ML18151A610

Submits Response to Violations Noted in Insp Repts 50-280/98-201 & 50-281/98-201.Corrective Actions:Development of New Analysis for Voltage Drops for EDG DC Loads Will Be Completed by 991216

ML18151A610
Person / Time
Site:	Surry
Issue date:	07/09/1998
From:	Ohanlon J VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
50-280-98-201, 50-281-98-201, 98-300, NUDOCS 9807160247
Download: ML18151A610 (63)

See also: IR 05000280/1998201

Text

• * * VIRGINIA ELECTRIC AND POWER COMPANY RicHMOND, VIRGINIA 23261 July 9, 1998 United States Nuclear Regulatory

Commission

Attention:

Document Control Desk Washington, D. C. 20555 Gentlemen:

VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 RESPONSE TO SURRY PLANT DESIGN INSPECTION

Serial No. NL&OS/SLW

Docket Nos. License Nos. NRC INSPECTION

REPORT NOS. 50-280/98-201

AND 50-281/98-201 98-300 R1 50-280 50-281 DPR-32. DPR-37 We have reviewed Inspection

Report No. 50-280/98-201

and 50-281/98-201

dated May 11, 1998 for Surry Units. 1 and 2: This report documents

the NRC's plant design inspection

conducted

February 16, 1998 through March 27, 1998. As requested

in the Inspection

Report, we have developed

a schedule and corrective

action plan for the unresolved

and inspector

follow-up

items identified

in Appendix A of the report. Immediate

corrective

actions have been taken for items of potential

safety significance

and action plans for aggressive

resolution

of the remaining

open items have been developed.

The specific schedule and corrective

action plan for each item is provided in Attachment

1. The Inspection

Report also noted items of a programmatic

concern. The corrective

actions taken to date and the plan to resolve these corrective

action,. configuration

management

and engineering

calculation

process issues are provided in Attachment

2. This plan includes provisions

to 1) conduct a root cause evaluation

of uncompleted

corrective

action resulting

from the internal Electrical

Distribution

System Functional

Assessment, 2) evaluate the applicability

of the Inspection

Report's results and findings to other plant systems and components, and 3) assess their impact on our earlier response to the NRC's 10 CFR50.54(f)

request for information

dated October 9, 1996. A summary of the commitments

made to resolve issues identified . in the Inspection

\ Report is provided in Attachment

3. Additionally, we are addressing

discrepancies

and weaknesses

identified

in the Inspection

Report, but not included in the cover letter or Appendix A. These items have been . assigned to responsible

individuals

for resolution, action plans are being developed

and the items are being tracked in our corrective

action program . -*. r, 9807160247

980709280.

PDR ADOCK 05000 G PDR ;( (,0 \ \,-*' /

• * * We have no objection

to this letter being made part of the public record. Please contact us if you have any questions

or require additional

information.

Very truly yours, Senior Vice President

-Nuclear Attachments

cc: US Nuclear Regulatory

Commission

Region II Atlanta Federal Center 61 Forsyth Street, S.W., Suite 23T85 Atlanta, Georgia 30303 Mr. R. A. Musser NRG Senior Resident Inspector

Surry Power Station

• * * SERIAL NO.98-300 ATTACHMENT

1 CORRECTIVE

ACTION PLANS FOR UNRESOLVED

ITEMS AND INSPECTOR

FOLLOW-UP

ITEMS

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-01

IFI LHSI Pump NPSH (Section E1 .2.1.2(d))

NRC ISSUE DISCUSSION

Serial No.98-300 ATIACHMENT

1 "The most limiting case for the NPSH available

to the LHSI pumps was determined

to be at the time of switchover

to cold leg recirculation

from the containment

sump. The most limiting accident scenario was the double-ended

pump suction guillotine (DEPSG) break with minimum safeguards

and maximum SI single train flow. These calculations

determined

that the available

NPSH of 16.7 ft at the time of switchover

to recirculation

phase exceeded the required NPSH. of 15.8 ft (.9 ft NPSH margin). To justify the available

NPSH of 16.7 ft, a containment

overpressure

of 12 ft and a containment

water height of 4.2 ft was credited.

The team noted that the use of containment

overpressure, which is the difference

of containment

pressure and sump vapor pressure, has generally

not been encouraged

by the NRG as indicated

in Regulatory

Guide 1.1, "Net Positive Suction Head for Emergency

Core Cooling and Containment

Heat Removal System Pumps" and NUREG 800, "Standard

Review Plan," Section 6.2.2. However, in the various correspondences

held between the NRG and Virginia Electric & Power Company (VEPCo) during the period from 1977 to 1978, the team found that VEPCo had always credited the use of containment

overpressure

in determining

the available

NPSH for the LHSI pump. Based on the small amount of NPSH margin available

to the LHSI pumps, and because there is a potential

negative impact on pump NPSH from containment

sump screen blockage, which is discussed

in the RS system review (Section E.1.3.1.2(c)), the team identified

the determination

of available

NPSH to the LHSI pump as an Inspection

Followup Item 50-280/98-201-01." VIRGINIA POWER RESPONSE The existing analysis results for Low Head Safety Injection (LHSI) pump available

Net Positive Suction Head (NPSH) demonstrate

that conditions

are sufficient

for the pumps to perform their safety-related

function.

This determination

is based upon conservative

analyses of the large break loss of coolant accident (LOCA) design basis accident scenario which establishes

the most demanding

conditions

for core an*d containment

heat removal from the LHSI pumps. The limiting scenario has been established

by prior analysis sensitivity

studies as a double-ended

guillotine

break in the pump suction piping. The analysis of NPSH for the LHSI pumps employs conservatisms

of the following

type: Page 1 of 46

, ** * * ------------------------

• Scenario development . Break flow model, break size and location Loss of offsite power Limiting single active failure * Key modeling assumptions

Serial No.98-300 ATTACHMENT

1 Core decay heat _is* calculated

using ANS Standard ANSI/ANS-5

1979 plus * 2 sigma uncertainty

Use of pressure flash break effluent model, which assumes fluid expands at constant enthalpy to the containment

total pressure.

Saturated

vapor goes* to atmosphere;

saturated

• liquid goes to sump (unmixed with atmosphere)

• Limiting values of key analysis parameters

Maximum Containment

Spray (CS), Inside Recirculation

Spray (IRS) and Outside Recirculation

Spray (ORS) spray thermal efficiency

Minimum Refueling

Water Storage Tank (RWST ) Water Volume Maximum RWST Level Setpoint for Recirculation

Mode Transfer (RMT) Maximum RWST Temperature

Minimum Service Water (Service Water) Flowrate Maximum Service Water Temperature

Maximum Containment

Bulk Average Temperature

Minimum Containment

Initial Air Partial Pressure Minimum IRS and ORS Flowrate (assumed for heat removal) Maximum LHSI flowrate for establishing

required NPSH Minimum CS Flowrate The existing recirculation

spray and LHSI pump NPSH analysis for Surry takes credit for. containment

pressure during the design basis LOCA to provide a part of the available

NPSH. The calculation

method uses the modeling and parameter

assumptions

listed above to obtain a conservative

prediction

of containment

pressure (underestimated)

and the sump water temperature (overestimated)

transients.

The containment

response analysis minimizes

the energy release to the containment

atmosphere

and maximizes

the energy release to the sump water. This is accomplished

by employing

conservative

modeling (pressure

flash model) of the break mass and . energy releases in the LOCTIC containment

response computer code. Virginia Power summarized

the analysis results and approach concerning

use of containment

overpressure

in the response to Generic Letter 97-04 (Reference

1 ). Reference

1 indicated

that this approach is consistent

with existing regulatory

guidance for plants with subatmospheric

containments, as described

in NUREG-0800, Section 6.2.2. The existing analysis approach, which credits a conservative

transient

analysis for containment

overpressure, was first employed during 1977, following

notification

from SWEC of inadequacies

in the analysis and system design of the recirculation

spray and low head safety injection

subsystems.

There were numerous letters between VEPCO and NRC during 1977 and 1978 addressing

the analyses and proposed modifications

to Page 2 of 46 I I

• * * Serial No.98-300 ATTACHMENT

1 resolve the NPSH issue for Surry. The NPSH analysis methodology

was the subject of March 2, 1998 meeting with several of the NRG inspectors

during the recent Surry A/E inspection.

Several key letters relating to licensing

of this approach for Surry were provided to the inspectors

following

this meeting and are summarized*

in Table 1. This correspondence

indicates

that NRG staff was aware of Virginia Power's methodology

to credit containment

overpressure

and found these methods and calculation

results acceptable

for Surry. The NPSH analysis results reported in Reference

1 are among the analyses submitted

with the Surry core power uprating request (Reference

2) and are currently

reflected

in Tables 6.2-12 and 6.2-13 of the Surry UFSAR for the safety injection

and recirculation

spray pumps, respectively.

During the fall of 1997, an assessment

was performed

for changes which involved removal of concrete heat sinks and relaxation

of the recalibration/recertification

schedules

for certain containment

RTDs used in monitoring

key parameter

initial conditions.

These changes modified the reported NPSH results from the previously

submitted

uprating analysis.

This assessment, which represents

a sensitivity

and supplements

the prior analysis, was implemented

under the provisions

of 1 OCFR50.59.

The UFSAR updates, which reflect the revised results, have been approved by the Station Nuclear Safety and Operating

Committee (SNSOC) and are being incorporated

into the UFSAR. COMPLETION

SCHEDULE No further action is needed with regard to the issue of crediting

a conservatively

derived containment

overpressure

for pump NPSH analysis.

With regard to the impact on pump NPSH from sump screen blockage, Virginia Power has included evaluation

of the effects of sump screen blockage on LHSI and RS pump suction head losses in the actions identified

to address item IFl-98-201-20 (Unqualified

Coatings).

REFERENCES

1. Letter from James P. O'Hanlon to USNRC, "Virginia

Electric and Power Company-Surry

Power Station Units 1 and 2, North Anna Power Station Units 1 and 2-Response

to NRC Generic Letter 97-04, Assurance

of Sufficient

Net Positive Suction Head for Emergency

Core Cooling and Containment

Heat Removal," Serial No. 97-594A, 12/29/97.

2. Letter from ;James -,p_ O'Han1on to *usNRC, "Virginra

Electric*

and Power Company-Surry

Power Station Units 1 and 2-Proposed

Technical

Specifications

Changes to Accommodate

Core Uprating," Serial No.94-509, 8/30/94 . Page 3 of 46

Table 1 Serial No.98-300 ATTACHMENT

1 * Licensing

Correspondence

Concerning

NPSH Analysis Methods & Overpressure

Credit Item 1 2 3 4 * 5 6 * Document Description

Section 6.2.2 of the Standard Review Plan. VEPCO 10-15-70 and 3-15-71 response to AEC question 6.11 VEPCO 8/20/77 submittal (Serial No. 362) justifying

continued

operation

with less than the desired. NPSH tff the recirculation

spray pumps. NRC 8/20/77 Safety Evaluation

for the NPSH problem at Surry .. VEPCO . 8/24/77 submittal (Serial No. 366) transmitting

the detailed report of tests and analyses for the NPSH issue. NRC Order for Modification

of License dated 8/24/77. Purpose N/A. This response provides the formula used for calculating

the NPSHa and . specifically

states that credit is taken for pressurization

of the containment.

This submittal

provides documentation

from the pump manufacturer

to indicate that the pumps will continue to operate to a minimum NPSH of 7 feet. Documents

NRC awareness

of the identified

problem with the NPSHa as a result of new considerations

in the overall thermodynamic

model. In this SE, the NRC specifically

acknowledges

that, "The calculated

pressure of the containment

and the temperature

of the water that accumulates

• in the containment

sump are important

parameters

in determining

recirculation

cooling pump operability

following

a LOCA with regard to available

NPSH. These terms in combination

with the pump static head and associated

line losses establish

available

NPSH during the transient." Documents

that adequate NPSH would be available

for the I RS pumps but not the . ORS pumps during a LOCA. (Adequate

safety is assured by the inside pumps). Commits to installing

flow-limiting

orifices in the discharge

of the outside recirculation

spray pumps. Requested

additional

analysis from * *vEPCO on *the NPSH issue. Also, the N RC again specifically

acknowledged

that, "The calculated

pressure of the containment

and the temperature

of the water that accumulates

in the containment

sump are important

parameters

in determining

recirculation

cooling pump operability

followinq

a Page 4 of 46

• 7 8 * * VEPCO 9/12/77 submittal (Serial No. 382/082477)

providing

the * analyses requested

in the N RC order of 8/24/77. NRC Order for Modification

of License dated 10/17177.

Serial No.98-300 ATTACHMENT

1 LOCA with regard to available

NPSH. These terms in combination

with the* pump static head and associated

line losses establish

available

NPSH during the transient." This submittal

provides the requested

curves showing the response of containment

total pressure, containment

vapor pressure, available

NPSH, sump water level, and sump water vapor pressure.

The NRC specifically

states that for the analyses submitted

on 9/12/77, "The methods used to calculate

the containment

pressure, containment

sump temperature, and available

NPSH have been reviewed for the North Anna plant and found to be acceptable.

The same methods were used in calculations

for Surry." Page 5 of 46

ITEM NUMBER 50-280/98-201-02

Serial No.98-300 ATTACHMENT

1 * FINDING TYPE IFI * * DESCRIPTION

Error in Calculation

SM-1047, "Reactor Cavity Water Holdup" (Section E1 .2.1.2(d))

NRC ISSUE DISCUSSION

• "Calculation

SM-1047, "Reactor Cavity Water Holdup," Revision 1 failed to account for some of the water volume lost over a period of time from the containment

floor. This error resulted in derivation

of containment

water height which was greater than that would actually occur during an accident.

SM-1047 identified

the various sources which added water to the containment

and the paths which drained water from. the containment

floor. The team's purpose of reviewing

SM-1047 was to verify that the containment

flood height values used in calculation

01039.6210-US-(B)-107, "Containment

LOCA Analysis for Core Uprate," Revision O was conservative

.. Calculation

01039.621O-US-(B)-107

was used to determine

the NPSH requirements

for the IRS, OR~ and LHSI pumps. The team found that SM-1047 did not account for loss of water from the containment

floor to the reactor cavity. Approximately

9 percent of the containment

spray flow would be lost to the refueling

canal which drained to the reactor cavity. Because SM-1047 was revised near the end of the inspection

period, the team did not have an opportunity

to review the latest SM-1047-calculation.

The team identified

review of SM-1047 and comparison

of SM-1047 results to calculation

01039.621O-US-(B)-107

as an lnspectio_n

Followup Item 50-280/98-201-02." VIRGINIA POWER RESPONSE Calculation

SM-1047, Revision*

2, was issued on March 18, 1998 to address this diversion

of water and several other issues which were raised by Westinghouse

Nuclear Safety Advisory Letter, NSAL-97-009, 11 Containment

Sump Volume lssues, 11 dated October 27, 1997. The following

summarizes

the results of Calculation

SM-104 7, Revision 2, as compared with the results of calculation

01039.6210-US(B)-107.

