Logs," Revision 20. Inspection report URI 50-382/97-25-02 was identified to review the completed revisions to the licensee's flooding calculations and the licensee's past operability and reportability determinations.

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The team inquired about the status of the above activities and final resolution of this issue. The licensee stated that revisions to calculations MN(Q)-6-4, " Water Level inside Containment," and EC-M89-004, " Water Levels inside Containment (Post-LOCA)," were not completed. One

. change that needed to be incorporated was a recent revision to procedure OP-902-002, " Loss-of-Coolant Accident Recovery Procedure," which directed the operators to secure the charging pumps.within 2 minutes of receipt of the RAS. This step would effectively terminate the transfer of any remaining RWSP inventory to the containment by the charging pumps; thereby, stranding a certain volume of water in the RWSP (a benefit for the purpose of determining the maximum containment flood level).. The team questioned whether there were any postulated single failures that could result in the transfer of the entire contents of the RWSP into the containment. Specifically, the team suggested that one potential single failure could be the failure of an LPSI pump to trip upon receipt of the RAS. The licensee subsequently determined that failure of a containment Si sump isolation valve (SI-602A,B) to open upon receipt of the RAS would allow one safety injection train to continue withdrawing water from the RWSP until the RWSP was empty. The licensee initiated CR 98-0750 to document this concem and reduced the administrative limit on maximum RWSP water inventory from 90 percent to 87 percent pending the resolution of the CR and completion of final calculations. This resulted in a very narrow control band for RWSP level, between the TS Section 3.5.4.a minimum required level of 83 percent and the administrative maximum level of 87 percent. This is an additional example of the licensee's failure to consider the potentialimpact of a credible single active failure on SIS operation and is URI 50-382/98-201-01c.

d.

LPSI Pump Technical Specifications Surveillance Test Basis The TS contain several specific LPSI pump performance requirements that must be periodically verified by conducting surveillance tests. Section 4.5.2.f requires that the LPSI pump discharge pressure be greater than or equal to 177 psig when operating in recirculation flow mode (i.e.,

flowing through the minimum flow line back to the RWSP). Section 4.5.2.h requires that for each LPSI pump, the total developed head must be greater than or equal to 268 feet but less than or equal to 292 feet at a flow rate of greater than or equal to 4810 gpm. The team questioned the bases for these test parameters and requested confirmation that the safety analysis assumptions regarding LPSI pump performance were bounded by the TS surveillance

. requirements.

The licensee did not locate a calculation or other design-basis document that verified the acceptability of the TS performance parameters. The team noted that the licensee did not identify the lack of adequate documentation in their design basis review effort. As a resuit, the licensee had a new calculation prepared by ASEA Brown Boveri Combustion Engineering i

Nuclear Power (ABB/CE) during the inspection. This calculation (C-PENG-CALC-016. "WSES3

- LPSI Pump and System Technical Specification Surveillance Requirements," Revision 00)

developed a minimum creditable delivery curve for the LPSI system (flow as a function of RCS j

pressure), on the basis of the LPSI pump performance parameters stated in the TS. The i

results of the this new calculation were evaluated in ABB/CE memo (ST-98-320, Revision 00,

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dated June 11,1998).' The calculation showed that at an RCS pressure of 15 psia, the

minimum creditable LPSI flow rate would be 4116 gpm, whereas the Cycle 9 large-break LOCA emergency core cooling system (ECCS) performance analysis utilized 4275 gpm. However, a sensitivity analysis performed by ABB/CE for Cycle 9, documented in CR 97-0649, determined

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that an LPSI flow rate as low as 4084 gpm at'15 psia RCS pressure would have an insignificant

impact.on core reflood hydraulics. It was concluded that the minimum creditable LPSI delivery

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- curve, developed in calculation C-PENG-CALC-016 was acceptable for Cycle 9. The licensee has incorporated the results of the new calculation into the Cycle.10 safety analysis groundrules

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(calculation _EC-S98-009). The licensee's failure to identify the lack of design bases

" documentation for the LPSI pump TS surveillance test parameters in the design basis review effort is identified as a weakness.

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ECCS Leakage Testing

.TS Section 6.8.4.a requires that the licensee establish a program to reduce leakage from the systems outside containment that could contain highly radioactive fluids following an accident and perform integrated leak tests of the identified systems at refueling cycle intervals or less.

This requirement was a post-TMI item (NUREG-0737, item lli.D.1.1). The licensee's conformance with this NUREG-0737 item is described in FSAR Section 1.9.37. This FSAR section states that for liquid systems, the leak rate is determined when a leak is detected. A leakage limit of 1 gpm from all systems that may possibly leak containment sump water into the

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reactor auxiliary building / controlled ventilation area system (RAB/CVAS) areas is established by the large-break LOCA radiological consequence analysis that is documented in FSAR Section 15.6.3.3 and Table 15.6-18.

The licensee has implemented the TS requirement in OP-903-110. " Surveillance Procedure -

RAB Fluid Systems Leak Test," Revision 3. This procedure stated that if a leak was identified, attempts could be made to stop or reduce the leakage before the leakage rate was measured.

The team identified that the as-found leakage was not being measured, which was not consistent with the FSAR commitment. The licensee reviewed OP-903-110 and determined that Revision 1 of the procedure had required the measurement of the leak rate before any sitempts to stop or reduce the leakage. However, in Revision 2 (February 1997), these steps were reversed for reasons that were not known by the licensee. The licensee initiated CR 98-0848 to document that the procedure was inadvertently changed in Revision 2, and that the as-found leakage should be measured (i.e., before any_ attempts to stop or reduce the leakage).

Since existing measured leakage was low, the team did not have any immediate safety

- concems. The failure to measure the as-found leakage consistent with the commitment stated in FSAR Section 1.9.37, and the lack of control of procedure revisions, is identified as URI 50-

-382/98-201-02.

f.

Dose Consequences of ECCS Back-leakage to the RWSP Back-leakage of recirculated ECCS water to the RWSP following an accident was identified as a concem in NRC Information Notice 91-56, " Potential Radioactive Leakage to Tank Vented to

~ Atmosphere," dated September 19,1991. During the recirculation phase of post-accident operation, the HPSI and CSS pumps would circulate containment sump water that could be highly radioactive. Potential leakage paths to the RWSP include the RWCP suction line check

. valves (SI-107A,B), the ECCS pump minimum flow line isolation valves (SI-120A,B and SI-121 A,B), the CSS pump test retum line isolation valves (CS-118A,B), and the SDC heat

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exchanger retum line isolation valves (SI-417A,B). All of these valves are classified as Category A in the licensee's pump and valve inservice test (IST) plan and are periodically leak-

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rate tested.

The large-break LOCA radiological consequence analysis described in FSAR Section 15.6.3.3 and Table 15.6-18 includes dose contributions from 5 gpm of ECCS back-leakage to the i

RWSP. For the 30-day control room dose, this contribution is 7.27 rem thyroid, and much lesser doses to the whole body and skin (the total 30-day control room thyroid dose from all

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sources is 21.04 rem). These doses were derived from calculation EC-S92-001, "NRC IN 91-

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56: Post-LOCA Releases Through RWSP," Revision 1. The team reviewed this calculation and determined that credit was taken for operating the reactor auxiliary building (RAB) normal ventilation system, after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the event, in the calculation of control room doses. The RAB normal ventilation exhaust system design includes a charcoal absorber, which was credited for cleaning up the RAB atmosphere before release. As described in FSAR Section 9.4.3, the RAB normal ventilation system is not safety related or seismically designed since its operation is not required to mitigate the consequences of an accident. The team considered it inappropriate to take credit for operation of this system in EC-S92-001. If the operation of the

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RAB normal ventilation system was not considered, the 5 gpm of ECCS back-leakage could result in control room doses that exceed the acceptance limits specified by 10 CFR Part 50, Append. ; A, General Design Criterion 19, and Section 6.4 of NRC's Standard Review Plan (SRP). The licensee initiated CR 98-0813 to document this concem. Since the existing measured back-leakage to the RWSP was low, the team did not have any immediate safety concems. The use of inappropriate design-basis assumptions for the determination of acceptable ECCS valve leakage limits is identified as URI 50-382/98-201-03.

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SI Sump Isolation Valve Testing The containment Si sump isolation valves, SI-602A/B, are normally closed and open when a RAS is received to allow the HPSI and CSS pumps to take suction from the accumulated water in the sump following a LOCA. Before the RAS, the valves would remain closed and would be exposed to the containment atmosphere on the upstream side until the sump water level rose above the top of the sump suction pipes. Excessive air leakage through these valves could fill portions of the ECCS suction piping where air could be ingested by the HPSI and CSS pumps, potentially causing degradation or air-binding of the pumps. Calculation EC-S91-016. "SI-602 Leakage Study," Revision 0, determined the maximum valve leakage rate where the total air '

accumulated in the ECCS pump suction piping from the sump would not adversely affect pump operation (i.e., the accumulated air would vent back to the containment or would accumulate in

the RWSP suction lines and would not be drawn into the pump suctions).

As described in Section 3.2.1.5 of the SIS Design-Basis Document (DBD) dated December 1997, the appropriate test for L'l-602A/B leakage was to include the valves as a test boundary in the containment integrated leak rate test (ILRT). The licensee's self assessment document,

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_"Waterford 3 Steam Electric Station SSF1-Type Review of the Safety injection System DBD,"

dated August 31,1993, Observation No. DBD-001-ME-007, noted that test methods in i

existence at the time of the self assessment were not adequate because the piping downstream

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l of the valves SI-602NB was not vented for the ILRT. The licensee's response to the observation at that time was that an appropriate leak rate test method for the valves would be developed.

The team inquired about the status of this item and was provided with a copy of Repetitive Work Task (RWT) Nos. 021593 and 021594. Per these tasks, the valve "T" rings are replaced every third refueling (about once every 4.5 years). after which the new "T" ring is leak checked at 44 to 45 psig to verify that the valves are " bubble-tight." The team was concemed that the as-found leakage of the valves was not being measured, and that the RWTs did not identify the valve test pressure or relate acceptable valve leakage to the limit established in calculation EC-S91-016. In addition, the SIS DBD was incorrect in stating that the valves would be tested as part of the ILRT. The licensee initiated ER-W3-98-0782 to address these concems, and also noted that the DBD discrepancy was previously identified during a DBD review conducted in 1997 (Open item Tracking No. Ol-SI-139-S). The licensee also stated that the allowable leakage calculated in EC-S91-016 was large (1.87 acfm at 44 psig), and that gross leakage of this magnitude would be indicative of the valve not being fully closed. The licensee considered successful valve stroke testing (in accordance with the IST program) as adequate demonstration that the valves were not grossly leaking. The failure to measure the as-found leakage from valves SI-602A/B, and the lack of a documented test procedure that specifies test parameters and acceptance criteria, is identified as URI 50-382/98-201-04.

h.

LPSI Pump Minimum Flow The licensee's letter W3P88-1840, response to NRC Bulletin No. 88-04, dated November 1, 1988, states that the LPSI pumps' share a common minimum flow retum line with the HPSI and CSS pumps and that the common lines have been sized to handle the combined mini-flows from the LPSI, HPSI, and CSS pumps. The response further indicates that the original manufacturers (Ingersoll-Rand) recommendation for minimum flow was 100 gpm and inservice testing demonstrated that for single pump operation, minimum flow through the discharge lines greater than 100 gpm was achieved with closed discharge valves.

The licensee letter W3P89-2100, dated October 31,1989, provided supplemental information regarding NRC Bulletin No. 88-04 and states that the pump manufacturer reviewed the pump's minimum flow requirements and provided recommendations in accordance with item 3 of the Bulletin Action Requested Section. For the HPS! pumps, the original minimum flow recommendation imposed an additional time restriction, with increased flow required for a short period and restrictions for continuous operation exceeding 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> in a 24-hour period.

However the letter stated that the LPSI pumps minimum flow was still 100 gpm and did not have the imposed time restriction.

Vendor Manual TD 1075.0045,"Ingersoll-Rand Low Pressure Safety injection Pumps Minimum Flow Evaluation," dated January 27,1989 documented the manufacturer's review completed as recommended by NRC Bulletin No. 88-04. This documentation indicated that the original 100 gpm recommendation was a short-period recommendation for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> or less that is required to prevent abnormal pump wear. A new minimum flow restriction of 2000 gpm was established within the manufacturer's Bulletin No. 88-04 review for continuous pump operation of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> or l

more.

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The licensee confirmed that for the small-break LOCA scenario, the LPSI pump would start on

' SAIS and for certain size breaks, RCS pressure could remain above the pump shutoff head for more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Operating procedure OP-902-002," Loss of Coolant Accident Recovery Procedure," Revision 7, dated December 15,1995, provides for the termination of SI (if not i

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. required); however, no specific precautions with regard to extended operation were identified.

Attachment 6, " Minimum LPSI Flow Versus Pressurizer Pressure," to OP-902-ATT, " Emergency Operating Procedure Attachments," Revision 4, dated December 15,1995, appears to indicate the expected LPSI flow versus RCS pressure, but did not identify any precautions for extended low-flow LPSI pump operation.

The licensee indicated that Revision 8 of the procedure (now in final review and verification)

would contain specific !. PSI termination criteria for securing the LPSI pumps if the RCS

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pressure is above the LPSI shutoff head and the RCS pressure is controlled. However, the

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team noted that the proposed revision was not adequate and did not address the situation

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where RCS pressure could be lower than the shutoff head, but high enough that the manufacturer's minimum flow recommendation could not be achieved. The licensee stated that l

the current operater training and simulator exercises train the operator to secure LPSI pumps if

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not required. The licensee issued CR 98-0850 to resolve the issue.

