ML18152A089
| ML18152A089 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 06/18/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A090 | List: |
| References | |
| 50-280-99-03, 50-280-99-3, 50-281-99-03, 50-281-99-3, NUDOCS 9907070033 | |
| Download: ML18152A089 (30) | |
See also: IR 05000280/1999003
Text
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.: 50-280, 50-281
Report Nos.: 50-280/99-03, 50-281/99-03
Licensee:
Virginia Electric and Power Company (VEPCO)
Facility:
Surry Power Station, Units 1 & 2
Location:
5850 Hog Island Road
Surry, VA 23883
Dates:
April 11 - May 22, 1999
Inspectors:
R. Musser, Senior Resident Inspector
K. Poertner, Resident Inspector
G. McCoy, Resident Inspector
T. Fredette, Resident Inspector, Plant Hatch (Sections 01.2 and M1.1)
D. Forbes, Radiation Specialist (Sections R1 .2 and R1 .3)
P. Fillion, Reactor Inspector (Sections E1 .3, E1 .4, E1 .5, E8.1 and E8.2)
J. Lenahan, Reactor Inspector (Sections E1 .3, E1 .4, E1 .5 and E2.1)
R. Bernhard, Senior Reactor Analyst (Section E 8.2)
Approved by: R. Haag, Chief, Reactor Projects Branch 5
Division of Reactor Projects
Enclosure
9907070033 990618
ADOCK 05000280
G
EXECUTIVE SUMMARY
Surry Power Station, Units 1 & 2
NRC Integrated Inspection Report Nos. 50-280/99-03, 50-281/99-03
This integrated inspection included aspects of licensee operations, engineering, maintenance,
and plant support. The report covers a six-week period of resident inspection; in addition, it
includes the results of announced inspections by a regional radiation specialist and regional
reactor inspectors.
Operations
Operators were attentive to plant conditions during the core off-load and displayed a
safety-conscious awareness and attitude toward critical parameters. However, the
inspectors observed that the licensee's operator communications expectations were not
rigorously implemented (Section 01.2).
The shutdown of Unit 2 for a scheduled refueling outage was well executed and
performed in accordance with approved procedures. The operators appropriately
responded to an erratic source range detector indication and failure of the main turbine
to trip properly (Section 01.3).
Overall condition of the Unit 2 containment, following plant shutdown, was observed to
be good with the exception of the residual heat removal (RHR) pump seals which
- exhibited signs of previous leakage. When the RHR system was placed in service, seal
leakage was observed on both RHR pumps (Section 01.4).
Reactor coolant system draindown activities to flange level were well controlled and
accomplished in accordance with the procedural requirements (Section 01.5).
Refueling operations were performed in accordance with Technical Specification*
requirements. However, personnel demonstrated a willingness to defuel the reactor with
degraded equipment. A malfunctioning instrumentation cable take up reel caused a
periodic lost of gripper engagement indication which would stop hoist movement. An
operator work around was used to maintain gripper engagement indication (Section
01.6).
During the installation of the reactor vessel upper internals assembly, two fuel alignment
pins were damaged as well as four fuel assembly top nozzles. The licensee removed
and repaired the upper internals and damaged fuel assemblies that were to be reused
- *(Section 01.7).
The failure to place the automatic load tap changer switch on the A Reserve Station
Service Transformer in the automatic position after a manual adjustment was identified
as a non-cited violation. This matter was the result of operator inattention during
equipment operation (Section 02.1 ).
2
The licensee's preparation of the Unit 2 containment prior to restart from a refueling
outage was satisfactory. Minor deficiencies were identified and corrected prior to
containment closeout (Section 02.2).
The failure to follow procedures to properly de-energize the Unit 2 High (Hi)
Consequence Limiting Safeguards (CLS) logic circuitry during the replacement of a Hi
CLS relay was identified as a non-cited violation. This resulted in an unanticipated
engineered safeguards actuation of the B train of Hi CLS. Operations authorized the
relay replacement under a tagout for the Hi-Hi CLS actuation logic and maintenance
personnel failed to verify the relay was de-energized (Section 02.3).
Maintenance
The licensee's planning for the inspection of low head safety injection check valve was
comprehensive. Coordination between various plant departments was evident.