The purpose of SM-1047, Revision 2, is to determine

the water holdup in the reactor cavity after a LOCA. The limiting cases for IRS, ORS and LHSI NPSH are considered.

This calculation

evaluated

the effects of the following

phenomena

on the available

safeguards

pumps Net Positive Suction Head (NPSH) following

a design basis Loss Of Coolant Accident (LOCA): 1) -holdup of-spray-water

in *the *reactor cavity; 2) recirculation

spray piping fill volume; 3) draining condensate

films on passive heat sinks in containment;

4) suspended

spray droplets in the containment

atmosphere.

Based on the calculation

results, the following

penalties

must be applied to the current NPSH available

results from calculation

01039.621O-US(B)-107.

These penalties

reflect the integrated

effects of the phenomena

listed above . * Outside Recirculation

Spray Pumps (ORS): -0.15ft Page 6 of 46

• * * * Inside Recirculation

Spray Pumps (IRS): * Low Head Safety Injection

Pumps (LHSI): -0.16 ft -0.17 ft Serial No.98-300 ATTACHMENT

1 The NPSH available, taking into account these minor penalties, remains acceptable

for the IRS, ORS and LHSI pumps. In addition, the phenomena

addressed

in this calculation

have no impact on containment

peak pressure, containment

depressurization

time, containment

subatmospheric

peak pressure or reported doses for the e.xclusion

area boundary or low population

zone. Changes to the Surry UFSAR are required.

COMPLETION

SCHEDULE The required UFSAR changes to reflect the calculated

NPSH analysis penalties

will be incorporated

into the Surry Safety Injection (SI) system UFSAR change packages compiled under the Design and Licensing

Basis Integrated

Review program. The UFSAR changes associated

with the Safety Injection

System, are to be incorporated*

into the UFSAR by August 31, 1998 . Page 7 of 46

• * * 50-281/98-201-03

URI Serial No.98-300 * * ATTACHMENT

1 ITEM NUMBER FINDING TYPE DESCRIPTION

Unit 2 LHSI Pump Minimum Flow (Section E1 .2.1.2(g))

NRC ISSUE DISCUSSION "The team had concerns with the design of the Unit 2 SI system to be able provide adequate minimum flow for continuous

LHSI pump operation.

The team's review of P&los* (11448-FM-089A, sh 1, Rev. 53, sh 2, rev 46 and sh 3, Rev. 46) found that the SI system piping configuration

was such that there was a potential

for pump-to-pump

interaction

if the discharge

pressure of one LHSI pump was stronger than. the other pump. Because of the location of the miniflow line which was downstream

of the check valves in the pump discharge

header, there was a potential

for the check valve associated

with the weaker pump to become backseated

by the higher discharge

pressure of the stronger LHSI pump. This would result in *a loss of pump miniflow for the weaker LHSI pump and operation

of the pump in a dead-headed

condition.

Parallel operation

of the LHSI pumps would be a concern during those accident scenarios

where the LHSI pumps would start and operate but would not immediately

inject into the reactor coolant system (RCS). For a small break LOCA, both LHSI pumps would start, but since the reactor coolant pressure was high the pumps would operate in parallel in the minimum flow mode. In this situation, the operators

would secure one of the LHSI pumps if RCS pressure was greater than 185 psig per step 13 of the emergency

operating

procedure (EOP), E-0. According

to licensee, the operators

would reach step 13 in the EOP no later than 30 minutes into the accident The licensee agreed with the team's concern that the SI system design was such that there was a potential

for dead-heading

the SI pumps. Because the licensee had not ever measured individual

LHSI pump flow with both LHSI_ pumps operating

in parallel, the engineers

performed

an evaluation

ME-0375, "LHSI Pumps Minimum Flow Recirculation

to RWST With No Flow to. Reactor Coolant System During Small Break LOCA," Revision 0, Addendum A to assess this condition.

ME-0375 determined

that. the flow division for the Unit 1 LHSI pumps was satisfactory

and above t~e minimum flow recommended

by the pump manufacturer.

the pump vendor, Byron Jackson, had informed the licensee in their 8 July 1988 letter that a minimum flow of 150 gpm was originally

specified

for the LHSI pumps. Th~ evaluation

indicated

that the flow between the Unit 1 LHSI pumps were evenly *balanced

with 52 percent of the total flow (201 gpm) being provided by one of the LHSI pumps and the remainder, 48 percent of total flow or 182 gpm, being provided by the second LHSI pump. Evaluation

ME-0375 also showed that the flow division between the Unit 2 LHSI pumps did not ensure minimum pump flow requirements

through both pumps. The evaluation

calculated

that there was a flowrate of about 95 percent (359 gpm) through the stronger Page 8 of 46

• * * Serial No.98-300 * ATTACHMENT

1 pump with the remainder

of flo~ (5 percent or about 18gpm) going through the weaker ,Unit 2 LHSI pump. Because the weaker Unit 2 LHSI pump (2SI-P-1A)

could not provide the minimum pump flow of 150 gpm when both LHSI pumps were operating

in parallel, the licensee performed

an evaluation

ET.CME 98-014, "Evaluation

of Operation

of LHSI Pumps Recirculating

to the RWST," Rev. 02, March 24, 1998, to determine

the operability

of the 2SI-P-1A pump. The licensee concluded

that the 2SI-P-1A pump was operable based on the following:

• There was documented

evidence to demonstrate

that the LHSI pumps have accumulated

about 65 minutes of operation

in low flow conditions

with no observable

adverse effect on their performance.

The licensee conducted

a review of past LHSI pump operation

and found that there had been about seven instances

of SI actuations

in which the LHSI pumps had operated in the minimum recirculation

flow mode. The maximum documented

SI duration was for 25 minutes on February 2, 1975. * * A review of periodic surveillance

tests and work orders for the 2SI-P-1A pump showed that the pump performance

had not degraded, and pump vibration

readings * were normal. * "Flashing" at the low flow condition

of 18 gpm was calculated

to occur at around 60 minutes into the low flow condition.

Under the scenario where both LHSI pumps were operating

under minimum flow conditions, the licensee estimated

that the operators

would secure one of the LHSI pump within 30 minutes into this event. The licensee estimate of 30 minutes was based on the time it would take the operators

to reach a section in the EOP which required operators

to make a decision on whether both LHSI pumps were necessary.

The team agreed that operator intervention

to secure one of the two Unit 1 LHSI pumps within 30 minutes to preclude the potential

for pump-to-pump

interaction

was a reasonable

resolution

to this design deficiency.

However, the team needed to review. the licensee's

long term resolution

to the pump-to-pump

interaction

issue with the Unit 2 LHSI pumps. The team concluded

that lack of test data which demonstrated

pump operability

with significantly

reduced minflow and the pump's inability

to pass vendor recommended

mitiflow were potential

operability

concerns.

The licensee issued DR 98-0660 to take corrective

actions. The team identified

the licensee's

long term resolution

to the Unit 2 LHSI pump minimum flow issue as URI 50-281/98-201-03.

The team also determined

that the licensee's

response to IE Bulletin 88-04 was inadequate

in that their response (VEPCo letter of August 8, 1988, serial no. 88-275A) failed to identify that there was pump-to-pump

interaction

issue associated

with the Unit 2 LHSI pumps which could result in near dead.:headed

condition

for the 2SI-P-1A pump." Page 9 of 46

• * * VIRGINIA POWER RESPONSE Background

Serial No.98-300 * ATTACHMENT

1 The two Low Head Safety Injection (LHSI) pumps for each unit share a common recirculation

line to the Refueling

Water Storage Tank (RWST). The recirculation

line ensures that there is a flow path for the pumps in the event that the pumps are started when Reactor Coolant System (RCS) pressure is greater than the shutoff head of the pumps. This can occur during injection

phase following

a Small Break LOCA or following

the receipt of an erroneous

SI initiation

signal. The recirculation

line is also used to perform quarterly

testing of the pumps. Westinghouse

indicated

in a letter that the LHSI pumps purchased

for Surry Power Station had very flat Total Developed

Head (TOH) curves and pointed out that there might be a problem operating

the two LHSI pumps in parallel discharging

to the RWST through the common minimum flow recirculation

line. In 1988, a test was performed

on the Surry Unit 1 LHSI pumps in response to the Westinghouse

letter. The test ran each pump individually

on recirculation

and gathered information

on flow, head and vibrations, then ran the two pumps in parallel and gathered information

on flow and head, to determine

if a strong/weak

pump relationship

exists. The test demonstrated

that there was little difference

between the performance

of the two pumps and, thus, the ability of the two LHSI pumps to operate in parallel discharging

through a common recirculation

line without one pump deadheading

the other. The vibration

data, taken on the pumps operating

individually

on both recirculation

lines, was well within specification.

No vibration

data was taken while the two pumps were running in parallel.

The results of the tests were forwarded

to Byron Jackson (BW/IP), the original supplier of the LHSI pumps, for their evaluation.

BW/IP confirmed

that the existing Surry LHSI pump miniflow lines are adequate for . parallel and single pump operation

based on current operating

practices

and repair history, but cautioned

against operation

with a pump discharge

valve* shut. The manufacturer

pointed out that the original minimum recircul.ation

flow for the LHSI pumps was 150 gpm per pump, based only on thermal concerns.

They now recommend

a minimum recirculation

flow of about 30 percent of rated flow to address hydraulic

instabilities

as well as thermal concerns, if the pump is to be run for extended periods of time (i.e., hours) on the recirculation

line. BW/IP pointed out that since the head capacity curve for the Surry LHSI pumps are essentially

flat for flow rates of less than 500 gpm, it is possible for one pump to reduce the flow through the companion

pump to levels less than 150 gpm in a circumstance

where one pump was severely limited in capacity because of excessive

wear or some other factor. NRG IE Bulletin 88-04, was issued on May 5, 1988. The NRG IE Bulletin requested: " ... all licensees

to investigate

and correct as applicable

two miniflow design concerns.

The first concern involves the potential

for the dead-heading

of one or more pumps in safety-related

systems that have a miniflow line common to two or Page 10 of 46

• * * Serial No.98-300 * ATTACHMENT

1 more pumps or other piping. configurations

that do not preclude pump-to-pump

interaction

during miniflow operation.

A second concern is whether or not the . installed

miniflow capacity is adequate for even a single pump in operation." Engineering

evaluated

the LHSI pump recirculation

lines and forwarded

the results of the evaluation

in a Technical

Report to Surry Power Station on August 8, 1988. Information

in the report was included in the Virginia Power reply to the NRG on IE * Bulletin 88-04. Since the miniflow recirculation

line for the two LHSI pumps was originally

sized for thermal protection

rather than to preclude possible hydraulic

instabilities, Virginia Power conservatively

determined

that the Surry LHSI system design would not support continuous

operation

in dual pump configuration.

However, it was concluded

that the design of the LHSI system is adequate for the modes and duration of operation.

expected under normal and accident conditions.

Because the piping configuration

for the LHSI * miniflow recirculation

line does not preclude pump interaction

during parallel operation, and the LOGA analysis assumes only one operating

LHSI pump, it was further concluded

that, if conditions

warranted, the second LHSI pump can be secured. As a result of an NRG commitment

in NRG IE Bulletin 88-04, Virginia Power performed

an evaluation

of a small break LOGA scenario on the simulator

to verify that the Surry Emergency

Operating

Procedures (EOPs) adequately

address and, therefore, minimize operation

of the LHSI pumps in the recirculation

mode. It was determined

that an emergency

procedure

revision was necessary

to ensure that one LHSI pump will be secured within 30 minutes when operating

in parallel with low flow conditions.

The EOP was revised to secure one LHSI pump during recirculation

only flow conditions.

Discussion

As a result of the NRG A/E Inspection*

questions, which relate to operation

of the Surry LHSI pumps on the minimum flow recirculation

line to the RWST, Engineering

has evaluated

Virginia Power's previous responses

to NRG IE Bulletin 88-04. Building on the test that was conducted

in 1988, Mechanical

Engineering

prepared a calculation

to confirm the conclusions

drawn from the test. The original vendor witness curves for the Unit 1 pumps were reviewed.

The curves show that the Unit 1 pumps are well matched at flows less than 500 gpm, so deadheading

of one pump by the other is not a concern when operating

in parallel with flow directed to the RWST through the recirculation

line. T~e calculational

results indicate that the flow split for these two pumps when * recirculating

to the RWST is about 52% for the strong pump. and 48% for the weak pump. Thus, both pumps will flow at least the 150 gpm recommended

by the pump vendor. Also, the recent pump test data for the two Unit 1 pumps confirm that the pump heads have not degraded.

The analysis supports the conclusion

that the minimum flow recirculation

line for Surry Unit 1 LHSI pumps is adequate for the modes and duration of operation

expected under normal and accident conditions.

Page 11 of 46

• * * Serial No.98-300 * ATTACHMENT

1 No parallel operation

testing was performed

on the Unit 2 pumps in 1988, as it was assumed that the Unit 1 configuration

was typical for both units. However, a review of the Surry Unit 2 LHSI pump curves indicates

that these pumps are not as well matche*d as the Unit 1 pumps at flows less than 500 gpm. The original vendor witness curves for the Unit 2 pumps were revjewed.

The curves show that 2-SI-P-1A

is a "weak" pump with a Total Developed

Head (TOH) at shutoff about 5 1 feet less than 2-SI-P-1 B. The stronger 'B' pump will provide the majority of the recirculation

flow at flows less than 350 gpm. Calculational

results indicate that the flow split for these two pumps when recirculating

to the RWST is about 95% for the strong pump and 5% for the weak pump. Because the recirculation

flow for the 'A' pump would be much less than that recommended

by the vendor, further review of the history of the pump's performance

and maintenance

was conducted.

It was found that the 5-foot difference

in TOH between pumps 2-SI-P-1A

and 2-SI-P-1B

has existed since original installation

and is not the result of degradation

of pump P-1A. In addition, recent pump test data for the Unit 2 pumps confirm that the pump heads have not degraded or significantly

diverged from the original performance.

A review of the operating

history* and maintenance

records for the Unit 2 LHSI pumps was then performed.

A review of operating

history since Surry startup revealed that there have been about seven SI activations

for Unit 2 with the RCS at operating

pressure.

During each of these activations, both pumps started aligned to recirculate

to the RWST with no feed forward to the RC system. Records indicate that for the inadvertent

SI activations

on 2/2/75 (duration

25 minutes), 8/22/80 (duration

9 minutes), 10/10/82 (duration

16 minutes), 3/27/88 (duration

6 minutes), and 8/2/91 (duration

9 minutes), the Unit 2 LHSI pumps operated in parallel recirculating

to the RWST for a total of 65 minutes. It should be noted that the operating

times reported are minimum times since the log e_ntries record only the initiation

of SI and SI reset, not the time when the LHSI pumps were secured. Once the reset is* accomplished, initial operator attention

is directed toward securing HHSi' flow and returning

the Charging/HHS!

pumps to their normal alignment.