The inconsistency between the manufacturer's recommendations and the response provided

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for Bulletin No. 88-04 and the absence of procedural guidance with regard to LPSI pump minimum flow requirements'are identified as URI 50-382/98-201-05.

I.

. LPSI Pump NPSH Calculation

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l The team reviewed calculation EC-M97-079, "LPSI Pump Minimum NPSH," Revision 0, to confirm that adequate NPSH margin existed during the injection, recirculation, and shutdown cooling modes of LPSI pump operation. The team determined that entrance losses were not p

l considered in the calculation for the cases where LPSI pump suction is from the RWSP

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(injection mode) and from the RCS hot leg (shutdown cooling mode). Inclusion of the entrance losses reduces available NPSH and could result in unacceptable NPSH margin. The existing calculation showed a NPSH margin of 3.41 ft for the limiting SDC suction case. The licensee

' subsequently revised the calculation to include the entrance losses, which reduced the NPSH

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margin by 1.12 ft; therefore, adequate LPSI pump NPSH margin still existed. Several other

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minor discrepancies 'which did not impact the calculation results were noted by the team.

E1.2.1.3. Conclusions The team concluded that the mechanical design of the LPSI and SDC systems was generally acceptable, and that the systems were capable of performing their safety functions assuming a L

loss-of offsite power (LOOP) and a single active failure; however, the team identified several examples where credible single active failures were not considered by the licensee. These examples affected the licensee's analyses of containment flooding, RWSP vortex formation,

' and LPSI pump maximum flow rate. Several design control concems were also identifed

' including credit taken for the operation of a nonsafety, nonseismic system (RAB normal ventilation) to mitigate the radiological consequences of an accident, inconsistency between the manufacturers LPSI pump minimum flow recommendations and the operating instructions, and

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calculation deficiencies including omission of a significant head loss term in the LPSI pump suction line (entrance losses). Several concems were also identified relating to test control, including the lack of design basis documentation to confirm the acceptability of the LPSI pump

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l performance parameters specified in the TS surveillance requirements, failure to measure as-

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found leakage of ECCS outside primary containment, and a lack of well-documented test L

parameters and acceptance criteria for leak rate testing of the containment SI sump isolation valves.'

E1.2.2 Emergency Feedwater System E1.2.2.1. Inspection Scope

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The mechanical design review of the emergency feedwater (EFW) system included design and

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licensing documentation review, system walkdown, and discussion with system and design

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engineers. The team reviewed applicable portions of the FSAR and TS requirements, flow diagrams, physical drawings, vendor documents, equipment specifications, calculations, operating and surveillance procedures, corrective action documents, modification packages,

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and safety evaluations. The scope of the review included the appropriateness of the design, bounding design conditions, validity of design assumptions, verification of design input,

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verification of heat loads and capability of chillers, vulnerability of components, considerations i

of single failures, adequacy of tests and surveillances and the adequacy of analyses of their results. The team also performed a system walkdown to verify the material condition of equipment.

E1.2.2.2 Observations arE Findings The system design documents reviewed by the team were consistent with the design bases

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except for the iterns identified in the following sections. The team noted that NRC (inspection report 50-382/97-25) has identified a violation of 10 CFR 50.59 requirements for a USQ issue

regarding the reduction of EFW flow values. The material condition of the system and general i

housekeeping appeared to be good, and no deficient conditions were observed.

a.

Condensate Storage Pool Level Measurement In the process of reviewing the suction flow path associated with the EFW pumps (as shown in l

Drawing G-160-sheet 6 of 6, " Flow Diagram CCW System," Revision 6), the team found that the level transmitter EFWILT-CD-9013A or B is measuring the static pressure from the EFW suction pipe of the condensate storage pool (CSP). This static pressure is then converted in terms of water elevation for CSP water level indication (EFW-ILI 9013A or B) in the control '

room. Since the level transmitter is installed in the suction side of the pump, when the EFW

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j pumps operate and water flows through the pipe, the pressure read by the level transmitter is reduced by friction (including entrance) losses and by the velocity head. These two factors bias

. the measurement and erroneously indicate a lower pool level than actual. The team I

' determined that the licensee did not consider the dynamic induced flow effects when designing l-I'

the level instrumentation for the CSP.

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The team estimated that under a worst-case full flow scenario, with only one suction path from CSP, the level error would be approximately 56% which could mislead the operators. This could cause the operators to switch suction from the CSP to the wet cooling tower (WCT) basin too early and admit the undesired basin water to the steam generators. The team noted that the level transmitter level error would be very small for normal flow rate, in addition, the team determined that as soon as the operators switch suction to the WCT basin, the flow through the level transmitter would reverse (because the CSP would be filled by auxiliary component

" cooling water (ACCW) through the EFW suction line); and therefore, the operators could be mislead by a larger error from the level transmitter showing that the CSP level is high off scale

. because of the high line pressure resulting from the high ACCW flow. Presently, this design

- deficiency is not recognized by the licensee and no operating instructions exist to address this -

issue. CR 98-0735 was written to document and resolve this issue. The team noted that the licensee did not correctly identify the worst-case errors in the above CR. In the interim, until the

' issue is resolved, the licensee stated that the operators were provided with sufficient information to ensure that they are cognizant of this phenomenon. The failure to account for friction and velocity head losses for CSP level indication is identified as URI 50-382/98-201-06.

f b.'

SG Level Transmitter Failure Each steam generator has one level transmitter that provides input to secondary (backup)

control valves (EFW-LT 223A/B).- Failure of one steam generator's level transmitter (SG-ILT-11.15A or 1125B ) could cause the EFW secondary control valves to open fully and admit more water than required. This excess water may go unnoticed in the control room until the water level in the affected steam generator would reach 85 percent. At this level, the high-level alarm would alert the operators to the problem, at which time they would have to quickly close the

- isc!ation valve in accordance with alarm response procedure OP-500-009, " Annunciator Response Procedure," Revision 5, Section 4.51, and prevent further flow to the affected steam generator. This failure mode and effect has never been analyzed at Waterford 3.

The team questioned the adequacy of the above design and the basis for the 85 percent alarm setpoint. In response, the licensee calculated the time it would take for the steam generator water level to reach the top of the steam generator from the 85 percent alarm setpoint. It was determined that the operators will have about 12 minutes from the time of the alarm to the time water enters the steam lines. if the steam generator is overfilled, water would enter the steam lines. This condition was not analyzed by the licensee.

The licensee has issued ER-W3-98-0764 to clarify and document the potential effects of any unanalyzed condition (failure mode and effect) and determine the design basis for the high-level alarm value of 85 percent. Qualitatively, the licensee stated that the high-level alarm was chosen because it is lower than the reactor trip setpoint (87 percent), but the licensee could not-identify the quantitative design basis for the alarm at the 85 percent level. This issue is.

identified as IFl 50-382/98-201-07.

EFW Pump Discharge Check Valve Testing c.

The team reviewed inservice testing of the EFW system check valves. The team noted that the IST tests of the EFW discharge check valves EFW-207A,B and AB, did not verify that the

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valves actually fully (reverse flow) close. The IST tests are performed in accordance with procedure OP-903-046, " Emergency Feed Pump Operability Check," Revision 14, dated April r

30,1998, if the check valves do not close, some of the pump's flow may be recirculated back through the EFW pumps (which are not operating) to the CSP rather than reaching the steam

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generators. This may prevent the EFW from fulfilling its safety function of maintaining the steam generators water level. The licensee initiated CR 98-0822 to document and resolve the

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issuei The licensee determined that the above condition did not result in any operability concems because the full-flow surveillance tests performed during the last refuel outage (RF08) were adequate to verify that the check valves were closed properly to ensure the required design-basis flow to the steam generators. The failure to ascertain that the pumps discharge check valves fully close in accordance with ASME Section XI, Subsection IWV-3522 and TS Section 4.05 is identified as URI 50-382/98-201-08.

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d.

EFW Tomado Missile Protection.

During the team's walkdown, it was observed that the safety-related turbine-driven EFW pump t

vent stack was installed outside, on the roof of the reactor auxiliary building (RAB). This was

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not protected from a tomado-generated missile.. In addition, the team noted that there was a

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95-foot section of turbine-driven EFW pump steam supply piping located outdoors, which was also not protected from tomado-generated missiles. Neither the team nor the licensee could

' identify any licensing documents that exempt the EFW pump vent stack and steam supply piping from being protected form missiles.

FSAR Section 10.4.9.1.1.2 states that the EFW system is able to perform its design functions following a tomado, includinh tomado-generated missiles. FSAR Section 3.5.1.4 states that the plant is designed for multiple tomado missiles and the design bases of Subsection 3.5.1. The NRC) safety evaluation report (SER), NUREG 0787, states that the EFW system is protected from tomado-generated missiles. Paragraph 3.5.2," Structures, Systems, and Components to be Protected from Extemally Generated Missiles," states that "all safety-related systems and components are located within tomado missiles protected structures or are provided with tomado missile barriers with the exception of a portion of the EFW system piping... The staff

~ has evaluated these exceptions and found them to be acceptable as described in Sections 10.4.9.2.. " The exceptions refers to a portion of the EFW system piping upstream of the flow control valve to steam generator No. 2 that was exposed above the reactor auxiliary building roof. The SER states however, that this piping has a sufficient wall thickness to withstand the most severe postulated tomado missile at this elevation without damage. Therefore, the team determined that the turbine steam exhaust stack and section of the steam piping inlet to the turbine are not included with these exceptions.

- The tomado missile protection for the ultimate heat sink (UHS) was questioned by the NRC previously (IR 50-382/96-202) ori October 1996. In a letter to the NRC (W3F1-97-0132, Tomado Missile Protection, dated June 4,1997) the licensee provided information pertaining to the reconstitution of Waterford 3 design and licensing bases for tomado missile protection.

The team noted that the NRC staff has not reviewed this letter and accepted the licensee's methodology consistent with the design and licensing bases. The licensee was using the probabilistic risk assessment (PRA) methodology (low probability) for not protecting unprotected

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piping and equipment on the basis of interpretation of NRC's standard review plan (SRP). The team considered the licensee's position not consistent with their design and licensing bases.

SRP, Section 3.5.1.4, " Missiles Generated by Natural Phenomena," states that the

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methodology used to identify appropriate design-basis missiles generated by natural

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phenomena shall be consistent with the acceptance criteria defined for evaluation of potential accidents from external sources in SRP Section 2.2.3. SRP Section 2.2.3, " Evaluation of Potential Accidents," addressed potential accidents involving hazardous materials or activities related to nearby industrial, military, and transportation facilities in the vicinity of the plant. The cross-reference from SRP Section 3.5.1.4 to SRP Section 2.2.3 addressed the identification of

. appropriate design-basis missiles generated by natural phenomena, not the frequency of a

' tomado missile strike on specific equipment or target. The team observed that the licensee's

l f use of SRP 2.2.3 criterion (10 per year) is not appropriate because it addresses potential accidents involving hazardous materials or activities in the vicinity of the plant, not tomado-j i

generated missiles.

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SRP 3.5.1.4 states that all plants should "be designed to protect safety-related equipment against damage from missiles which might be generated by the design-basis tomado for the plant." Further, Branch Technical. Position AAB 3-2 (which was originally referenced by the

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SRP) states that protection of structures, systems, and components (SSCs) necessary to place

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and maintain the plant in a cold shutdown may generally be accomplished designing protective barriers to preclude missile strikes. It further states that if protective barriers are not installed, the SSCs themselves should be designed to withstand the effects of a tomado, including tomado missile impacts. While the SRP provides guidance for assessing the need to protect SSCs from nJ=!Ies generated by:other phenomena (i.e., other than a tomado) on the basis of the probability of damage, this criteria is not applicable to tomado missiles. Therefore, the l

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licensee's use of probability to demonstrate adequate protection from tomado generated missiles and use of the SRP in this manner is not appropriate.

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The turbine stack and steam piping could be damaged by a tomado generated missile and adversely affect the operability of the EFW turbine-driven pump. The team noted that assuming

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the turbine-driven pump is damaged because of lack of adequate tomado-missile protection, J

and a single failure of a diesel generator, there would be only one motor-driven EFW pump i

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. available for plant cooldown.- The design basis requires flows from either two motor-driven l.

pumps or a turbine-driven pump to safely cooldown the plant.

The licensee contends that the vent stack and steam lines are not to be protected on the basis of low probability. Thus, this issue is referred to the NRR staff for further review. ( IFl 50-

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382/98-201-09).

. E1.2.2.3.' Conclusions

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' On the basis of review of design-and licensing-basis documents, the team determined that the i

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mechanical aspects of the EFW system could generally perform its safety functions to provide cooling water to steam generators for the purpose of removing decay heat from the reactor coolant system during design-basis events in general, the EFW design observed during the walkdown was consistent with the design-basis requirements.

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However, the team identified several issues such as the CSP _ level instrumentation did not consider the dynamic flow induced effects such as friction and velocity head losses when

' determining the water lovel in the CSP; the potential overpressure condition in the nitrogen i

system affecting the functionality of EFW system control valves (refer to Section 1.5.2e); the

- lack.of analysis to support the failure mode and effects of a failure of one steam generator level transmitter that had the potential of overfilling steam generator; failure to test the turbine-driven i

EFW pump discharge check valves in the reverse direction; and failure to protect the turbine-driven EFW vent stack and steam lines from tomado missiles. The team noted that NRC (inspection report 50-382/97-25) has identified a violation of 10 CFR 50.59 requirements for a USQ issue regarding the reduction of EFW flow values.

