ML18151A624
| ML18151A624 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 05/11/1998 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML18151A625 | List: |
| References | |
| 50-280-98-201, 50-281-98-201, NUDOCS 9805260011 | |
| Download: ML18151A624 (48) | |
See also: IR 05000280/1998201
Text
OFFICE OF NUCLEAR REACTOR REGULATION
Docket Nos.: 50-280; 50-281
License No.:
Report No.:
50-280/98-201; 50-281/98-201
Licensee:
Virginia Electric and Power Company
Facility:
Surry Power Station
Location:
Virginia Electric and Power Company
5850 Hog Island Road
Surry, Virginia 23883
Dates:
February 16 through March 27, 1998
Inspectors:
James Isom, Team Leader, PECB, NRR
Edmund A. Kleeh, Operations Engineer, PECB, NRR
Augusto M. Bizarra, l&C Engineer*
A. K. Chatterji, Electrical Engineer*
Ken G. Gauthaman, Mechanical Engineer*
Mansoor H. Sanwarwalla, Lead Engineer*
Robert J. Sheldon, Mechanical Engineer*
- Contractors from Sargent & Lundy Corporation
Approved by: Donald P. Norkin, Section Chief
Special Inspection Section
Events Assessment, Generic Communications,
and Special Inspection Branch
Division of Reactor Program Management
Office of Nuclear Reactor Regulation
9805260011 980511
ADOCK 05000280
Ci
' ...
TABLE OF CONTENTS
EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i
Ill. Engineering ............................................................. 1
E1 .0 CONDUCT OF ENGINEERING ............................................ 1
E1 .1 Inspection-Scope and Methodology ..................................... 1
E1 .2 Safety Injection (SI) System ........................................... 1
E1 .2.1 Mechanical Design Review .................................. 1
E1 .2.2 Electrical Design Review .......... , .... , ..................... 9
E1 .2.3 Instrumentation and Controls (l&C) Design Review ............... 22
E1 .2.4 System Walkdown ...................... , ................. 24
E1 .3 Recirculation Spray System .......................................... 25
E1 .3.1 Mechanical Design Review ................................. 25
E1 .3.2 Electrical Design Review ................................... 30
E1 .3.3. ln_strumentation and Control (l&C)Design Review ................ 30
E1 .4 UFSAR and Design Documentation Review .............................. 34
E1 .4.1 Scope of Review ......................................... 34
E1 .4.2 Inspection Findings ....................................... 34
E 1.4.3 Conclusion ............................................. 38
Appendix A - List of all open items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A 1
Appendix B - Exit Meeting Attendees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
Appendix C - List of Acronyms ..................................... ; ......... C1
~
EXECUTIVE SUMMARY
From February 16, through March 27, 1998, the staff ofthe U.S. Nuclear Regulatory
Commission (NRG), Office of Nuclear Reactor Regulation (NRR), Events Assessments,
Generic Communications and Special Inspection Branch, conducted a design inspection at
Surry Nuclear Plant. This inspection included onsite inspections during February 16-20,
March 2-13 and March 23-27, 1998. The inspection team consisted of a team leader and an
inspector from NRR, and five contractor engineers from Sargent & Lundy Corporation.
The purpose of the inspection was to evaluate the capability of the selected systems to perform
safety functions required by their design bases, the adherence of the systems to their design
and licensing bases, and the consistency of the as-built configuration with the updated final
safety analysis report (UFSAR). The team selected the safety injection (SI) system, the
recirculation spray (RS) system, and their support-interface systems for this inspection because
of the importance of these systems in mitigating design basis accidents at Surry. The team
followed the engineering design and configuration control section of Inspection Procedure (IP)
93801 for this inspection. For the selected systems, the team reviewed the UFSAR, Technical
Specifications, design bases documents (DBDs), calculations, drawings, modification packages,
surveillance procedures, and other documents.
Overall, the team found that the s.elected systems were capable of performing their design-
basis safety functions, although some discrepancies were identified regarding adherence of the
systems to their design and licensing bases.
The team identified a safety injection (SI) system design deficiency which could result in
potential dead heading of one of the Unit 2 low' head safety injection (LHSI) pumps. Although
this issue was communicated to the industry through IE Bulletin 88-04, the licensee had not
evaluated the Unit 2 LHSI pumps against this concern. The SI systems for both units were
susceptible to the pump-to-pump interaction, although only one of the two Unit 2 LHSI pumps
(2SI-P-1A) was found to be operating near dead head conditions. Damage to pump 2SI-P-1A
would be prevented by securing one of the two LHSI pumps within 30 minutes of SI initiation.
The coating on the reactor coolant pump (RCP) motors was not qualified to withstand the post-
accident conditions in the containment. The RCP coatings could delaminate during the
accident and cause further blockage of the containment sump screens. Because the LHSI and
the RS pumps had little NPSH margin, the team was concerned that the additional sump
blockage could cause further reduction in the pump NPSH margin. The licensee's preliminary
review indicated that the sump blockage from the RCP motor coatings would not result in
operability concern for the LHSI and the RS pumps. However, because there may be additional
unqualified coatings inside containment, the licensee determined that additional analysis was
necessary to ensure adequate available NPSH. As a related matter, the team also had
concerns with the use.of containment overpressure to satisfy NPSH requirements for their LHSI
and RS pumps. This matter will be referred to the NRC technical staff for review.
The design of the emergency diesel generator (EOG) battery transfer which provided the ability
to transfer DC power between EOG 1 and 3 or EOG 2 and 3 was not supported by the existing
design bases or the UFSAR. Furthermore, the team identified concerns with licensee's practice
of connecting the DC busses with both batteries still tied to the busses. This alignment had not
been analyzed nor was it reflected in the present version of the UFSAR.
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.
The licensee failed to effectively resolve issues identified through t.heir engineering analyses
and self-assessments. These examples included: failure to resolve the acceptability of AC
voltage whfch 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).
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.
The licensee used the corrective action process to respond to the team's identified deficiencies.
There were no immediate. operability concerns identified during the inspection .
ii
....
i*
111. Engineering* .
E1 .0 CONDUCT OF ENGINEERING
E1 .1 Inspection Scope and Methodology
The purpose of the inspection was to evaluate the capability of the selected systems to perform
safety functions required- by their design bases, the adherence of the systems to their design
and licensing bases, *and the consistency of the as-built configuration with the updated final
safety analysis report (UFSAR}. The systems selected for inspection were the safety injection
(SI} system, the recirculation spray (RS} system, and their support-interface systems .. These
systems were selected on the basis of their importance in mitigating design basis accidents at
Surry.
The inspection was performed in accordance with NRC inspection procedure (IP} 93801,
"Safety System Functional Inspection." The engineering design and configuration control
section of the procedure was the primary focus of the inspection.
The open items resulting from this inspection are included in Appendix A. The acronyms used
in this report are listed in _Appendix B .
E1 .2 Safety Injection (SI} System
E1 .2.1 Mechanical Design Review
E1 .2.1.1 Inspection Scope
The team evaluated the capability of the SI System to provide adequate emergency core
cooling flow under accident conditions. The team reviewed the plant design drawings,
calculations, accident analyses, the containment flooding analysis, design change packages
(DCP}, the UFSAR, the system design basis document (SDBD}, technical specifications (TS},
operating procedures, maintenance and surveillance tests, NRC Information Notices (IEN} and
Bulletins (IEB}, Generic Letters (GL}, and engineering evaluations associated with the system.
E1 .2.1.2 Observations and Findings
E1 .2.1.2(a} SI Accumulator Performance
'
The team reviewed calculation SM-0917, "Surry LBLOCAAnalysis, 1981 Model Using BASH
Code, SIF Fuel with 15 percent SGTP," Revision 0, Addendum A which analyzed the plant
requirements/response for a large break LOCA, and calculation SM-0597, "Post-LOCA
Shutdown Reactivity for Surry Units 1 and 2 at Uprated Conditions," Revision 1, Addendum A
which determined the required boron concentra+ion. The team found these analyses
satisfactory and found the SI accumulator design information contained in the analyses were
consistent with the TS requirements and with operations procedures.
1
The team identified a discrepancy with calculation 01039.621O-US-(B)-107 "Containment LOCA
Analysis for Core Uprate," Revision 0. This analysis used a lower, non-conservative
accumulator pressure of 650 psig to determine the containment pressure during a LOCA. The
analyses should have used a higher accumulator pressure of 665 psig which is the accumulator
high pressure alarm setting as specified in procedure O-DRP-004, "Precautions, Limitations and
Setpoints," Revision 19, attachment 7, Safety Injection System Setpoints. The higher SI
accumulator *pressure would have resulted in higher containment pressure. The licensee
performed an analysis {Reference ET-NAF-980035, -Revision 0, 2/26/98) that showed that the
higher accumulator pressure caused only a minor increase {.03 psia) in the containment
subatmospheric peak pressure. The existing analysis results, when adjusted for these
changes, remained within their acceptance criteria. Deviation Report {DR) S98-057 was
initiated to revise the calculation 01039.6210-US-{B)-107.
E1 .2.1.2{b) SI System Flow
The team reviewed the following calculations:
ME-0251, "High Head Safety Injection Flow Rate as a Function of RCS Pressure for
"As-Built" Configuration," Revision 0
ME-0375, "Minimum Delivered LHSI Flow for LB LOCAAnalysis and PT-18.3DFlow
Test Acceptance Criteria Minimum," Revision 0
ME-0408, "Minimum and Maximum Safety Injection System Flow Analysis for Input to
Surry Core Uprating Containment Analysis - Surry 1 & 2," Revision O
ME-0440, "Minimum HHSI Delivered Flow to Cold Legs by 1-CH-P-1B in "As-Left" {April
1997 Refueling Outage f Flow Balance Configuration - Surry Unit 1," Revision 0,
Addendum B
SM-0596, "Post LOCA Recirculation Switchover Times for Surry at Uprated Conditions,"
Revision 0, Addendum 2
SM-07 43, "Charging/SI Flow Balance Acceptance Criteria," Revision 1; Addendum B
SM-0917, "Surry LBLOCA Analysis, 1981 Model Using BASH Code, SIF Fuel with
15 percent SGTP," Revision 0, Addendum A
SM-0991, "HHSI Flow Requirement for Injection to the Hot Leg at Hot Leg Recirculation
Switchover," Revision 0
SM-1081 "Surry Small Break LOCA Analysis on the HP-UNIX Platform," Revision 0
The team found these analyses satisfactory and the SI system flow during the injection, cold
and hot leg recirculation phase was acceptable and consistent with the applicable licensing,
design and operations documents.
The team identified a minor discrepancy in calculation ME-0375, "Minimum Delivered LHSI
Flow for LB LOCA Analysis and PT-18.3D Flow Test Acceptance Criteria Minimum," Revision 0
regarding the use of "k" factors. Calculation ME-0375, in three instances, used "k" values for
the reducer/expander that were based on the smaller pipe end. Calculation ME-0342, "HHSI
Flow Analysis," Revision 0, attachment 11.5, deteimined that the "k" factor for
- reducer/expander for use in flow analysis was based on the larger pipe end. This was not
conservative because it resulted in lower pressure drops and a smaller flow errors. The team
concluded that this non-conservatism had an insignificant effect on the calculation and the flow
test procedure because there was sufficient flow margin available to accommodate this error.
The licensee will revise calculation ME-0375 to incorporate the correct "k" factor. The revision
will be tracked by Action Item SR-38-Sl-298.10 and Engineering Task Number 98-0097. *
2
...