Therefore, the actual elapsed time from SI initiation

until the LHSI pumps were secured was longer and may have exceeded 30 minutes for the early SI activations.

It would be expected that in response to an actual SB LOCA, one of the LHSI pumps would be secured in less than the times noted above for the inadvertent

SI activation.

The EOPs require that one LHSI pump will be secured when operating

in parallel with low flow conditions.

In correspondence

with the NRC in response to IEB 88_.04, we indicated

that this action would take place in less than 30 minutes. However, discussions

with Surry Training indicates

that for normal training scenarios, the second LHSI pump is secured in 10 to 15 minutes and that for more complicated

training scenarios, the second LHSI purnp is secured in 15 to 20 minutes . Page 12 of 46

• * * Serial No.98-300 * ATTACHMENT

1 A review of work orders for Sur~ Unit 2 LHSI weak pump, 2-SI-P-1A, since unit startup has shown that the pump has not been pulled for maintenance

on the rotating elements since 1980, when modifications

were made to their suction bell which resulted from model testing of the North Anna LHSI pumps. Periodic test data fpr the past several years indicates

that pump performance

has not degraded and pump vibration

readings have been normal. Since the data seems to contradict

conventional

wisdom that damage to the pump is likely at very low recirculation

flows, a review of the installed

configuration

was performed

to identify any design or operating

features that would mitigate the effects of low flow operation.

Pump Design The Surry LHSI pumps are Byron Jackson (BW/IP) Model 18CKXH two stage vertical pumps. The pumps outer casing is a cylinder about 53 feet long encased in concrete with a 12 inch suction connection

located about 7 feet from the bottom of the pump casing and a mounting flange for the pump assembly at the top. It can be seen from the pump vendor drawings that the pump is of a robust design. The pump has a 2.187 inch diameter shaft. Shaft bearings are included at the tail shaft, between the two stages, at the outlet of the 2nd stage, as well as at intermediate

points on the vertical shaft. This arrangement

of bearings provides a high degree of stability

to the impellers.

Running clearances

of the wear rings are greater than those of the bearings.

The combination

of multiple bearings in the pumping section and large wear ring clearances

results in a pump that is very tolerant of conditions

that might cause rubbing of the wear rings. The pump discharge

column connects the discharge

from the pump 2nd stage to the pump discharge

head assembly and supports the non-rotating

portions of the pump. The pump operates at 1800 RPM and has stainless

steel impellers

that are designed to produce the rated flow with a required NPSH of only 17 .5 Ft. Operating

Conditions

Case 1 -Low Flow Through The Pump In a low flow* situation

we would normally expect flow recirculation

within the pump impeller which could increase pump vibrations

and, if the pumps operate for long periods at low flows, the temperature

of the water in the pump could increase enough to flash. However, during the inadvertent

SI activations

discussed

above or during any postulated

SB LOCA, the two LHSI pumps are *recirculating

to the* RWST pumping cold water (45°F) and are operated with about 108 foot head on the pump suction (TS minimum RWST level to pump suction 1 sT stage impeller centerline

elevation).

The saturation

temperature

at this pressure is about 295°F. Since the LHSI pump supply from the RWST is at 45 degrees and is designed for operating

temperatures

of 230°F, we can stand a substantial

temperature

rise across the pump with no concern for bearing or wear ring clearances.

Page 13 of 46

• * * Serial No.98-300 * ATTACHMENT

1 _Since the LHSI pump casing is encased in concrete, which is buried in the ground, the water initially

inside the pump casing would be at the ground temperature

of about 55°F. After the pump starts, the replacement

water from the RWST will be at a temperature

of 45°F. Therefore, at a flow of 18 gpm through the pump, we would expect an initial temperature

rise of the water across the pump impellers

from 55°F to about 102°F. The design temperature

of the LHSI pump is 230°F so the 102°F temperature

is well within the design temperature

of the pump. Also, since the *saturation

temperature

of the water at the 1st stage impeller is about 295°F, due to the. static head of water from the RWST, we would not expect flashing in the pump suction. A calculation

of the temperature

distribution

in the pump after 30 minutes was performed

assuming heat transfer from the water in the pump discharge

column to the water in the pump casing outside the column. The calculation

assumes that all heat from the motor horsepower.

at pump shutoff head is used to heat the water in the pump bowls and that no heat is transferred

to the surrounding

concrete.

Also, the cooling effect of the 45°F water coming in from the RWST is ignored. For these conditions, the bulk temperature

of the water in the pump discharge

column would be about 135°F and the temperature

in the pump casing outside the column would be about 101°F. Again, this temperature

is well within the design temperature

of the pump. This would explai.n why the pump has not sustained

any damage at the calculated

flow of approximately

18 gpm . Case 2 -No Flow Through The Pump Although performance

data and calculations

indicate that there would be flow through the "weak" pump, there are sufficient

uncertainties

in both such that it cannot be shown conclusively.that

there is flow through the 'A' pump when operated in parallel with the 'B' pump on the recirculation

line. Therefore, an evaluation

was performed

to consider this possibility

.. As mentioned

above, water is supplied to the LHSI pumps from the RWST so the pressure at the pump suction due to the static head between the RWST and pump suction elevations

is 47.4 psig (62.1 psia). The saturation

temperature

at 62'. 1 psia is 295°F, so we would expect flashing in the pump casing when the water. in the casing reaches this temperature.

If the temperature

inside the pump increases

68.6°F/min

due to energy added to the water in the pump by the motor, the time required to flash the water in the pump bowls would be 3.5 minutes. It appears that water inside the pump bowls would flash to steam in about 3:5 minutes if there was no flow through the pump. However, we have experienced

parallel operation

of the pumps as a result of SI activations

ranging from at least 6 minutes to in excess of 25 minutes for Unit 2, and have not experienced

failure or damage to the pumps. The explanation

for this again lies with the design and installed

configuration

of the pump. Because this is a vertical pump, and there are large columns of relatively

cool Page 14 of 46

• * * Serial No.98-300 ATTACHMENT

1 water on both the suction and t_he discharge

sides of the pump, any voids caused by flashing in the pump bowl are rapidly filled. In the absence of actual flow through the pump, natural circulation

currents would be created in the discharge

column and casing since the heat addition is at the bottom of the pump. These currents will rapidly remove the heat from the pump bowls and, thus, minimize voiding. As noted above, the bulk t_emperature

of water in the pump discharge

column would only reach approximately

135°F in 30 minutes, the maximum time required to secure one LHSI pump. The effects of vibrations

caused by voiding are mitigated

by the robust design* of the bearings and, therefore, rubbing of the wear rings is prevented.

Because the pump operates relatively

slowly (1800 RPM) and is designed to operate with a relatively

low required NPSH at design flow (17.5 Ft.), voiding in the pump does not cause impeller damage characteristic

of high-energy

cavitation.

Instead, the impeller would be subject * to long-term

erosion, which is not a concern for the short period of operation

described

here. Following

the period of parallel operation, the weaker 'A' pump is either shut down and potentially

restarted

later, or the stronger 'B' pump is shut down and the 'A' pump has exclusive

use of the recircula~ion

flow path. In either case, the pump is expected to operate normally and fulfill its safety function.

Therefore, it could be concluded

that: There has been some flow through the "weak" 2-SI-P-1A

pump during the past SI activations, (and will be in the future since testing of the pumps have not shown any degradation

of the pump performance)

and this low flow was. sufficient

to prevent flashing in the suction and damage to the pump, .or We have operated the "weak" 2-SI-P-1A

pump at shutoff with nc;, flow and the robust design of the pump and its installed

configuration

mitigates

any effects of void_ing in the pump bowl. There was no short-term

damage as a result of the operation.

Conclusions

Calculations

recently performed

confirm the conclusion

of the 1988 Engineering

Report, that the minimum flow recirculation

line for Surry Unit 1 LHSI pumps is adequate for the modes and duration of operation

expected under normal and accident conditions.

However, this is only because the pumps are currently

well matched. A change of only a few feet of TOH on one pump would result in a flow imbalance

in Unit 1 similar to Unit 2. The Surry Unit 2 LHSI pumps are not as well matched as the Unit 1 pumps at flows less than 500 gpm. Calculations

show that the 'A' LHSI pump is subjected

to less than the recommended

minimum flow when both pumps are operated in parallel using only the recirculation

flow path. Operating

history of the SI system since Unit 2 startup and maintenance

history of the "weak" LHSI pump (2-SI-P-1A), which has operated for Page 15 of 46

• * * Serial No.98-300 * ATIACHMENT

1 periods from 9 minutes to in ex_cess of 25 minutes on recirculation

in parallel with the strong pump, has demonstrated

that it can operate in this mode for the expected period of time during a SBLOCA without damage. Results from 2-0PT-Sl-005, LHSI Pump Test (quarterly

periodic tests on minimum recirculation

to the RWST) and the most recent periodic test for pump 2-SI-P-1A

from 2-0PT-Sl-002, Refueling

Test of the Low Head Safety Injection

Check Valves to the Cold Leg, (tests at full flow injecting

to the RC System during refueling

outage) confirm that pump 2-SI-P-1A

has not degraded and will supply the LHSI flows assumed in current LOCA analysis.

Based on the above information, it is concluded

that the Surry Unit 2 LHSI pumps are capable of performing

their intended function.

Resolution

Although the LHSI pumps are operable, a modification

package will be prepared to address the susceptibility

of the LHSI Pumps to interaction

during periods when the pumps are operated in parallel on the recirculation

flowpath with no forward flow. At a minimum, the modification

will relocate the recirculation

line tie-in for each pump from their present position, in a common line downstream

of the pump discharge

check valve, fo a point upstream of the check valve. This will. prevent the potential

situation

where a "strong" pump has exclusive

use of both recirculation

lines and the associated "weak" pump is operated with low flow. The modification

package will be implemented

during the 1999 Refueling

Outage for Unit 2 and the 2000 Refueling

Outage for Unit 1 . In addition, a review of Virginia Power's response to NRC IEB 88-04 (both Stations)

will be conducted

to assess the thoroughness

of the response and, thus, ensure that there are no other pumps that are susceptible

to .Potentially

harmful interactions.

This review will be completed

by October 1, 1998 and a revised response submitted, if necessary.

COMPLETION

SCHEDULE A modification

package will be implemented

during .the 1999 Refueling

Outage for Unit . 2 and the 2000 Refueling

Outage for Unit 1 to resolve the susceptibility

of the LHSI Pumps to interaction

during periods when the pumps are operated in parallel on the recirculation

flowpath.

Virginia Power's evaluations

performed

in response to NRC IEB 88-04 will be reviewed to ensure that there are no other invalid assumptions

regarding

pumps that are susceptible

to potentially

harmful interactions.

This review will . be completed

by October 1, 1998 and a revised response submitted, if necessary . Page 16 of 46

• * * ITEM NUMBER FINDING TYPE 50-280/98-201-04

IFI Serial No.98-300 ATTACHMENT

1 DESCRIPTION

Motor Thermal Overload for 1-S 1-P-1 B Pump (Section E1 .2.2.2.1 (d)) NRC ISSUE DISCUSSION "The team reviewed the safety evaluation

which was used to document the replacement

of 1-St-1 P-B motor performed

under work order EWR 88-072. The* original 250 HP motor for LHSI pump, 1-SI-P-18, was replaced with a larger 300 HP motor. The replacement

motor required a minimum starting voltage of 75 percent at the motor terminals

compared to the original motor that required 70 percent voltage. Calculation

EE-0034, "Surry Voltage Profiles," Rev. 01 determined

that adequate voltage was available

at the motor terminals

to enable the motor to start. However, calculation

EE-0038, "Electrical

Power Review of 1-SI-P-18

Motor Replacement", Rev. 0, determined

that adequate motor thermal overload protection

at the higher current ranges could not be provided for the replacement

motor with the existing breaker. The safety evaluation

concluded

that due to limitations

of the operating*

bandwidth

of the overcurrent

protection

device, the thermal protection

of the motor could not be assured under certain conditions.

The licensee stated that providing

adequate thermal * protection

was not as critical as ensuring that the 1-SI-P-1 B pump would start and operate when required.

The team's review of the SI pump thermal protection

issue will be an Inspection

Followup Item 50-280/9.8-201-04." VIRGINIA POWER RESPONSE As stated above, providing

adequate*

thermal protection

is not as critical as ensuring that the Safety Injection (SI) pump starts and operates when required.

The -bandwidth

associated

with the *overcurrent

protective

device for. the 1-SI-P-1 B motor does not . . permit 100% thermal protection

of the motor under short circuit/locked

rotor conditions.

Assuring starting and running capability

for the motor, as opposed to providing

motor thermal protection, is proper for a motor as important

to the plant safety analysis as the Low Head Safety Injection

pump. It has been determined

that improvements

can be made which will continue to assure operation

while providing

full range thermal protection

of the motor. The operability

of-the motor*is*unaffected*by*the1ack

of-complete

protection.

The motor may experience

greater damage during a short circuit/locked

rotor condition

than if the trip device had removed the motor from service. In either case, the motor is no longer available

due to this single failure condition.

The existing protection

is designed to ensure the continued

operation

of the pump/motor, during all normal and accident conditions, in order to perform its safety function . Page 17 of 46

• * * Serial No.98-300 ATTACHMENT

1 The short circuit/locked

rotor protection

concerns associated

with the 1-SI-P-1 B motor will be resolved by revising Calculation

EE-0497 to specify new Long Time Delay/ Instantaneous (LTD/INST)

trip settings for the breaker. A Design Change Package (DCP) will be written to implement

the new LTD/INST trip settings by modifying

or replacing

the breaker, as required, associated

with the 1-SI-P-1 B pump motor. COMPLETION

SCHEDULE Calculation

EE-0497 will be revised by November 15, 1998. The Design Change Package (DCP) to. install the new LTD/INST trip settings by modifying

or replacing

the breaker, as required, associated

with the 1-SI-P-1 B pump motor, will be implemented

by June *30, 1999 . Page 18 of 46

• * * 50-280/98-201-05

IFI Serial No.98-300 ATTACHMENT

1 ITEM NUMBER FINDING TYPE DESCRIPTION

Adequacy of 4160 VAC Electrical

Cables to Withstand

Fault Current (Section E1 .2.2.2.1 (e)) NRC ISSUE DISCUSSION "The team determined

that #1 and #2 AWG cable sizes which were used to supply electrical

power to the high head. safety injection, auxiliary

feedwater, component

cooling water and residual heat removal pump motor loads from the 4160 V AC bus were not adequately

sized to carry the fault current on the 4160 VAC bus. The team was concerned

with the potential

damage to the cables before the breakers could operate and isolate the fault. The team reviewed a preliminary

evaluation

performed

by the licensee to determine

the cable conductor

temperature

rise due to exposure to the available

fault current, and concluded

that either the up-stream

breaker would operate to isolate the fault or the cable conductor

would fail. Although the cables in question are per original design, because of the possibility

of cable failure from fault currents, the team identified

the acceptability

of this cable design as Inspection

Followup Item 50-280/98-201-05." VIRGINIA POWER RESPONSE Virginia Power agrees that documented

verification

of the ability of 4160 VAC_ cables to withstand

postulated

fault currents will add to our confidence

in our original design. To determine

the adequacy of 4160 VAC electrical

cables to withstand

fault current, two types of faults are considered.