E1.3

' Electrical Design Review :

E1.3.1 Inspection Scope The team reviewed the ability of the electrical power supplies to the LPSI/SDC, EFW, and interfacing systems to perform their design functions under normal and accident conditions.

This evaluation addressed electrical altemating current (AC) bus loading, direct current (DC)

battery loading and distribution, protective coordination, emergency diesel generator (EDG)

loading, plant modifications, and testing. The team also performed a walkdown of the electrical systems and selected mechanical systems to verify the material condition of the equipment.

The scope of the review also included review of the following calculations: (1) EC-E90-006,

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" Emergency Diesel Generator Loading and Fuel Oil Consumption," Revision 3; (2) EC-E91-050,

" Degraded Voltage Relay Setpoint & Plant Load Study," Revision 3; (3) EC-E91-056, " Relay Settings and Coordination Curves for 6.9 kV,4.16 kV and 480V Buses," Revision 1; (4) EC-E91-253,125V Class 1E Coordination Study," Revision 0; (5) EC-E91-061, " Battery 3A-S Cell Sizing," Revision 2; (6) EC-E91-062, " Battery 3B-S Cell Sizing," Revision 2; (7) EC-E91-016,

" Battery 3AB-S Cell Sizing," Revision 4; (8) EC-E91-058, " Battery 3A-S "A-Train" Calculation for Station Blackout," Revision 2; (9) EC-E91-059, " Battery 3B-S *B-Train" Calculation for Station Blackout," Revision 2; (10) EC-E91-060, " Battery 3AB-S Calculation for Station Blackout NUMARC 87-00," Revision 2; and (11) EC-E91-051, " Battery Charger Size Verification,"

Revision OA.

E1.3.2 Observations and Findings On the basis of the review of the design and licensing documentation noted above, the team verified that the essential power supplies for the selected mechanical systems were capable of performing their safety functions. The material condition of the systems and general housekeeping appeared to be good, and no discrepancies were observed. However, the team identified the following issues.

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a. - 10 CFR Part 21 Evaluations The manufacturer of Agastat relays issued a 10 CFR Part 21 notification, dated September 29, 1994, conceming the inability of the E7000 series relays to switch a 1-ampere load at rated voltage. The licensee had not performed an evaluation to determine if the condition was

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adverse to quality at Waterford 3. The licensee did not perform an evaluation in accordance l

with Site Procedure W2.301, " Identification, Evaluation, and Reporting Process for 10 CFR Part

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21 Compliance," Revision 2, and Licensing Procedure LP-122, " identification, Evaluation, and Reporting of Defects and Noncompliances Under 10 CFR Part 21," Revision O. The licensee's initial review determined that 13 other 10 CFR Part 21 notifications between July 1994 and June 1996 were not evaluated. The licensee initiated CR 98-0819 to address the programmatic l

concems of 10 CFR Part 21 reviews not performed between July 1994 and June 1996. The licensee issued Engineering Request (ER) W3-98-0750 to evaluate the technical concem associated with the 10 CFR Part 21 notification received from Agastat conceming the E7000 l

timing relays during the inspection. The team identified this item as Unresolved item 50-382/98-I

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201-10.

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b.

Emergency Diesel Generator

' The team reviewed the licensee's position conceming Information Notice (IN) 92-53, " Potential '

Failure of Emergency Diesel Generators Due to Excessive Rate of Loading," dated July 29, 1992.' This IN identified the potential EDG failures if certain' electrical loads are automatically

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started at the same time as other loads that are sequenced on to the emergency buses. The engineered safety features actuation system (ESFAS) loads could be started at an inappropriate time if the load sequencer design requires both a signal from the load sequencer and a process signal.: Most EDG installations require that loads be sequenced or connected to

.the EDG in a way that allows the engine and voltage regulator to recover frequency and voltage

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after each large motor load is started and before the next load is connected. Normal design practice is to use a timing' device that starts the loads on a predetermined schedule on the basis i

of the required accident loading sequence and the EDG's loading capabilities. However, at Waterford 3, the loads would not start until both a signal from the load sequencer and a process signal are obtained. The process signal could change the scheduled loading of the EDG under I

accident conditions. Some loads which require a process signalin addition to the sequencer signal were the 300-hp containment spray pump; 400 wet cooling tower fans; 600-hp chiller compressor; an-hp Emergency Feedwater Pump d various air handling and heating, ventilation, and air conditioning (HVAC) units for the switchgear, fuel building, and control rooms. There is a potential for overlapping these loads during sequencing. This could cause an undesirable voltage and frequency response which could adversely affect the operation of the diesel.

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Waterford 3 committed to RG 1.9, " Selection of Diesel Generator Set Capacity for Standby Power Supplies," 1971, which states that the EDG should be capable of starting and accelerating to its rated speed, in the required sequence, all the needed engineered safety feature and emergency shutdown loads. Also, at no time during the loading sequence should

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' the frequency and voltage decrease to less than 95 and 75 percent of nominal, respectively.

. The licensee provided document 460000011, " Emergency Diesel Generator Units Dynamic

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' Loading Study," Revision 0, which evaluated the condition described in IN 92-53. The dynamic study combined all permissive actuated loads as one load block at the end of the diesel loading sequence.. On the basis of this scenario, the diesel frequency decreased below the

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. requirements of RG 1.9. The dynamic study showed that the frequency dipped to 93.3 percent and was capable of retuming to its design frequency (60 hertz). The licensee changed the FSAR Section 8.3.1.2.4,c to reflect the deviation from the RG (that they did not meet the 95

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percent frequency requirement of RG 1.9). The Licensing Design Change Request (LDCR) 93-0094, dated August 29,1994, and 10 CFR 50.59 safety evaluation dated January 19,1994, documented this change. The safety evaluation did not identify this item as an unreviewed

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l safety question (USQ) even though the safety margin as stated in the FSAR and the TS Bases was reduced and the possibility of a malfunction of equipment important to safety of a different

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type other than any evaluated in the FSAR was created because of the potential overlapping of diesel loads and the frequency response was less than that specified in RG 1.9. The team noted that the EDGs were never tested to verify the excessive rate of loading because of the

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permissive load sequence design which could adversely affect the operation of the diesel.

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' Further, during the review of the EDG dynamic load study, the team questioned whether the loading of all the cequenced/ permissive loads at the last load block was the most limiting case for the EDG. The licensee could not demonstrate that this scenario would be the worst case for frequency and voltage excursions for the EDG. The team also identified other inconsistencies conceming electrical loading data that was not current with the FSAR loading tables and accident scenarios (refer Sections 1.3.2.d and 1.6). Waterford Action Tracking System

(WATS) 88373 was issued to establish a mechanism of evaluating the effects of load changes

' on the EDG dynamic loading. CR 98-0791 and WATS 88348 were issued to address the concems of EDG loading.

The team identified the adequacy of EDG dynamic load study and the USQ issue as URI 50-382/98-201-11.

125 Vdc and 120 Vac Uninterruptible Power Supply System c.

The safety-related 125 Vdc and 120 Vac uninterruptible power supply (UPS) system consists of one 125 Vdc battery, two battery chargers, and three uninterruptible power supplies for each safety train. Each UPS system is normally powered from the 480 Vac Class 1E buses. Upon loss of ac power, the UPS systems are powered from the 125 Vdc battery. The team reviewed modification package DC-3362, " Replacement of Battery 3AB-S," Revision 0, and DC-3362, t

" Replacement of 3A-S and 3B-S Class 1E Station Batteries and Associated Equipment,"

Revision 2, and identified concems associated with the duration of the battery duty cycie for the design-basis accident (DBA), the increase in battery recharge times, and a nonconservative TS for battery intercell connection resistances.

-125 Vdc Batterv Dutv Cvele The team reviewed modification DC-3362, Revision 2, which replaced the existing Class 1E-station batteries 3A-S,3B-S, and 3AB-S. The LDCR 93-0022, associated with DC-3362 revised the battery duty cycle FSAR Figures 8.3-2,3,4 and Tables 8.3-2,3,4. The existing battery duty cycles required during a DBA with LOOP were reduced from i hour to 17.3

- seconds for station batteries 3A-S & 3B-S and from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to 31 minutes for station battery 3AB-S. The team's review of the 10 CFR 50.59 safety evaluation, dated April 27,1995, noted that the licensee did not address or provide a basis for the reduced duty cycle of the batteries to perform during a DBA with LOOP. The licensee stated that the batteries were only required to function during a LOOP until ac power is restored to the battery chargers, which was 17.3 seconds for batteries 3A-S & 3B-S and 31 minutes for battery 3AB-S. No technical bases for

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" the reduction in battery duty cycle times were provided within the safety evaluation for DC-3362. During the inspection the licensee evaluated the batteries and determined that adequate capacity and minimum de voltage were available to support the DBA loads for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and that

TS surveillance testing for the station blackout (SBO) profiles enveloped the DBA battery profile.' The team reviewed battery sizing calculations EC-E91-061, EC-E91-062, and EC-E91-016 and also noted that the 125 Vdc loads, which were required when the battery chargers are re-energized during a LOCA concurrent with a LOOP were not accounted for in the battery

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sizing calculation. The licensee agreed that the battery chargers could not instantaneously

accept loads when they are being re-energized. Loads not addressed in the battery sizing calculations for this duration were the component cooling water (CCW) & EFW spring charging I

rnotors and closing coils, EDG standby fuel oil booster pump, and other de loads required during the EDG load block 2b. The licensee's preliminary evaluation indicated that the batteries

- have sufficient capacity to support these loads. The licensee stated that the electrical calculations associated with 125 Vdc battery sizing and loading would be revised to include I

those loads that are required during battery charger energization. The licensee issut.1 CR 98-0792 to address the concems of the battery duty cycle and battery loading.

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Station Batterv Intercell Connection Resistance J

The team reviewed TS 4.8.2.1.b.2 and 4.8.2.1.c.3 which state that the connection resistance between cells and terminals must be less than 150 x 10 ohms. The licensee was questioned

as to the basis of the intercell resistance and whether the electrical voltage drop calculations had considered this value. The licensee stated that the station batteries installed under modification package DC-3362 had their discharge characteristic curves calculated on the basis I

of a manufacturer intercell connection resistance of 20-50 x 104 ohms (TM C173.0005

. (457000349), " Vendor Technical Manual for C&D Charter Power Systems," Revision 13). The team questioned the licensee as to why the station voltage drop calculations did not reflect this nonconservative value of the TS or that the safety evaluation performed for these modifications did not change the TS to reflect the manufacturer's design values. During the inspection, the licensee evaluated critical loads such as the EDG breaker closing coil and inverter to determine

whether they would have adequate voltages to operate with higher intercell resistance. The licensee determined that there were no operability concems. The licensee initiated WATS i

88227 and CR 98-0758 to address the effect of intercell resistance on equipment voltage, the TS and the 10 CFR 50.59 evaluation.

Station Batterv Charaer Sizina_

i The 125 Vdc battery and battery charger sizing was calculated on the basis of the safety-related inverters being powered from the ac power supply. Review of TS 3.8.3.1,3.8.2.1, and discussion with station operating personnel noted that the 125 Vdc buses, battery, one battery charger, inverters, and associated 120 Vac buses are required for operation without entering a limiting condition of operation (LCO). The 480 Vac safety-related buses, which normally power the UPS system are not mentioned in the TS as required. Also, TS 3.8.2.1 states that only one of the two battery chargers is required to remain operable. The team was concerned that the battery charger sizing considered only a small de load (normal loading without any UPS load) in its calculation of battery recharge time. Review of modification package DC-3362, which

. increased the battery size from 1200 to 2320 ampere-hour for batteries 3A-S and 3B-S, showed

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that the time to recharge a fully discharged battery while supplying a steady state load of 35

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amperes increased from 11 to 22.19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> for one battery charger and from 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to 9.63 hours7.291667e-4 days <br />0.0175 hours <br />1.041667e-4 weeks <br />2.39715e-5 months <br /> for a two-charger operation. The battery charger steady state loading of 35 amps did not include any loading from the UPS system. The team was concemed that battery recharge time would be in excess of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for one charger with the UPS powered from the battery charger.

The team identified that the 10 CFR 50.59 safety evaluation associated with modification DC-3362 did not address the increased time to recharge the station battery nor did the battery

. charger calculation, EC-E91-051, " Battery Charger Sizing / Recharging Capability for C&D Batteries," Revision OA,- for considering the loading of the UPS system on the de system. The additional UPS loading could require a two-charger operation. The licensee issued CR 98-u 0792, which established interim controls to maintain the 480 Vac power to the UPS systems

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and to address the above concems.

Given the identified concems, the team determined that the licensee's 10 CFR 50.59 safety evaluation for modification package DC-3362 was inadequate since it did not identify the need for revising the TS to reflect the intercell connection resistance specified by the manufacturer.

Further, the safety evaluation did not discuss the effect of the decrease in the safety-related battery duty cycle from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 17.3 seconds for batteries 3A-S and 3B-S, and from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to 31 minutes for battery 3AB-S and the increased duration of battery recharge time. The calculations for battery and battery charger needed to be revised to show the loading, sizing, duty cycle and battery charger charging times. The team identified this item as URI 50-382/98-201-12.

d.