Appropriate use of mock-ups and As-Low-As-ls-Reasonably-Achievable concepts was
observed. Technical input from craft workers was used extensively in the planning
process (Section M 1.1).
Because of binding problems with two new rotating elements, the licensee was unable to
install a new rotating element in the Unit 2 A motor driven auxiliary feedwater pump. The
original rotating element was visually inspected and reinstalled in the pump (Section
M1.2).
The licensee identified a problem with hold-down spring retaining bolts on several fuel
assemblies present in the Unit 2 core and decided to the repair any potentially
susceptible fuel assembly scheduled to be returned to the core. The top nozzles on 16
fuel assemblies were successfully replaced (Section M1 .3).
Observed maintenance activities were properly performed. Personnel conducting the
activities were knowledgeable and properly followed work package instructions. The
- tagout for the A motor driven auxiliary feedwater pump was properly implemented
(Section M1 .4).
Five routine periodic tests observed were properly performed. The tests were properly
approved by station management, test procedures were properly followed by
knowledgeable workers and Technical Specification requirements were satisfied
(Section M1.5).
Engineering
The modification to resolve Thermo-Lag issues inside the Unit 1 and Unit 2 containments
has been completed (Section E 1.1 ) ..
The Unit 2 low head safety injection (LHSI) pump recirculation lines were modified to
improve recirculation flow for the weaker pump during parallel pump operation. While
the recirculation flow for the weaker pump increased from previous values, the flow rates
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for both LHSI pumps were below the vendor's recommended values. The licensee
determined the achieved recirculation flow rates were acceptable (Section E1 .2).
The inspectors reviewed a sample of design changes implemented on Unit 2 during the
current refueling outage and concluded that the licensee's design change process met
the requirements in the area of design control (Section E1 .3).
The inspectors reviewed a sample of recently completed safety evaluations performed
pursuant to 1 O CFR 50.59. The safety evaluations reached correct conclusions
concerning whether the proposed change would compromise safety and whether an
unreviewed safety question was involved. Documentation of the safety evaluations was
complete (Section E1 .4).
The inspectors reviewed deviation reports generated during the spring 1999 refueling
outage and concluded that the licensee's corrective action program was meeting the
requirements of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action" (Section
E1.5).
The licensee's program for maintenance, inspection and repairs to containment coating
was adequate. Containment liner corrosion at the basement slab/liner intersection was
observed (Section E2.1).
Plant Support
The licensee was effectively maintaining controls for personnel monitoring, control of
radioactive material, radiological postings, radiation area controls, and high radiation
area controls as required by 10 CFR Part 20 (Section R1.2).
The licensee was maintaining programs for controlling exposures As-Low-As-ls-
Reasonably-Achievable (ALARA) and continued to be effective in controlling overall
collective dose. All personnel radiation exposures during 1999 to date were below
regulatory limits (Section R1 .3).
Report Details
Summary of Plant Status
Unit 1.operated at power the entire reporting period. Unit 2 operated at power until April 18,
1999, when the unit was shutdown for a scheduled 36 day refueling outage. The unit remained
shutdown for the remainder of the inspection period.
01
01.1
I. Operations
Conduct of Operations
General Comments {71707, 40500)
The inspectors conducted frequent control room tours to verify proper staffing, operator
attentiveness, and adherence to approved procedures. The inspectors attended daily
plant status meetings to maintain awareness of overall facility operations and reviewed
operator logs to verify operational safety and compliance with Technical Specifications
(TSs). Instrumentation and safety system lineups were periodically reviewed from
control room indications to assess operability. Frequent plant tours were conducted to
observe equipment status and housekeeping. Deviation Reports (DRs) were reviewed
to assure that potential safety concerns were properly reported and resolved. The
inspectors found that daily operations were generally conducted in accordance with
regulatory requirements and plant procedures.
01.2
Control Room Observations During Unit 2 Core Offload (71707)
The inspectors monitored control room activities during the initial portion of the Unit 2
core offload. The inspectors observed that, in general, operators were attentive to plant
conditions during this period, maintained communications with personnel on the
containment refueling bridge during fuel assembly movement, and displayed a safety-
conscious awareness and attitude toward critical parameters.