. *
E1 .2.1.2(c) Pump Performance
The team reviewed the HHSI and LHSI pump quarterly surveillance test procedures and
trending data on pump degradation to verify the pump's ability to provide the required flow:
1-0PT-CH-001, "Charging Pump Operability and Performance Test for 1-CH-P-1A,"
Revision 24
1-0PT-CH-002, "Charging Pump Operability and Performance Test for 1-CH-P-18,"
- * Revision 22
1-0PT-CH-003, "Charging Pump Operability and Performance Test for 1-CH-P-1C,"
Revision 22
. *
1-0PT-Sl-005, "LHSI Pump Test," Revision 8
The surveillance tests and trending data over the last 6 years for both Units 1 and 2 indicated
no pump degradation.
E1 .2.1.2(d) SI Pump Net Positive Suction Head (NPSH)
The team reviewed the following calculations, technical reports and engineering evaluations:
. 14937.44-US(B)-068, "NPSH Available to HHSI and LHSI Pumps from RWST,"
Revision 1
ME-0024, "Low Head Safety Injection Pumps Net Positive Suction Head Required Surry
Units 1 and 2," Revision 0
01039.6210-US-(B)-107, "Containment LOCA r\\nalysis_for Core Uprate," Revision 0
01039.6210-US-(B)-106, "LOCTIC LOCA Input Parameter Values for Core Uprating,"
Revision 0
SM-1116, "Evaluation of Reduction in Containment Heat Sink and Extended RTD
(LM & CV) Replacement Schedule on Surry Containment Analysis," Revision O
ET-NAF-98001, "Containment Sump Volume Issues," Revision 0
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
NRC as indicated in Regulatory Guide 1.1, "Net Positive Suction Head for Emergency Core
Coolir:,g and Containment Heat Removal System Pumps" and NUREG 800, "Standard Review
Plan," Section 6.2.2. However, in the various correspondences held between the NRC 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 pumps.
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
3
discussed in the RS system review (Section E1 .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.
.
The team identified the following discrepancies associated with the calculations:
Calculation 14937.44-US(B}-068, "NPSH Available to HHSI and LHSI Pumps from
RWST," Revision 1 was not updated to incorporate the latest and more accurate LHSI
flow rate value of 3371 gpm. Calculation 12846.19-PE-023, "Maximum LHSI Pump
Flow Recalculation - Injection Phase," Revision O provided the LHSI flowrate value of
3220 gpm for use in calculation 14937.44-US(B)-068. However, the LHSI flow
determined in calculation 12486.19-PE-023 was not the maximum flow as it did not
account for the pump recirculation flow and the difference in flow with one line spilling to
the containment. At a later date, calculation ME-0408, "Minimum and Maximum Safety
Injection System Flow Analysis for Input to Surry Core Uprating Containment Analysis -
Surry 1 & 2," Revision O provided a revised LHSI flow rate of 3371 gpm. The new,
higher flow rate was not incorporated into calculation 14937.44-US(B)-068. There was
no concern as sufficient NPSH margin of 55.5 ft was available to the LHSI pumps.
Calculation 14937.44-US(B)-068 will be revised to include the LHSI flow rate determined
in calculation ME-0408 (tracking no. SR-38-Sl-298.4 and engineering task tracking
no. 98-0085).
Calculation 01039.6210-US-(B)-107, "Containment LOCA Analysis for Core Uprate,"
Revision 0, used a non-conservative LHSI flow rate of 3291 gpm to determine the NPSH
available to the LHSI pump with suction from the containment sump. Flow rate of 3305
gpm from calculation ME-0408 should have been used instead. The small difference in
flow* (14 gpm) had a minimal affect on the available NPSH determined in calculation
01039.6210-US-(B)-107. Calculation 01039.6210-US-(B)-107 will be revised to include
the higher LHSI flow rate of 3305 gpm (tracking no. SR-38-Sl-298.5 and engineering
task tracking number 98-0086).
Valves %-CH-FCV-1160 (loop fill header) were supposed to be shut when RCS
temperature exceeded 200 °F. However, procedures %-OP-CH-005, "Aligning Charging
and Seal Injection to the Normal and Alternate Charging Head~r." Revision 10 allowed
them to be open during normal operation. This situation could potentially cause the
HHSI pump to experience pump run-out and could also affect the pump NPSH because
an additional, unthrottled flow path could exist during a LOCA. There is no SI signal to
close these valves. This was identified by the licensee and the licensee issued
DR S98-0465 to address this issue.
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 dra:ned 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.
4
Calculation 01039.6210-US-(B)-107 was used to determine the NPSH requirements for
the IRS, ORS and LHSI pumps.
The team found that SM-104 7 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 01039.6210-US-(B)-107 as an
Inspection Followup Item 50-280/98-201-02.
The team reviewed analysis, engineering transmittal CME 98-0012 (which showed vortexing
was not a concern), and found it to be acceptable. In 2ddition, vortex suppression plates, as
recommended in report LHL-742, "Surry Power Station Hydraulic Model Studies Outside
Recirculation Spray Pumps and Low Head Safety Injection Pumps," dated October 1978, were
installed in the pump can inlets to prevent vortexing.
E1 .2.1.2(e) Valve Operability
The team reviewed the following calculations which established the differential pressures which
the valves were subjected to under various operating conditions to ensure that the SI valves
couid stroke under the design operating conditions:
14937 .32-M-1, "Maximum Differential Pressure High Pressure Safety Injection and
Auxiliary Feedwater Valves," Revision 0, Addendum B
14937.07-M-3 Maximum Differential Pressure Across Chemical and Volume Control
System MOVs to Determine the Torque and Overload Settings," Revision 0,
Addendum B
14937.07-M-8, "Maximum DP Across SI-MOV-X842 and SI-MOV-X890C," Revision O,
Addendum D
14937.07-M-9, "Maximum Differential Pressure Across Safety Injection System MOVs to
Determine Torque and Overload Setting,° Revision 0
ME-0144, "Maximum Differential Pressure Across Chemical and Volume Control System
MOV's 1275A,B,C, 2275A,B,C, 1286A,B,C, 2286A,B,C, 1373 and 2373," Revision 0,
Addendum A
Calculation ME-0211, "Thrust Band Calculations for Surry Safety Related Rising Stem
Motor Operated Valves," Revision 2, Addendum C
Except for the following discrepancy, the team determined that the motor operators were
designed to provide the requisite thrust to operate the valves.
Calculation 14937.07-M-3 did not consider the "piggyback" mode of operation in determining
the differential pressure (DP) across the alternate charging valves 1-CH-MOV-1287A,B,C for
use in the valve thrust capability review. The DP during "piggyback" operation would be
2747 psi instead of the 2630 psi as determined in the calculation 14937.07-M-3. There were no
torque settings on the 1-CH-MOV-1287 A,B,C valves. The opening and closing of the valves
were both controlled by limit switch. The licensee performed a preliminary analysis,
CME 98-0019, "Evaluation of Thrust Requirements for 01-CH-MOV-1287A,B,C Surry Power
Station - Unit 1," Revision 0, which determined that the motor operators for the valve had
sufficient thrust to stroke these valves with the higher DP. The team agreed with the licensee's
5
analysis that the valves had sufficient thrust to overcome the increase in the differential
pressure from 2630 psi to 2747 psi. The licensee will revise calculation 14937.07-M-3 to
address the higher DP. This revision will be tracked by action item SR-38-Sl-298.1 and
engineering task number-98-0109.
E1 .2.1.2(f) Piping Design Pressure and Temperature
The team reviewed the following SI and associated CH System Piping and Instrumentation
Diagrams (P&ID), System Design Basis Document, _SDBD-SPS-SI, and Pipe Class Design
Standard STD-MEN-0004, Revision 9 to verify that the pressure and temperature classification
for the suction piping from the RWST and containment sump, minimum recirculation piping, and
discharge piping to the RCS were adequate.
11448-FM-088B, sh 1, Rev. 32;sh 2, Rev. 38;sh 3, Rev. 12
11448-FM-088C, sh 1, Rev. 22;sh 2, Rev. 20
11448-FM-089A, sh 1, Rev. 53;sh 2, Rev.- 46;sh 3, Rev. 46
11448-FM-0898, sh 1, Rev. 28;sh 2, Rev. 22;sh 3, Rev. 24; sh 4, Rev. 20
The team determined that the design pressure and temperature ratings of the piping were
acceptable.
Additionally, the team reviewed calculations, engineering analysis, operations procedures and
other documents to verify that the relief valves' setpoints and capacities were adequate to
protect the piping from overpressure .
ME-0364, "Low Head Safety Injection Pump Discharge Relief Valve Set Point
Calculation", Revision O
Westinghouse Equipment Specification G-676257, "Auxiliary Relief Valves," Revision O
EWR 90-139, "Eval Ml Relief Valve Setpoints/Surry/1&2," Revision O
The team determined that the relief valves' setpoints and capacities were adequate except for
the following discrepancy.
Procedure 1-SI-OPT-0014, "Cold Shutdown Test of SI Check Valves to RCS Hot Leg and Cold
Legs," Rev. 3 which specified the allowable backleakage through LHSI cold leg injection check
valves 1-Sl-241, 242, 243 did not properly incorporate the assumption made in calculation
ME-0364, "Low Head Safety Injection Pump Discharge Relief Valve Set Point Calculation,"
Revision 0. ME-0364 takes credit for the leak tightness of these check valves. However,
procedure 1-SI-OPT-0014 allows the backleakage through the check valves to be as high as
1.295 gpm for each valve. This combined leakage from the 3 check valves would exceed the
capacity of 1.8 gpm of relief valve 1-SI-RV-1845B. Currently, the team was not concerned that
the piping would become overpressurized because the latest test data for these check valves
(for both Units 1 and 2) established that the maximum leak rate was 0.123 gpm. DR S-98-0721
was written to address the consistency of the check valve leakage acceptance criteria in
1-0PT-Sl-014 with the check valve assumption madeiri calculation ME-0364.
E1 .2.1.2(g) LHSI Pump Operation in Minimum Recirculation Mode
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&IDs
6
(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 the mini_n,um 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. The 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 pump with the
remainder of flow (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:
o
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
7
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 minflow were potential
operability concerns. The licensee 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.
E1 .2.1.2(h) Design Change Packages and Safety Evaluations
The team reviewed four design change packages (DCPs) and five safety evaluations (SEs) to
verify that the SI system design basis was being maintained. With the exception of following
discrepancies, the team found that the DCPs and SEs were acceptable:
Revision 3 to DCP 91-027, "LHSI and ORS Pump Cooling Coil Mod/ Surry/ Unit 1 & 2,"
changed the design of the LHSI Pump seal coolers from 300 psig/300 °F to
170 psig/250 °F and stated that supporting calculation DE0-0088, "LHSI and ORS
Pumps Seal Cooler Sizing" would be revised to reflect the new sealer cooler design
conditions. The calculation DE0-0088 was not revised. DR S-98-0603 was issued to
identify this discrepancy.
Calculation DE0-0047, "Evaluate LHSI Pump Seal Water Cooler and Support," Rev. O
was performed to seismically qualify the licensee designed LHSI Pump seal water
cooling coils in the Rev. 2 issue of DCP 91-027. However, the. engineers did not
document their conclusion that no change to seismic analysis as documented in DE0-
0047 was necessary when Revision 4 to the DCP 91-027 enlarged the cooling coil size.
The licensee agreed and DCP 91-027 will be revised.
The LHSI pump seal coolers were originally supplied by the vendor and calculation
DE0-0011, "Evaluate LHSI Pump Seal Water Cooler and Support," Rev. O was
performed to seismically qualify the new LHSI Pump seal water cooling coils.
Revision 2 of the DCP changed the cooling coil from vendor supplied to licensee
designed and fabricated on site, and calculation DE0-0047, "ORS & LHSI Pump Seal
Water Heat Exchanger Tubing & Support Qualification/ Surry 1 & 2," Rev. 0 was
performed to seismically qualify the licensee coil design. Revision 9 of the* DCP added
some quick-disconnects to the cooling coil system. However, to determine if the weight
- of the disconnects would have any impact to the seismic qualification of the coolers, the
8
DCP referred to superseded calculation DE0-0011 instead of to the current calculation
DE0-0047 which qualified the site fabricated cooling coils. DCP 91-027 will be revised.