They are ground faults and three phase faults. Ground faults, which are most likely to occur of the two postulated

faults, are. not a * problem since their short circuit current will be limited by the distribution

system grounding

resistance.

This is true since these faults could be caused by either a phase to ground short in a motor winding or by a local cable insulation

failure which would result in a single phase to ground fault. Three phase faults, while assumed to be least probable, will generate the highest short circuit current. For our specific application, the cable sizes involved will either vaporize or quickly melt. In either case, existing overcurrent

devices are set to interrupt

the fault in approximately

5 cycles. This short duration is not believed to be long enough to support the ignition of the cable. We have discussed

this issue with Stone and Webster, and based on their experience

from testing cable und~r similar overload conditions, the cables do riot instantaneously

ignite. A sustained

overcurrent

condition

must exist for ignition to occur . Page 19 of 46

'* * * * Serial No.98-300 ATTACHMENT

1 In order to further assess this situation, cables from Emergency

Bus 1 H were analyzed . These cables are typical for each of the other Emergency

Buses. Cables affected were: 1H4PH1 1H5PH1 1H6PH1 1H7PH1 1H10PH1 1H11PH1 Triplex #2 aluminum 220' 3/C #1 aluminum 200' 3/C #1 * aluminum 200' 3/C 500mcni aluminum 50' 3/C #1 aluminum 160' 3/C #2 aluminum 365' feeder for the Auxiliary

Feedwater

pump feeder for the A Charging pump feeder for the C Charging pump feeder for load center transformers

• feeder for the Component

Cooling pump feeder for the Residual Heat Removal . Pump The EDG feeder cable was neglected

since they are also larger than the minimum size discussed

in the original portion of the response.

Breaker operating

times of 5 cycles were conservatively

used. Acceptable

conductor

temperature

per the EPRI guide book is 250 degrees Celsius. Per IEEE 242-1986, the* minimum size aluminum conductor

fed from 4 KV bus should be 250 MCM to meet its requirements. (Surry is not committed

to IEEE 242.) Therefore, the 500 MCM aluminum feeder for the load center is acceptable. (Note: The "I squared T 11 for this cable is calculated

to be 167 degrees Celsius, which conforms to the IEEE guideline.)

• For the #1 and #2 AL cables, the "I squared T" values have resulted in temperatures

of 3352 degrees Celsius and 14,267 degrees Celsius being calculated

for faults at the * bus. These values exceed the boiling point for aluminum, (e.g. 2454 degrees Celsius,.

Note: melting point temperature

is 660 degrees Celsius).

It is expected that these conductors

will therefore

vaporize rather than propagate

flame and induce fire in the raceway system. For faults at the load, Virginia Power conservatively

looked at the AFW, CH and RHR feeds* based on their cable type and circuit length. The results indicate conductor

temperatures

of 1466 degrees Celsius, 1354 degrees Celsius and 540 degrees Celsius, respectively.

It is expected that the AFW and CH feeders will therefore

melt and act like fuses to interrupt

the current. Assuming a more realistic

breaker opening time of 7 cycles for the RHR feeder, will result in a. conductor

temperature

higher than the melting point. It should be noted that the RHR pumps are not used in normal operation

or in any accident response.

They are generally

used to bring the unit to cold shutdown.

There were no other cables sized between #1 and 500 MCM fed off of the 4KV bus, therefore, no other cable types were evaluated.

Based on the .above, there is-no -operability

-0r -fire .concern related to-these cables. A formal Technical

Report will be generated

to document the acceptability

of the 4KV cable design. COMPLETION

SCHEDULE A Technical

Report will be issued by December 1, 1998 to document the acceptability . . of the 4KV cable design. Page 20 of 46

• * * 50-280/98-201-06

IFI Serial No.98-300 * ATTACHMENT

1 ITEM NUMBER FINDING TYPE DESCRIPTION

Breaker-to-Breaker

and Breaker-to-Fuse

Analysis (Section E1 .2.2.2.1 (f)) NRC ISSUE DISCUSSION "The team's review of the Calculation

EE-0497, "SR 480V Load Center Coordination", Rev. 0 revealed that breaker-to-breaker .or breaker-to-fuse

coordination

evaluations

were not performed

for all Class 1 E circuits.

The calculation

had concluded

that these additional

coordination

evaluations.

needed to be performed.

The licensee informed the team that these additional

evaluations

had not been performed.

An action item SR-38-EP-99.10 was initiated

to complete the remaining

evaluations.

Review of the licensee's

breaker-to-breaker

and breaker-to-fuse

coordination

is results considered

Inspection.

Followup Item 50-280/98-201-06." VIRGINIA POWER RESPONSE Calculation

EE-0497, "SR 480V Load Center Coordination," concluded

that additional

• breaker-to-breaker

coordination

is needed (no breaker-to-fuse

coordination

issues were identified), however, none of the problems identified

were safety significant.

The existing settings are acceptable

based on current operating

and calculated

accident loading. Therefore, no operability

issues exist. Virginia Power will provide additional

tripping margin, as required, between the individual

motor feeders and actual motor Full Load Current/Locked

Rotor cu*rrent * (FLC/LRC).

In addition, the overcurrent

setpoints

for the MCC supply breakers will be increased, as required, such that the breaker settings do not limit load below the MCC ratings. This will. be accomplished

by revising calculation

EE-0497 and preparing

a DCP to implement

the setpoint changes and replace affected trip devices as required.

These changes will assure that breaker to breaker coordination

provides*

appropriate

electrical

system protection.

COMPLETION

SCHEDULE Calculation

EE-0497 will be revised by November *1 s, 1998. A Design Change Package (DCP) will be generated

to provide additional

breaker coordination,.

to support implementation

by the end of the 2000 Unit 2 and 2001 Unit 1 refueling

outages . Page 21 of 46

• * * 50-280/98-201-07

IFI ----------------

---ITEM NUMBER FINDING TYPE DESCRIPTION

Breaker Replacement (Section E1 .2.2.2.1 (g)) NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 'The team noted that at Surry all electrical

penetrations

were protected

with only one breaker per original design. The review of the technical

reports, EE-0094 & EE-0095 revealed that for several of the penetratio.ns

the existing breakers did not provide adequate protection.

The technical

report had recommended

replacement

of the breakers providing

inadequate

protection.

The team was informed that installation

of all breakers was not complete and was being done under a generic breaker replacement

package DCP 92-099. The team's review of the licensee's

actions to replace selected breakers under DCP 92-099 is considered

Inspection

Followup Item 50-280/98-201-07." VIRGINIA POWER RESPONSE Technical

Reports EE-0094 and EE-0095 document the evaluation

of electrical . containment

penetrations

for protection

against short-circuit

conditions

and overload conditions.

These reports document that the identified

exceptions

to proper protection

are not considered

serious due to the nature of the loads served by these circuits.

In addition, the areas not fully protected

are generally

small. In the event of a short-circuit, the lack of protection

would most likely result in decreased

qualified

life, not total failure. Therefore, the existing circuit breakers are capable of preventing

penetration

and seal damage to the extent that they will protect the integrity

of the containment

in the event of a short-circuit

failure. There are no operability

concerns with this protection

issue. Work scope additions

to DCP 92-099 are being prepared to replace existing breakers with the correct size breaker . IAW Technical

Reports, EE-0094 and * EE-0095. Replacement

of the improperly

sized breakers will be performed

by the end of the next refueling

outage for each unit. COMPLETION

SCHEDULE Unit 1 breakers will be replaced by the end of the Fall 1998 refueling

outage. Unit 2 breakers will be replaced by the end of the Spring 1999 refueling

outage . Page 22 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-08

URI EOG Battery Transfer Switch (Section E1 .2.2.2.2(a))

NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The team asked the licensee to provide the original design basis and any design changes to the EOG batteries'

transfer scheme. Surry EOG battery design was such that the field flash and control circuits of either EOG 1 or 2 could be manually transferred

in accordance

with emergency

operating

procedures (EOPs) to another DC source, EOG .3 battery. After a completed

manual transfer, the affected circuitry

for either EOG 1 or EOG 2 and EOG 3 will be supplied from EOG 3's battery. The licensee determined

that the EOG batteries'

transfer *scheme was the original design and that the only design change was to add fuses in the control circuits for the batteries

to . perform redundant~train

isolation.

The team identified

the following

concerns for this circuitry:

• No analysis was available

which demonstrated

that EOG 3's battery was able to supply the field flash and control circuits of more than one EOG. As stated in Section E.1.2.3.2.e., calculation

14937.28, "Verification

of Lead Storage Battery Size for Emergency

Diesel Generators", Rev. 2 sized each EOG battery to supply the* field-flash

and control circuits for one EOG for two hours of operation.

• The use of EOG 3's battery to supply two operating

EDGs may potentially

lead to .a common mode failure. Because there was no analysis which demonstrated

that EOG 3's battery can successfully

start and operate bot_h EDGs simultaneously, in the event that the *transfer

switch was used to power an EOG with a faulted battery, this situation

could result in the failure of both trains of EDGs (the EOG with initially

faulted battery and EOG #3). * The actual operation

of these switches may violate the licensee's

separation

criteria between trains. The Surry plant standby power systems were evaluated

against IEEE 308-1974 in the original Safety Evaluation

Report (SER); and the .licensee

based the acceptability

of the plant's onsite voltages in accordance

with the stated criteria in IEEE 308-1974.

That document in Section 5.3.2(3) states that "DC distribution

circuits to redundant

equipment

shall be. physically

and electrically

independent

of each other." Presently

when a transfer is made, redundant

125 VDC load groups are connected

to a singular DC source. * * The operation

of a transfer switch may be undetected.

The team was concerned

that there was a potential

for the trcfnsfer

switch to be out of its normal position because there was no local or remote annunciation

which indicated

that the switch is out of its normal position.

In addition, the operators

were not required to check the proper position of the switch during their normal outside tours. However, the operators

do check once a month that the switch is in the proper place as part of their "blue tag" verification

program. The licensee decreased

the probability

of a transfer switch's misposition

by installing

a "blue" tag on each switch allowing it to be operated only with the Shift Supervisor's

permission.

Page 23 of 46

• * * Serial No.98-300 ATIACHMENT

1 The licensee initiated

DR S-98-0605

to evaluate and disposition

this concern but die;! not conclude its review during the inspection._

The team considered

the design of the EOG battery transfer scheme a potential

unreviewed

safety question (USQ) since the transfer-scheme

was not discussed

in the UFSAR and may not have been reviewed by the NRC. The UFSAR states each EOG * was supplied by an independent

control battery and that the independence

of the EDG's batteries

and starting circuits increases

each EDGs' reliability.

The basis of a USQ would be that the use of the transfer switch would create a malfunction

of equipment

important

to safety of a different

type than evaluated

previously

in the UFSAR. Although the common mode failure of the EDGs for a unit is evaluated

in the UFSAR under an SBO; this analysis is outside the design basis accident envelope and its initiating

cause is not the failure of an improperly

sized EOG battery. The licensee's

evaluation

pertaining

to the design adequacy of the transfer switch and the determination

of whether the design of the EOG transfer switch constitutes

a potential

USQ is considered

an Unresolved

Item 50-280/98-201-08." VIRGINIA POWER RESPONSE *' Virginia Power agrees that the design of the EOG battery transfer switch would require further evaluation

prior to use. As an original plant feature to provide emergency

or abnormal operating

flexibility, the switch was not intended to be used during normal operating

conditions.

In fact, with the possible exception

of testing as part of the operational

readiness

program to support plant restart activities

in the late 1980's, we have found no other evidence that this switch has ever been used. Reassessment

of this feature from a risk perspective

would likely conclude that the potential

risk of common mode failure exceeds the benefit of flexibility

in contingent

actions. Accordingly, rather *than analyze the current installation

for use, Virginia Power has disabled the switch by locking the switch in the "open" position.

A Design Change . Package will be generated

to permanently

disable the switch. As a note of clarification, this feature was initially

constructed

prior to issuance of IEEE 308-71 and the original review of electrical

and l&C issues by the NRC was conducted

in the time frame of the issuance of IEEE 308-71. Notation in the NRC discussion

of Surry being evaluated

to IEEE 308-74 is incorrect.

The relevant IEEE 308 reference

does not distinguish "physical

and electrical" independence.

We surmise that only electrical

independence

was confirmed

when the electrical

system was initially

reviewed in the Operating

License process. * * COMPLETION

SCHEDULE Virginia Power has disabled the switch by locking the switch in the "open" position.

A Design Change Package (DCP) will be generated

to support permanently

disabling

the switch. The switch will be permanently

disabled by June 30, 1999 . Page 24 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-09

URI DC Tie Breaker (Section E1 .2.2.2.2(b))

NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The main DC buses are capable of being connected

together by a molded-case

switch which has no overcurrent

or fault protection.

During normal operation

each main DC . bus is supplied by two battery chargers with a station battery floating on that bus. The buses are only tied together, during plant shutdown for maintenance

on one of the batteries, to prevent loss of either DC main bus even momentarily.

Calculation

EE-0499,"DC Vital Bus short Circuit Current," Rev. 1 analyzes for the maximum fault current at the main DC buses with four chargers and one *battery connected

to the tied main DC buses. The combined fault contribution

of two batteries

connected

to a common DC bus has never been evaluated

in Calculation

EE-0499. UFSAR page 8.4-5 states that parallel operation

of the DC buses is permitted

when either battery is out for maintenance.

Maintenance

operating

procedure (MOP) EP-030, "Removal from Service and Return to Service of Station Battery 1A", rev 0, step 5.1 .3 allows the molded-case

tie switch to be closed with both batteries

connected

to the bus. Although there is a caution statement

before step 5.1.3 which warns the technicians

to minimize the time the DC busses are cross-tied

with both batteries

tied to the bus, the * team considered

that there was sufficient

potential

for a bus fault to develop across the load side terminals

of a breaker housed in a main DC bus (approximately

30 to 60 minutes) while in this situation.

The licensee performed

a preliminary

calculation

during the inspecUon

that showed, for ~ither unit, the worst case fault current with both batteries

connected

to a common DC bus was over 30,000 amps. That value is well above the interrupting

rating of 22,000 amps for the main DC bus breakers.

By permitting

the tie switch to be closed with both batteries

on a common bus, the licensee has operated the plant outside of its design basis because the evolution

was not supported

by the existing UFSAR or the present fault current analysis for the main DC buses. The licensee has agreed with this. assessment

by the team and issued DR S-98-0719.

• The team considered

this issue as another potential

USQ because the potential

failur~ sequence appeared to be of a different

type of equipment

malfunction

than evaluated

in either the current -UFSAR or--the -existing

design -basis analysis. -Neither of those documents

permitted

both station batteries

to be simultaneously

connected

to the cross-connected

DC buses. The team was informed by the licensee that an earlier version of the UFSAR -prior to DCPs 85-32 and 85-34 which performed

DC vital bus expansions

for Unit 1 and Unit 2 respectively

-permitted

parallel operation

of batteries

and chargers.