However, the inspectors observed poor operator communication practices as
exemplified by three-part communications in the control room not being consistently
practiced, and in fact, appeared to be the exception rather than the rule. This included
control room operators communicating to each other, as well as, operators giving
direction to non-control room personnel.
The inspectors discussed these observations with licensee management, who
acknowledged that their expectations for three-part communications were not met. The
inspectors concluded that the licensee's operator communications expectations were oot
rigorously implemented.
2
01.3
Unit 2 Shutdown for Refueling Outage
a.
Inspection Scope (71707)
The .inspectors observed and assessed performance.of the operating crew during the
shutdown of Unit 2 for a planned refueling outage.
b.
Observations and Findings
C .
On April 18, the inspectors observed portions of the Unit 2 shutdown for a scheduled
refueling outage. At 12:52 a.m., the unit was removed from the grid and the reactor was
manually tripped at 1 :03 a.m. When the main turbine was tripped from the control room,
the turbine relatched following the trip without operator action. The turbine was retripped
by the operating crew and the turbine remained unlatched. A DR was initiated to
document the relatching of the main turbine following a manual turbine trip. Following
energization of the source range detectors, detector N-32 exhibited erratic indication and
was declared inoperable. The detector was subsequently replaced prior to fuel offload.
Overall, the shutdown was well executed and performed in accordance with approved
procedures.
Conclusions
The shutdown of Unit 2 for a scheduled refueling outage was well executed and
performed in accordance with approved procedures. The operators appropriately
responded to an erratic source range detector indication and failure of the main turbine
to trip properly.
01.4
Unit 2 Containment Walkdown
a.
Inspection Scope (71707)
. The inspectors performed a detailed walkdown of the Unit 2 containment following entry
into the cold shutdown condition.
b.
Observations and Findings
The inspectors performed a detailed walkdown of all major areas of the Unit 2
containment once containment vacuum was broken and cold shutdown was achieved.
- The walkdown included all elevations, reactor coolant pump cubicles, reactor coolant
system loop .rooms, the pressurizer cubicle, the containment sump, and seal table room.
The overall condition of containment was good in that; 1) Leakage from piping system
mechanical connections was minimal, 2) The sump was free of debris, 3) Material
condition of components was good, and 4) No excess material was located within
containment.
The inspectors did note large accumulations of boric acid on the residual heat removal
(RHR) pumps. The leakage originated from the pump seal area. During subsequent
.
C.
3
containment inspections when the RHR system was in service, the inspectors noted
active seal leakage for both idle and operating pumps. The amount of leakage was in
the range of multiple drops per minute. This item was discussed with the operations shift
supervisor and the Superintendent of Operations. The licensee had previously identified
seal leakage for the RHR pumps and had initiated work requests to perform repairs
(replace the pump seals). During the current refueling outage, the boric acid deposits
were removed and based upon an evaluation of the seal leakage, the licensee deferred
the planned corrective maintenance to a future outage. The evaluation included the
removal and inspection of a carbon steel fastener on RHR pump 2-RH-P-1 B. Corrosion
on the fastener was within acceptable limits. See Section E2.1 for additional discussion
on the effects of the RHR pump seal leakage.
Conclusions
Overall condition of the Unit 2 containment, following plant shutdown, was observed to
be good with the exception of the residual heat removal (RHR) pump seals which
exhibited signs of previous leakage. When the RHR system was placed in service, seal
leakage was observed on both RHR pumps.
01.5
Unit 2 Draindown to Flange Level
a.
Inspection Scope (71707)
The inspectors observed portions of the activities associated with lowering reactor
coolant system (RCS) water level to allow removal of the reactor vessel head.
b.
Observations and Findings
The inspectors observed control room activities associated with lowering RCS level from
22 percent pressurizer level to flange level to allow removal of the reactor vessel head.
The activity was controlled by procedure 1-0P-RC-004, "Draining the RCS to Reactor
Flange Level," Revision 11. The inspectors reviewed the procedure prior to initiation of
the draindown and verified that the required initial conditions were met. The activity was
well controlled and accomplished in accordance with the procedural requirements.
c.
Conclusions
Reactor coolant system draindown activities to flange level were well controlled and
accomplished in accordance with the procedural* requirements.
01.6
Unit 2 Refueling Observations
a.
Inspection Scope (71707)
The inspectors observed the defueling of the Unit 2 reactor .