EWR 93-006, "LHSI Pump Discharge Relief Valve Set Pressure Change I Surry /
Unit #1 & #2," Rev. A changed the set point for relief valves 1-SI-RV-.1845 A, B, C from
220 psig to 242 psig. P&ID 11448-FM-089A, Sheet 2 was not revised and the current
. issue, Rev. 46, still showed the set point as 220 psig. Drawing Change Request
No. 98-0312 was issued to delete this information from the P&ID as relief valve set points
were now controlled by procedure 1-DRP-008,-"Relief and Safety Valve Setpoints."
Procedure 1-DRP-008, Revision 17 contained.the correct relief valves se~points.
E1 .2.1.3 Conclusion
Except.for the concerns regarding the Unit 2 LHSI (2SI-P-1A) pump dead heading issue and
the potential for sump screen blockage from unqualified coatings (discussed in detail in Section
E1 .3.1.2(c)), the team concluded that the mechanical design for the SI System could provide
- adequate emergency core cooling flow under accident conditions.* The system provided the
required NPSH for the SI pumps when taking suction from either the RWST or the containment
sump. Discrepancies were observed in the operating procedures, calculations, design change
packages and check valve testing criteria.
E1 .2.2 Electrical Design Review
E1 .2.2.1 AC and DC System Inspection Scope
The team reviewed the emergency diesel generators, the 4160 VAC system, the 480 VAC
system, and the 120 VAC power sources which provided power to the SI and RS systems for
adequate equipment sizing; regulatory and industry standard compliance; electrical separation;
voltage drops and available voltages at equipment terminals; protective device sizing,
coordination and setpoints; and controls and interlocks. For the DC system review, the team
assessed the portions of the following areas that are applicable to the RS, SI, and 125 VDC
systems: sizing of station and EOG batteries, load flow calculation for 125 VDC system
(voltage drop), electrical protection and fault rating of DC penetrations, fuse control for DC
circuits, surveillance tests for station and EOG batteries, design control and configuration
control in regard to DC load changes, and control of calculations in accordance with
administrative procedures.
The team reviewed USAR Section 8.0, TS Sections 1.4, 3.16, 4.6 and 8.0, system descriptions,
electrical requirements, design basis documents, design change packages, surveillance test
requirements, and other miscellaneous electrical documents related to the design basis.
E1 .2.2.2 Observations and Findings
E 1.2.2.2.1 AC System Review
E1 .2.2.2.1 (a) Emergency Diesel Generator (EDG)
The inspection team reviewed the following documents and found that the steady state loads
under various postulated accident conditions remained within the rated capacity of the EOG
(2750KW for 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />) and consistent with plant TS:
9
..
drawing 11448-FE-1A1, "List of Loads Supplied by Emergency Diesel Generator
calculation EE- 035, "EOG Loading Analysis," Rev. 1 dated 03-05-98
The team also verified that the licensee had properly reflected the appropriate electrical load
associated with the LHSI and HHSI pumps into their loading analysis for the EOG. The monthly
surveillance procedure, "Number 3 Emergency Diesel Generator Monthly Start Exercise Test,"
O-OPT-EG-001, Rev. 10 satisfactorily verified the EOG loading design requirement.
The team also verified that the worst case transient load (8.56 MVA), which occurred during the
LOOP+CLS transient, was within the EOG capability (10.5 MVA). The team noted that the
EOG voltage and frequency dips resulting from the most limiting transient loading recovered
within acceptable time limit before the application of the next sequenced step load. EOG
surveillance test 2-0PT-Z-002, "ESF Actuation with Undervoltage and Degraded Voltage," dated
October 1, 1997, showed that the sequence timers actuated within their set-point limits and
consistently enveloped the timings set for various systems in Tech. Report NE- 664,"Safety
Analysis Impact due to Addition of EOG Sequencer, Surry Units 1&2," Rev. 02.
E1.2.2.2.1(b) 4160 VAC System
The team reviewed the following drawings and calculations to determine the adequacy of the
voltage protection and voltage set point for degraded and undervoltage condition at the 4160V
Class 1 E buses 1 H and 1 J:
calculation EE-502, "4.16 KV Bus Degraded Voltage & Loss of Voltage Relay Safety
Limits ," Rev. 01
calculation EE-0385, "4160V Undervoltage Relays Types SLV & NGVCSA," Rev.01
The determined that at the degraded voltage setpoint of 90+/-1 percent volts at the 4160
electrical busses, all electrical equipment fed off the buses would continue to operate
satisfactorily. The team found the design of the 4160 VAC system adequate except for the
following discrepancy. *
The team found that the licensee had concluded in calculation EE-502 that some 480 V buses
fed from the 4160 VAC Class IE bus could experience below design voltage levels of
88 percent (design minimum was 90 percent) when a minimum voltage of 89 percent at the
4160 VAC Class 1E bus was considered. Although the recommendation in calculation EE-502
was to increase the TS minimum voltage at the 4160 VAC bus, this recommendation was not
implemented. Based on the te*am's questions on the long term resolution to this problem, the
licensee performed additional evaluation on this low voltage condition and concluded that it was
unlikely the 480V buses would experience voltages lower than _89 percent based on:
Surry's historical steady state voltages and transmission voltage data (consistently in
90 percent plus range)
the provision of the automatic voltage tap ~hanger on the Surry Reserve Auxiliary
Transformer
voltage profiles developed in calculation EE -034, "Surry Voltage Profiles," Rev. 1
The team agreed with the licensee's new analysis that it was unlikely that the 480VAC buses
would experience voltages lower than 89 percent. However, the team concluded that the
10
licensee's failure to address this potential design issue a weakness. The licensee wrote DR S-
98-0569 to address this observation.
E1.2.2.2.1(c) 480 and 120 VAC System
The team's review of:
calculation EE-0038 ,"Electrical Power Review of 1-SI-P-1B Motor Replacement," Rev.
0
calculation EE-0497, "SR 480 V Load Center Coordination," Rev. 0
calculation 14257.29 - E - 1, "Consolidation of MCC Control Circuit Cales," Rev. 0
found no problems. Attachment C1 to calculation EE-0497 demonstrated that the breakers for
LHSI pump motors were adequately set for both the instantaneous and short time delav trips
except for 1-SI-P-1 B pump motor (see Section E 1.2.2.2.1.g). Attachment C4 to calculation EE-
0497 demonstrated that the breakers for RS pump motors were adequately set for both the
instantaneous and short time delay trips. The team also reviewed the inside recirculation pump
elementary diagram 11448 - ESK- 6 AB, Rev. 7 and noted that the timer (62-14 H4) settings of
120 seconds to start the pump were consistent with the load sequence time-lines for a loss of
offsite power (LOOP)+consequence limiting safeguards (CLS).
E1 .2.2.2.1 (d) Evaluation of Plant Modifications
The team reviewed the safety evaluation which was used to document the replacement of
1-Sl-1 P-B motor performed under work order EWR 88-072. The original 250 HP motor for
LHSI pump, 1-SI-P-1 B, 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-1 B 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-1B pump would start and operate when required. The
team's review of the SI pump thermal protection issue will be an Inspection Followup
Item 50-280/98-201-04.
E1 .2.2.2.1 (e) Cable Ampacity and Short Circuit Rating
The team reviewed the following calculations to verify that the cables were adequately sized to
carry the normal and short circuit rated current:
(1)
Calculation 14937.3049-E-001, "Impact on Cable Ampacity from Installation of Tray
Covers," Rev. 02
(2)
Calculation 01039.101 O-E-3, "Cable Sizing Emergency Diesel Generator 1, 2 & 3 to
. Emergency Buses 1H, 1J, 2H, 2J," Rev. O
11
Additionally, because Surry did not have cable ampacity calculations for many of their electrical
cables, the team requested ampacity calculations for selected cables (loads of 25 HP and
above) which penetrated containment to ensure that these cables were adequately sized.
Specifically, the team requested a cable ampacity evaluation to be performed for 10 inside
containment cables when a derating for 50 *c was applied. The licensee"s sampling evaluation
conclu<;ied that the 1 O cable samples met the ampacity derating for 50 *c. The team also
requested a similar evaluation to be done for a sample cable inside containment that serviced
loads smaller than 25HP .. Based on a review of the sample evaluation, the team found the
cable sample evaluated to be adequately sized.
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 VAC bus were not adequately sized to
carry the fault current on the 4160 VAC bus. The team was conc;erned 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.
The team reviewed calculation 01039.1010 - E -3 and found it acceptable. The team noted that
the existing installed power cable was suitable to carry a continuous EOG output of only 2850
KW continuous which was about 100 KW more than the expected maximum EOG loading of *
2750 KW.
E1 .2.2.2.1 (f) Protective Coordination
The team's review of the calculation EE-0497, "SR 480V Load Center Coordination," Rev. O
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.
E1 .2.2.2.1 (g) Electrical Penetration *Protection
The team reviewed Technical Report {TR)# EE-0094 & EE-095 dated January 13, 1994, and
calculation EE-0503, "Electrical Penetration Continuous Current Sizing Ampacity Cable
Penetration," Rev. O to determine whether the penetration conductor ampacity ratings and short
circuit current withstand limits for the IRS pump motors were consistent with vendor data and
installed configuration. Calculation EE-0503 established that a 250 MCM size penetration
conductor could carry 184.48 amps at normal containment temperature and 118.35 amps at the
containment accident temperature. Additionally, it was determined that the IRS pump motors
could draw a maximum of about 362.5 amps at maximum pump flow during most limiting
(accident) condition. Because the IRS motors were supplied through two 250 MCM conductors*
12
.,
per phase which could only supply 236 amps, these MCM conductors appeared to be
insufficiently sized to be able to carry the required full load current of 362.5 amps.
The licensee contacted Conax, the penetration assembly vendor, and determined that
calculation EE- 0503 was in error. The ampacity data provided by the vendor had already
factored in the correction factors for Surry temperature profile and no additional corrections
were required. As per the vendor, a 250 MCM penetration conductor was good for 230 amps
and with 2 conductors per phase in the circuit the penetration was capable of handling motor
full 'load current of 362.5 amps without exceeding its current limit of 460 amps. The team
determined that with no derating applied to vendor ampacity data, the presently installed
penetration conductors for the IRS pump motors were adequately sized to carry the required
load. The technical report and the calculation, EE-0503, incorrectly established the current
carrying capacity for the penetration conductors for it considered an additional derating factor
which was not necessary. The licens~e has written a DR S-98-0720 to establish appropriate
ampacity ratings consistent with vendor data and as installed conditions.
Though calculation EE-0503 evaluated the sizing of the penetration conductors for continuous
current, it did not address the short circuit withstand capability of the electrical penetration.
Surry Station had no calculation of record to demonstrate that short circuit withstand capability
of the penetration conductors furnished by the vendor was not exceeded with the "as installed"
conditions. The licensee agreed to perform an evaluation of the medium voltage (MV) and low
voltage (LV) penetration assemblies for Surry Unit 1. The evaluation showed that the short
circuit withstand capabilities for the medium voltage (MV) and LV penetration assemblies
exposure to short circuit currents at Surry were within their acceptable ratings except for one
circuit. The licensee identified this circuit as a feed to a welding receptacle used only during
refueling outages. The licensee has tagged the circuit and will relocate it to the appropriate
penetration assembly from the presently installed assembly.
The team noted that at Surry all electrical penetrations were protected with only one breaker
per original design. The review of the technical reports, EE-0094 & EE-0095 revealed that for
several of the penetrations 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.