Because the earlier version of the UFSAR allowed parallel operation

of batteries

and chargers to the DC bus, the licensee believed that this type of battery alignment

can continue to be performed

without the evolution

resulting

in a USQ. Page 25 of 46

• * * Serial No.98-300 ATIACHMENT

1 However, the team's conclusion

was that the earlier version of the UFSAR was no longer applicable

to the current DC system. It appeared to the team that the UFSAR change regarding

battery alignment

limitation

was made to recognize

the newer and more capable batteries

installed

under DCPs 85-32 and 85-34. The team's rev!ew of the design changes contained

in DCPs 85-32 and 85-34 found that the modification

upgraded the capacity of the station batteries

from 1500 to 1800 amp-hours.

With increased

battery capacity, it was no longer possible to interrupt

the fault current using the main DC bus breakers.

Although the main DC bus breakers interrupting

capability

was increased

in the same modification, the increase was not sufficient

to adequately

interrupt

the fault current from both sets of batteries.

Both the current UFSAR and design basis analysis took this conservative

viewpoint.

However, the safety evaluations

for DCPs 85-32 and 85-34, and those for subsequent

revisions

to pertinent

MOPs (1 MOP-EP-30

and 204) did not address the safety aspects of operating

with the more capable station batteries

in parallel.

It appeared to the team that the previous UFSAR * description

which had allowed parallel battery operation

to the DC busses with the DC cross-ties

shut did not necessarily

preclude the potential

for this previously

acceptable

alignment

to be considered

a potential

USO issue in the new modified DC system. The team concluded

that the previously

accepted DC alignment

may pose a potential

USO since the design was changec;I

and operation

of the DC system in other than presently

described

in the UFSAR warrants new reviews by both the licensee and the NRC. The licensee is evaluating

this issue under DR S-98-0719.

A fault current above the DC breaker's

interrupting

capacity is a new type of equipment

malfunction

which makes the total loss of DC power, never evaluated

in the UFSAR, credible because the common DC bus voids the argument of the independent

DC trains. The catastrophic

failure of a DC main bus breaker could lead to additional

faults, that could not be cleared because there are no fault-rated

disconnect

devices in the main battery feeds. Determination

of whether shutting the DC tie breaker with both batteries

connected

to the DC busses con$titutes

an USO is considered

to be Unresolved

Item 50-280/98-201-

09." VIRGINIA POWER RESPONSE Virginia Power agrees that shutting the DC tie breaker with both station batteries

and ali four battery chargers connected

to the DC busses is not a desired configuration

but was part of the original design as described

in the FSAR. DR S-98-0719

was written against the DC bus cross-tie

to document that the interim configuration

of two batteries

and four chargers was not covered by a calculation

and would likely exceed the fault interrupting

current of the DC bus. Virginia Power will revise the Maintenance

Operating

Procedures (MOP) -for removal from service -and-return -to -service of station batteries, which currently

allow the molded-case

tie switch to be closed with both batteries

connected

to the bus. Until the MOPs are revised these procedures

have been restricted

from use. The new procedures

will ensure that both station batteries

and four chargers will not be tied together simultaneously . Previous parallel operation

of the cross-tied

DC Bus sections connecting

two batteries

and four chargers was evaluated

to ensure that this configuration

was within the Surry Page 26 of 46

• * * Serial No.98-300 ATIACHMENT

1 design basis. The original UFSAR allowed for parallel operation

of the batteries

and chargers as an abnormal line-up. During the cross-tied

configuration

with two _1500 amp-hour batteries

and two 200 amp chargers operating

in parallel, the EHB branch breakers (10,000 amp interrupting

rating) in the DC Switchboard

would not have been able to interrupt

a fault in close proximity

• to the switchboard.

However, this configuration

was used only during cold/refueling

shutdown conditions, independent

DC trains were not required and the consequences

of either a feeder fault or a bus fault were the same. In 1988, the DC System was upgraded by implementation

of DCP 85-32 and 85-34. * The main station battery capacity was increased

to 1800 amp-hours

and the original DC Switchboard

EHB branch breakers were replaced with Mark 75 HFB breakers {20,000 amp interrupting

rating). Short-circuit

calculation

14937 .16'-E-1 (later superceded

by EE-0499) was performed

to confirm that the interrupting

capability

of the DC branch breakers were adequate.

However, it could be deduced from that short-circuit

calculation, although acceptable

for normal operation, that the DC branch breakers were unable to interrupt

a fault near the DC Switchboard

while in parallel operation.

• As a result, the portion of the UFSAR statement

regarding

parallel operation

of the chargers and batteries

was revised. The revised statement

restricted

the parallel operation

of the bus sections to conditions

where either battery is out of service for maintenance.

The revised UFSAR statement

did not preclude using the cross-tie

breaker with two batteries

connected

as a means to allow one battery to be disconnected.

Prolonged

operation

with the DC Bus sections in parallel with both batteries

still connected

was no longer permitted

and procedures

were changed to ensure that the step for closing the DC cross-tie

was immediately

followed by the steps to disconnect

either of the batteries.

This procedure

structure

minimized

the time that the DC Bus was susceptible

to excessive

fault currents.

During shutdown conditions, independent

DC trains are required for AFW cross connect support of the operating

unit. The _loss of independence

of the DC trains is allowed for 14 days during shutdown.

Again, the corisequences

of either a feeder fault or a bus fault are the. same. During the execution

of the cross-tie, the MOP requires \he plant to be in Cold Shutdown or Refueling

Shutdown.

In accordance

with Technical

Specifications, two trains of shutdown cooling are required to be operable if fuel is in the reactor. If there is a loss of the DC buses, the vital buses would transfer to their alternate

source without interruption

of' power to the vital loads. The emergency

AC buses and running pumps would continue to be energized.

Therefore, there would be no interruption

of flow, flow indication

or temperature

indication

for the RHR system. If DC power is lost, Loss of DC Power Procedure, %-AP-10.06, would provide guidance for this type of event. This procedure

would -be-used -to provide guidance .for--manual -breaker-operation

if there is a need to swap RHR or CC pumps etc. in order to maintain shutdown cooling. Similarly, this procedure

would be used if the opposite unit requires the use of the AFW pump or Charging pump. Virginia Power concludes

that the plant was within its design and licensing

basis when the DC Bus Sections operated at refueling

shutdowns

with two . batteries

and four chargers in parallel for switching

operations, therefore

this plant configuration

does not represent

a USQ. Page 27 of 46

• * * COMPLETION

SCHEDULE Serial No.98-300 ATTACHMENT

1 Maintenance

Operating

Procedures (MOP), for removal from service and return to service of station batteries, which currently

allow the molded-case

'tie switch to be closed with both batteries

connected

to the bus, will be revised by October 1 , 1998, which is prior to the next unit outage when they will be used . Page 28 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-10

IFI DC Bus Tie Interlock (Section E1 .2.2.2.2(b))

NRC ISSUE DISCUSSION

Serial No.98-300 ATIACHMENT

i "The licensee is also reviewing

the need to have an interlock

on the tie switch between the two main DC buses in accordance

with paragraph

4d of Section D of Safety Guide 6. This interlock

is to prevent inadvertent

operation

of the tie switch. Licensee has written DR S-98-0661

to resolve the matter. The licensee's

review of whether an interlock

on the tie switch is needed is considered

to be Inspector

Followup Item 50-280/98-201-1

O." VIRGINIA POWER RESPONSE The manual DC bus tie breaker (molded case switch) does not have an interlock, in accordance

with paragraph

4d of Section D of Safety Guide (SG) 6, to prevent inadvertent

operation.

As a result, DR S-98-0661

was written to document the design condition.

Recommended

initial corrective

action, to tag the breaker to ensure administrative

control, has been taken. The tag requires Shift Supervisor.permission

to operate the switch. The absence of an interlock

is not considered

an operability

issue since the DC bus tie breaker is controlled

by a procedure

which contains adequate instructions

and precautions.

This switch is not normally in use. Virginia Power will perform an evaluation

to document whether the existing DC cross-tie

configuration

needs to meet SG 6 requirements

and if so, the evaluation

will determine

if modifications

are warranted.

COMPLETION

SCHEDULE Virginia Power will perform an evaluation

to document whether modifications

are warranted

to comply with SG 6 by August 1, 1998. If modifications

are required, Design Change Packages (DCP) will be developed

to support implementation

by the end of the Unit 2, 2000 refueling

outage and by the end of the Unit 1, 2001 refueling

outage . Page 29 of 46

• * * 50-280/98-201-11

IFI Serial No.98-300 * ATTACHMENT

1 ITEM NUMBER FINDING TYPE DESCRIPTION

Station Battery Calculation

Discrepancies (Section E1 .2.2.2.2(d))

NRC ISSUE DISCUSSION "The team verified the sizing of the four station batteries

for their two-hour loac;t profiles in accordance

with calculation

EE-0046, "Surry 125 VDC Loading Analysis", Rev. 1. Calculation

was acceptable

with the following

exceptions:

• Assumption

4 of calculation

EE-0046 did not use the most conservative

values for DC input currents to the inverters

from the applicable

test reports. * * Calculation

did not consider the closing of the 4KV breaker for charging pump C during the first minute. * Closing spring charging motors of 4KV breakers were assumed to draw 60 amps instead of the more conservative

value of 80 amps * Worst case load demand requirements

of a LOCA with high-high

CLS were not . considered

for the sizing of the station batteries.

The licensee initiated

DR S-98-0606

to address the resolution

of this topic, and performed

an evaluation

in accordance

with IEEE 485 that demonstrated

that the station batteries

still had sufficient

margin even when all above concerns were considered.

However, the inverters

beca~e limited to a load of 9 KVA instead of their full load of 15 KVA due to the reduction

in the battery design margin. The licensee's

resolution

of these discrepancies

found in the calculations

is considered

Inspection

Followup Item 50-280/98.:201-11." VIRGINIA POWER RESPONSE DR S-98-0606

did not cover the items noted* above, but was written to document errors in performing

Addendum A to Calculation

EE-0046. Response to DR S-98-0606

concluded

that the station battery load analysis remains valid and the related equipment

will perform their design function.

To address the items noted above, an informal sizing evaluation

was performed

in accordance

with IEEE 485 during the A/E Inspection (in response to Item S-98-260)

which concluded

that the station batteries

are acceptable.

A subsequent

addendum to Calculation

EE-0046 for the new Unit 1 annunciator (Addendum

01 B) took into account conservative

values for inverter input current, included a first minute breaker operation

for the "C" charging pump, incorporated

a conservative

value for spring charging motor inrush, and included other conservatisms (i.e., added random load believed to bound any worst case loading scenario).

This Addendum provides confidence

that the design margins associated

with the station batteries

bound ttie concerns noted above. * Page 30 of 46

• * * Serial No.98-300 ATIACHMENT

1 DC Loading Calculation

EE-0046 will be revised to formally account for the discrepancies

noted above . COMPLETION

SCHEDULE * Calculation

EE-0046 will be revised by March 30, 1999 . Page 31 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-12

IFI EOG Battery_ Design Margin (Section E1 .2.2.2.2(e))

NRC ISSUE DISCUSSION

Serial No.98-300 ATIACHMENT

1 "The team reviewed calculation

14937.28, Revision 2. The calculation

assumed a successful

EOG start at the end of the two-hour load profile and at least one unsuccessful

start in the first minute. )"he team identified

discrepancies

with the assumption

and other design inputs to the calculation.

The licensee issued DR S-97-0677 to review the following

three concerns:

• Calculation

should provide the worst-case

battery loading by assuming at least two unsuccessful

starts in the first minute. * The starting currents for some DC motors, in the EOG starting circuits, may be partially

concurrent

with the current drawn by the EOG field flash circuitry.

• The second start attempt in the first minute invokes two redundant

starting circuits (DC auxiliary

motors and control circuitry)

instead of one, thereby almost doubling the load demand previously

assumed. Also, the licensee committed

to verify whether some additional

continuous

loads may be added to the battery load profile . Each concern can cause the battery load current to increase, thus reducing previous battery loading margins. The licensee did not reevaluate

the sizing of the EOG batteries

but felt that there was no operability

concern because of the available

design margin with the EOG batteries.

The licensee's

review of the identified

discrepancies

on the battery design margin is considered

to be Inspection

Followup Item 50~280/98-201-,12." VIRGINIA POWER RESPONSE An operability

review was performed

for" the issues listed above per DR S-98-0677

response.

This review concluded

that adequate margin is available

in the EOG battery sizing such that the discrepancies

identified

will not reduce the available

margin so as to effect battery operability.

The specific discrepancies

identified

are considered

enhancements

to the existing calculations

in that the conclusions

of the calculation

will not change. Calculation

14937.28 for the EOG Battery two-hour load profile will be revised to incorporate

the concerns listed above. In addition, calculation

14937.75, for the. EOG Battery four-hour

load profile, will be reviewed to determine

if similar discrepancies

exist, and will be revised accordingly.

COMPLETION

SCHEDULE Calculations

1493_7.28

and 14937.75 will be revised by December 16, 1998 . Page 32 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-13

IFI DC Fault Contribution (Section E1 .2.2.2.2(f))

NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The team reviewed calculation

EE-0499, "DC Vital Bus Short Circuit Current", Rev. 1, and determined

that all DC buses and associated

cabling for the main 125 VDC system were conservatively

sized for the available

short circuit currents.

Double-pole

breakers provide the correct overload and fault protection

for the DC system distribution

circuits, and the correct sizing of protective

devices ensures the requisite

selective

coordination

between protective

devices in series when applicable.

A similar analysis did not exist to determine

the available

fault currents to the components

and distribution

circuitry

supplied by the EDG batteries.

Licensee wrote DR S-98-0677

to review this concern. Review of DR S-98-0677

is considered

to be Inspection

Followup Item 50-280/98-201-13." VIRGINIA POWER RESPONSE The referenced

DR is associated

with EDG battery duty cycle. No DR has been issued regarding

available

fault current since there has been no condition

identified

in which available

fault current exceeds component-

design. Virginia Power will prepare a new calculation

to determine

the available

fault-currents

to the components

and distribution

circuitry

supplied by the EDG batteries.

Resolution

of any identified

improperly

sized components

will be handled by the corrective

action process. COMPLETION

SCHEDULE An EDG Battery _short-circuit

calculation

will ~e completed

by December 1, 1998 . Page 33 of46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-14

IFI DC Load FlowNoltage

Drop (Section E1 .2.2.2.2(g))

NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The team reviewed calculation

EE-0046, 11 Surry 125 VDC Loading Analysis", Revision 1 in regard to voltage available

to DC components.

The licensee did not calculate

the actual voltage at DC devices or components

but at the ends of the field cables exiting the 125 VDC switchboards

and panels. In many cases, a field cable terminates

in an enclosure

or rack in which the actual end component

can be found but in several other cases additional

cables. or wiring are traversed

to get to the actual end components.