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b.
Observations and Findings
C.
Fuel handling evolutions were observed both in the containment and in the fuel building.
Activities were adequately supervised and TS requirements were met. A foreign material
control monitor was posted at the access to the refueling cavity area to ensure all
personnel entering the area were not taking unnecessary items into the area. No
problems were encountered in latching fuel assemblies with damaged hold down spring
retaining bolts. See Section M1 .3 for additional discussion on the damaged hold down
spring retaining bolts.
During the defueling process, the operators encountered problems with the
instrumentation cable take up reel on the manipulator crane. At certain rotational
positions on the take up reel slip ring assembly, the manipulator crane indication for
gripper engagement would be lost while raising or lowering the hoist. When the gripper
indication was lost the hoist would stop. To correct this, the operators mechanically
adjusted the cable to move the take up reel, indication was regained and the hoist
operated normally. This condition deteriorated to the point where the operators would
stop the movement of the take up reel (at a position on the reel where gripper indication
was maintained). Then as the hoist was raised, operators placed the instrument cable
slack on the deck of the manipulator crane. The inspectors viewed this operator work
around as an unnecessary distraction during a critical plant evolution, i.e., movement of
spent fuel. Continuing the core offload demonstrated a willingness by refueling
personnel to defuel the reactor with less than optimal equipment conditions. When a
replacement take up reel assembly became available, it was installed and the remainder
of the core was off-loaded.
Conclusions
Refueling operations were performed in accordance with technical specification
requirements. However, personnel demonstrated a willingness to defuel the reactor with
degraded equipment. A malfunctioning instrumentation cable take up reel caused a
periodic lost of gripper engagement indication which would stop hoist movement. An
informal operator work around was used to maintain gripper engagement indication.
01.7
Damage to the Unit 2 Reactor Vessel Upper Internals Fuel Alignment Pins
a.
Inspection Scope (71707 *. 62707)
b.
The inspectors-reviewed the events surrounding the damage to the Unit 2 reactor vessel
upper internals fuel alignment pins which occurred during upper internals reinstallation.
Observations and Findings
On May 8, following reinstallation of the Unit 2 reactor vessel upper internals, the
licensee determined, through seating verification measurements, that the upper internals
assembly was not fully seated. The following day, the licensee made the determination
that the upper internals would have to be removed and inspected for potential damage to
5
both the upper internals and fuel assemblies. The inspectors remotely monitored the
removal of the upper internals and observed that the evolution was carried out in a
careful and deliberate manner. Once removed, an inspection of the upper internals
underside revealed that at least one, and potentially two fuel alignment pins were bent.
An inspection of the fuel top nozzles revealed four assemblies (R-8, R-9, P-8 and M-8)
with some form of damage (rolled/scratched metal) near one of the two S holes in the top
nozzles. Additionally, six assemblies were observed to be slightly misaligned.
The licensee contracted the Nuclear Steam System Supply (NSSS) vendor to repair
(bend back) the damaged upper internals fuel alignment pins. While the. NSSS vendor
was mobilizing, the licensee removed fuel assemblies adjacent to those with damaged
top nozzles so that the fuel assemblies could be visually inspected prior to removal from
the core. Other than the damage noted to the fuel assembly top nozzles, no structural
damage to the fuel assemblies was noted. A total of 18 fuel assemblies were removed
from the core for inspection and/or reconstitution (replacement of the top nozzle). The
final assembly to be removed, at core location R-9, could not be grappled using the
refueling bridge mast grapple due to damage the bundle received through contact with
the upper internals. The licensee obtained an alternate lifting tool (a cruciform shaped
tool known as the SFACHT) from the NSSS vendor which they used to remove the fuel
assembly from core location R-9. The inspectors observed the removal of this assembly
from the reactor and noted that the evolution was performed in accordance with
procedural requirements and in a safe and deliberate manner. The fuel assembly
removed from core location R-9 was not re-used, however, the other three assemblies
with damage to their top nozzles were reconstituted with new top nozzles prior to fuel
reload.