E1 .2.2.2.1 (h) EDG Fuel Oil System
As per UFSAR Sec. 8.5, the EDG "day" tank have adequate fuel oil supply for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> full load
operation. As per calculation EE-0045, "Emergency Diesel Generator Voltage and Frequency
Response", Rev. 0, 205 gallons of fuel are consumed per hour. Therefore, for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of
operation 615 gallons of fuel oil are required in the "day" tank. As per TS Sec. 3.16, 290
gallons are required in "day" tank. This equates to about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of full load operation. The
requirement in the TS for fuel oil in the "day" tank is less conservative than stated in the
As per licensee, there is inconsistency in the various design documents in use of the term "day"
tank. Generally this term is used for any fuel storage tank that is located in the immediate
vicinity of the EDG. For Surry, there are two tanks located in the immediate vicinity of the EDG.
13
One is the base tank at the base of the diesel skid from which the diesel draws its fuel, and the
other is a wall mounted tank. The base tank gets refilled from the wall mounted tank. The wall
mounted tank is refilled from the underground tanks by the fuel oil pumps. The base tank has a
volume of 310 to 476 gallons and the wall mounted tank has a volume of 470 to 510 gallons.
The combined capacity of the base tank and the wall mounted tank is greater than 615 gallons
required for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of operation. The UFSAR refers to the "day" tank as the combined
capacity of the base tank and the wall mounted tank, whereas the TS refers to the "day" tank as
the base tank. At Surry, the fuel oil system up to and including the underground tanks is safety
grade. The 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of fuel supply to the EOG is, therefore, assured as required by the UFSAR.
However, inconsistency in use of the term "day" tank has led to non-conservative requirement
in TS.
This item was also previously identified during the EDSFA, and a commitment to revise the TS
was made. The TS change was not issued. The licensee initiated Deviation Report 898-0568
to bring consistency between the UFSAR and the TS.
E1 .2.2.2.1 (i) EDS FA Action Items
The team reviewed the status of selected "Open Action Items" resulting from the licensee
initiated EDSFA performed during Jun 1992 time frame. The following "Open Action Items"
were found still unresolved:
Impact of high DC voltage on DC components (Action Item N. A-185)
Delete requirement from UFSAR for periodic testing to measure insulation resistance of
equipment and circuits (Action Item N. 1-368)
Testing procedure changes for station battery discharge test (Action Item No. I - 453)
Provision for providing protective relay on EOG excitation circuit (Action Item No. 1-057)
The licensee wrote DR S-98-613 to investigate the reasons why the action items had not
resolved.
E 1.2.2.2.2 DC System Review
E 1.2.2.2.2(a) EOG Batteries Transfer Scheme
- 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, EDG 3 battery. A~er 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 EDG battery to supply the field-flash and control circuits for
one EOG for two hours of operation.
14
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 both 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-
197 4 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
308-197 4. 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 transfer 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.
The licensee initiated DR-S-98-0605 to evaluate and disposition this concern but did not
conclude its review during the inspection.
The team considered the design of the EOG battery transfer scheme a potential unreviewed
safety question (USO) 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 ED Gs' reliability. The basis of a USO 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 SBC, 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 EDG transfer switch constitutes a potential
USQ is considered an Unresolved Item 50-280/98-201-08.
E 1.2.2.2.2(b) Main DC Buses Molded-Case Tie Switch
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;
15
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) 1-MOP-EP-030,
"Removal from Service and Return to Service of Station Battery 1 A", 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 terminnls 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 inspection that showed, for either
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 failure
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 USO.
-
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 review 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
changed 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 5-98-0719. A fault current above the DC
breaker's interrupting capacity is a new type of equipment malfunction which makes the total
16
!'
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 constitutes an USQ is
considered to be Unresolved Item 50-280/98-201-09.
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 50-280/98-201-10.
E 1.2.2.2.2(c) Electrical Penetrations
The team questioned the licensee on the fault protection and adherence to the single failure
criteria for DC circuits directed through penetrations. The licensee had no analysis that justified
the sizing of the DC penetrations for faults and that supported compliance with the single failure
criteria for the penetrations' fault protection. The licensee performed a evaluation that
demonstrated that all DC penetration feedthroughs were fully rated for available fault currents
and were appropriately sized for nominal continuous currents. Thi~ also enabled these circuits
to meet the single failure criterion.
E 1.2.2.2.2(d) Sizing of Station Batteries
The team verified the sizing of the four station batteries for their two-hour load 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
became limited to a load of 9 KV A instead of their full load of 15 KV A 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.
E 1.2-°2.2.2(e) Sizing of EDG Batteries
The team reviewed calculation 14937.28, Revision 2. The calculation assumed a successful
EDG start at the end of the two-hour load profile and at least one unsuccessful start in the first
17
,r
minute. The 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, theseby 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.
E 1.2.2.2.2(f) DC Fault Contribution
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 seiective 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 EOG batteries. Licensee wrote DR S-98-0677 to review
this concern. Review of DR S-98-067tis considered to be Inspection Followup Item 50-
280/98-201-13.
E 1.2.2.2.2(g) DC Load FlowNoltage Drop
The team reviewed calculation E-0046, "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 a 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 interrack connector (twelve-foot, 750 MCM cable) when in fact
there are two such connectors which for battery 1A will cause an another .24 VDC drop in
battery terminal voltage at the end of a battery discharge. The licensee wrote DR S-98-067 4 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. *
18
A similar analysis did not exist to determine whether the DC components supplied by the EDG
batteries had 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.
E 1.2.2.2.2(h) DC Load Control
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 data base of SELL
(Station Electrical Load List) and then incorporated in the next update of that data base.
- 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 data base annually.
No one person is accountable for electrical load changes and has ownership
responsibility for incorporating them in SELL data base.
The time between both calculation revisions and SELL data base updates (5 to 7 years
for sorne 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 7 out
of the 30 DCPs had not properly incorporated load changes into the marked up printout
of the SELL data base. These errors probably would have been inputted into the SELL
data base at the next annual update. The total error on DC bus 2B, 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.
E 1.2.2.2.2(i) Surveillance tests
The performance tests for the station and EDG 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 10 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 EDG 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
19
.,.
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.
E 1.2.2.2.20) Fuse Control
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.
E 1.2.2.2.2(k) Ground Detection Schemes and Ampacity of DC Cables
The licensee did not have a formal calculation for sizing the ampacity of existing DC cables and
was not generating ampacity calculations to support new cables for DCPs. However even with
this lack of documentation to support the ampacity ratings of existing and new DC cables, the
licensee was able to verify the ampacities of the samples of DC cables and penetration
feedthroughs selected by the team.
The team reviewed the ground detection schemes for the station and EDG batteries. The one
for the station batteries was a standard ground detection scheme using indicating lights so the
team concentrated on the one for the EDGs. The licensee monitors for grounds by weekly .
voltage to ground checks on both the positive and negative buses for each EDG battery. The
only problem that the team was able to determine was that the system was subject to grounds
during the voltages to ground checks since the monitoring was not continuous. The acceptance
criteria for .the weekly monitoring was established to detect any grounds smaller than 139,000
ohms which seems reasonable since the ground current produced by higher resistances will be
almost negligible.
E 1.2.2.2.2(1) Design Control Issues
The team identified several incidences of failure to follow required or standard design control
practices:
Attachment #20 and addendum A in calculation EE-0046 presented opposing views of
load shedding during an SBO. Attachments were to be used to support a calculation not
to modify its content per Nuclear Design Control Manual, NCDM 3. 7, Revision 9, *
Attachment 2, page 10. Step 6.1.3 of that same procedure allowed an addendum to
modify or supplement content in a calculation. Thus attachment 20 should have been
an addendum instead of an attachment.
20
f
Attachment 20 and Addendum A did not take exception to Assumption 4 in calculation
EE-0046 which stated that the inverters would be assumed to be at full load during
battery discharge. Attachment 20 and addendum A respectively assumed inverter
loading based on connected load or actual current measurements.
Calculation EE-0499 did not identify any required assumptions in accordance with
NCDM 3.7, Step 6.3.6 and attachment 2, Page 9 under the heading ASSUMPTIONS.
Appendix R coordination study was not updated to reflect a more conservative fault
current value and calculation 14937 .16 was not superseded when calculation EE-0499
was performed. Because EE-0499 determined a more conservative fault currents on
station battery buses than calculation 14937.16, it should have been used to revise the
Appendix R coordination study. Before calculation EE-0499 was completed, calculation
14937.16 provided the inputs to the Appendix R coordination study. Licensee initiated
deviation report S-98-0679 to resa!ve this matter.
Licensee did not supersede calculations 1250-035:-001 and 14937.75 when calculation
EE-0046 - which is the most recent calculation performed to determine the size of the
battery - was completed.
Drawings 11448-ESK-6EH1&6EH and 11448-ESK-6EG & 6EG1 each contained a 125
VDC circuit that energizes a solenoid valve to close a pneumatic control valve that
admits steam into-the turbine-driven auxiliary steam generator feed pump for a unit.
Based on the team's questions, the licensee determined that the overcurrent devices for
these circuits were not the fuses shown only in the positive leg of each circuit on the
above drawings but were in fact two pole circuit breakers. Licensee wrote DR No. S-98-
0468 to document this discrepancy and resolve the matter. Each of the four drawings
identified ar~ control room priority drawings in accordance with VPAP-0302.
One controlled Drawing 11448-FE-1G differs from another drawing 11448-FE-1A2 about
presentation for tie breaker as a molded case switch or as a breaker. Each drawing was
a control room priority drawing as stated on in procedure VPAP-0302.
E.1.2.2.3
Conclusion
The team concluded that adequate AC and DC supply systems were available for both normal
and accident conditions. *
The team raised several concerns with the licensee's resolution of problems previously
identified in their electrical calculations. The licensee did not have cable ampacity calculations
or breaker-to-breaker and breaker-to-fuse coordination evaluations. Some of the problems
identified through the EDSFA effort had not been resolved.
The team had concerns with the lack of good design basis for the EOG battery transfer switch.
Additionally, it appeared that the licensee had not thoroughly evaluated the acceptability of
shutting the DC tie with both batteries still connected to the busses. The design of the EOG
battery transfer-scheme was weak in that it could potentially lead to common mode failure of
the EDGs associated with one unit. There were problems identified with electrical calculations,
problems with the process for tracking DC load changes, and inadequate technicai evaluation
for paralleling batteries.
21
It appeared to the team that the EDG battery transfer scheme and closing the DC tie breaker
were potential USQ issues.
E1 .2.3 Instrumentation and Controls (l&C) Design Review
E1 .2.3.1 Inspection Scope
The team reviewed SI l&C design and interfacing portions of the RWST for conformance with
the design bases. Specific areas of review included the SI system flow, pressure and
temperature instrumentation; accumulator level and pressure instruments; and the RWST level
and temperature instrument loops. Additionally, the team reviewed applicable SI system design
documents such as the UFSAR, TS; SDBD, setpoint documents, setpoint calcul~tions,
instrument loop uncertainty calculations, specifications, maintenance, surveillance, and
operating procedures, design drawings, modification packages, and miscellaneous l&C
documents.
E1 .2.3.2 Observations and Findings
E1 .2.3.2(a) RWST Level Instrumentation
The team reviewed the RWST level instrumentation to verify that (1) adequate water volume
was maintained in the tank as per TS 3.3.A..1 for accident mitigation, and (2) switchover to
recirculation phase was initiated at the proper water level in the RWST to ensure that adequate
volume of water was available in the containment to satisfy NPSH requirement for the LHSI
pumps. Surry has a safety-related wide range level and non-safety related narrow range level
instrumentation for the RWST. The wide range level instrumentation was used to initiate
switchover to recirculation phase and also provide indication of the RWST level in the control
room. The narrow range level instrumentation was installed to provide accurate indication and
alarming of RWST level in the 90-100 percent range to satisfy TS 3.3.A.1 requirement. The
team determined that the level in$trumentation were adequate to perform their design function,
but had the following observations:
The team's review of the numerous problems associated with overfilling the Unit 1 RWST
found that the overfill problems occurred, in part, because the Unit 1 RWST had the
overflow pipe which was below the 100 percent span of the NR level instrumentation and
because the licensee had been given the incorrect probe calibration curve by the vendor.