These additional

cables or wiring runs cause additional

voltage drops possibly hindering

the operability

of a given end component.

The licensee wrote a DR S-98-0649

to . evaluate all affected circuits and determine

the effects of any additional

voltage drops on the operability

of end components. . Preliminary

calculations

performed

by licensee during inspection

did not indicate a problem with any device being unable to perform its safety function due to low voltage at it input terminals.

Additionally, this calculation

showed only one inter-rack

connector (twelve-foot, 750 MCM cable) when in fact there are two such connectors

which for battery 1 A will cause an another .24 VDC drop in battery terminal voltage at the end of a battery discharge.

The licensee wrote DR S-98-0674 to document and evaluate the impact of the additional

cable. These two items are considered

to be Inspection

Followup Item 50-280/98-201-14." VIRGINIA POWER RESPONSE The initial design of the Surry .DC system did not include calculations

of the actual* voltage at the end DC devices. Informal evaluations, performed

in response to DR S-98-0649, have not identified

any equipment

which cannot perform its safety function due to minimum voltage concerns.

Worst case bounding conditions

were assumed and the voltage was determined

to be adequate.

For this reason, all affected equipment

has been determined

to be able to perform it's intended safety function for worst case DC voltage levels. In order to ensure end components

are receiving

acceptable

voltage, new calculations

will be performed

for all affected DC circuits.

Any component

determined

to be detrimentally

affected by the actual voltage seen at the device, will be analyzed per the corrective

action process. In addition, although *the calculation

shows only one inter-rack

connector

for battery 1 A, when in fact there are two such connectors, the evaluation

in response to DR S-98-0674 has determined

that this drop in battery terminal voltage is bounded by the existing design basis and is not an operability

concern. The revision of calculation

Electrical

Engineering

EE-0046, noted in response to item 50-280/98-201-11

above, will incorporate

the existence

of two inter-rack

connectors

for station battery 1 A . Page 34 of 46

COMPLETION

SCHEDULE Serial No.98-300 ATTACHMENT

1 * Calculation

EE-0046 will be revised by March 30, 1999. * * The development

of a new DC System transient

model and calculation

encompassing

end components

will be complete _by December 16, 1999 . Page 35 of 46

• * * ITEM NUMBER FINDING TYPE 50-280/98-201-15

IFI Serial No.98-300 ATIACHMENT

1 DESCRIPTION

• Adequate DC Component

Voltage (Section E1 .2.2.2.2(g))

NRC ISSUE DISCUSSION "A similar analysis to Item 50-280/98-201-14

does not exist to determine

whether the DC components

supplied by the EOG batteries

have the requisite

voltage at their input terminals.

Licensee is to review this concern under DR S-98-0677.

This is considered

to be Inspection

Followup Item 50-280/98-201-15." VIRGINIA POWER RESPONSE The referenced

DR is associated

with EOG battery duty cycle. No DR has been issued regarding

adequate voltage at end devices since there has been no condition

identified

in which available

fault current exceeds component

design. Specific design calculations

and testing have not been completed

to assure available

voltages meet equipment

requirements.

Successful

equipment

function and functional

testing indicate that available

voltage operates the equipment

properly.

Additional

calculations, which have been recommended

to increase our level of confidence

in our design, will be performed

by Virginia Power. In order to ensure end components

are receiving

acceptable

voltage, a new analysis will be performed

for components

supplied by the EOG Batteries.

Any component

determined

to be detrimentally

effected by the actual voltage seen at the end device will be analyzed per the corrective

action process. COMPLETION

SCHEDULE The development

of a new analysis for voltage drops for EOG DC loads will be complete by December 16, 1999 . Page 36 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-16

IFI DC Load Control (Section E1 .2.2.2.2(h))

NRC ISSUE DISCUSSION

Serial No.98-300 * ATTACHMENT

1 The team reviewed the methodology

for documenting

load changes for both AC and DC buses, and some recent DCPs (design change packages)

that had actual load changes in them. Electrical

load changes are initially

recorded in a computer printout of the database of SELL (Station Electrical

Load List) and then incorporated

in the next update of that database.

Several concerns with this process were identified

by the team during the inspection.

The licensee agreed with the following

team's concerns and will evaluate the process under DR S-98-0726:

• Load changes at lower buses are not always reflected

in total loading of upstream buses in between updates of the SELL data base. * Procedure

STD-EEN-0026,"Guidelines

for Electrical

System Analysis," Revision 5, Step 6.1.2 requires that new loads be inputted to the electrical

data base four weeks prior to issuing a draft DCP. Presently

only the SELL printout is marked up prior to issuance of a DCP with new load changes inputted into the electrical

database annually . * No one person is accountable

for electrical

load changes and has ownership

responsibility

for incorporating

them in SELL database.

• The time between both calculation

revisions

and SELL data base updates (5 to 7 . years tor some critical calculations)

is too long with only the marked up SELL printout reflecting

the true status of the loading of electrical

buses in the interim. * Licensee reviewed 30 DCPs in response to a question by the team and found that T out of the 30 DCPs had not properly incorporated

load changes into the marked up printout of the SELL database.

These errors probably would have been inputted into the SELL database at the next annual update. The total error on DC bus 28, the bus most impacted, was 4 amps. The licensee momentarily

lost control of the loading on its DC buses because electrical

load changes were improperly

tracked. This item was identified

as Inspection

Followup Item 50-280/98-201-16." VIRGINIA POWER RESPONSE Virginia Powers' immediate

response was to verify the existing DC bus coridition, as noted above, was acceptable.

We have reconciled

the 4 amp difference

and have shown that adequate battery margin exists for the discrepancies

identified.

In addition to the .DCPs screened by the NRC Inspector, Engineering

has reviewed all DCPs with DC electrical

changes tor affect on the SELL. Only minor discrepancies

were identified . For the errors that were found, Engineering

has incorporated

the corrections

into .the appropriate

SELL documents.

Page 37 of 46

• * * Serial No.98-300 ATTACHMENT

1 The procedures

governing

the .control of the SELL will be revised to strengthen

the requirement

to reflect load changes at lower buses in total loading of upstream buses, in between updates of the SELL data base. In addition, these procedures

wiil be revised to include an appropriate

time frame for issuance of a revised SELL to be * consistent

with the current Design Change Process. Procedures

will also be changed to assure changes which may affect values in other programs are applied appropriately.

The anticipated

procedures

affected will be NDCM STD-EEN-0026, "Electrical

Systems Analysis," and Implementing

Procedure

EE-010, "Update, Review and Approval of the GDC-17 and SELL." Engineering

will give SELL training, encompassing

the revised procedures, to .the Electrical

Engineering

staffs both at Innsbrook

and at Surry. The responsibilities

of the individuals

required to maintain the SELL database will be emphasized.

COMPLETION

SCHEDULE The required changes to procedures, NDCM STD-EEN-0026, "Electrical

Systems Analysis" and Electrical

Engineering

Implementing

Procedure

EE-010 "Update, Review and Approval of the GDC-17 and SELL" will be completed

by December 15, 1998. Electrical

Engineering

training as described

above will be completed

by March 15, 1999 . Page 38 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-17

IFI Battery Surveillance

Test (Section E1 .2.2.2.2(1))

NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The performance

tests for the station and EOG batteries

were not performed

in accordance

with IEEE 450-1980 which licensee imposed on itself. Licensee would terminate

the performance

tests after a specified

time not at the end voltage of 1. 75 volts per cell per IEEE 450. This caused the battery capacity to be recorded at too low of a value and interfered

with accurate trending of battery capacity.

IEEE 450 invokes the performance

of a service test each year once battery capacity drops at least 1 O percent from the last test. Early termination

of the performance

tests delays the invoking of this increased

monitoring.

Licensee was aware of this deviation

from IEEE 450 and had initiated

an update of the involved procedures.

To date only the performance

tests for Unit 2 station and EOG batteries

have been revised. If the capacity is less than 90 percent, the procedure

requires that a deviation

report be written, instead of the performance

of a service test each year as required by IEEE 450. As a further corrective

action for trending performance

tests, the licensee will extrapolate

the data of the last discharge

test for each station battery to determine

the actual capacity if the test had been completed

per IEEE 450. This item was identified

as Inspection

Followup Item 50-280/98-201-17." VIRGINIA POWER RESPONSE The three performance

test procedures

0/1/2-EPT-0106-08

for the EDG batteries

have been revised to conform with IEEE 450-1980.

The procedures

for the Station batteries

will be revised accordingly.

The data from the last discharge

test has been extrapolated

for each Station battery and actual capacity was acceptable

based on the acceptance

criteria of IEEE 450. In addition, the battery capacity trends have been completed

and are being maintained.

for the EDG batteries.

Trending for the Station batteries

is being done and will be made consistent

with the methods for EOG trending in conjunction

with procedure

development.

COMPLETION

SCHEDULE**

Procedure

revisions

and capacity trending will be in place for Station batteries

by September

30, 1998 . Page 39 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-18

IFI Fuse Control (Section E1 .2.2.2.2U))

NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The licensee has developed

a fuse control program that consists of comprehensive

fuse lists and procedures

for replacement

of fuses. The fuse lists were detailed tabulations

of the safety-related

fuses in power and instrument

circuits depicting

inherent characteristics

for identification

and sizing. The licensee estimated

that 90 percent of the fuses in the fuse lists have been both design and field verified.

An attempt has been made to incorporate

all the safety-related

fuses in the fuse lists but there are outliers for which the licensee was unable to estimate the number during the inspection.

Deviation

reports have been issued indicating

that the fuses installed

in some non-safety-related

circuits were not correct. The team sampled installed

fuses and the data in the fuse lists and found the fuses to be adequately

sized and the supporting

data to be accurate.

Recently . the licensee experienced

a failure of a replacement

fuse because it did not have a time overcurrent

plot similar to that of original fuse. The licensee realizes that its Item Equivalency

Evaluation

Review (IEER) process for fuses needs to be upgraded to include similar overcurrent

plots as a further qualifying

item in the replacement

of fuses. This item was identified

as Inspector

Followup Item 50-280/98-201-18." VIRGINIA POWER RESPONSE The specific discrepancies

in fuse type or size have been corrected

under the Virginia Power corrective

action program. The fuse control program referenced

was developed

after the plant was complete and in operation.

The method of capturing

the 'as built' configuration

was to take. the specified

fuse information

from existing drawings.

When . this method could not be applied, due to missing information, field walkdowns

collected

information

from the installed

fuses. This process has continued

and information

is * added as it is identified.

The referenced

DRs are examples of this process in action. The same DR review demonstrated*

that there have been very few problems with incorrect

fuses installed

in the field. For these reasons, Virginia Power will continue to complete the fuse lists on an as-needed

basis. The "90% of the fuses on the fuse list" that were stated as "verified" during the inspection

were-intended-to

reflect the-process

identified

above. Virginia Power has not had reason to question the original specification

of fuses or changes to fuses made under our design control program, therefore, no specific design basis reconstitution

for fuses has been. initiated.

An investigation

into the replacement

fuse mentioned

above was performed.

Virginia Power has researched

the Item Equivalency

Evaluation

Review (IEER) electronic

database and determined

that there were no IEER's performed

at Surry Power Station Page 40 of 46

• * * ------------~---

Serial No.98-300 ATTACHMENT

1 for a replacement

fuse. The fuse mentioned

above was determined

to be a replacement

fuse(s), which through p*ersonnel

error, was not processed

through the formal item equivalency

evaluation

process prior to being issued out of inventory

and installed

into plant equipment.

A Design Reference

Procedure (DRP) exist for fuses, which specifically

denotes the manufacturer/model

of the fuse to be used and the specific plant location(s)

where installation

of the fuse is acceptable.

Any suggested

fuse, for either safety related, NSQ, or non-safety

related applications

that is not an identical (like for like) replacement

is required to have the appropriate

technical

reviews performed

and documented

either through a Design Change Package (DCP) or an IEER prior to installation.

VPAP-0708, "Item Equivalency

Evaluation" requires that all the critical characteristics

for design be documented

for the original and recommended

substitute.

If there are any differences, a technical

explanation

for acceptability

must be provided and documented

in the IEER or may be included as an attachment

in the form of an ET (Engineering

Transmittal)

provided by engineering

for added technical

justification.

A critical design characteristic

for fuses is the time current curve. An IEER would consider, for comparison

purposes, the time current curves as the primary, if not the most critical of the design characteristics.

An IEER requires an independent

design review, which would include the comparison

of the curves. * Virginia Power has determined

that the procedure

for the Item Equivalency

Evaluation, VPAP-0708, will not require a revision.

Virginia Power will review the maintenance

work management

process for ensuring that non-identical

replacement

fuses are processed

through this IEER program and will provided enhancements

to the process if required.

Virginia Power will train appropriate

personnel

on the IEER program as it relates to identical

fuse replacements.

COMPLETION

SCHEDULE Virginia Power will review the process for ensuring that non-identical

replacement

fuses are processed

through this IEER program and will provide enhancements

to the IEER and maintenance

work management

process, if required, by December 15, 1998. Virginia Power will train appropriate

personnel

on the IEER program as it relates to identical

fuse replacements

by March 15, 1999 .. Page 41 of 46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-19

IFI RS System Flow (Section E1 .3. t.2(a)) NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The team evaluated

the following

calculations

to evaluate the capability

of the RS system to fulfill its safety function:

• 01039.621O-US-(B)-107, "Containment

LOCA Analysis for Core Uprate," Rev. O * 01039.621O-US-(B)-106, "LOCTIC LOCA Input Parameter

Values for Core Uprating," Rev. 0 * ME-0405, "Minimum.

Required TOH for Inside Recirculation

Spray (IRS) Pump for Core Uprate -Units 1 & 2," Rev. 0 * ME-0418, "Minimum Required TOH for Outside Recirculation

Spray (ORS) Pump for Core Uprate -Units 1 & 2," Rev. 0 In the analysis, a total RS flow of 5700 gpm was considered

of which 2700 gpm was contributed

by the IRS pumps and 3000 gpm was contributed

by the ORS pumps. The review identified

that calculation

ME-0405 did not take into account flow diversion

from the Unit 1 IRS pumps which would not be available

to the RS spray headers. The team and licensee identified

the following

diversion

paths: * Through 3/8" vents on the RS side of-the Recirculation

Spray Coolers (1-RS-E-1A

& 1 B) with no isolation

valves. * Through Y2" instrument

tubing on the RS side of the Recirculation

Spray Coolers with partially

(1 Y2 turns) open manual valves 1-RS-70 & 72 and fully open instrument

valves 1-RS-71 & 73 downstream

of level switches 1-RS-LS-152

A & B. * Through Y2" fully open drain valves 1-RS-84 & 85 downstream

of which are 1/8" orifices.