Emergency Diesel Ger)erator Loading The team reviewed calculation EC-E90-006 and determined that the calculation methodology considered the electrical loading of both emergency diesel generators during accident conditions during a LOCA/ LOOP, main steam line break (MSLB) with a LOOP, and shutdown I

with a LOOP. The calculation did not evaluate the worst-case loading of the EDG caused by having only a single diesel generator operating, nor did it consider the maximum brake horsepower (bhp) requirements for major loads such as the EFW, LPSI, and containment spray (CS) motors. The EFW, LPSI, and CS pump motors were analyzed as 380 bhp,435 bhp, and 277 bhp. A review of pump data for the above pumps by the team noted that the EFW, LPSI,

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and CS motors could operate at 460 bhp,470 bhp and 290 bhp, respectively. The team's review of the EDG rating showed that the EDG could operate at 4400 kW continuously and at 4840 kW for a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period. Preliminary evaluation by the licensee during the inspection determined that the maximum loading was still within the rating of the EDG. The team determined that the licensee had not established or documented the maximum loading of the i

EDGs. The licensee initiated WATS 88353 to revise calculation EC-E90-006 to document the maximum EDG loading. The team identified this as IFl 50-382/98-201-13.

- e.

Nonsafety Load Connection The team identified the plant's normal computer supply, powered from 480 Vac bus 3A31-S cubicle 8C, tripped on loss of offsite power but automatically sequenced to the safety-related bus after 2 minutes as shown on drawing B 289, Sheet 20-1, " Power Distribution and Motor Data 480V Swgr 3A31-S One Line Diagram." This automatic sequencing of nonsafety loads

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after load shedding during a ' loss of voltage is not in conformance with the FSAR Section 3.3.1.2.15(e)(7) which states that reconnection of rion-essential loads can only be done manually under administrative control.

Additionally, Section 8.3.1.2.13 (a) of the FSAR and Section 8.4.5 of the NRC's SER for Waterford 3 state that for loads fed from 480 volt motor control centers (MCCs), the bus is divided into Class 1E and non-Class 1E sections and the loss of voltage signal isolates the non-Class 1E section by tripping the interconnecting breaker. However, the team identifed that non-Class 1E loads Diesel Generator 3A-S Air Compressor #1 and #2 are powered from the

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Class 1E bus portion of MCC 3A312-S even though a non-Class 1E bus is provided. These MCC loads were not tripped or isolated during a loss of voltage as stated in the FSAR and the SER. The licensee stated that all nonsafety loads were either tripped on loss of voltage or were installed with two protective devices to ensure that the safety-related buses would not degraded.

The licensee ir' iated CR 98-0763 to address the above issues. The team identifed this item as URI 50-382/98-201-14.

f.

Station Battery Charger and inverter Operation at Degraded Grid Voltage Condition The team reviewed calculation EC-E91-050 and noted that the voltages at safety-related MCCs powering the safety-related inverters and battery chargers were less than the required minimum

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voltage of 432 Vac during a plant degraded grid voltage situation. The team noted that the licensee did not identify this. issue in their corrective action process. The required input voltages, as stated by the licensee (per Vendor instruction and FSAR Section 8.3.2.1.2), for the inverters and battery chargers were 480 volt i 10 percent (432 - 512 Vac). It was determined that, during a degraded voltage condition, the voltage available at the safety-related MCCs powering the Class 1E battery chargers and inverters ranged from 420 to 424 Vac for safety train A and B MCCs and 417 to 421 Vac for safety train AB MCC. Therefore, insufficient ac voltage was available to operate the safety-related battery chargers and inverters and no analysis existed to verify that the safety-related dc system would be capable of powering the 125 Vdc and 120 Vac safety-related loads, which were normally powered by the battery charger and inverters. The licensee briefed the operating personnel to ensure that they were aware of the particular operating concoms and verified that suitable alarms were available to alert the operators in advance of the potential for affecting the operability of the battery charger and

- inverter. The licensee stated that plant annunciation occurs for degraded grid voltage at 97.5 percent and at 94.7 percent of 4 kV bus voltage. Operator action is required to correct this condition to an acceptable level in accordance with operating procedure OP-500-004,

" Annunciator Response Procedure, Control Room Cabinet D,". Revision 07. The team determined that there are no immediate safety concems since the licensee has estabiished administrative controls in place to correct the degraded bus conditions. The licensee issued CR 98-0844 to address this issue. The team identified this item as URI 50-382/98-201-15.

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g.

Testing issues

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The following testing issues were identified by the team:

1. The team reviewed TS 4.8.2.1d, battery duty cycle testing, for battery 3A-S. The testing was performed under Procedure ME-03-230, Task 001733, Work Authorization (WA) 01156279 during Refueling Outage 8. Review of the test data indicated that the voltage at the end of the duty cyck was 116.1 Vdc. However, the value recorded during the surveillance was 120.2 Vdc. The licensee determined that the acceptance criteria of 111 Vdc was met and that an incorrect value was documented. The licensee

- issued CR 98-0717 to correct this condition, i

2. 'The team reviewed EDG sequencing test procedure OP-903-115," Train A Integrated Emergency Diesel Generator / Engineering Safety Features Test," Revision 4, and

. determined that load shedding and load sequencing of loads associated with load blocks 2a,6b, and 6d are verified but the actual timing of the load blocks as stated in FSAR Table 8.3-1 was not documented. The licensee stated that the timing devices are calibrated separately to verify their accuracy. The licensee issued ER-W3-98-0773 to determine whether actual timing of these load blocks should be included in the above procedure. The team identified this item as IFl 50-382/98-201-16.

3. The team reviewed WA 01156296, Task 001734, surveillance procedure ME-003-230, Revision 11, that was performed on May 22,1997 to verify TS Surveillance 4.8.2.1d for battery 3AB-S. The battery test met or exceeded the profile for the 4-hour SBO battery load profile. The 4-hour SBO profile is defined as minute 0 to 1 (363 amps), minutes 1

' to 224 (279 amps), minutes 224 to 239 (285 amps) and minutes 239 to 240 (342 amps). The DBA profile is defined as minute O to 1 (363 amps), minutes 1 to 30 (279

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amps), and minutes 30 to 31 (342 amps). This SBO load profile testing did not envelop the last remaining one minute (30 to 31 minutes) of the DBA profile. The team noted that the final minute of the DBA profile required a discharge amperage of 342 amps (FSAR Figure 8.3-4) whereas the testing required per SBO for that period was 279 amps. Therefore, at minutes 30 to 31, the SBO load profile'(279 amps) did not envelop the accident profile (342 amps). The licensee stated that there is no immediate safety or operability concem because even though the SBO profile did not fully envelop the DBA profile at 30 to 31 minutes, the SBO profile test verified the same current at the end of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, which is a more limiting test than the DBA load profile at a 30 to 31 j

minute period. The licensee initiated ER-W3-98-0774 to evaluate the adequacy of the existing test methodology. The team identified this item as IFl 50-382/98-201-17.

h.

- Other Related Electrical Calculations Review The team identified the following weaknesses associated with electrical calculations:

The team reviewed calculation EC-E90-006 and noted that the assumption for the battery

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charger loading was contingent on the actual plant readings and not actual or estimated DBA loading. During the inspection, the licensee showed that the sustained loading of the

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battery charger during a DBA was within the assumed loadings of the analysis. The licensee initiated WATS items 88219 and 88218 to provide additional clarification within the calculation for the DBA loads.-

The licensee assumed in calculation EC-E91-253 that the protective coordination curve for

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a 10-amp TED 1240 breaker could be scaled on the basis of the characteristics of a 15-

' amp TED breaker curve. 'The assumption was not verifed. During the inspection, the licensee verified the assumption by comparing known manufacturer data for the 10-amp TED breaker. The licensee initiated WATS item 88225 to update calculation EC-E-91-253 to show that the assumption conceming the breaker characteristics was confirmed.

The team reviewed calculation EC-E89-014, " Circuit Breaker D.C. Control Circuit Loop

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Lengths," Revision 2. The team identified that the closing coil for the 4160 Vac breakers was rated at 90 to 130 Vdc. The calculation had considered the effects of low coil voltage; however, no consideration was given considering operating the breaker closing coils at voltages in excess of 130 Vdc. The de system could be operating at 137.5 Vdc in accordance with operating procedures. The licensee contacted the manufacturer and

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determined that operation of the coil would be acceptable up to 140 Vdc. The licensee initiated ER-W3-98-0770 to address this concem and update calculation EC-E89-014.

E1.3.3 Conclusions The essential power supplies for the selected mechanical systems and its support-interface systems were capable of performing their design basis safety functions. The team identified

- two deficiencies in 10 CFR'50.59 safety evaluations, including an unreviewed safety question j

concerning the failure to meet frequency requirements during EDG sequencing. The team

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identified programmatic concems for evaluating 10 CFR Part 21 notifications for conditions

adverse to quality. Engineering calculations were generally adequate, but the team identifed

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errors, nonconservative assumptions which required further review by the licensee. Other issues included: nonsafety loads were automatically sequenced or connected to the safety buses contrary to the design and licensing bases requirements; during degraded bus voltage

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condition, ac input voltages available for battery chargers and inverters were less than the manufacturer's input voltage requirement; and weaknesses in surveillance testing of batteries and EDGs.

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E1.4 Instrumentation and Control Design Review

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- E1.4.1 inspection Scope The team evaluated the ability of the instrumentation and controls for the EFW and LPSl/SDC systems to perfomi the design duty and safety functions during normal power operation and accident conditions. The system design evaluation included review of the FSAR, TS, applicable analyses and calculations, operating procedures, and plant modifications. The team concentrated on reviewing switchover setpoints, plant protection system (PPS) instrumentation,

engineered safety feature (ESF) and ESFAS trip actuation setpoints and their response times,

~ performance testing and RG 1.97 commitments. System walkdowns were also conducted.

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E1.4.2 Observations and Findings The team found the post-accident monitoring instrument design consistent with the guidance of RG 1.97. The modification packages reviewed were generally of good quality, consistent with the design bases, and the associated 10 CFR 50.59 evaluation conclusions were acceptable.

The team reviewed various scaling documents such as the level instrumentation for the CSP.

and RWSP and found them acceptable and consistent with the plant design. The team also reviewed various uncertainty calculations such as for the plant protection system setpoints and found them generally acceptable and consistent with the plant design. The equipment sampled during plant walkdown matched the design documents. However, the team identified the.

following issues.

a.

ASME Section XI Performance Testing Instrumentation The team reviewed instrument accuracy requirements for instruments (ACC IFl7074A/B, CC f

IFl7070A1/B1, S1 IF11306, SI IFl1307, SI IFl0390A/B ) used for the pump performance tests for i

ACCW, CCW, LPSI, HPSI, and charging pumps to verify consistency with ASME Section XI.

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. Section 3.9.6 of the FSAR states that the pumps specified in the program will be inservice

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tested (if applicable) according to the requirements of ASME Section XI, Subsection IWP.

Specifically, TS 4.0.5 requires inservice testing of ASME Code Class 1,2, and 3 pumps in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable addenda as required by 10 CFR Part 50.55a(g), except where specific written relief was l

. granted by the Commission. The team questioned whether Waterford 3 instrumentation was consistent with these requirements.

The Waterford 3 inservice test program was updated to the requirements of the 1989 edition of the ASME Code,Section XI for the second 10-year interval and met the requirements of Section 3.9.6.1 of the FSAR. Pump testing was to be performed in accordance with ASME/ ANSI OMa-1988, (Part 6), " Inservice Testing of Pumps in Light-Water Reactor Power Plants." This part established the requirements for preservice and inservice testing to assess the operational readiness of certain pumps used in nuclear power plants. Acceptable instrument accuracy was required to be i 2 percent of the full scale specified in Table 1 of Section 4.6.1.1.

The licensee stated that ER-W3-97-0390-00-00 was written in August 14,1997, to perform an evalJation to establish the acceptability of the instruments listed in Table 6.5 of OP-100-014,

" Technical Specification and Technical Requirements Compliance," Revision 9, and their acceptability for continued use in the inservice testing program. The results of the evaluation

. were to establish that the accuracy requirements of OMa-1988, Part 6, could be met, and factors such as uncertainties would not significantly affect the repeatability of the data used for trending the degradation of components.

The licensee initially stated that an analysis of the appropriate instrumentation was in progress but had not been completed before the start of the design inspection. Once the analysis was completed, the team reviewed the available instrument accuracy data. The team found that the flow and pressure indicators, ACC IFl7074A/B, CC IFl7070A1/B1, SI IF11306, SI IFl1307, SI

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IFl0390A/B used for the ACCW, CCW, LPSI, HPSI performance testing and the charging pump discharge pressure test did not meet the i 2 percent full-scale totalloop accuracy requirements of OM-6. The totalloop accuracy error ranged between 0.95 percent and 2.34 percent above the OM-6 requirement ofi 2 percent. The team also questioned whether the pumps remained operable based on this data. The errors were subsequently documented in CR-98-0734 to address the operability concems. The team noted that the licensee performed the pump tests between February 25,1998 and June 2,1998, after the above ER was written to question the instrument's accuracy. The licensee did not promptly evaluate the condition adverse to quality, i

until it was questioned by the team during the inspection.

During the inspection, the licensee evaluated the effect of exceeding i 2 percent total loop accuracy on each of the safety-related pumps. The result was compared to the acceptance criteria and found to remain within limits. The licensee stated that the pump flows and pressure continue to show the performance in the acceptable range with no signs of degradation. The team reviewed this data and concluded that the data was acceptable and that the pump tests would have been provided with adequate instrumentation to perform IST. Instrumentation used

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for IST that had accuracies inconsistent with ASME Section XI Code requirements is identified as URI 50-382/98-201-18.

b.