At the time of the narrow range probe was installed under DCP 81-046A, the licensee did
not realize the importance of the installation details such as the tank curvature and the
amount of steel around the capacitance probe. This resulted in the vendor supplying the
calibration curve which was not appropriate for the Unit 1 NR level probe and whi'ch did not
produce accurate level indication for the Unit 1 RWST level instrument. Licensee was
eventually successful in investigating and correcting the problems associated with the
Unit 1 NR RWST indication (EWR 91-20). The 1eam observed that , although this type of
probe (capacitance probe) did not require initial or periodic checks to verify proper probe
performance, had the licensee performed an initial calibration testing of the probe during
the modification, many of the problems might have been identified earlier. The narrow
range level instrument loop LT-102 was designed and installed to provide accurate
indication and alarming of RWST level in the 90-100 percent range to satisfy Tech Spec 3.3.A.1 requirement. *
22
Based on the team's concern that the operators may be using the less accurate wide range
RWST level indication, the licensee initiated a survey of on-shift operators at Surry to verify
which of the RWST level instrumentation (narrow-range or wide-range) was used for TS
compliance. The team expected that the narrow-range indicator would have been selected
since it was designed for that function. In response to the request, 26 licensed operators
were polled. The survey indicated that 15 operators used the 4 wide range channels
n
.. 1-1 OOA, B, C, D) exclusively and 11 operators used both the 4 wide-range and the .
narrow-range indicators. Although it appeared that the operators did not understand the
design intent of the narrow-range instrument to satisfy TS compliance. licensee determined
that the use of wide range instruments was acceptable (ET-NAF-980042, "Safety Analysis
Limit for RWST Level for Current PT-36 Surveillance Practices, Surry Power Station
Units 1 and 2," March 9, 1998) in that there was a very high probability for one out of the
four wide-range channels accurately indicating an actual low level condition which would
initiate filling up of the RWST in accordance with alarm. response procedure 1 A-A 1, "RWST
Tech Spec LO LVL," Rev. 3.
E1 .2.3.2(b) SI Accumulator Level Instrumentation
The team reviewed the SI accumulator level instrumentation which provides input for RG 1.97
indication and Tech Spec HI/LO accumulator level alarms in the main control room. The team's
review determined minor inconsistencies between the transmitter span calculation, loop
uncertainty calculation and instrument calibration procedure.
Calculation EE-0376, "SI Accumulator Level Xtmr Spans Transmitter L T920, 922, 924, 926, 928
and 930," Rev. 0, calculated a span of O - 23.68 inches water column (W.C.) for all Units 1 and
2 accumulator level transmitters. However, calculation EE-0377, "SI Accumulator Level
Setpoint, CSA," Rev. 0, calculated the instrument loop uncertainty for the accumulator level
instrument loop based on a span of O - 23.83 inches W.C. Although this calculation referenced
calculation EE-0376 as source document, the 23.83 inches span was not consistent with the
23.68 inches span established by calculation EE-0376.
Also, calibration procedure 1-IPM-SI-L-920, "SI Accumulator Tank 1-SI-TK-1A Level Loop L-1-
920 Calibration," Rev. 0, provided instructio,s for calibration of a typical level instrument loop,
based on a span of O - 23.57 inches W.C., which did not agree with span values in calculation
EE-0376 or calculation EE-0377. Per the licensee's investigation, the instruments were
actually calibrated per the procedure and calculations EE-0376 and EE-0377 were in error.
Preliminary calculation using the as-installed span showed a slightly lower instrument error that
.would result from calculations EE-0376 and EE-0377, which was conservative. To correct
these discrepancies, the licensee issued Engineering Task Assignment Tracking Numbers 98-
0098-1 and 98-0098-2.
E1 .2.3.2(c) RWST and SI Instrument Loop Accuracy and Setpoint Calculation
The team reviewed the following licensee's documents for setpoint methodology, uncertainty
calculation, and related calculations for various RWST and SI instrument loops to verify that
adequate tolerance for instrument errors had been incorporated in the design:
14257. 73-C-2, "Instrument Accuracy for RG 1.97 High Pressure Safety Injection
Transmitters-DC-84-38-1," Rev.O
23
14257.73-C-16, "Instrument Channel Accuracy for RG 1.97 Accumulator Tanks Pressure
Transmitter Upgrade, DC-87-001, DC-87-002," Rev. O
EE-0453, "Refueling Water Storage Tank {RWST) Temperature Uncertainty {T-CS100A,
T-CS100B, T-CS200A and T-CS200B)," Rev. 2
EE-0112, "Refueling Water Storage Tank Level Uncertainty," Rev. 1
EE-0377, "SI Accumulator Level Setpoint, CSA," Rev. 0
EE-0707, "Surry Refueling Water Storage Tank Uncertainty- Narrow Range," Rev. 0
SM-778, "Calculation of Surry LHSI Flow Uncertainty," Rev.a
STD-GN-0030, "Nuclear Plant Setpoints," Rev. 5
STD-EEN-0304, "Calculating Instrumentation Uncertainties by the Square Root of the Sum
of the Squares Method," Rev.2.
The teai:n's review determined that the calculations adequately demonstrated loop accuracies
and setpoints.
E1 .2.3.2(d) System Modifications
The team reviewed two l&C modification packages for the SI and RWST systems:
j. DCP 81-046A, "Refueling Water Storage Tank Narrow Range Instrumentation"
2. DCP 93-003-3, "HHSI Flow Indicator Addition" *
Based on the review, the team concluded that the modifications maintained existing design and
10 CFR 50.59 evaluation and documer1t closeout were performed adequately.
E1 .2.3.3 Conclusions
The l&C design for the SI system and interfacing portion of the RWST was considered
adequate. Minor inconsistencies were observed in the calculations and surveillance procedure
for the SI accumulator level instrumentation
E1 .2.4 System Walkdown.
E1 .2.4.1
Inspection Scope
The team conducted a walkdown of the SI System and the plant areas, including the pump
.rooms, the RWST, penetration area, the control room simulator, the switchgear rooms, the
diesel generator rooms, and the cable spreading room. The team focused on comparing
system configuration to the design basis documents and the UFSAR. The team also looked
closely at equipment condition, area cleanliness, tagging, and the nieans used to avoid
potential hazards such as missiles, flooding, fire, and pipe rupture.
E1 .2.4.2 Observations and Findings
The team determined that the overall material condition of the plant areas was good. The
equipment sampled matched the design documents. However, the team made the following
observations.
The team observed that the sensing lines for Regulatory Guide 1.97 flow transmitter
FT-1943A had an unsupported span of approximately 8' to 9'. This installation was not in
24
accordance with tubing instrument specification SUl-0001, "Specification for Installation of
Instrumentation," Rev. 4, which required 5'-0" maximum unsupported span for ~" tubing.
DR# S98-0392 has been initiated by the licensee to take corrective action. This
discrepancy was also identified independently by the licensee.
The team observed a high point in the sensing lines for Regulatory Guide 1.97 flow
transmitter FT-1940A. The installed configuration could result in erroneous flow indication
due to air pockets in the transmitter sensing line. The transmitters were not installed in
accordance with installation specification SUl-0001 and standard installation drawing
NASUAE2.STD, "Flow Transmitter Installation Detail" which required sensing lines to be
sloped and not have any high points. The licensee has issued DR# S98-0392 to take
corrective action. This discrepancy was also identified independently by the licensee.
The team observed a low pointat the flow element taps for Charging Pump 1C flow
transmitter FT-1183. The installed configuration could act as trap where debris and crud
accurriulatibn in the lirie could result in erroneous flow indication. The taps were not
installed in accordance with specification SUl-0001, which required that sensing lines be
sloped and not have any low points. Based on review of the design drawings, the flow
element taps were sloped downward in accordance with the manufacturer's
recommendation, but the sensing line downstream of the manufacturer's connection did not
have any drain provision as required by specification SUl-0001. The licensee indicated that
the installation was done in accordance with specification NUS-9115 (now voided and
superseded by specification SUl-0001) which lacked adequate guidance. According to the
licensee, there have been no problems associated with the affected instrument sensing
lines that have been identified, therefore the installation was considered acceptable.
E1 .2.4.3 Conclusions
In general, the SI System design observed during walkdown was consistent with the design
basis requirements. The team identified minor installation discrepancies related to improper
instrument line span, and low and high points in instrument lines.
E1 .3 Recirculation Spray System
E1 .3.1 Mechanical Design Review
E1 .3.1.1 Inspection Scope
The team evaluated the capability of the Recirculation Spray (RS) system to depressurize the
- containment within one hour and maintain it at subatmospheric conditions to ensure
containment integrity and minimize release of radioactive fission products from the containment
following any High Energy Line Break (HELB) accident inside containment. The team also
reviewed the RS system capability to remove decay heat, and its interface with the Service
Water (SW) system that removes heat from the RS coolers.
25
E1 .3.1.2 Observations and Findings
E1 .3.1.2(a) RS System Flow
The team evaluated the following calculations to evaluate the capability of the RS system to
fulfill its safety function:
01039.621O-US-(8)-107, "Containment LOCA Analysis for Core Uprate," Rev. 0
01039.621O-US-(8)-106, "LOCTIC LOCA Input Parameter Values for Core Uprating,"
Rev. O
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-1 A & 1 B)
with no isolation valves.
Through Y:z instrument tubing on the RS side of the Recirculation Spray Coolers with
partially (1 % 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 & 8.
Through Y:z 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 & 18)
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-18 & 19 and fully open instrument valves
2-RS-43 & 57 downstream of level switches 2-RS-LS-252 A & 8.
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 8) being 3029 gpm, to
the recirculation spray headers after allowing for the losses 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-R,S-E-1C & 10)
with no isolation valves.
26
Through W' 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 Y:t 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-1 C and
1 D) with no isolation valves.
Through W' 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 losses 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 continue 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 the ORS flow
requirements to the 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 50-281/98-
201-19.
E1 .3.1.2(b) RS Pump Surveillance Testing:
The team reviewed and evaluated the test data associated with the following surveillance tests
performed on the IRS and ORS pumps:
1-0PT-RS-003, "Flow Test of Inside Recirculation Spray Pumps 1-RS-P-1A and 1-RS-
P-18," Rev. 10
27
J
2-0PT-RS-003, "Flow Test of Inside Recirculation Spray Pumps 2-RS-P-1A and 2-RS-
P-1 B, "Rev. 9
- *
1-0PT-RS-001, "Containment Outside Recirculation Spray Pumps Flow and Leak
Tests," Rev. 7
2-0PT-RS-001, "Containment Outside Recirculation Spray Pumps Flow and Leak
Tests," Rev. 8
The test data showed that the both the IRS and ORS pumps provided sufficient flow to satisfy
requirements specified in the surveillance tests.
E1 .3.1.2(c) RS Pump Net Positive Suction Head (NPSH)
The team reviewed calculation 01039.6210-US-(B)-107, "Containment LOCA Analysis for Core
Uprate," Rev. O which determined the NPSH available for the IRS and ORS pumps.
This calculation used the SWEC LOCTIC co1T1puter program to determine the available NPSH
for the RS Pumps. The most limiting case for the NPSH available to the RS pumps was
determined to be the Double Ended Hot Leg Guillotine (DEHLG) with maximum SI and both
trains available since the minimum NPSH occurs early in the transient. In this calculation the
containment pressure, sump water vapor pressure and the height of the sump water were
utilized, along with the pressure losses, to calculate the available NPSH. Calculation .