The NSSS vendor verified that there were two bent fuel alignment pins on the underside
of the upper internals corresponding to core locations R-8 and R-9. These pins were
bent back into position. The licensee conducted a root cause investigation to determine
the reasons for the bending of the fuel alignment pins. The root cause evaluation had
not been finalized at the end of the inspection period; however, a preliminary
determination stated that an out of specification gap (high) between the R row of fuel and
the reactor baffle plate caused the misalignment between the alignment pins and the fuel
assembly top nozzles. The licensee verified this gap was in tolerance prior to re-
installing the upper internals.
c.
Conclusions
During the installation of the reactor vessel upper internals assembly, two fuel alignment
pins were damaged as well as four fuel assembly top nozzles. The licensee removed
and repaired the upper internals and damaged fuel assemblies that were to be reused.
6
02
Operational Status of Facilities and Equipment
02.1
Reserve Station Service Transformer Automatic Load Tap Changer
a.
Inspection Scope (71707)
b.
The inspectors reviewed the licensee's actions when the A Reserve Station Service
Transformer (RSST) load tap changer selector switch was found in the incorrect position.
Observations and Findings
The RSSTs are equipped with an automatic load tap changer to maintain a desired
voltage range on the emergency buses during long-term grid voltage transients. At 2:56
a.m. on May 17, Unit 1 operators received an alarm from annunciator 1K-G3, Bus 1J
Overvoltage. They reviewed the Annunciator Response Procedure (ARP) 1 K-G3 "Bus
1J Over Volt," and manually adjusted the A RSST tap changer as described in the ARP.
At 12:33 p.m. on the same day an operator noted during his rounds that the A RSST tap
changer selector switch was in OFF. Subsequent investigation by the licensee
concluded that the operator who had adjusted the tap changer had missed the last step
in ARP 1 K-G3 to place the tap changer selector switch in the AUTO position. The switch
was placed in the proper position and a DR was written. With the load tap changer in the
manual position, no automatic voltage compensation would occur in response to grid
voltage fluctuations and prevent equipment powered from the emergency buses from
operating outside their normal voltage band.
Technical Specification 6.4.A.3 requires detailed written procedures, in part, for actions
to be taken for specific and foreseen malfunctions of systems or components including
alarms. In addition, TS 6.4.D requires that procedures described in Specifications 6.4.A
and 6.4. B shall be followed. The failure to properly follow ARP 1 K-G3 is a violation of TS 6.4.D. This licensee identified Severity Level IV violation is being treated as a Non-Cited
Violation (NCV) consistent with Appendix C of the NRC Enforcement Policy. This
violation is in the licensee's corrective action program as DR S-99-1353 and is identified
as NCV 50-280/99003-01.
c.
Conclusions
The failure to place the automatic load tap changer switch on the A Reserve Station
Service Tr1;1nsformer in the automatic position after a manual adjustment was identified
as-a non-cited violation. -This matter was the*result of operator inattention during
equipment operation.
02.2
Unit 2 Containment Closeout
a.
Inspection Scope (71707)
On May 21, the inspectors performed a containment closeout walkdown to review
containment conditions prior to unit restart.
'
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b.
Observations and Findings
C.
The inspectors accompanied the plant operators as they performed a walkdown of the
Unit 2 containment prior to the unit restart. A number of items were noted during the
walkdown such as an unsecured trash rack door to the containment sump, tywraps and
small bits of loose wire on the decking. All the large equipment stored inside
containment was adequately secured, and no loose debris was noted inside the
containment sump. The overall condition of the containment was adequate to support
restart of the unit. Responsible licensee personnel were informed of walkdown findings
prior to exiting containment.
Conclusions
The licensee's preparation of the Unit 2 containment prior to restart from the refueling
outage was satisfactory. Minor deficiencies were identified and corrected prior to
containment closeout.
02.3
Unit 2 Engineered Safeguards Feature (ESF) Actuation During High (Hi) Consequence
Limiting Safeguards (CLS) Relay Replacement
a.
b.
Inspection Scope (71707, 62707)
The inspectors reviewed the events and licensee's actions following the receipt of an
unexpected ESF actuation during a relay replacement activity in the Hi CLS system.