Condensate Pot Pressure Response

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The team conducted a review of the total response time acceptance criteria for ESFAS setpoints. ESFAS total response times included various loop components ( i.e., diesel start time, sequencer, sensor bistables, logic matrix, and actuating device). Component response times when added to dieselloading response times are bounded by the requirements referenced in Table 7.3-13 of the FSAR and the Technical Requirements Manual (TRM). The

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i surveillance test procedures required verification of individual component response times for the instrument loops.

The pressurizer pressure transmitter loops (RC IPT0101C and RC IPT0102C) were chosen for review since they ensure the integrity of the RCS boundary for any event that could lead to an overpressurization of the RCS. The pressure was sensed using instrument tubing, a 3/16 inch flow restrictor, and a condensate pot. The same process tubing served the reactor vessel level indicating system narrow range (RC ILT0108) and wide range (RC ILT0109) transmitters adding additional tubing volume.

The team was concemed that additional delays contributed by instrument piping volumes, condensate pot volume, and a flow restrictor could be transferred hydraulically to the pressure transmitter. The total response time from the start of a transient to the reaction of the end-device might not remain bounded by the accident analysis.

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The team asked if the instrument tubing, condensate pot, and flow restrictor volumes were considered part of the total response times. The licensee stated that Section 1.8 of the FSAR committed Waterford 3 to the provisions in Section 3 of the IEEE-STD-279-1968, " Criteria for Protection Systems for Nuclear Power Generator Stations." This section required that the design bases document the minimum performance requirements including the system response times. Section 1 of this standard defined the system as encompassing all electric and

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mechanical devices and circuitry (from sensors to actuation device input terminals) involved in generating those signals associated with the protective function.

The licensee also stated' that IEEE-Standard-603-1977, " Standard Criteria for Safety Systems for Nuclear Power Generating Stations," defined a sensor as that portion of a channel which responded to changes in a plant variables or conditions, and converted the measured process variables into a safety system signal. They also stated that the components that connect the sensor to the process variable were defined as a process-to-sensor coupling and that the

' condensing pot was an example of a coupling as defined by lEEE standards 279 and 603 and can be excluded from the design bases. ~

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The team interpreted IEEE standard 603 to include the process lines. Furthermore, since the condensate pot and restricting orifice were part of the process line, they should be included as

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part of the design, in response to the team's concem, a preliminary calculation was puformed,

" Condensate Pot Response Time," Revision 0. It analyzed a pressurizer pressure instrument loop containing piping volume, a free volume condensate pot, and a flow restrictor. A conservative assumption was made to represent the worst-case scenario of 1200 psia pressure transient within 2 seconds. The calculation determined that the volumes contribute an

' additional time delay between 20 to 40 milliseconds.

The licensee stated that their analysis determined that this time delay was insignificant and remained bounded by the current des!gn-bases accident analysis, which is currently equal to 29.925 seconds with a loss-of-offsite power, The team reviewed the new calculation supporting this conclusion and found th,e input, assumptions, and methodology were appropriately used.

c.

Uncertainty Calculations

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The team reviewed calculation EC-192-019, " Plant Protection System SetpoWi Uncertainty Calculation," Revision 2.: The calculation determined the uncertainties, setpoints, and allowable values of the Waterford 3 PPS and ESFAS instrument loops. The calculation listed the response times for the RPS and ESFAS actuations. The team found inconsistency in the response tirrs referenced in the calculation compared to that in the TRM, for the low RWSP level recirculation actuation signal. The calculation listed the time as less than 120/108.5 seconds and the TRM as 25 seconds for the same parameter The licensee stated that the

. TRM number M in error and was previously identified in design basis review (DBR) open items

. Ol-CS-87-S anr2 OI-CS-95-S. The licermee also stated that the corrective actions were not completed and the surveillance ted.s were performed adequately in accordance with the values specified in the above calculation.

The team reviewed calculation EC-192-034," Steam Generator Elongation Between the Instrument Taps for the Narrow & Wide Range Level Instrumentation Loops," Revision 0. This

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calculation established the expansion between the instrument to ps as the temperature in the steam generators was increased from cold-shut down conditio% to coerating mode. The team questioned the apparent inconsistency between the tap-to-tap distanco found in the steam generator elongation calculation and the number found in PPS catulation EC-192-019 (183.813 inches compared to 180.84 inches). The team was concemed that an inappropriate design

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' nput could make the steam generator trip setpoint lesc 2.1servative. The licensee evaluated i

this condition and determined that using 180.84 inches in the PPS calculation would have an

insignificant impact on the total uncertainty and setpoints.

The team found that the' remainder of the caiculations were adequate and the methodology used was consistent with the design guide.

E1.4.3 Conclusion

. The team concluded that the design ofinstrumentation and controls for the EFW and LPSI/SDC

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systems was adequate to support the safety functions of the systems and was consistent with t the licensing bases.- However, the team identified that the licensee had not met the instrument accuracy requirements for monitoring instruments capable of evaluating ASME XI pump performance data. The licensee did not adequately consider additional piping volumes and theirimpact on ESF actuation response time.

E1.5 System Interfaces

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E1.5.1! Inspection Scope

The team reviewed mechanical aspects of the portions of component cooling i,ater (CCW)

system; the auxiliary component cooling water (ACCW) system including the dimate heat sink (UHS); the heating, ventilation, and airconditioning (HVAC) system for pump rooms; the instrument air and nitrogen gas system; and chilled water system to ensure that these systems properly supported functioning of the LPSI)/SDC and EFW systems.

Thh review of interfacing system attributes involved the FSAR, TS, calculations, drawings, procedures and results, and licensing commitments. System walkdowns and discussions with

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licensee personnel were also conducted.

- E1.5.2 Observations and Findings With the exception of the following items, the team found that the interfacing systems supported the design bases of the LPSI/SDC and EPN systems.

a.

Ultimate Heat Sink Basin Water Storage Capacity Basis The limiting LOCA scenario for determination of UHS basin capacity required as presented in Section 9.2.5.2 and Table 9-2-10 of the FSAR and the TS 3/4.7.4 basis is predicated on large-

' break LOCA UHS heat dissipation requirements and requires 164,389 gallons. This is

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consistent with licensee's calculation MN(Q)-9-9, " Wet Cooling Tower Losses During a LOCA,"

Revision 3. The water inventory requirements for the long-term cooling event described in

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Section 6.3.3.4 of the FSAR " Post-LOCA Long Term Cooling," identifies ari EFW supply cf 344,000 gallons, which equates to 170,000 gallons from the CSP and 17.000 gallons from the

- UHS basin. This volume exceeded Section 9.2.5.2 of the FSAR's large-break LOCA UHS

- water requirements and current TS bases (164,389 gallons). The FSAR scenario did not address water consumption associated with UHS heat dissipatL.n of containment heat loads,

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and subsequent cooldown from hot standby conditions and SDC operation. Calculation MN(Q)-

9-9 also identified that Section 6.3.3.4 of the FSAR requires 344,000 gallons for EFW, and states that this more conservative long-term cooling plan is still in effect, but did not use this as a basis for water requirements within this calculation. Although the calculation concluded that the large-break LOCA consumes 164,389 gallons for UHS heat dissipation, the calculation did not provide justification for exclusion of the small-break LOCA analysis, with 174,000 gallons as the required WCT Basin inventory. The calculation indicated qualitatively that the heat loads for large-break LOCA conditions are used whereas EFW requirements are predicated on the much lower heat load conditions of a small-break LOCA.

The licensee indicated that DBR open item OI-EFW-157-C identified that a new calculation was necessary to determine the required volume in two UHS basins for the combined EFW Makeup and ACCW requirements, and a post-LOCA long-term cooling reanalysis is currently in progress. LDCR 98-0094 is being prepared to revise FSAR Section 10.4.9 to address all EFW events that may require condensa;e from the WCT.

The recognition of additional functional requirements for the WCT basin to support EFW system water storage needs, in addition to the UHS heat dissipation needs is identified as IFl 50-382/98-201-19.

b.

Post Accident Spent Fuel Pool Cooling

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Calculation MN(Q)-9-3, " Ultimate Heat Sink Study," Revision 2, determined the heat capacities of the WCTs and dry cooling towers (DCTs) under LOCA conditions and provided a technical basis for FSAR Figures 9.2-4, " Heat Load Dissipation of Ultimate Heat Sink After LOCA," and i

9.2-4a, " Wet Cooling Tower Integrated Heat Load Curve After LOCA." The calculation also I

provided the maximum heat loads from a large break-LOCA as an input for evaluation of the WCT water consumption within calculation MN(Q)-9-9 * Wet Cooling Tower Losses During a LOCA," Revision 3.

The calculation (W'.1)-9-3) determined the heat stored within the fuel pool as a result of the isolation of SFP ccmag and heatup to 180 *F. The stored energy was then modeled as a uniform increase in the SFP heat load from 11.2 million Btu /hr to 11.4 million Btu /hr on the UHS to be dissipated at a constant fuel pool temperature of 180 *F over the next 25 days.

By comparing the fuel pool heat exchanger data sheet included as Attachment 8.9 of calculation MN(Q)-9-17, "Tomado Multiple Missile Protection for the UHS," Revision 2, with a fuel pool temperature of 180'F and CCW temperature of 115 'F, the team estimated that the i

initial SFP heat load that could be rejected may exceed 50 million Btu /hr. The team was concemed that when input as a uniform heat dissipation over 25 days within calculation MN(Q)-

9-9, the modeling technique reduces the coincident containment heat load and SFP heat load during wet cooling tower operation and thereby reduces the WCT water consumption. The

iicensee evaluated this additional heat load and indicated that approximately 15,250 gallons of additional water would be required (above the values specified in TS Bases 3/4.7.4 and the above calculation) to dissipate the additional heat load assuming the WCT dissipated all the

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heat. However, since analysis MN(Q)-9-9 supported that only 44,000 gallons were required from the inoperable WCT basin, adequate margin existed in the inoperable WCT basin for the

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additional 15,250 gallons (each basin has a volume of 174,000 gallons).

Additionally, the licensee indicated that SFP heat rejection would be controlled as part of the Emergency Plan (E-Plan) responsibilities by providing guidance to operations based on assessments of the meteore;0gical conditions at the time of the event. Piant operating procedures did not address these restrictions explicitly. The licensee cited procedure EP-002-100," Technical Support Center (TSC) Activation, Operation and Deactivation," Revision 26, as the applicable guidance procedure. The licensee believed that adequate procedural guidance

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Attachment 8.9 of calculation MN(Q)-9-17 analyzed the off-normal performance of the SFP heat exchanger and determined that, at conditions comparable to the post-LOCA scenario analyzed

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within calculation MN(Q)-9-9, a CCW flow reduction from the normal flow of 1600 gpm to 440

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gpm could dissipate the SFP load of 11.4 million Stu/hr. However, the guidance provided by procedure EP-002-100, Attachment 7.12," Post Accident Contingencies and Concems" simply indicated that Fuel Pool cooling should be restored before the Fuel Pool Temperature exceeds 180*F and that CCW flow through the standby fuel pool heat exchanger should be secured.

EP-002-100 provided no procedural guidance or cautions to restrict SFP heat loading on the UHS to 11.4 million Stu/hr as used within the WCT and DCT capacity analysis and development of inputs for determination of UHS heat rejection water consumption. To maintain operation consistent with the FSAR, TS Bases and supporting analysis, SFP cooling operation restrictions must be applied. The lack of procedural guidance regarding SFP cooling operation restrictions is identified as URI 50-382/98-201-20.

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Spent Fuel Pool Makeup Requirements J

Section 9.1.3.3 of the FSAR identifies that makeup to the spent fuel storage pool is from the seismic Category 1 RWSP and/or the CSP. Calculation EC-M97-006," Design Basis for CCW Makeup," Revision A, established a required makeup volume of 93,226 gallons for the SFP for l

a 30-day period following a LOCA or a design basis tomado event. Calculation EC-M97-006 identified that the RWSP contents and initial CSP contents are accounted for in a LOCA event and not available for post-LOCA long-term makeup to the SFP. The water volume within the unavailable WCT basin is credited as a makeup source for gravity drain to the operational WCT basin. This _ water is then transferred to the CSP using the ACCW pump and ultimately as makeup to the SFP via the CCW system.

Calculation MN(Q)-9-9, " Wet Cooling Tower Losses During a LOCA," Revision 3, which forms the basis for TS 3/4.7.4 " Ultimate Heat Sink Bases" concluded that 164,389 gallons is required for a large-break LOCA considering evaporation and drift losses, and a 5 percent allowance for solids, resulting in a margin of 9611 gallons. The calculation also determined that SFP heat dissipation at the UHS requires 218,155 gallons. The increased consumption is accommodated by the margin within the operable basin and makeup from the inoperable basin. Table 9.2-10 of the FSAR " Water Requirements for Wet Cooling Towers - Post LOCA Essential Loads," states that when considering the fuel pool cooling heat load, approximately 44,000 gallons of makeup is required to the WCT basin if only one train is available.

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The team concluded that the UHS volume requirements as described within the FSAR, TS bases and supporting design calculations were inconsistent with the facility design and licensing bases. The FSAR states that makeup to the spent fuel storage pool is from the seismic Category l RWSP and/or the CSP. The UHS basin has a function to contain plant water inventory requirements for makeup to various systems in addition to supporting the WCT j

i evaporative cooling functions. Although 44,000 gallons were identified as necessary to support SFP heat dissipation at the UHS, the additional water requirements to support SFP makeup l (93,226 gallons) in accordance with the FSAR were not considered in overall water consumption for the WCT basins.