01039.621O-US-(B)-106, "LOCTIC LOCA Input Parameter Values for Core Uprating," Rev. O
provided the input for the screen, piping and pump entrance pressure losses.
For the IRS pumps the minimum NPSH available was determined to be 13.0 ft. versus a
required NPSH of 10.2 ft. at a pump flow rate of 3500 gpm. For the ORS pumps the minimum
NPSH available was 10.0 ft. versus the required 9.1 ft. at a pump flow rate of 3250 gpm. The
NPSH available for both pumps was greater than required.
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 tum
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 analysis 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 con~ainment and ~valuate the
28*
- ----
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 an Inspection
Followup Item 50-280/98-201-20.
E1 .3.1.2(d) Environmental Qualification of.the IRS Pump Motor
The team reviewed environmental qualification file, QDR S-4.4, Rev. 09 for inside
containment recirculation (IRS) GE Model SK pump. motors. The team determined that the
motors are qualified to perform their safety function during a LOCA. The team, however,
had the following observations regarding the qualification:
To determine the qualified life of the IRS pump motor for normal service, the EQ file
considered that the pump motors were run for 30 seconds every year. This was not
consistent with procedure 10PT-RS-003, "Flow Test of Inside Recirculation Spray
Pumps 1-RS-P-1 A and 1-RS-P-1 B", that required the pumps to run much longer for full
flow testing every refueling outage. Consideration of the longer run time for the motor
would reduce the motor qualified life. The reduction in qualified life would not
significantly affect the existing motor qualified life, but it would reduce the qualified
margin. The licensee agreed to revise the EQ file to eliminate the specific operational
testing duration and assume a conservative bounding operational testing duration for
qualification.
In a couple of instances, Pages D-8 & 10, the EQ file stated that after 60 minutes into
the accident only one IRS pump was required to maintain the containment at
subatmospheric pressure. The EQ file did not cite any reference for this information
nor the basis for this information. The licensee could not verify the basis for this
statement in the EQ file. The licensee agreed to revise the EQ file to clarify that only
one IRS pump would be required after the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after LOCA to maintain the
containment at subatmospheric pressure and cite the corresponding reference.
Following the first hour after LOCA, Arrhenius methodology for accelerated aging was
used to justify post-LOCA qualification for the IRS pump motors. Arrhenius
methodology is valid for a single reaction and when ample supply of oxygen is available
for the oxidation/degradation to occur. For the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into a LOCA, multiple
reactions due to temperature, radiation, chemical spray, humidity and pressure are
occurring simultaneously, and also there may be little or no supply of oxygen.
NUREG/CR 5313, "EQ Risk Scoping Study," dated 1/89; therefore, recommended that*
real time be considered for qualification for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the accident. Use of
accelerated aging instead of real time in the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after LOCA will provide a
higher post-LOCA qualified life but is considered non-conservative. For qualification of
the IRS pump motor, use*of real time for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> would lower the post-LOCA
qualified life. The motors were currently determined to be qualified for 120 days for
post-LOCA, whereas qualification was only required for 30 days *post-LOCA as per
Surry's licensing commitment for post-LOCA operability. Ample margin existed in
existing qualified life and, therefore, qualification should not be affected. The licensee
agreed to revise the EQ File to use real time to justify qualification for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
after LOCA.
The revisions to the QDR S-4.4 will be tracked under ECR-1609.
29
- - - -
-- -- -- --
E1 .3.1.3 Conclusions
The team concluded that the RS system was adequately designed to provide the required
flow to the RS spray headers to mitigate the consequences of a LOCA which also bounds
the MSLB. Also, the system provided the required NPSH for the RS pumps when taking
suction from the containment emergency sump in the recirculation mode. However, the
team had concerns regarding unidentified flow paths in the discharge side of the RS pumps
that were not taken into account in the containment analyses of record that established the
flow requirements to the spray headers. Also, the team was concerned about the presence
of, as yet not quantified, unqualified coatings inside containment that could potentially
reduce the NPSH for the ECCS pumps by blocking the emergency sump screens.
E1 .3.2 Electrical Design Review
See Section E1 .2.2
E1 .3.3. Instrumentation and Control (l&C)Design Review
E1 .3.3.2 Observations and Findings
E1 .3.3.2(a) Containment Water Level Instrumentation
The team reviewed the calibration basis for RG 1.97 containment sump level instrument
loops 151 A and 151 B. Calculation 12846.01-PE-030-0, "Containment Water Volume vs.
Elevation," Rev.a calculated the containment volume with respect to height. Design
reference procedure 1-DRP-003, "Curve Book," Rev. 36, page 123, shows a volume/height
curve for the containment, entitled, "Containment Sump Volume vs. Wide Range Level (LI-
RS-151 A and 1518) Feet." The team noted that these documents were not consistent. For
a containment height of 9 ft, calculation 1_2846.01-PE-030-0 calculated a volume of 600,000
gallons, whereas, the curve book, 1-DRP-003, shows 490,000 gallons. The licensee
confirmed that calculation 12846.01-PE-030-0 was correct and the*curve book was in error.
Since the instruments were scaled O - 9' level, control room level indicators Ll-151A and B
were not impacted by the volume discrepancies. The licensee evaluated the condition and
determined that the transmitters would still be able to provide the required input for safety
related indication. Also, the nomenclature in the curve book read "containment sump
volume ... " which was incorrect as the wide range level instrumentation was actually
measuring the containment volume. However, the curve book which was issued for control
room use contained incorrect information.* Also, UFSAR Sec. 7.5.2.2 needed to be updated
to reflect the correct instrument range. DR # S-98-0496 was issued to take corrective
action.
E1 .3.3.2(b) RS Heat Exchanger Level Instrumentation
The team reviewed the design of the level switches provided to monitor accumulation of
water in the RS HX which were normally kept in a dry lay up condition. During normal plant
operation the RS HX were kept dry, and any presence of SW water in the RS HX was
detected by level switches LS-152A, B, C & D that provided an alarm signal to the control
room. The level switches were shown on drawing 11448-FM-084B, "Flow/valve Operating
Nu.mbers Diagram Recirculation Spray System," Sht.1, Rev.18, and Sht. 2, Rev. 26. The
drawings indicated drain valves RS-70, 72, 74 & 76 for the level switches to be normally
30
_,,
open. This valve lineup would cause water in the float chamber to drain and defeat the
purpose for which the level switches were provided. Further review of Operating Procedure
1-0P-RS-001A, "Outside Recirc Spray System Alignment," Rev.2, confirmed that the valves
were throttled 1 ~ turns open. The licensee indicated that the drain valves were kept partly
open to al.low drainage of condensation in the service water side of the heat exchangers to
prevent nuisance alarm. A preliminary calculation performed by the licensee determined
that this valve position would permit a leakage rate of up to 1.39 GPM before the alarm was
activated. No engineering analysis or functional test to justify this leakage rate was
provided to the team. A preliminary evaluation by the licensee showed that the potential for
SW water leakage in the RSHX was considered insignificant due to the dry lay up
configuration of the RSHX. This issue did not*constitute any safety or operability concern.
The licensee has issued PPR 98-032 and DR# 98-0710 to take corrective action.
E1 .3.3.2(c) Intake Canal Level Instrumentation
The inspection team evaluated the Intake Canal level instrumentation to verify its capability
to initiate turbine trip and isolation of the non-safety related portion of the SW system,
consisting of circulating water valves MOV-CW-100A through D, 106A through D, 200A
through D, 206A through D and service water valves MOV-SW-101A & B, 102A & B, 201A
& B and 202A & B. On low-low intake canal level signal, the turbine tripped and the above
valves closed to conserve flow for RS cooling on decreasing water level in the canal. TS Sec. 3.14 and TS Table 3.7-4 provided the design bases for this isolation function: The
instrumentation system also provided signal for RG 1.97 level indication and HIGH/LOW
level alarming in the main control room. The instrument loop that performed the isolation
function was safety-related. The indication/alarm instrumentation was in a separate loop,
listed as RG 1.97, Category 2 variable, which was not required to be safety related. The
team determined that the level instrumentation were adequate, but had the following *
observations:
The original design for the Intake Canal level instrumentation was classified as non-
safety related, however, in their letter #88-689 to the NRC, dated 10/19/88, Surry
committed to upgrade the intake canal level instruments to safety grade. DCP 88-33
was written to upgrade the Intake Canal level isolation system and the indication
instrument loops. The DCP upgraded only the power source for the level transmitter
associated with the RG 1.97 indication but not the transmitter or the bubbler tube or the
instrument air supply to the bubbler tube. The* Q-List still showed the level transmitter
as "NSQ" and still was the same type as the original transmitter. As per the licensee,
the portion of the commitment to provide safety related instrument to initiate non-
essential service water isolation was implemented but the indicator loop was not
upgraded. By not upgrading the indication instrument, plant safety or operability was
not affected. However, the licensee did not inform the NRC of their decision to not
implement their commitment to upgrade the level transmitter for intake canal level
indication and alarming. The licensee became aware of this issue on January 15, 1998,
just before this inspection, and issued DR 98-0171 to take corrective action. The DR
included an action to justify that the level indication was not required to be safety
related .
The team reviewed calculation EE-0043, "Instrument Loop Accuracy for Intake Canal
Level," Rev. 0, to verify instrument uncertainty for the Intake Canal level RG 1.97
. indicators Ll-101 and 201. This calculation determined an uncertainty of +9.07", which
31
assumed a worst case water temperature of 32F and a specific gravity of 1.025 for
salinity effect. The team noted that the effect due to high water temperature was not
addressed in the calculation. In response, the licensee performed a preliminary
- analysis to address the effect due to the maximum expected water temp of 1 OOF. The
analysis determined an uncertainty of +11.536", which was greater than the results of
. Calculation EE-0043. It also confirmed that high water temperature was the limiting
factor for instrument inaccuracy that was not considered in the original ec.lculation.
Engineering Task No. 98-0136 has been initiated to take corrective action. There was
no operability or safety concern as a result of this observation since existing
HIGH/LOW intake canal level alarm was set at a conservative value with adequate
margin.
Intake canal level HIGH/LOW alarm setpoints at30' and 26', respectively, were
established in modification DCP 88-33-3. The normal operating range of the intake
canal level was 26' to 30', as described in UFSAR Sec. 10.3.4.2, whose high and low
limits coincide with the HIGH/LOW alarm setpoints. Based on the team's observation,
the alarm setpoints had no allowance for instrument uncertainty nor an existing
calculation to justify the setpoints. This absence of uncertainty calculation was not
consistent with procedure STD-GN-0030, "Nuclear Plant Setpoints," Rev. 5, which
required that uncertainty calculation be provided for alarm setpoints that relate to a TS
value with an associated safety limit, such as the intake canal level. With the present
setpoints, the high and low alarm values of 30' and 26' could drift beyond the normal
operating range of the intake canal level if instrument uncertainty were taken into
account, therefore, defeating the purpose of the alarms. The licensee concurred and
issued Engineering Task No. 98-0136 to determine intake canal level alarm
uncertainties and reevaluate the alarm setpoints. There was no operability or safety
concern as a result of this observation since the alarm setpoints had adequate margin
with respect to intake canal safety analytical low level limit of 23' and maximum of 36'.
Existing TS Tables 3.14 and 3.7-4 specified a safety limit of 23' and a TS setpoint of
23'6" for the intake canal level. The intake canal level instrumentation was set at the
low level setpoint of 23'6"to automatically initiate turbine trip and non-essential service
water isolation. Calculation EE.:0274 established a setpoint uncertainty of 6.49".