Observations and Findings
On April 26, at approximately 8:37 a.m., with Unit 2 in the refueling shutdown mode, a
spurious Hi CLS signal was generated during the replacement of relay 2-CLS-RLY-181
in the B train of the Hi CLS system. The relay was being replaced as a preventive
maintenance activity in accordance with work order 00392317-01 and procedure O-ECM-
1801-01, "Westinghouse Type BF or BFD Relay Replacement," Revision 12. All
components associated with the CLS system, with the exception of 2-RM-TV-2008 and
the Hi CLS actuation logic, were properly tagged out and defeated .. Upon receipt of the
Hi CLS signal, trip valve 2-RM-TV-2008 closed as designed. This isolated the
containment particulate and gaseous radiation monitors.
This event was initially reported to the NRC in accordance with 10 CFR 50.72 as a four
- hour non-emergency*ESF actuation. Subsequent to this report, the licensee determined
that the event did not meet the criteria for reporting an ESF actuation. Specifically, the
event was determined not to be reportable because the actuation of the Hi CLS logic
was the result of an invalid signal and resulted in the actuation of only one component
which did not mitigate the consequences of the event. On May 21, the licensee
retracted the event report.
,
A review of the event by the inspectors and the licensee revealed that the relay being
replaced was not in the proper configuration for relay removal. Specifically, the Hi CLS
C.
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logic was energized and therefore procedu~e O-ECM-1801-01 requires that a temporary
modification Uumper) be used to properly isolate the relay. Operations personnel
authorized the replacement of relay 2-CLS-RLY-181 and assigned the work to the tagout
for the Hi-Hi CLS actuation logic. In doing so, they failed to recognize or inform
maintenance personnel that Hi CLS relay 2-CLS-RLY-181 would not be de-energized.
Personnel replacing the relay incorrectly assumed, without verifying, that the relay was
de-energized and did not request the use of a jumper. Detailed written procedures for
preventive or corrective maintenance operations which would have an effect on the
safety of the reactor are require by TS 6.4.A. 7. The failure to follow procedures which
are required by TS 6.4.A.7 is a violation of TS 6.4.D. This Severity Level IV violation is
being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy.
This violation is in the licensee's corrective action program as DRs S-99-1013 and S-99-
1018, and is identified as NCV 50-281/99003-02.
Conclusions
The failure to follow procedures to properly de-energize the Unit 2 High (Hi)
Consequence Limiting Safeguards (CLS) logic circuitry during the replacement of a Hi
CLS relay was identified as a non-cited violation. This resulted in an unanticipated
engineered safeguards actuation of the B train of Hi CLS. Operations authorized the
relay replacement under a tagout for the Hi-Hi CLS actuation logic and maintenance
personnel failed to verify the relay was de-energized.
II. Maintenance
M1
Conduct of Maintenance
M1 .1
Inspection of Unit 2 Safety Injection Check Valve
a.
Inspection Scope (62707, 71750)
b.
The inspectors observed elements of maintenance planning, mock-up training, As-Low-
As-ls-Reasonably-Achievable (ALARA) planning and engineering support for open and
inspection activities of six-inch low head safety injection check valve 2-Sl-79. The valve
had failed a leak test early in the Unit 2 refueling outage.
Observations and Findings
- The inspectors-attended a series of planning meetings related to the work surrounding
check valve 2-Sl-79, which was projected by health physics (HP) department as a high
radiation dose job, based on historical data and plant conditions. Each meeting was
comprehensive, and attempted to take advantage of "lessons learned" from previous
work activities on a similar check valve (1-Sl-85) conducted during the last Unit 1 outage.
The inspectors observed that ideas were constantly solicited from craft mechanics,
welders, health physics personnel and supervisors on ways to reduce radiation dose
and/or expedite the job. Special attention was given to staging extra tools for valve
disassembly, mechanics practicing disassembly using mock-ups, foreign material
9
exclusion (FME) control and contingencies if inspection of.the valve should determine
that replacement would be necessary.
The inspectors reviewed procedure O-MCM-0417-01, "VELAN Swing Check Valves
Inspection and Overhaul," Revision 6, and accompanied the mechanical maintenance
supervisor in observing the valve inspection from a remote video monitor. The valve
inspection included cover removal and inspection, FME apparatus installation, as-found
visual inspection (VT), hangar and disc removal, and "blue check" of the seating surface.