The licensee stated that makeup to the fuel pool is not a UHS design-basis requirement.

Further, the licensee indicated that ACCW would have fulfilled its LOCA safety function and be secured before the fuel pool would require makeup; therefore, makeup to the fuel pool would not impact the 30-day water volume for heat dissipation at UHS. However, the team noted that this response did not address the multi-function purpose of the WCT basin to maintain water inventory for multiple plant functions in addition to the inventory necessary to satisfy the UHS heat dissipation functions.

The failure to account for additional functional requirements for the WCT basin to support SFP system makeup water storage needs, in addition the UHS heat dissipation needs, is identified as URI 50-382/98-201-21.

d.

RWSP Purification Loop Seismic Capacity Section 9.1.3.3 of the FSAFfidentifies that makeup to the spent fuel pool is from the seismic Category l RWSP and/or the condensate storage pool (CSP). The NRC SER (NUREG-0787)

identified that the makeup to the fuel pool is provided by the seismic Category i CSP and/or RWSP via the seismic Category 1 CCW makeup pumps and piping and/or the non-seismic RWSP purification pump and piping.

CR 97-2551, dated November 5,1997, documented single failure vulnerabilities of makeup control valves to fail open upon loss of air, which may challenge CSP inventory. This was reported to the NRC and documented in Licensee Event Report (LER) 97-026-00, dated December 5,1997. As a result of the identified potential failures, adequate CSP water volume margin may not be available following a seismic event if it is used as designed via CCW makeup pump transfer for SFP makeup.

As a temporary solution to the problem, the licensee provided additional guidance in procedure OP-901-522 * Seismic Event,' to utilize the RWSP purification loop for makeup to SFP and perform necessary walkdown to verify system condition before putting in service. This corrective action was based on the detailed engineering evaluation in CR 96-1282. CR 96-1282 had identified that portions of the RWSP purification line are not seismically analyzed and during a design-basis earthquake, the line could potentially break and divert water from the suction of the ECCS. CR 96-1282 concluded that, during a design-basis seismic event, the RWSP purification system would not experience a catastrophic failure and deplete RWSP

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inventory during RWSP purification operation. Component evaluations within CR 96-1282, as

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performed for the RWSP purification pump, concluded the pump would maintain its structural integrity and remain anchored to the floor during and after a design-basis seismic event.

Neither.CR 96-1282 nor CR 97-2551 addressed system functionality or the functionality of supporting systems such as electric power supply. During the course of the inspection, the licensee reviewed the necessary components within the RWSP purification loop, including the support systems and concluded that the RWSP purification loop would remain functional to supply water to the SFP if required. The licensee stated that the permanent solution to address the original CCW makeup system design deficiency is currently being reviewed.

e.

Potential Overpressure of Nitrogen System

' Emergency Feedwater control valves EFW-223A(B), EFW-224A(B), and EFW isolation valves,

>

EFW-226A(B), EFW-229A(B), are controlled by instrument air and backed up by a nitrogen supply system. The valves are equipped with ASME Section ill safety-related accumulators, which maintain a pressure of about 750 psig. The accumulators are pressurized by a l

nonsafety-related nitrogen system located in the yard. - This nonsafety nitrogen supply is

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pressurized to 2400 psig. Nonsafety pressure regulators (NG-147A or B) and a noncode relief l

valve (NG-149) are located downstream of the main gaseous nitrogen tank, upstream of the i

nitrogen accumulators. There is no safety-related ASME Code component in the nitrogen system upstream of the accumulators protecting the safety-related components from the high pressure, nonsafety portion of the nitrogen system.

The team identified that failure of a nonsafety-related pressure regulator in the nitrogen system

could affect the safety functions of both trains of EFW system flow control and isolation valves since the relief valve to protect the safety system was also nonsafety, noncode, and undersized. According to the pressure rating of safety-related Class 3 components downstream (800 psig), this overpressurization could jeopardize the capability of the isolation and the control valves of the EFW system to open or close during a design-basis event. The licensee immediately investigated the team's concem and documented it on CR 98-0684 The

. licensee determined that overpressurization could cause the nitrogen system inopera% and subsequently cause connected safety-related systems to become inoperable. The l'.:er/ se's assessment was based on the fact that relief design was contrary to the requiremena of ASME Section 111 or Vill Code. in addition, if the pressure regulator (NG-147A or B) in the no tsafety

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portion of the nitrogen system failed open undct worst-case upstream pressure conditions, !!

would be capable of passing 650 scfm, while relief valve NG-149, just downstream of the pressure regulator, was only capable of passing 170 scfm (at 1000 psig) plus 10 percent accumulation. This issue was documented on CR 98-0683. The licensee determined that other safety-related systems (LPSI, HPSI, Containment Spray, CCW, ACCW, safety injection tank) were also affected by this design deficiency. Potential for ovearessurizing the safety

. system components beyond its rating put the plant outside its design bases. A 1-hour notification was submitted by the licensee on May 14,1998, in accordance with 10 CFR 50.72 requirements.

immediate actions were taken to ensure operabikty. These included locking open isolation valve NG-1502 to put relief valve NG-1506 in service.. NG-1506 is an ASME Sec%n Vill relief valve with the capacity to relieve the pressure regulating valve's fully open capacky, and is set

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at 802 psig.. This relief valve was installed on March 1997 to protect downstream piping and components when nitrogen is supplied from nitrogen truck.' The team identified that the l

licensee's initial corrective action to address operability of the system was not adequate

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because the relief valve they used to protect the system in the interim was also undersized

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since the relief valve set pressure of 802 psig did not account for accumulation and line losses,

especially due to the port size of upstream isolation valve NG-1502.~ The team questioned the

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adequacy of the interim oorrective action to address operability.

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In the followup investigation, the licensee personnel determined that NG-1502 is a reduced port valve and would thus limit the fiow from the system to NG-1506. Once this oversight was detected, further evaluation determined that NG-1506 would be unable to adequately relieve system pressure and maintain the safety-related portions of the system at their design

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pressure. CR 98-0706 was written to document and resolve this issue. The immediate action

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taken to address this condition was to disconnect the main source of nitrogen (gaseous tank)

and connect the supply line to the standby nitrogen tanker. The licensee replaced the undersized relief valve (NG-149) on May 21,1998, with an ASME Section Vill relief valve adequately sized to maintain nitrogen system pressure at its 800 psig setpoint, and the nitrogen l

system was retumed to normal operation (from gaseous nitrogen supply system).

l The team noted that on October 9,1996, a condition report CR 96-1589 was written identifying i

- that the set pressure of NG-149 was 1000 psig,25 percent higher than the 800 psig design pressure of the safety-related portion of the system. ASME Section lil Code requires the relief valves to be set at the limiting system's design pressure to prevent exceeding the design L

pressure. The operability assessment was predicated on meeting the allowable stresses from pressure boundary standpoint and was not contingent on component functionality. The L

corrective action for this CR was to initiate a station modification request (SMR) to provide overpressurization protection to the safety-related piping in the nitrogen system, including

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protection to the ebht safety related accumulators and Penetration 14. As a result, System Engineering issued SMR NG-009 on December 20,1996. SMR NG-009 was never reviewed

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by the SMR Review Committee because the SMR review committee did not meet until Refueling Outage 8, at which time, only emergent outage restraint issues were discussed. The y

Project Review Committee was formed on August 21,1997, to approve funding for site projects.

L SMR NG-009 was prioritized as number 30 of 32 items identified for refueling outage (RF09).

I Due to this low priority, the SMR was not approved for implementation during RF09. The

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licensee closed the CR on January 21,1997, on the basis of pending corrective action via SMR NG-009.

Also, CR 96-1463 was issued on September 20,1996, to address the nitrogen control panel bypass line installed per plant modification (DCP 3206) that did not have a relief valve installed to protect the system from overpressurization in the event of failure of the Gas Charging Assembly. This CR also identified the potential overpressurization of the nitrogen system that could affect safety-related systems and referred the corrective actions to SMR NG-009.

i As indicated above, the licensee had prior opportunities to correct the potential overpressure condition that could affect several safety-related systems, in addition, there were several NRC generic communications regarding potential overpressurization of safety-related system due to failure of nonsafety-related systems.

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'The licensee issued LER 98-010 on June 15,1998 which concluded that the affected systems Twould withstand the overpressurization and remain operable. This assessment was predicated on the ability of the piping and component to withstand the respective pressure integrity (stress

levels). This'was documented in licensee's calculation EC-P98-005.- The functional capability

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I of the components in the safety-related portion of the nitrogen system (such as pressure regulator, relief valve, check valve, and solenoid valve) to withstand an overpressure condition

.was not determined by licensee analyses or tests, but rather on the basis of a memo from the vendor. The licensee did not provide any vendor documentation (analyses or tests) for the team's review to verify the functional capability of the safety-related components under overpressure condition.

The potential overpressurization of the nitrogen system that could affect several safety-related systems is identified as URI 50-382/98-201-22.

i EFW Motor-Driven Pump Room HVAC The EFW motor-driven pumps are cooled by chilled water. The licensee has documented in i

calculations MN(Q)- 9-3, Ultimate Heat Sink Study," Revision 2, and MN(Q)-9-17, "Tomado Multiple Missile Protection of Cooling Towers," Revision 2, that during post LOCA or following events such as a tomado, the chilled water temperature may rise above its maximum design temperature of 42*F (Design Specification 1564.747," Water Chillers," Revision 15) and may reach temperatures as high as 52'F. But when calculating (Calculation 51, " Emergency

Feedwater Pump Rooms," Revision 2) the maximum temperature in the EFW motor-driven pump rooms, the licensee used a'nonconservative chilled water temperature of 42 'F.

l The team questioned the impact of this discrepancy on maintaining the design-basis temperature of 104*F for the rooms. The licensee has recalculated the temperature in the l

EFW motor-driven pump rooms and determined that the room temperature may reach 117 F.

The pump motors are qualified to operate in a maximum temperature of 104 'F (Specification 1564.117, " Emergency Steam Generator Feedpump and Accessories," Revision 7).

The licensee's further review determined that the maximum temperatures in the CCW and the shutdown heat exchanger rooms were also affected. It was determined that the CCW rooms may reach 116 'F and the shutdown heat exchanger rooms may reach 108 'F. The safety-

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related equipment in these rooms are qualified to operate at a maximum temperature of 104 'F.

The licensee has issued CR 98-0852 to document and resolve this issue. The licensee's operability evaluation determined that equipment can perform their safety function for

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temperature as high as 122*F. Therefore, there were no operability concems. The team l

identified this issue as URI 50-382/98-201-23 (:

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Condensate Storage Pool Level Not Being Monitored When Filled By ACCW

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l When EFW flow is established using water from ACCW, the CSP is getting filled at the same time, but the operating procedure (OP-902-005, " Loss of Offsite Power / Station Blackout

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Recovery Procedure," Revision 9, dated December 1,1995) directing the operators to establish

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' this flow, did not provide any instruction to the operators to monitor water level in the CSP. This -

condition is aggravated by the fact that level monitoring is not possible during this operation because the level instrument would be biased with a large error indicating that the CSP water level is high off scale. If the operators do not monitor the CSP's water level, there could be a l

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potential for overfilling and damaging the CSP (refer Section E1.2.2.2.a for details).

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The team noted that during the design-basis upgrade program, the licensee questioned the flow l

back rates to the CSP when the EFW pumps are aligned to ACCW discharge. This item (EFW open item 130)is being tracked since October 4,1997. This item recommended that a

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calculation be prepared to determine flow back rates to the CSP. It also recommended that a level setpoint be determined to prevent the CSP from overflowing. The adequacy of procedures to monitor CSP level when filled by ACCW is identified as IFl 50-382/98-201-24.

h.

ACCWS'- EFW Suction Path Testing When water in the CSP is depleted (at 25 percent level), the licensee relies on establishing EFW flow using the WCT basins in accordance with operating procedure, OP-902-005, * Loss of Offsite Power-Station Blackout," Revision 9. This flow is established by running the ACCW pumps and opening isolation valve ACC-116A/B. When opened, this valve exposes the suction piping of EFW to the discharge piping of ACCW. Excess flow would then refill the CSP through the EFW suction pipes at the same time feeding the steam generators.

The piping arrangement connecting the ACCW to EFW has never been flow tested to ensure that the full design flow would pass through the lines. Such testing is required to identify blockages, restrictions, or other system problems anywhere in the piping arrangement, where flow is to be unrestricted from the WCT through ACCW to EFW. The licensee stated that the only tests they performed was stroking the valve, periodic draining of drain valves, and ultra sonic testing of lines to verify wall thickness of pipes. The team determined that licensee's existing testing was not adequate to ensure that the full dus.gn flow would pass through the lines. The team noted that in the previous NRC inspection report (50-382/96-202), the NRC had identified that the lack of testing of infrequently used lines such as the WCT basin lineup to the EFW was a weakness in the licensee's implementation of Generic Letter (GL) 89-13 program. To date, the licensee had not taken any corrective action to address this issue. The team identified this issue as IFl 50-382/98-201-25.

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WCT Basin /ACCW Pump Vortex Consideration CR 95-0657 was generated as a result of the EFW self assessment and identified that vortex formation was not considered in the design for the CSP. Corrective action plans for similar conditions state that all other storage pools and tanks with a safety function should be investigated for documentation that vortexing was considered. Storage pools and tanks identified include the RWSP, EDG Fuel Oil and Day tanks, Boric Acid Makeup (BAM) tanks, Volume Control Tank (VCT) and WCTs.