Taking this instrument uncertainty into account, the intake canal level channels, set at
23'6", would potentially actuate when actual level was as low as 22'11.51"
(23'6"setpoint minus 6.49"uncertainty) which is below the safety limit of 23'. The low
level setpoint was, therefore, below TS limit after taking instrument uncertainty into
account. As a result, (1) The existing system might not have been operable because
the actuation point could be below tech spec value after taking into account the
instrument uncertainty and (2)The existing level setpoint and the tech spec values were
both set at 23'6", with no margin.
This issue was identified by the licensee on February 2, 1998, prior to the inspection
and to address any immediate* operability concerns (PPR 98-005). The licensee
reviewed the instrument calibration data sheets from 12/97 to 2/2/98 and found that the
actual actuation level was set at a minimum of 23' %", which satisfied the safety /TS
limit of 23'. The licensee concluded that there was no immediate operability concern .
To address the operability concerns prior to December 1997, the licensee issued DR
. 98-0302. It was found that there were two instances when actuation points were below
32
the 23' limit. Because of a potential report ability, the licensee is currently evaluating
the past operating record of the intake canal level instrumentation.
Based on the team's observation, it appeared that when the intake canal level setpoint
was established, there was no procedure at Surry to provide guidance in the
determination of adequate margin and instrument uncertainty that would have resulted
in a more conservative setpoint. Setpoint methodology STD-GN-0030 and tech report
NE-0994, providing th~ necessary guidance, were subsequently issued at a later date.
An action item was also included in DR 98-0302 to reevaluate the tech spec values and
setpoints in accordance with setpoint methodology STD-GN-0030 and NE-0994, revise
surveillance procedures and other document as required.
E1 .3.3.2(d) RS Instrument Loop Accuracy and Setpoint Calculations
In addition to those calculations discussed in Sec. E1 .3.3.2a and E1 .3.3.2d, the team also
reviewed the following licensee's calculations for various RS instrument loops to verify that
adequate tolerance for instrument error had been incorporated in the design:
EE-0134, "WR Containment Sump Level Indication," Rev. 1
EE-0724, "Canal Level Probe Channel Statistical Accuracy Calculation Channei
Numbers: 1-CW-LS-102, 1-CW-LS-103, 2-CW-LS-202, 2-CW-LS-203," Rev.a
EE-0164, "NR Containment Sump Level Indication," Rev.1
The team's review determined that the above calculations adequately demonstrated the
capability of the instruments to perform their intended function
E1 .3.3.2(e) System Modifications
The team reviewed two l&C modification packages associated with the RS system:
DCP 79-S61, "Containment Water Level Indication".
DCP 92-028-3, "Replacement of Radiation Monitoring Recorders and Rate Meters"
Based on the review, the team concluded that the design, 10 CFR 50.59 evaluation and
document closeout were performed adequately for these modifications.
E1 .3.3.3 Conclusions
The instrumentation and controls design for the RS and interfacing portion of the SW
system was considered adequate. The team observed that incorrect information on
containment vs. height was provided in the data book issued for use in the control room.
The team also noted the absence of any engineering justification regarding as-installed
configuration for the RS HX level instrument drain valves. A weakness in design control
was seen regarding the intake canal level instrumentation where instrument uncertainties
were not accounted for in the setpoints and Tech Spec and non-conservative use of water
temperature in determining instrument uncertainty .
33
E1 .4 UFSAR and Design Documentation Review
E1 .4.1 Scope of Review
The team reviewed the UFSAR, DBDs, and various drawings for consistency with the
design and licensing basis.
E1 .4.2 Inspection Findings
The team identified the following discrepancies:
UFSAR Figures 3.1-1 and 4.2-1 show all the breakers in DC System open.
The design margin for the station batteries stated in UFSAR Table 12.0-1 seems
erroneous because battery design sizing factors have not been incorporated in battery
demand load requirements.
Load profiles in UFSAR Figure 12.1.-2 do not agree with those in calculation EE-0046.
UFSAR page 14-17 refers to load shedding of non-Q loads but this appears not to be
true since battery does not directly load shed any non-Q loads during a LOCA.
UFSAR Sections 22.2 and 22.4 discuss closing the cross-tie during normal and
abnormal operations whereas the tie breaker is administratively closed only during
refueling or shutdown.
Reference is made in UFSAR Sections 1.4.28, 6.3.2.1 and 14.8.5.4.4 to "Hot Standby
plant condition. "Hot Standby" is not defined as a plant condition in TS Section 1.0.
UFSAR Table 6.2-4 says the SI Accumulator boron level is 2250 ppm. The table should
indicate that 2250 ppm is the minimum boron concentration in the accumulator to be
consistent with TS 3.3.
UFSAR Section 5.2.1,7 states containment isolation valves are "located so as to require
a minimum length of piping between the isolation valve and their penetrations". The
inside containment isolation valves (as listed in UFSAR Table 5.2-1)
1-SI-HCV-1851A/B/C for Penetration 20 (SI Accumulator Makeup) and valves
1-SI-HCV-1850A/B/CD/E/F for Penetration 106 (SI Test Line) are located near the SI
Accumulators which means there is a long piping run to the penetrations.
Penetrations 20 and 106 are classified as Class 5 piping penetrations which only require
normally closed isolation valve outside containment. The solenoid valves at the ,
accumulator were included as isolation valves in UFSAR Revision 17. UFSAR
Section 5.2 wili be clarified and is being tracked by ICMP Data Base Tracking Number
3050210100.00100, Item 1.
UFSAR Table 6.2-4 and Training Document Table 52-1 say the SI Accumulator
operating temperature is 100 - 150 °F. The tables should indicate that the maximum
accumulator temperature is 105 °F to be consistent with calculation SM-0917 and
01039.6210-US-(B)-107 which use a maximum temperature of 105 °F for LOCA and
Containment analyses.
34
UFSAR Table 6.3-1 says RWST Operating Temperature is 45 °F whereas the
temperate is normally controll'ed between 40 and 43 °F.
UFSAR Section 6.2.2.2.4 states that valves 8" and less in size which must function on a
SI Signal operate in 10 seconds (maximum). Procedure 1-0PT-Sl-020, "CSD Test of
Charging and Safety Injection MOVs and Check Valves," Revision 3 has a maximum
stroke time of 10.5 seconds for valves 1-S1-MOV-1867C,D and 11.5 seconds for valves
1-CH-MOV-1289A,B both of which are required to operat~ on SI signal. The maximum
stroke times for these valves was evaluated in Report NP #2057, "Type 1 Evaluation
Maximum Stroke Times for SI & CH MOV's Surry Power Station," dated August 8, 1989
and found to be acceptable. A UFSAR change was not prepared when the periodic
tests were revised to include the new acceptance criteria.
In UFSAR Figure 6.1-1, the HHSI hot leg recirculation lines are shown tapping into the
LHSI hot leg recirculation line downstream of check valves Sl-238, 239 and 240. Unit 1
P&ID 11448-FM-0898, SH 4, Revision 20 shows them connected upstream of these
check valves. The Unit 2 P&ID 11548-FM-089B, SH 4, Revision 25, however, shows
them connected downstream of the check valves as shown in UFSAR. The P&IDs
correctly depict the SI System difference between Units 1 and 2.
As per UFSAR Section 1.4.39, two tests are performed on the EDG every refueling
outage - one test at scheduled shutdown and the other before start-up. However, as
per TS Section 4.6.A.1.b only one test is performed on the EDG during refueling. As
long as the diesel performs within its TS requirements, the number of tests to be
performed during the refueling is immaterial. Surry Station performs the test once every
refueling outage as per the TS.
UFSAR Section 8.5 page 8.5-8 incorrectly states a degraded voltage range of 74 -
90 percent instead of a degraded voltage range of 75-90 percent as stated on
page 8.5-6 of the UFSAR and in Tech Spec. Table 3.7-4 item 7.a.
In UFSAR Section 8.5 (page 8.5-6), a statement is made that the time delays on a loss-
of-voltage condition and initiation of an automatic transfer of class_ IE emergency buses
is discussed below. The UFSAR does not include any discussion on the time delays.
Without this discussion it is difficult to interpret some of the time delays mentioned in the
The calculation EE-502 Page 15, Section 6.2.1.1 states that Automatic Load Tap
Changer (L TC) on Reserve Aux. Transformer changes one step (0.625 percent) every
two seconds, while UFSAR page 8.5-1 states that LTC changes one step
(0.625 percent) every second. Calculation EE-502 is correct and is consistent with
installed equipment and the UFSAR is incorrect.
As per UFSAR Section 8.0 Page 8.5-8, the EDG is loaded within 25 seconds whereas
TS Section 4.6.A.1.b states that the EDG will assume load in less than 30 seconds. The
TS requirement for EDG loading time is less conservative than the UFSAR. The
licensee could not provide any design basis to justify the two different times for the EDG
to assume load. According to licensee, the 25 seconds and 30 seconds referred to in
the UFSAR and TS has no safety significance. The licensee will, therefore, delete the
35
e
reference to the total time for the EDG to assume load in both the UFSAR and TS. The
licensee has i1"1itiated DR S-98-0509 to track this item, and all corrective actions will be
addressed in accordance with VPAP1601, "Corrective Actions."
UFSAR Table 5.2-1 identified SI accumulator test valves HCV-1850A through Fas
being automatically actuated by SI signal. The as-built schematics showed these valves
as remote manually operated. The licensee concurred that the UFSAR was in error and
issued Action Items SR-38-Sl-296.10 and 11 to initiate corrective action for both Units 1
and 2. This observation has no operability or safety impact.
The UFSAR Table 6.3-1 lists the recirculation spray water in the tube side of the RS
HXs and the service water in the shell side, whereas the specification NUS-2082,
"Containment Recirculation Spray Coolers", Rev. 3 indicates that the recirculation spray
water flows through the shell side and the brackish water through the tube side.
As per UFSAR Section 6.3.1.4, Page 6.3-11, the minimum NPSH available to the IRS
pumps occurs following a DEPSG. However, as per calculation 01039.621 O-US-(8)-
107, "Containment LOCA Analysis for Core Uprate," Rev. 0 the DEHLG is the most
limiting case for NPSHA for IRS pumps.
UFSAR Figure 6.3-2, indicates that the flow path through check valves %-RS-18 and
manual valves %-RS-17 & 19 is used to check the operation of the outside recirculation
weight loaded check valves RS-11 & 17 in Units 1 & 2. However, procedures 1-0PT-
RS-004, Rev. 0, "Outside Recirculation Spray Check Valves," 1-26-93 and 1-0PT-CT-
. 201, Rev. 9, "Containment Isolation Valve Local Leak Rate Testing (Type C
Containment Testing)," 7-15-97 do not indicate using this flow path and the valves.
UFSAR Table 6.3-1, reflects the old design flow and total developed h~ad for the RS
pumps.
The statement in UFSAR Section 1.4.17 which states that radioactivity concentration is
monitored at the containment fan cooler service water discharge is not correct. The
containment fan coolers used for containment cooling for normal plant operation are
cooled by the component cooling water system for which no radiation monitoring is
required/provided.
DBD Figures 3.1-1 & 4.2-1 should be correctly revised to show the tie between main DC
buses as a molded case switch or as a breaker.
The SI SDBD, Paragraph 13.3.2 incorrectly states that Technical Specification 3.3
requires power to be removed from valve MOV-1890C in the open position and valves
- MOV-1869 A, Band 1890 A, Bin the closed position. This requirement is now
contained in Technical Specification 4.11.
The SI SDBD, Table 11.1-5 incorrectly states that there is a minimum temperature for
the SI Accumulators. The current LOCA analyses considers only a maximum
temperature for the accumulators since this is a more conservative assumption.
'
Figures 3.1-1A, 3.3-1A, 4A, 4C, 4D and 4.2-1A in the SI SDBD erroneously indicate an
extra check valve downstream of valve 1-S1-MOV-1890C in LHSI discharge piping to the
RC cold legs.