Similar flow diversion

paths were also identified

with the Unit 2 IRS pumps: * Through 3/8" vents on the RS side of the Recirculation

Spray Coolers '(2-RS-E-1A

& 1 B) with no isolation

valves. * Through Y2" instrument

tubing on the RS side of the Recirculation

Spray Coolers with partially

(1 Y2 turns) open manual valves 2-RS-18 & 19 and fully open instrument

valves 2-RS-43 & 57 downstream

of level switches 2-RS-LS-252

A & B. The licensee performed

preliminary

analyses, ET CME-98-0013, Rev. 2, -ET NAF-980038, Rev. 1, and safety evaluation

98-0033, which determined

that the total flow diverted for the IRS pumps in Unit 1 and Unit 2 was about 47 and 44 gpm respectively . The analyses also determined

that all IRS pumps in both units would provide more than the required 2700 gpm, the least (Unit 1, Train A) being 2738 gpm and the most (Unit 2, Train B) being 3029 gpm, to the recirculation

spray headers after allowing for the losses Page 42 of 46

• * * Serial No.98-300 . ATTACHMENT

1 through the above mentioned

unidentified

flow paths. The inspection

team concurred

with the conclusions

of the analyses . The review also identified

that calculation

ME-0418 did not take into account flow diversion

from the Unit 1 ORS pumps which would not be available

to the RS spray headers. The team and licensee identified

the following

diversion

paths: * Through 3/8" vents on the RS side of the Recirculation

Spray Coolers (1-RS-E-1C

& 1 D) with no isolation

valves. * Through %" instrument

tubing on the RS side of the Recirculation

_Spray Coolers with partially

(1 % turns) open manual valves 1-RS-74 & 76 and fully open instrument

valves 1-RS-75 & 77 downstream

of level switches 1-RS-LS-152

C & D. * Through %" fully open drain valves 1-RS-86 & 87 downstream

of which are 1/8" orifices.

Similarly, the calculation

ME-0418 did not take into account the flow diversion

paths for the ORS pumps in Unit 2. * Drain lines routed to the emergency

sump and located downstream

of check valves, 2-RS-11 and 17, with spectacle

flanges 2-'RS-FNG-70A

& 71A. These drain lines do not indicate any line number identification

or pipe sizes on the drawing. * Through 3/8" vents on the RS side of the Recirculation

Spray Coolers (2-RS-E-1C

and 1 D) with no isolation

valves . * Through %" instrument

tubing on the RS side of the Recirculation

Spray Coolers with partially

(1 % turns) open manual valves 2-RS-20 & 21 and fully open instrument

valves 2-RS-64 & 65 downstream

of level switches 2-RS-LS-252

C & D. The licensee's

preliminary

analyses, ET CME-98-0013, Rev. 2, ET NAF-980038, Rev. 1, and safety evaluation

98-0033, in this case determined

that the total flow diverted for the ORS pumps in Unit 1 and Unit 2 was about 47 and 87 gpm respectively.

The analyses further determined

that all ORS pumps in both units provide less than the required 3000 gpm, the worst (Unit 2, Train B) being 2958 gpm and the best (Unit 1, Train B) being 2998 gpm, to the recirculation

spray headers after taking into account the losses through the above mentioned

unidentified

flow paths. However, for either A or B Train, the IRS pump flows have enough margins to cover the reduced flow from both ORS pumps, such that the total required flow of 5700 gpm for any RS train used in the containment

analysis was not affected.

The worst case IRS and ORS combination

was Unit 1, Train A, which would deliver 5721 gpm to the spray headers after*allowing

for the loss~s through the unidentified

flow paths in both the IRS and ORS pumps. Therefore, the preliminary

analyses concluded

that the acceptance

criteria for the containment

analyses of record would conti~ue to be met even with the loss of flow from the unidentified

flow paths for both Surry Units . Safety evaluation

98-0033 was prepared to revise the UFSAR Section 6.3 to discuss the impact of the diverted flow through the vents and drains, and that the reduction

in Page 43 of 46

• * * Serial No.98-300 ATTACHMENT

1 the ORS flow requirements

to ~he spray headers would not affect the total RS flow values used in the containment

analysis for core uprate. Also, licensee issued DR S-98-0673 to take corrective

actions, including

alternatives

to minimize flow through the unidentified

flow paths. Licensee's

long term resolution

to this issue is considered

an Inspection

Followup Item 50-280/98-201-19." VIRGINIA POWER RESPONSE The following

flowpaths, that divert flow from the Recirculation

Spray System (RS) headers, were determined

to be unac_counted

for in previous RS system flow analysis:

• RS Heat Exchangers (RSHX) shell level switch vent/drains

that are maintained

open * Drain line downstream

of Outside RS inside Containment

Isolation

Valve * Shell vents on the RSHXs Engineering

Transmittals

CME 98-0013, Rev. 2, and NAF 98-0038, Rev. 0, were . prepared to provide technical

assurance

of the ability* of the RS system to deliver required flows through the combination

of both the inside and outside RS system spray arrays in order to effect design basis containment

depressurization, while accounting

for system flows through vents and drains that are currently

not included in ttie RS system design basis flow calculations.

The analysis concluded

that the RS system continues

to meet the acceptance

criteria for the containment

analysis of record . The need for each of these flowpaths

will be evaluated

and, if not necessary, it will be deleted. For the flowpaths

that can be eliminated, a Design Change Package (DCP) and/or procedure

revisions

will be prepare~.

The changes will be implemented

by the end of the 1998 RFO for Unit 1 and the 1999 RFO for Unit 2. System flow calculations

will be updated by the implementation

of the DCPs to include those flowpaths

that could not be eliminated.

In addition, a review of the Surry Containment

Spray system will be performed

to ensure that unanalyzed

diversion

flowpaths

do not exist. This review will be completed

by December 15; 1998. COMPLETION

SCHEDULE Design. Changes will be implemented

to eliminate

non-needed

flow paths for the RS system by the end of the 1998 refueling

outage for Unit 1 and 1999 refueling

outage for Unit 2. System flow calculations

will be updated by the implementation

of the DCPs to include those flowpaths1hat

could not be eliminated.

The Containment

Spray System review will be completed

by December 15, 1998 . Page44 of46

• * * ITEM NUMBER FINDING TYPE DESCRIPTION

50-280/98-201-20

IFI Unqualified

Coatings (Section E1 .3.1.2(c))

NRC ISSUE DISCUSSION

Serial No.98-300 ATTACHMENT

1 "The team, however, noted that the coating (paint) systems on the RCP motors were not qualified

to withstand

the post accident conditions

in the containment.

Their delamination

during accident and subsequent

migration

inside containment

to the containment

emergency

sump could result* in the blockage of the fine-mesh

screens surrounding

the sump. This in turn would impede the flow of the spray water. * Thus, adversely

affecting

the NPSH of the RS and LHSI pumps that take suction from this sump in the long term recirculation

mode after a LOCA. A preliminary

evaluation

performed

by the licensee indicated

that due to the tortuous path and the low velocity (SWEC calculation

14937.30-US(B)-075, "Transport

of Paint Chips to the Containment

Sump Screens," Rev. 0, December 12, 1988) at which the failed coatings from the RCP motors would be transported, operability

of the RS and LHSI pumps would not be affected.

• However, the licensee has not yet identified

all the unqualified

coatings inside containment

that could potentially

fail due to irradiation

at the post accident environmental

conditions

inside containment.

Also, the calculation

14937.30-US(B)-

075 did not address the running of the .LHSI pumps and the resultant

effect on the velocity, zone of influence, and the quantity of failed coatings in suspension

in the water. Therefore;

the licensee has initiated

a PPR 98-022 and DR S-98-0667

to determine

all the unqualified

coatings inside containment

and evaluate the impact of their delamination

and migration

to the containment

sump screens and eventual blockage of the containment

sump screens. Licensee's

evaluation

of the effect from unqualified

coatings on the containment

sump screens is considered

ah Inspection

Followup Item 50-280/98-201-20." VIRGINIA POWER RESPONSE The acceptability

of coatings in containment

applied in accordance

with the original *construction

specification

is based on the original evaluations

for selection

and application

of coatings.

A degree of testing and assessment

of the original coatings was conducted

• • that *documen,ed

• • the *suitability

of application

for an accident environment.

The analysis performed

employed methods that were considered

to be state of the art. Controlled

documents

were employed to direct the application

of coatings in containment

and have been periodically

revised to incorporate

DBA qualified

coatings .that met adopted industry standards.

Based on Virginia Power's previous assessment

of coatings inside containment, the operability

of the containment

sump is currently

not in question.

Page 45 of 46

• * * Serial No.98-300 ATTACHMENT

1 An effort has commenced

in which unqualified

coatings and other debris sources (herein now referred to as debris) inside containment

will be identified.

This information

will be evaluated

to determine

the affect of debris migration

and potential

blocking of the containment

emergency

sump. The adverse affect~ of sump blockage on NPSH of the RS and LHSI pumps that take suction from the sump will also be evaluated.

Virginia Power has developed

a* preliminary

Scope of Work that addresses

the major elements and parameters

to be investigated

as discussed

in the inspection

report. The objectives

of this investigation

have been divided into two major tasks described

below. These tasks will be implemented

in distinct phases. Task 1: Task 2: Perform a coating condition

assessment

-This task will determine

the qualification

status of coating inside containment.

This will also provide the initial data base required to initiate the unqualified

coating log that tracks the status of unqualified

coatings inside containment.

This task will provide a basis for a program to be developed

to evaluate coatings on replacement

equipment

and components

for use inside containment.

• Analysis and assessment

of available

NPSH margin -This task will estimate the amount of coating surface area that can fail by evaluating

the total debris (insulation, coating and other) blockage and resulting

pressure drop compared to the available

NPSH margin. Also, zones of influence

for determining

the quantity of debris that migrates to the emergency

sump will be identified

and analysis of debris transport

and NPSH will be performed.

The Scope of Work and Schedule are listed in this response as preliminary.

This is due to the expected issuance of an NRC Generic Letter addressing

unqualified

coatings.

Virginia Power will follow the action plan outlined above until such time that a Generic Letter is issued. At this point, Virginia Power will review the requirements

of the Generic * Letter and assess the need to modify our action plan. Revisions

to our scope and schedule may be in order to join an integrated

tndustry review and response.

Any changes to the above action plan and schedule, due to the issuance of a Generic Letter, will be promptly communicated*to

the NRC. COMPLETION

SCHEDULE The preliminary

schedule for the completion

of Tasks 1 and 2 is January 31, 2001 . Page 46 of 46

• • * * ATTACHMENT

2 PROGRAM ENHANCEMENTS

SERIAL NO.98-300

• * * PROGRAM ENHANCEMENTS

1 ). Corrective

Action NRC Observations

related to the Corrective

Action Process Serial No.98-300 ATTACHMENT

2 In the Executive

Summary to NRC Inspection

Report Nos. 50-280/98-201

and 50-281/98-201, the NRC made the following

observation: "The licensee failed to effectively

resolve issues identified

through their engineering

analyses and self-assessments.

These examples included:

failure to resolve the acceptability

of AC voltage which was calculated

to be less than the design value of 480 volts at the bus; failure to perform the recommended

breaker-to-breaker

or breaker-to-fuse

coordination

evaluations;

and some corrective

actions resulting

from the licensee's

Electrical

Distribution

Safety Functional

Assessment (EDSFA)." Virginia Power Response Corrective

actions for Virginia.

Power are guided by our administrative

procedures

VPAP-1501, "Deviation

Reports" and VPAP-1601, "Corrective

Action." These administrative

guidelines

lay the foundation

for early identification

of issues and the complete and thorough resolution

of identified

concerns.

Station Management

has taken an active role in ensuring that deviation

reports (DRs) and commitment

tracking system {CTS) items are properly and thoroughly

resolved.

Although, Virginia Power" has a strong program, it is recognized

that improvements

to the programs can be made to ensure corrective

actions are effectively

implemented.

• * Virginia Power recognizes

that recommendations

and follow-up

actions identified

in Engineering

documents

such as calculations, technical

reports, and Engineering

Transmittals (ETs) have not always been* clearly translated

into completed

actions or tracked to resolution.

Engineering

is evaluating

the causes and possible remedies for this situation.

Program weak_nesses

and human error have contributed

to deficiencies

in the implementation

of these programs.

This comprehensive

evaluation

will provide insight into actions needed to prevent a repeat of the problems identified

during the inspection

effort. For example, issues will be tracked to resolution

by providing

appropriate

tracking mechanisms, engineers

will be trained to provide closure on open issues, and procedural

guidance will be added to assure required corrective

actions are always included in the established

corrective

action program. Revisions

will then be made to applicable

procedures

and standards

by August 31, 1998 to ensure that required actions are identified, tracked and fully implemented.

This evaluation

will address all Engineering

procedures

and standards

for preparing

calculations, technical

reports, and ETs. Training will then be provided to all appropriate

Engineering

personnel

by September

30, 1998 to ensure the programmatic

improvements

are Page 1 of 6

• * * Serial No.98-300 ATIACHMENT

2 Additionally, Engineering's

Potential

Problem Reporting (PPR) process will be reviewed for possible enhancements.

The PPR process is used to evaluate complex technical

issues to determine

whether a deviating

condition

exists. The PPR process ties to the existing company DR process have been strengthened

in recent months to ensure problems are quickly and thoroughly

identified

and then fed into the Station's

existing corrective

action programs.

As Virginia Power noted during the inspection, the EDSFA/EDSFI

identified

a number of Engineering

actions which have not yet been completed.

As a result, a Root Cause Evaluation (RCE) is being conducted

to determine

what open issues remain, why the issues were not properly completed

and identify an action plan for resolution

of the open issues. This root cause evaluation

is reviewing

all of the action items from EDSFA, not just the open items,* to ensure that actions taken or planned are acceptable.

The results of the RCE will be presented

to management

for approval of recommended

corrective

actions by July 31, 1998. Engineering

is developing

a new work management

tool that will support the resolution

of corrective

actions. This new "Task Tracking" program will provide a comprehensive

tracking system of the Engineering

work load to provide management

with information

to allocate resources

to support effective

and timely completion

of corrective

action work items . Page 2 of 6

• * * 2). Configuration

Management

NRC Observations

related to Configuration

Management

Serial No.98-300 * ATIACHMENT

2 In the May 11, 1998 cover letter transmitting

NRC Inspection

Report Nos. 50-280/98-

201 and 50-281/98-201, the NRC made the following

observation: "Based on the number of discrepancies

found in your UFSAR and your design basis documents (DBDs), your additional

attention

to improve the quality of these documents

appeared warranted." In the Exe6utive

Summary to NRC Inspection

Report Nos. 50-280/98-201

and 50-281/98-201, the NRG made the following

observation: "Other discrepancies

included instances

where the surveillance

procedures

were not consistent

with design bases, differences

between the as-built configuration

and the system design as shown on the drawing or the UFSAR, and various calculation

deficiencies.

The team had some difficulties

in obtaining

the most recent calculations

because the licensee's

calculation

index system did not distinguish

between active and inactive calculations.