To address the issue, calculation EC-M95-012 * Minimum Pipe Submergence to Prevent Vortexing," Revision 1, was generated to evaluate vortex formation in the CSP, BAM tanks,

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e EDG Oil Storage tanks, EDG Oil Feed tanks, RWSP, and VCT. The WCTs had vortex breakers installed per Design Change Notice (DCN) MP-887 in 1983 and were therefore not included in the calculation.

DCN MP-887 was generated to resolve initial concems identified during plant startup that the ACCW pumps _were not performing in accordance with the vendor pump curves. The DCN provided structural details for installation of a cross vortex breaker in an unconventional configuration. The pump suction tumed downward with the cross vortex breaker undemeath the pipe inlet. No basis for the design selection or predicted hydraulic performance was included within the design package. Acceptance of the design was to be based on the post-modification retest of the pumps. However, the licensee indicated that pressure readings in the original test were also suspect, and with relocated instrumentation during the retest, acceptable pump performance was achieved. Basin water levels during the retests were not documented and therefore hydraulic performance of the vortex breaker could not be assessed.

CR 97-1844 identified that calculation EC-M95-012 used a nonconservative vortex calcdation methodology. Corrective actions identified within CR 97-1844 addressed only those tanks within the scope of EC-M95-012. The extent of condition did not consider the WCY vortex

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breaker design.

The team noted that calculation MN(Q)-9-38, " Capacity of Wet Cooling Towers," Revision 3, established a TS capacity for the WCT at 174,002 gallons considering a full useable volume from the TS minimum water level (-9.86 ft), to the ACCW pump suction curb height.

Assumption 5.1 and 5.2 in the above calculation indicated the ACCW pump suction is at the same elevation as the sucti6n cur.b and the WCT is assumed to be empty at this elevation.

Therefore, it appears that the TS WCT volume basis considers the water down to the suction lip as the useable volume and has no identified allowance for vortex formation.

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The licensee believes that the solids allowance within the calculated WCT basin volume will provide adequate submergence to preclude vortex formation. WATS 88082 was established to I

track revision to calculation EC-M95-012 to include a basis for not requiring a vortex limit for the WCT basin. The team identified this issue as IFl 50-382/98-201-26.

J.

ACCW Transfer to the CSP /WCT Basin Cross-Connect Operation i

Two redundant WCT Basins exist for the UHS. Assuming a failure of one basin, the water volume can be transferred to the operating basin through cross-connect line. This design feature is discussed in FSAR Section 10.4.9. Special Test Procedure STP 01156126 was

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developed, in part, to verify wet cooling tower basin cross-connect flow capacity. The test acceptance criterion was established at 20 gpm, given the expected evaporation and drift losses from the functional basin. Measured flow from a full basin to an empty basin was 242 gpm at the full differential elevation difference between the basins.

ACCW pump capacity is approximately 6500 gpm in the WCT operating mode. The licensee had not evaluated system capacity to support transfer of water to the CSP for EFW, CCW, or SFP interface system makeup water requirements. Calculation MN(Q)9-44,."ACCW Pumps NPSH," dated November 2,1983, concluded that the pumps have sufficient NPSH considering

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I a flow rate of 6500 gpm and a water level down to the lip of the suction pipe. The team noted that the present inverted suction pipe arrangement could create a slight suction lift condition, which could air bind the suction line if air is entrained. The team was concemed that operation in this mode may result in a rapid pump down of the basin, with limited makeup capability by the.

WCT cross-connect.

The licensee indicated that water inventory management and cross-connect operation are addressed in the Emergency Plan. The licensee cited procedure EP-002-100, " Technical Support Center (TSC) Activation, Operation, and Deactivation," Revisbn 26, dated October 13, 1997, as the applicable procedure for guidance. However, the team noted that the guidance provided by procedure EP-002-100, Attachment 7.12, " Post Accident Contingencies and Concems," indicated that makeup to the operable WCT basin via the unavailable WCT basin (cross-connect operation) should be established if the operating basin level is less than 5

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percent and the Essential Chiller is using ACCW for cooling. The licensee believed that adequate procedural guidance was provided. The team did not agree with the licensee's i

position. These instructions did not address the concems for the transfer of WCT water to the CSP because of the potential for rapid pump down of the basin and limited makeup capability by the WCT cross-connect. Further, the procedure did not address how the cross-connect operation is to be performed. The lack of procedural guidance regarding ACCW Transfer to the CSP and Basin Cross-connect Operation is identified as URI 50-382/98-201-27.

k. Safeguards Pump Room A Heat Load in CR 97-2062 the licensee identified a concern regarding potential overheating of equipment in Safeguards Pump Room A."A LOCA was postulated with a single failure of essential chiller A, and with the AB HPSI pump in service in place of the Train B HPSI pump. This would result in the Train A HPSI, LPSI, and CSS pumps and the AB HPSI pump (also located in Safeguards Pump' Room A) all operating simultaneously, with room cooling provided by only a single safety-related room cooler.AH-2 (3B-SB)]. Calculation EC-M97-031, Revision 1, Train A Safeguards r

Pump Room Tempecature Rise, was prepared to determine the rate of temperature rise in Safeguards Pump Roam A for this accident scenario. The calculation determined that operator actions would be necessary in about 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to prevent the room temperature from exceeding the qualification limit for tre cump motors. The operator actions would consist of securing the Train A pumps or restoring ope,ttion of essential chiffer A.

The team reviewed calculation EC-M97-031 and determined that the heat generation rates used for the HPSI, LPSI, and CSS pump motors were not conservative. The calculation used pump brake horsepower (BHP) values corresponding to design flow rates rather than worst-case pump runout conditions. A preliminary licensee evaluation indicated that operator actions would be required at about 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> rather than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> if the more conservative pump heat loads were used. There is still adequate time for the operator to recognize, assess, and respond to high safeguards pump room temperature conditions. in addition to revising the calculation, procedure OP-500-013 (Annunciator Response for Control Room Cabinet SA) may

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also require revision, since it currently contains notations referring to the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> room heatup time. The licensee initiated CR 98-0800 to address the concem.

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1. UHS Basin Temperature During Tomado Calculation MN(Q)-17, "Tomado Multiple Missile Protection of UHS," Revision 2, dated September 26,1995, determined the performance of the UHS during shutdown following a

. tomado scenario. Assumption 5.15 indicated that the heat load from the Essential Chiller is

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- dissipated by the WCT ACCW pumps with 105 'F basin water until the DCT, at 60 percent i

Jcapacity, can maintain CCW temperature less than 110 'F, at which time, the essential chilled

' load can be realigned to the CCW eystem.-

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- Within the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the event analysis, the DCT is not available, the WCT in the natural draft mode may not be capable of rejecting the entire heat load, and the remaining heat load is

. absorbed by the water volume of a WCT basin, which may result in a temperature rise above 105 'F. _However, the calculation preserved the assumption of 105 "F, by considering the entire

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heat load to be absorbed by the WCT basin volume resulting in a 25 *F temperature rise from i

an initial temperature of 80 'F to 105 'F. The team noted that the current TS 3/4.7.4 (Ultimate Heat Sink) requires that the average basin water temperature be maintained less than or equal to 89 *F. Before TS Change Request NPF-38-180 submitted on' July 25,1996, the TS required that the average basin water temperature be maintained less than or equal to 95 *F. An initial basin water temperature of 89 *F or 95 'F with the projected first 2-hour post-tomado heat load

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would result in cooling water temperature of 114 'F or 120 'F respectively, to the Essential Chiliers.- The licensee determined that this condition did not impact equipment operability

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because the chiller could operate properly with a maximum cooling water inlet temperature of 120*F.

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The licensee disagreed with this observation and indicated that the basis for verification of UHS capacity was the fact that previous testing showed a potential basin temperature rise to 114 'F

with the tomado head loads applied. The demonstration within the calculation that the 2-hour heat load, when applied to the WCT basin volume at an initial condition of 80 'F results in heatup to 105 *F was provided for information only. Consideration of the TS limiting values

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would only be an enhancement to the calculation. However, the team noted that the 114 'F test results cited appear to conflict with the 105 'F as presented in assumption 5.15. Therefore, the

' licensee's above statement had no basis. The use of non-conservative temperatures in lieu of TS limiting values is identified as URI 50-382/98-201-28.

. E1.5.3 - Conclusions The mechanical design of the systems interfacing with LPSI/SDC, and EFW was genera y n

adequate. However, interactions between nonsafety and safety systems as well as intedacing systems were not properly evaluated. For example, failure of a nonsafety-related nitrogen

. pressure regulator in the nonsafety-related nitrogen system could potentially overpressurize nitrogen lines and affect the safety functions of several safety-related systems.

The team identified several design and configuration control issues. The licensee had not establiched or documented all design-basis water consumption requirements of WCT basins.

In several cases the licensee had not established adequate procedures or instructions to implement design-basis requirements. The corrective actions in some cases were not

. adequate.

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. 1.6 Final Safety Analysis Report and Other Document Reviews ?

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- The followlng FSAR concems were identified by the team during the inspection:

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There is an inconsistency between the FSAR and other licensing documents concerning

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the containment flood level. FSAR Section 3.6A.6.3 states, "All safety related equipment in.

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the RCB is. located above the highest water level of -0.79 ft MSL. Thus; the flooding analysis for RCB is not required." (RCB refers to the reactor containment building.) In the document entitled " Louisiana Power & Light Company, Waterford SES Unit 3, Response to NUREG-0588 (Interim Staff Positions on Environmental Qualification of Safety-Related i

Electrical Equipment)," Section B.1.6 " Submergence," stated that the flood level inside containment is +0.5 ft MSL. This value was determined in calculation MN(Q)-6-4," Water Level inside Containment," Revision 0. The licensee issued CR-98-0750 to resolve the inconsistency..

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Section 8.3.1,1.3 of the FSAR states that in all cases motor rated horsepowers are greater than the normal running load and the associated maximum emergency load. As noted in CR 98-0919 the EFW motors could operate at 520 hp, which is above their rated -

horsepower of 400 hp. The licensee initiated WATS item 88349 to evaluate the FSAR

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' statement.

• Table 8.2-5 of the FSAR states that the 125 Vdc load center buses have a continuous

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rating of _400 amperes. However, the bus would be be subjected to higher current in accordance with battery sizing calculations and FSAR figures 8.3-2,2A and 8.3-3,3A. The licensee's preliminary evaluation indicated that this condition would not affect the function of load center buses because of the split bus arrangement and short duration of peak load.

' The licensee issued ER-W3-98-895-00-00 to resolve this concem.

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Section 8.3.1.1.1 of the FSAR incorrectly identifies the number of safety /nonsafety related MCCs associated with the 480 voit ESF auxiliary system. The licensee initiated LDCR 98-

' 0104 to correct the FSAR.

' Section 3.1.2 o' f the FSAR states that systems and components vital to the mitigation and

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control of incident conditions are designed to withstand the effects of a LOCA coincident with the effects of the safe shutdown earthquake. The design guide (DIEC-!C-502) states that the licensing design basis for Waterford 3 does not require both seismic and accident conditions to be analyzed concurrently. The licensee issued ER-Temp-98-0857 to clarify FSAR and appropriate sections of setpoint design criteria document.

The team identified other minor discrepancies with FSAR, drawings, design basis documents, and TS basis. The licensee took prompt action to initiate appropriate corrective actions.

XI : Exit Meeting Summary

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After completing the onsite inspection, the team conducted an exit meeting with the licensee on l

June'19,1998. During the meeting the team presented the results of the inspection. A list of persons who attended the exit meeting is contained in Appendix B. Proprietary material was i

reviewed during this inspection, but this report contains no proprietary information.

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1.6 Final Safety Analysis Report and Other Document Reviews

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. The following FSAR concems were identified by the team during the inspection:

- There is an inconsistency between the FSAR and other licensing documents conceming

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the containment flood level. FSAR Section 3.6A.6.3 states, "All safety related equipment in

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the RCB is located above the highest water level of -0.79 ft MSL. Thus; the flooding

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analysis for RCB is not required."(RCB refers to the reactor containment building.) in the j

document entitled " Louisiana Power & Light Company, Waterford SES Unit 3, Response to

)

- NUREG-0588 (Interim Staff Positions on Environmental Quali5 cation of Safety-Related Electrical Equipment)," Section B.1.6, " Submergence," stated that the flood level inside containment is +0.5 ft MSL. This value was determined in calculation MN(Q)-6-4, " Water

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Level inside Containment,". Revision O. The licensee issued CR-98-0750 to resolve the inconsistency..

Section 8.3.1.1.3 of the FSAR states that in all cases motor rated horsepowers are greater

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than the normal running load and the associated maximum emergency load. As noted in CR 98-0919 the EFW motors could operate at 520 hp, which is above their rated horsepower of 400 hp. The licensee initiated WATS item 88349 to evaluate the FSAR

.. statement.

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Table 8.2-5 of the FSAR states that the 125 Vdc load center buses have a continuous rating of 400 amperes. _However, the bus would be be subjected to higher current in accordance with battery sizing calculations and FSAR figures 8.3-2,2A and 8.3-3,3A. The licensee's preliminary evaluation indicated that this condition would not affect the function

.of load center buses because of the split bus arrangement and short duration of peak load.

' The licensee issued ER-W3-98-895-00-00 to resolve this concem.