36
SDBD-SPS-RS, Table 11.1-5, Item 2 states that the minimum acceptable IRS pump
flow rate is 3,500 gpm. Also, SDBD Table 6.1-1, Item 1 states that the design
requirement is 3,000 gpm. However, calculation 01039.6210-US-(B)-107, "Containment
LOCA Analysis for Core Uprate," Rev. 0 uses 3,000 gpm.
SDBD-SPS-RS, Table 11.1-5 states that the NPSHR for the IRS pumps shall be 10.1 ft.
@ 3,500 gpm. Also, SDBD Section 12.1 states that the NPSHR is 8.4 ft @ 3,000 gpm.
However, according to calculation 01039.6210-US-(B)-107, "Containment LOCA
Analysis for Core Uprate," Rev. 0 with CCN-A, the correct NPSHR for the IRS pump is
rn.2 ft. @ 3,500 gpm and 8.2 ft. @ 3,000 gpm.
SDBD-SPS-RS, Table 11.1-5 and Section 12.2 state that the NPSHR for the ORS
pumps is 8.4 ft.@ 3,000 gpm. According to above calculation 01039.6210-US-(B}-107
the correct value is 9.1 ft. @ 3,250 gpm.
SDBD-SPS-RS, Section 14.1.26 refers to a reference 25.3.37 in SDBD which is
annotated as "Not used."
SDBD-SPS-RS, Table 14.1.1 references to a Line Designation Table that is no longer
utilized as a design document and all the information formerly contained in this table
have been entered into a controlled Electronic Data System (EDS).
As per SDBD Sections 2.1.1 and 2.2.1, one of the safety related functions of the RS
system is removal of radioactive iodine from the containment atmosphere. However, as
per the SER and UFSAR only the containment spray system is credited with this
function, and no credit is taken for iodine removal via the RS system.
As per Surry drawing 11448-FE-19AJ, the leads from EOG# 1, EOG# 2 and EOG #3
batteries are all tied together at one junction box located in EOG # 3 room. This
essentially tied all three EOG batteries together and made them appear susceptible to a
fire in any one on the EOG rooms. During their walkdown on 2/18, the team verified
licensee's information that there was a fuse box located next to the junction box in the
EOG #3 room which was not shown on the drawing 11448-EE-19AJ. The fuses in the
fuse box provide for isolating the EOG #3 battery from the EOG # 1 or EOG #2 battery
or from each other whenever there is a fire the EOG rooms. Incomplete design
information was provided in drawing 11448-FE-19AJ by not indicating the fuse box
which made the diesels appear susceptible to a fire. Drawing 11448-FE-19AJ will be
revised to reflect "as built" conditions. The revision to the drawing will be tracked by SR-
38-EP-99.1.
NCRODP Table 54-1, lists the fluid in the Recirculation Coolers as Service Water in the
shell side and RS water in the tube side, whereas the specification NUS-2082,
"Containment Recirculation Spray Coolers," Rev. 3 indicates that the recirculation spray
water flows through the shell side and the brackish water through the tube side.
The Safety Injection System Training Document needs to be revised to reflect the actual
operation of accumulator venting. The SI Training Document, Page 13, discusses
venting the accumulators to the Gaseous Waste System which is no longer allowed.
37
Procedure 1-0P-Sl-002, "Safety Injection Accumulators," Revision 10 only has
instructions for venting the accumulators to containment.
E 1.4.3 Conclusion
The team identified numerous minor discrepancies in the UFSAR and DBDs which indicated
the need for improved control and updating of these documents .
38
.{'
APPENDIX A
OPEN ITEMS
This report categorizes the inspection findings as unresolved items and inspection follow-up
items in accordance with NRC Inspection Manual, Manual Chapter 0610. An unresolved
item (URI) is a matter about which more information is required to determine whether the
issue in question is an acceptable item, a deviation, a nonconformance, or a violation. The
NRC Region II office will issue any enforcement action resulting from their review of the
identified URls. * An inspection followup itern (IFI) is a matter that requires further inspection
because of a potential problem, because specific licensee or NRC action is pending, or
because additional information is needed that was not available at the time of the
inspection. The URls and IFls found in this insJjection are listed below:
Item Number
50-280/98-201-01
50-280/98-201-02
50-281/98-201-03
50-280/98-201-04
50-280/98-201-05
50-280/98-201-06
50-280/98-201-07
50-280/98-201-08
50-280/98-201-09
50-280/98-201-10
50-280/98-201-11
50-280/98-201-12
Finding Type
IFI
IFI
IFI
IFI
IFI
IFI
IFI
IFI
IFI
Description
LHSI Pump NPSH(Section E1 .2.1.2(d))
Error in Calculation SM-1047, "Reactor
Cavity Water Holdup" (Section E1 .2.1.2(d))
Unit 2 LHSI Pump Minimum Flow
(Section E1 .2; 1.2(g))
Motor Thermal Overload for 1-S 1-P-1 B
Pump (Section E1 .2.2.2.1 (d))
Adequacy of 4160 VAC Electrical Cables to
Withstand. Fault Current (Section
E1 .2.2.2.1 (e))
Breaker-to-Breaker and Breaker-to-Fuse
Analysis (Section E1 .2.2.2.1 (f))
Breaker Replacement (Section
- E1 .2.2.2.1 (g))
A1
EDG Battery Transfer Switch
(Section E1 .2.2.2.2(a))
DC Tie Breaker (Section E1 .2.2.2.2(b))
DC Bus Tie lnterlock(Section E1.2.2.2.2(b))
Battery Cale Discrepancies
(Section E1 .2.2.2.2(d))
Battery Design Margin (Section
E1 .2.2:2.2(e))
- t'
50-280/98-201-13
IFI
DC Fault Contribution (Section
E1 .2.2.2.2(f))
50-280/98-201-14
IFI
DC Load FlowNoltage Drop
(Section E1 .2.2.2.2(g))
50-280/98-201-15
IFI
Adequate DC Component Voltage
(Section E1 .2.2.2.2(g))
50-280/98-201-16
IFI
DC Load Control(Section E1 .2.2.2.2(h))
50-280/98-201-17
IFI
Battery Surveillance Test(Section
E1 .2.2.2.2(1))
50-280/98-201-18
IFI
Fuse Control(Section E1 .2.2.2.20))
50-280/98-201-19
IFI
RS System Flow (Section E1 .3.1.2(a))
50-280/98-201-20
IFI
Unqualified Coatings (Section E1 .3.1.2(c))
A2
NAME
Robert F. S.aunders
David A. Christian
Leslie N. Hartz
Richard H. Blount
Bryce L. Shriver
Ron M. Berryman
Richard K. MacManus
Jim H. McCarthy
Johns P. Jaudon
Donald P. Norkin
Robert C. Haag
Randall A. Musser
W. Keith Poertner
APPENDIXB
EXIT MEETING ATTENDEES
ORGANIZATION
Vice President Nuclear Engineering and Services
Site Vice President
Nuclear Engineering Manager
Manager Station Safety and Licensing
Manager Operations and Maintenance
Manager Configuration Management
A/E Team Lead; Supervisor Component Engineering
Manager Nuclear Licensing and Operations Support
Director, DRS/Region II - NRC
Section Chief, NRR/DRPM - NRC
Branch Chief, DRP/Region II - NRC
Sr. Resident Inspector - NRC
Resident Inspector- NRC
81
.
- ..
e
AMPS
ANSI
CAT
cc/hr
CFR
CLS
CME
cs
CSA
cu ft
DEHLG
DEPSG
DP
DR
OF
ft .
fUsec
FT
GDC
GL
gpm, GPM
HP.
IFI
IN
IRS
KW
LHSI
LOCTIC
LT .
APPENDIXC
LIST .OF ACRONYMS *
Alternating Current
Amperes
American National Standards Institute
Alarm Response Procedure
American Society of Mechanical Engineers
Chemical Addition Tank
cubic centimeters per hour
Code of Federal Regulations
Charging
Consequence Limiting Safeguards
Corporate Mechanical Engineering
Channel Statistical Allowance
cubic feet
Design Basis Accident
Design Basis Document
Design Change Package
Double Ended Hot Leg Guillotine
Double Ended Pump Suction Guillotine
differential pressure
Deviation Report
Emergency Core Cooling Systems
Environmental Qualification
Engineered Safety Features
Engineering Work Request
degrees Fahrenheit
feet
feet per second
Flow Transmitter
General Design Criteria
Generic Letter
gallons per minute
High Head Safety Injection
Horsepower
Heat Exchanger
Integrated Configuration Management Preject
Inspection Follow-up Item
Information Notice
Inside Recirculation Spray
Integrated Review Team
Kilowatt.
Low Head Safety Injection
Loss of Coolant Accident
Loss of Coolant Transient Inside Containment
Level Transmitter
- C1
,*
(*
,)
MWT
ml/min
MVA
NAF
NCRODP
NPSHA
NPSHR
NRG
OPT
ORS
ppm
psi
psia
psig
RC
REA
RMT
RS
SDBD
SDRE
SH
TS
VEPCo
WC
Megawatts (Thermal)
milliliters per minute
Motor Operated Valve
Main Steam Line Break
Megavolt Ampere
Nuclear Analysis and Fuels
Nuclear Control Room Operator Development Program
Net Positive Suction Head
Net Positive Suction Head (Available)
Net Positive Suction Head (Required)
Nuclear Regulatory Commission
Nuclear Safety Advisory Letter
Nuclear Specification .
Operations Periodic Test
Outside Recirculation Spray
Piping and Instrument Diagram
Procedure Action Request
parts per million
Potential Problem Report
pounds per square inch
pounds per square inch absolute
pounds per square inch gauge
Request for Engineering Assistance
Regulatory Guide
Radiation Monitor
Recirculation Mode Transfer
Restriction Orifice *
Recirculation Spray
Refueling Water Storage Tank
System Design Basis Document
Source Document Routing and Evaluation
Safety Evaluation
Sheet
Safety Injection
Surry Power Station
Stone & Webster Engineering Corporation
Total Developed Head
Technical Specification
Updated Final Safety Analysis Report
Virginia Electric & Power Company
Water Column
C2
~
- . ,
f'
- J. P. O'Hanlon
-2-
MAY 11, 1998
Please provide a schedule, within 60 days, detailing your plans to complete the corrective
actions required to resolve the open items listed in Appendix A to the enclosed report. This
schedule will enable the NRC staff to plan for the reinspection and closeout of these items.
In addition, as with all NRC inspections, we expect that your staff will evaluate the applicability
of the results and specific findings of this inspection to other systems and components
throughout the plant. In addition, please evaluate the inspection findings, both specific and
programmatic, against your response to NRC's request (October 9, 1996) for information
pursuant to 1 O CFR 50.54(f) regarding adequacy and availability of design bases information.
In accordance with Title 10, Section 2. 790(a) of the Code of Federal Regulations, a copy of this
letter and the enclosure will be placed in the NRC's Public Document Room. Any enforcement
action resulting from this inspection will be handled by NRC Region II via separate
correspondence.
Should you have any questions concerning the enclosed inspection report, please contact the
project manager, Mr. Gordon E. Edison (301) 415-1448, or the inspection team leader,
Mr. James A. Isom, at (301) 415-1109.
Docket Nos:: 50-280
and 50-281
Sincerely,
Original signed by
John F. Stolz, Chief
Events Assessment, Generic Communications,
and Special Inspection Branch
Division of Reactor Program Management
Office of Nuclear Reactor Regulation
Enclosure: Inspection Report 50-280/98-201 ;50-281/98".'201
cc w/enclosure: See next page .
DOCUMENT NAME: G:\\JAI\\SURRYRPT.WPD
To receive a copy of this document, indicate in the box: "C" = Copy without enclosures "E" = Copy with enclosures "N" '= No copy
OFFICE*
PECB:DRPM
D:PD21
NAME
DPNorkin
PTKuo
DATE
5/
/98
5!.r/198