ML18151A610
| ML18151A610 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/09/1998 |
| From: | OHANLON J P 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)
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
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
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
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
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
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
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
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
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
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