Section 8'.3.1.1.1 of the FSAR incorrectly identifies the number of safety /nonsafety related

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MCCs associated with the 480 volt ESF auxiliary system. The licensee initiated LDCR 98-0104 to correct the FSAR.

Section 3.1.2 of the FSAR states that systems and components vital to the mitigation and

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control of incident conditions are designed to withstand the effects of a LOCA coincident with the effects of the safe shutdown earthquake. The design guide (DIEC-!C-502) states that the licensing design basis for Waterford 3 does not require both seismic and accident conditions to be analyzed concurrently. The licensee issued ER-Temp-98-0857 to clarify

~ FSAR and appropriate sections of setpoint design criteria document.

The team identified other minor discrepancies with FSAR, drawings, design basis documents, and TS basis. The licensee took prompt action to initiate appropriate corrective actions.

-XI Exit Meeting Summary After completing the onsite inspection, the team conducted an exit meeting with the licensee on June 19,1998. During the meeting the team presented the results of the inspection. A list of persons who attended the exit meeting is contained in Appendix B. Proprietary material was reviewed during this inspection, but this report contains no proprietary information.

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1.6l Final Safety Analysis' Report and Other Document Reviews

, The following FSAR concems were identified by the team during the inspection:

There is an inconsistency between the FSAR and other licensing documents concerning

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the containment flood level. FSAR Section 3.6A.6.3 states, "All safety related equipment in the RCB is located above the highest water level of-0.79 ft MSL Thus; the flooding analysis for RCB is not required." (RCB refers to the reactor containment building.) In the document entitled " Louisiana Power & Light Company, Waterford SES Unit 3, Response to i NUREG-0588 (Interim Staff Positions on Environmental Qualification of Safety-Related i

' Electrical Equipment)," Section B.1.6, * Submergence," stated that the flood level inside I

containment is +0.5 ft MSL. This value was determined in calculation MN(Q)-6-4," Water Level inside Containment," Revision O. The licensee issued CR-98-0750 to resolve the

- inconsistency..

Section 8.3.1.1.3 of the FSAR states that in all cases motor rated horsepowers are greater

.

L

~

than the normal running load and the associated maximum emergency load. As noted in l

CR 98-0919 the EFW motors could operate at 520 hp, which is above their rated i

horsepower of 400 hp. The licensee initiated WATS item 88349 to evaluate the FSAR statement.

'

...

Table 8.2-5 of the FSAR states that the 125 Vdc load center buses have a continuous rating of 400 amperes. However, the bus would be be subjected to higher current in accordance with battery sizing calculations and FSAR figures 8.3-2,2A and 8.3-3,3A. The licensee's preliminary evaluation indicated that this condition would not affect the function of load center buses because of the' split bus arrangement and short duration of peak load.

The licensee issued ER-W3-98-895-00-00 to resolve this concem.

!

Section 8.3.1.1.1 of the FSAR incorrectly identifies the number of safety /nonsafety related

.

l MCCs associated with the 480 volt ESF auxiliary system. The licensee initiated LDCR 98-

'

. 0104 to correct the FSAR.

Section 3.1.2 of the FSAR states that systems and components vital to the mitigation and

.

control of incident conditions are designed to withstand the effects of a LOCA coincident l

. with the effects of the safe shutdown earthquake. The design guide (DIEC-!C-502) states

that'the licensing design basis for Waterford 3 does not require both seismic and accident conditions to be analyzed concurrently. The licensee issued ER-Temp-98-0857 to clarify FSAR and appropriate sections of setpoint design criteria document.

The team identified other minor discrepancies with FSAR, drawings, design basis documents, i

l and TS basis. The licensee took prompt action to initiate appropriate corrective actions.

. XI Exit Meeting Summary After completing the onsite inspection, the team conducted an exit meeting with the licensee on June,19,1998. During the meeting the team presented the results of the inspection. A list of persons who attended the exit meeting is contained in Appendix B. Proprietary material was reviewed during this inspection, but this report contains no proprietary information.

..d

..

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APPENDIX A OPEN ITEMS This report categorizes the inspection findings as unresolved items and inspection follow-up items in accordance with NRC Inspection Manual, Manual Chapter 0610. An unresolved item (URI) is a matter about which more information is required to determine whether the issue in

- question is acceptable, a deviation, a nonconformance, or a violation. The NRC Region IV office will issue any enforcement action resulting from their review of the identified URis. An inspection followup item (IFI)is a matter that requires further inspection because of a potential problem, because specific licensee or NRC action is pending, or because additional information is needed that was not available at the time of the inspection. The URis and IFis found in this inspection are listed below:

ltem Number Finding Ittig TYRS 50-382/98-201-01a,b,c URI Single Active Failure Analysis (Section E1.2.1.2(a)(b)(c))

50-382/98-201-02 URI ECCS Leakage Test Acceptance Criteria (Section E1.2.1.2(e))

50 382/98-201-03

URI Dose Consequences of RWSP Back-Leakage (Section E1.2.1.2(f))

50-382/98-201-04 URI Containment Sump Isolation Valve Leakage Testing (Section E1.2.1.2(g))

50-382/98-201-05 URI LPSI Pump Minimum Flow (Section E1.2.1.2(h))

50-382/98-201-06 URI CSP Level Measurement (Section E1.2.2.2(a))

50-382/98-201-07 IFl Steam Generator Level Transmitter Failure (Section E1.2.2.2(b))

50-382/98-201-08 URI EFW Discharge Check Valve Testing (Section E1.2.2.2(c))

50-382/98-201-09 IFl EFW Tomado Missile Protection

'

(Section E1.2.2.2(d))

50-382/98-201-10 URI 10 CFR Part 21 Reviews (Section E1.3.2(a))

50-382/98-201-11 URI USO Issue and EDG Dynamic Analysis (Section E1.3.2(b))

A-1

-,=

,.. ~4 ~,

..

50-382/98-201-12.

URI '

10 CFR 50.59 Evaluation - Battery Modification (Section E1.3.2(c))

50-382/98-201-13 IFl EDG Loading (Section E1.3.2(d))

50-382/98-201-14 URI Nonsafety Load Sequencing (Section E1.3.2(e))

50-382/98-201-15 URI Battery Charger and inverter Operation at

. Degraded Grid Voltage (Section E1.3.2(f))

50-382/98-201-16 IFl

' EDG Load Sequencing Test Procedure (Section 1.3.2(g2))

50-382/98-201-17 IFl Battery Surveillance Test (Section E1.3.2(g3))

50-382/98-201-18 URI instrument Accuracy (Section E1.4.2(a))

50-382/97-201-19 IFl UHS Basin Capacity (Section E1.5.2(a))

50-382/97-201-20 URI Procedure For SFP Cooling (Section E1.5.2(b))

50-382/97-201-21 URI SFP Makeup Requirements (Section E1.5.2(c))

50-332/97-201-22 URI Potential Overpressure of Nitrogen System

.

-

(Section E1.5.2i,

"

50-382/97-201-23 URI EFW Pump Room HVAC (Section E1.5.2(f))

50-382/97-201-24 IFl CSP Water Level (Section E1.5.2(g))

50-382/97-201-25 IFl ACCW-EFW Suction Path Testing (Section E1.5.2(h))

50-382/97-201-26 IFl WCT Basin /ACCW Pump Vortex (Section E1.5.2(l))

50-382/97-201-27 URI ACCW Transfer / Cross-Connect (Section E1.5.2(j))

50-382/97-201-28 URI UHS Basin Temperature (Section E1.5.2(l))

.

A-2 l

p.<.

r, L.

APPENDIX B EXIT MEETING ATTENDEES Enterav Ooerations. Inc (EOli

,

C. Dugger, Vice President, Operations F. Titus, Vice President, Engineering l

A. Wrape lil, Director, Design Engineering -

' E. Ewing, Director, Nuclear Safety and Regulatory Affairs D. Vinci, Manager, Plant Engineering l

C. Fugate, Superintendent, Operations l

J. Houghtaling, Technical Assistant, Design Engineering l

J. Holman, Manager, Safety Analysis R. Burski, Director, Plant Modifications and Construction.

l G. Pierce, Director, Quality Assurance J. Lewis, Manager, Emergency Planning J. Howard, Manager, Procurement / Programs Engineering

,

'

J. Burke, Supervisor, Civil Engineering D. Viener, Supervisor, Mechanical Engineering i

L. Rushing, Manager, Mechanical Engineering.

l R. Allen, Manager, Operational Experience Engineering L

T. Brennan, Technical Coordinator, Design Engineering L

P. Jackson, Supervisor, Design Engineering j

D. Gallodoro, Supervisor, Configuration Management l

P. Gropp, Manager, Design Engineering, Electrical /l&C

'

E. Brauner, Systems Engirieer

-

L M. Kliebert, Systems Engineer

.

i M. Be.rendt, Systems Engineer P. Stanton, Design Engineer

K. Cook, Design Engineer.

R. Gilmore, Design Engineer

,

l C.. Thomas, EOl C. Garbe, Design Engineer l

T. Fleischer, Design Engineer

'

V. Coy, Design Engineer l

. E. Field, Lead Design Engineer i

J. Breyne, Systems Engineer E. Beckendorf, Security l

D. Cooks, Specialist, Site Support l

S. Workman, Design Engineering l

M. Cooper, Licensing Specialist, ANO-1

'

'

R. Putnam, Design Engineer P. Wagner, Consultant /EOl S. Melancon, Consultant /EOl

' G. Matharu, Engineering Supervisor Z. Wahab, Technical Coordinator, Design Engineering D. Urciuoli, Licensing Engineer B-1

n.A.

,

U.S. Nuclear Reaulatorv Commission I

f'

D. Norkin, NRR -

R. Mathew, NRR T. Famholtz, RIV

. J. Keeton, RIV T. Stetka, RIV '

R. Najuch, Team Member M.~ Yeminy, Team Member D. Vandeputte, Team Member

"

P. Bienick, Team Member D. Schuler, Team Member-

.

1 l

'

B-2

e -i A.

-

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- APPENDlX C ACRONYMS ABB/CE ASEA Brown Boveri Combustion Engineering Nuclear Power ac, AC Alternating Current -

ACCW Auxiliary Component Cooling Water acfm Actual Cubic Feet Per Minute ASME

. American Society of Mechanical Engineers BAM Boric Acid Makeup bhp

. Brake Horse Power CR Condition Report CCW Component Cooling Water CSAS Containment Spray Actuation System CS Containment Spray.

CSP Condensate Storage Pool

' CSS Containment Spray System CVAS:

Controlled Ventilation Area System DBA Design Basis Accident DBD Design Basis Document DBR Design Basis Review de, DC.

Direct Current DCN Design Change Notice DCT Dry Cooling Tower E-Plan Emergency Plan ECCS.-

Emergency Core Cooling System EDG Emergency Diesel Generator EFW Emergency Feedwater EOP Emergency Operating Procedure.

ER-Engineering Request ESF Engineered Safety Features ESFAS Engineered Safety Features Actuation System FSAR Final Safety Analysis Report hp, HP Horse Power HPSI High Pressure Safety injection HVAC Heating, Ventilation,Airconditioning IEEE Institute of Electrical and Electronic Engineers IFl Inspection Followup item

'

ILRT Integrated Leak Rate Test IN information Notice

'

IP Inspection Procedure IST Inservice Test kV Kilovolt kW Kilowatt IST Inservice Test LCO Limiting Condition of Operation C-1

oA.

i

'

LDCR'

Licensing Document Change Request

,LER-Licensee Event Report '

LOCA-Loss-of-Coolant Accident

[

' LOOP Loss-of-Offsite Power

!

LPSI Low Pressure Safety injection MCC Motor Control Center MSLB Main Steam Line Break

NPSH Net Positive Suction Head NRC U.S. Nuclear Regulatory Commission NRR, Office of Nuclear Reactor Regulation NUREG NRC Technical Report Designation PCT Peak Clad Temperature ppm

' Parts per Million PPS Plant Protection System PRA Probabilistic Risk Assessment psia Pounds per Square Inch Absolute psig Pounds per Square inch Gage RAB Reactor Auxiliary Building RAS Recirculation Actuation Signal RCB Reactor Containment Building-RCS Reactor Coolant System RG

. Regulatory Guide RWSP Refueling Water Storage Pool RWT Repetitive Work Task SBO

.. Station Blackout scfm

' Standard Cubic Feet per Minute SDC Shutdown Cooling -

SER, Safety Evaluation Report SFP_

~ Spent Fuel Pool SlAS Safety injection Actuation Signal SIS Safety injection System SRP Standard Review Plan SMR Station Modification Request SSFl Safety System Functional inspection SWEC Stone & Webster Engineering Corporation TMI Three Mile Island TRM Technical Requirements Manual TS Technical Specifications TSC Technical Support Center UHS Ultimate Heat Sink UPS Uninterruptible Power System URI Unresolved item USO Unreviewed Safety Question VCT Volume Control Tank

.WA Work Authorization i

WATS Waterford Action Tracking System

'

WCT Wet Cooling Tower

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,

,-

C-2

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• lklfY ft l

~

Distribution:

Docket File (50-382)

PUBLIC PIPB R/F.

BSheron FGillespie RBorchardt RMathew i

CPatel l

JHannon

,

- DNorkin EAdensam CRossi, AEOD

TFamholtz, SRI JWiggins, RI i

BMallett, Ril

'

JGrobe, Rlll EMerschoff, RIV TGwynn, RIV AHowell, RIV TStetka, RIV i

PHarrell, RIV ACRS OGC g

t'

I i

.