The team also identified

a number of UFSAR and DBD discrepancies." Virginia Power Response Virginia Power agrees that additional

attention

to improve the quality of the Updated Final Safety Analysis Report (UFSAR) and Design Basis Documents (DBD) is warranted

and that discrepancies

exist among those various documents.

Actions to identify and resolve those discrepancies

have been underway since April 1997 when Virginia Power established

a new organization

within its Nuclear Business Unit to address the concern. The new organization, entitled the Integrated

Configuration

Management

Project, has as its .primary goal the effective

management

of ongoing programs intended to improve design and licensing

bases documentation, and to demonstrate

compliance

with those bases in the operation

of Surry Power Station. The overall Project approach is to complete the verification

and validation

of plant configurations, operations

documents, the UFSAR, and Improved Technical*

Specifications (ITS) on a system-by-system

basis, following

the issuance of individual

system Design Basis Documents.

Integration

Review teams, lead by project engineers

and comprised

of engineering, operations, and licensing

personnel, conduct comprehensive

reviews utilizing

a -rigorous -methodology

to *demonstrate

that operations

at Surry complies with its design and licensing

bases, and to initiate change documents

as required.

The Project was initially

described

in our February 7, 1997 response to NRC's October 9, 1996 1 OCFR50.54(f)

request for information

regarding

the adequacy and availability

of design basis information.

Further details were provided in our May 23, 1997 letter to Page 3 of 6

• • * * Serial No.98-300 ATTACHMENT

2 the NRC in which the scope and methodology

of an updated FSAR review and validation

plan were provided to meet NRC's expectations

as expressed

in the October 18, 1996 Enforcement

Policy revision.

The Project represents

a substantial

undertaking

by Virginia Power. Upon management

approval of the Project, substantial

efforts were required to mobilize the new organization.

These effects included staffing, acquiring

physical facilities

and computer resources, and developing

the detailed methodology, procedures, and computer software necessary

to support various Project . tasks. Project staffing is roughly 70 personnel, including

more than 50 full-time

project staff and an equivalent

of 20 full-time

technical

staff drawn from within the Virginia Power Nuclear organization

to support the various integrated

review teams. During the inspection, NRG observed instances

where the surveillance

procedures

were not consistent

with the design bases, and* differences

were identified

between the as-built configuration

and the system design as shown in a drawing or in the UFSAR. . The NRG also identified

a number of other UFSAR and DBD discrepancies.

It is Virginia Power's intent to address and correct each discrepancy

identified

by the N RC in a timely manner. Each discrepancy

has been entered into the Project's

tracking database and will be resolved during the integrated

review for the affected system in accordance

with the Project's

published

schedule.

In summary, Virginia Power has already focused appropriate

attention

and resources

on the concern expressed

in the NRG's May 11, 1998 inspection

report. Based on Project results to date, the Integration

Reviews are demonstrating

the adequacy qf design and licensing

bases information

on a system basis, and initiating

corrective

action, when required.

However, to determine

whether any enhancements

to existing processes

are appropriate, those review processes

will be assessed in light of the specific observations

described

in NRG Inspection

Report Nos. 50-280/98-201

and 50-281/98-201

regarding

design and licensing

bases documents.

That assessment

will be completed

by August 31, 1998 . Page4 of 6

• * * 3). Calculation

Deficiencies

NRC Observations

related to Calculation

Deficiencies

Serial No.98-300 ATTACHMENT

2 In the Executive

Summary to NRC Inspection

Report Nos. 50-280/98-201

and 50-281 /98-201, the NRC made the following

observations: "The team had some difficulties

in obtaining

the most recent calculations

because the licensee's

calculation

index system did not distinguish

between active and inactive calculations." "The licensee did not have a robust amount of electrical

calculations

to support the AC and DC system design basis. The following

were unavailable:

cable ampacity calculation

to verify cable sizing; calculations

to demonstrate

that the penetration

circuits were within design limits; analyses which justified

the sizing of the DC penetrations;

analyses which examined the fault currents to the DC components

and their distribution

circuitry;

and analyses which showed that the DC voltage at the component

level was adequate to operate the devices." Virginia Power Response Virginia Power has high confidence

that plant systems are conservatively

designed with respect to plant design basis. The Design Basis Document (DBD) program, which has been in process since 1989, has completed

identification

of critical calculations

for electrical

systems and performed

an assessment

to determine

the adequacy of those calculations

to support the electrical

system design. Where necessary, critical calculations

were reconstituted

to ensure that the minimum set of design information

exists to de_monstrate

that system functional

requirements

are met. DBD open items were generated

to further upgrade the body of electrical

calculations

to enhance the . availability

of design basis information.

The DBD program contains an ongoing element to identify and resolve open issues related to electrical

calculations;

Through planned and ongoing efforts, Virginia Power will address additional

calculations, which have been recommended

to increase our level of confidence

in our design. * Additional

measures to control documentation

of which calculations

are active will be pursued to reduce the likelihood

of an error in maintaining

our program. Calculation

Control -An enhancement

to the Virginia Power calculation

control program has been implemented

which reinforces

the requirement

that all users determine

which calculations, or portions of calculations

are active prior to their reference

or use. A study-is being-conducted

to determine

• if any further changes to this program are needed that would enhance the users ability to determine

the status of calculations..

The study will be completed

and any changes to the program will be incorporated

by January 31, 1999 . Page 5 of 6

• * * Serial No.98-300 ATTACHMENT

2 Electrical

Calculations

-The design of the Surry Power Station was such that detailed component

level calculations

were not documented, in some cases, during original design. To upgrade the calculatio'n

availability

for the electrical

systems, the following

calculations

will be performed:

1. Cable ampacity calculations

to verify cable sizing will be completed

by December 1 , 1998. 2. Calculations

to demonstrate

that the penetration

circuits are within design limits will be completed

by December 1 , 1998. 3. Analyses to justify the sizing of the DC penetrations

will be completed

by December 31, 1998. 4. Analyses to examine the fault currents to the DC components

and their distribution

circuitry

will be completed

per the response to Item 50-280/98-201-13.

5. Analyses to show that the DC voltage, at the component

level, is adequate to operate the devices* will be completed

per the responses

to Items 50-280/98-201-

14 & 15 . Page 6 of 6

• * * ATTACHMENT

3 SUMMARY OF COMMITMENTS

SERIAL NO.98-300

• * * Serial No.98-300 * ATTACHMENT

3 SUMMARY OF COMMITMENTS

The following

commitments

are made in response to the findings identified

in Inspection

Report Nos. 50-280/98-201

and 50-281/98-201.

• 1. 2. ITEM NUMBER DESCRIPTION

• COMMITMENT

ITEM NUMBER DESCRIPTION

50-280/98-201-02

Error in Calculation

SM-1047, "Reactor Cavity Water Holdup" The UFSAR changes associated

with the Safety Injection

System NPSH analysis penalties

are to be incorporated

into the UFSAR by August 31, 1998. 50-281/98-201-03

Unit 2 LHSI Pump Minimum Flow COMMITMENT

A modification

package will be implemented

during the 1999 Refueling

Outage for Unit 2 and the 2000 Refueling

Outage for Unit 1 to resolve the susceptibility

of the LHSI Pumps to interaction

during periods when the pumps are operated in * parallel on the recirculation

flowpath.

Virginia Power's evaluations

performed

in response to NRC IEB B8-04 will be reviewed to ensure that there are no other invalid assumptions

regarding

pumps that are susceptible

to potentially

harmful interactions.

This review will be completed

by October 1, 1998 and a revised response submitted, if necessary.

3. . ITEM NUMBER DESCRIPTION

COMMITMENT

50-280/98-201-04

Motor Thermal Overload for 1-S 1-P-1 B Calculation

EE-0497 will be revised by November 15, 1998. The Design Change Package (DCP) to install the new * LTD/INST trip settings by modifying

or replacing

the breaker, as required, associated

with the 1-SI-P-1 B pump motor, will be implemented

by June 30, 199.9. . Page 1 of 6

Serial No.98-300 ATTACHMENT

3 .. * 4 . ITEM NUMBER 50-280/98-201-05

DESCRIPTION

Adequacy of 4160 VAC Electrical

Cables to Withstand

Fault Current COMMITMENT

A Technical

Report will be issued by December 1, 1998 to document the acceptability

of the 4KV cable design. 5. ITEM NUMBER 50-280/98-201-06

DESCRIPTION

Breaker-to-Breaker

and Breaker-to-Fuse

Analysis COMMITMENT

Calculation

EE-0497 will be revised by November 15, 1998. A Design Change Package (DCP) will be generated

to provide * additional

breaker-to-breaker

coordination

and to support implementation

by the end of the 2000 Unit 2 and 2001 Unit 1 refueling

outages. 6. ITEM NUMBER 50-280/98-201-07

DESCRIPTION

Breaker Replacement

• COMMITMENT

Work scope additions

to DCP 92-099 are being prepared to replace existing breakers with the correct size breaker IAW Technical

Reports, EE-0094 and EE-0095. Unit 1 breakers will be replaced by the end of the Fall 1998 refueling

outage. Unit 2 breakers will be replaced by the end of the Spring 1999 refueling

outage. 7. ITEM NUMBER 50-280/98-201-08

DESCRIPTION

EOG Battery Transfer Switch COMMITMENT

A Design Change Package will be generated

to support permanently

disabling

the EDG Battery transfer switch. The switch will be permanently

disabled by June 30, 1999 . * Page 2 of 6

.. * 8 . 9. ITEM NUMBER DESCRIPTION

COMMITMENT

ITEM NUMBER DESCRIPTION

COMMITMENT

10. ITEM NUMBER * DESCRIPTION

COMMITMENT

• 11. ITEM NUMBER DESCRIPTION

COMMITMENT

12. ITEM NUMBER DESCRIPTION

COMMITMENT

50-280/98-201-09

DC Tie Breaker Serial No.98-300 ATTACHMENT

3 Maintenance

Operating

Procedures (MOP), for removal from service and return to service of station batteries, will be revised by October 1 , 1998. 50-280/98-201-10

DC Bus Tie Interlock

Virginia Power will perform an evaluation

to document whether modifications

are warranted

to comply with Safety Guide (SG) 6 by August 1, 1998. If modifications

are required, Design Change Packages will be developed

to support implementation

by the end of the U11it 2, 2000 refueling

outage and by the end of the Unit 1, 2001 refueling

outage. 50-280/98-201-11

Station Battery Calculation

Discrepancies

Calculation

EE-0046 will be revised by March 30, 1999. 50-280/98-201-12

EOG Battery Design Margin Calculations

14937.28 and 14937.75 will be revised by December 16, 1998 .. 50-280/98-201-13

DC Fault Contribution

An EOG Battery short circuit calculation

will be completed

by . December 1 ; 1998 . Page 3 of 6

r ., * * * 13. ITEM NUMBER DESCRIPTION

COMMITMENT

14. ITEM NUMBER DESCRIPTION

COMMITMENT

15. ITEM NUMBER DESCRIPTION

COMMITMENT

16. ITEM NUMBER DESCRIPTION

COMMITMENT

50-280/98-201-14

DC Load FlowNoltage

Drop Serial No.98-300 ATTACHMENT

3 Calculation

EE-0046 will be revised by March 30, 1999 The development

of a new DC System transient

model and calculation

encompassing

end components

will be completed

by December 1, 1999. 50-280/98-201-15

Adequate DC Component

Voltage The development

of a new analysis for voltage drops for EOG DC loads will be completed

by December 1, 1999. 50-280/98-201-16

DC Load Control The required changes to procedures, NDCM STD-EEN-0026, "Electrical

Systems Analysis" and * Electrical

Engineering

Implementing

Procedure

EE-010 "Update, Review and Approval of the GDC-17 and SELL" will be completed

by December 15, 1998. Electrical

Engineering

Training, as noted in the response, will be completed

by March 15, 1999. 50-280/98-201-17

Battery Surveillance

Test Procedure

revisions

and capacity trending will be in place for Station batteries

by September

30, 1998 . Page 4 of 6

I' Serial No.98-300 * ATTACHMENT

3 ,J. ~7. ITEM NUMBER 50-280/98-201-18

• DESCRIPTION

Fuse Control COMMITMENT

Virginia Power will review the process for ensuring that non-identical

replacement

fuses are processed

through this IEER program and will provide enhancements

to the IEER and maintenance

work management

process, if required, by December 15, 1998. Virginia Power will train appropriate

personnel

on the IEER program as it relates to non-identical

fuse replacements

by March 15, 1999. 18. ITEM NUMBER 50-280/98-201-19

DESCRIPTION

RS System Flow COMMITMENT

Design Changes will be implemented

to eliminate

non-needed flow paths for the RS system by the end c:.if the 1998 refueling

outage for Unit 1 and 1999 refueling

outage for Unit 2 . System flow calculations

will be updated by the * implementation

of the DCPs to include those flowpaths

that could not be eliminated.

The Containment

Spray System review will be completed

by December 15, 1998. 19. ITEM NUMBER 50-280/98-201-20

DESCRIPTION

Unqualified

Coatings*

COMMITMENT

The preliminary

schedule for the project is January 31, 2001 for the completion

of Tasks 1 and 2 as described

in the response . * Page 5 of 6

• * * * Serial No.98-300 ATIACHMENT3

20. CORRECTIVE

ACTION PROGRAM COMMITMENT

Revisions

will be made to applicable

Corrective

Action Program procedures

and standards

by August 31, 1998 to ensure that required actions are identified, tracked and fully implemented.

This evaluation

will address all engineering

procedures

and standards

for preparing

calculations, technical

reports, and ETs. Training will be provided to all appropriate

engineering

personnel

by September

30, 1998 to ensure the programmatic

improvements

are understood

and utilized.

The results of the Electrical

Distribution

System Functional

Assessment (EDSFA) Hoot Cause Evaluation (RCE) will be presented

to management

for approval of recommended

corrective

actions by July 31, 1998. 21. CONFIGURATION

MANAGEMENT

22. COMMITMENT

Specific observations

described

in NRC Inspection

Report Nos. 50-280/98-201

and 50-281/98-201

regarding

design and licensing

bases documents, wili be reviewed to _ determine

whether any enhancements

to the existing Integrated

Review Team processes

are appropriate.

• This assessment

will be completed

by August 31, 1998 . CALCULATION

DEFICIENCIES

COMMITMENT

Changes will be incorporated

into the calculation

control program by January 31, 1999. To upgrade the calculation

availability

for the electrical

systems, the following

calculations

will be performed:

• 1. Cable ampacity calculations

to verify cable sizing will be completed

by December 1, 1998. 2. Calculations

to demonstrate

that the penetration

circuits are within design limits will be completed

by December 1, 1998. 3. Analyses to justify the sizing of the DC penetrations

will be completed

by December 31, 1998. . 4. Analyses to examine the fault currents to the DC components

... .and .. their ... distribution

--circuitry

will be completed

per the response to Item 50-280/98-201-13.

5. Analyses to show that the DC voltage, at the component

level, is adequate to operate the devices will be completed

per the responses

to Items 50-280/98-201-14

& 15 . Page 6 of 6