The inspectors observed that the two mechanics worked expediently, yet were cautious
in following procedural steps. The mechanics were in radio communication with the
supervisor who was also following the procedure. The visual inspection revealed that
the valve seat was severely eroded and that valve cutout and replacement would have to
be accomplished. The effectiveness of preplanning activities was evident in that the
entire inspection activity, from mechanics starting disassembly to installing an FME cover
over the valve body and vacating the valve area, took less than 30 minutes.
c.
Conclusions
The licensee's planning for the inspection of low head safety injection check valve was
comprehensive. Coordination between various plant departments was evident.
Appropriate use of mock-ups and As-Low-As-ls-Reasonably-Achievable concepts was
observed. Technical input from craft workers was used extensively in the planning
process .
M 1.2 Rotating Element Replacement on 2-FW-P-3A
a.
Inspection Scope (62707)
b.
The inspectors observed portions of the planning, replacement, and troubleshooting
efforts during the replacement of the rotating element on Unit 2 motor driven auxiliary
feedwater pump, 2-FW-P-3A.
Observations and Findings
The rotating element for 2-FW-P-3A was scheduled to be replaced in response to
concerns about diffuser cracking and the effect on pump performance. New stainless
steel rotating assemblies (diffuser and impeller assemblies mounted on a common shaft)
had been purchased from the vendor and were going to be used as a one-for-one
- replacement for the rotating assembly-currently installed in the pump. During the
installation of the new rotating assembly, the mechanics noted that the pump shaft would
not spin without rubbing. The pump was disassembled and inspected. Metal filings and
indications of metal-to-metal rubbing were found inside the rotating assembly. After
consultation with the vendor, the inner diameter of the rotating assembly was machined
to increase the tolerances. When the rotating assembly was installed into the pump
casing for the second time, binding was again noted when the shaft was rotated. A
second rotating assembly was installed in the pump casing and again binding was noted .
The original rotating element was cleaned and reinstalled in the pump. No degradation
C.
10
of the diffuser assembly was noted during visual inspection. The pump was satisfactorily
retested and returned to service. The licensee is investigating the cause of the binding
in the replacement rotating assemblies.
Conclusions
Because of binding problems with two new rotating elements, the licensee was unable to
install a new rotating element in the Unit 2 A motor driven auxiliary feedwater pump. The
original rotating element was visually inspected and reinstalled in the pump.
M1 .3
Fuel Assembly Top Nozzle Replacement
a.
Inspection Scope (62707)
The inspectors observed portions of the inspection and repair of fuel assemblies found to
have damaged hold;.down springs retaining bolts.
b.
Observation and Findings
Prior to the removal of the spent fuel assemblies from the reactor vessel, the licensee
. was informed of problems at other plants which had discovered that certain fuel
assemblies had damaged hold-down spring retaining bolts. Although the specific design
of the fuel assemblies were different at the other plants, bolts from the same lot were
used on 60 assemblies that were present in the Unit 2 reactor core, and 44 of these
assemblies were scheduled to be reloaded during refueling. None of the Unit 1
assemblies had hold-down bolts from the lot in question. Licensee management decided
to replace the top nozzles on any fuel assembly in question which was to be returned to
the core during refueling. During removal of the fuel assemblies from the Unit 2 reactor
core, each assembly was visually inspected. Several of the 60 assemblies were noted to
have enlarged gaps in the top nozzle indicating possible problems with the hold-down
spring bolts. The Unit 2 core was re-designed such that only 16 of 44 fuel assemblies
would be reused in the. upcoming fuel cycle. The top nozzle assembly on each of the 16
fuel assemblies was replaced with a new top nozzle assembly with improved hold-down
springs and bolts from a different lot. No problems were encountered during the
replacement of the top nozzles on the reused fuel assemblies.
c.
Conclusions
- The licensee identified a problem with hold-down spring retaining bolts on several fuel
assemblies present in the Unit 2 core and decided to the repair any potentially
susceptible fuel assembly scheduled to be returned to the core. The top nozzles on 16
fuel assemblies were successfully replaced.
11
M1 .4
Observation of Maintenance Activities
a.
Inspection Scope {62707)
b.
C.
The inspectors observed portions of the following work orders (WOs):
409702-01
401130-01
404767-01
405974-01
406454-04
375462-01
410971-01
Fuel Assembly Repairs, Surry Unit 2
lnspecUOverhaul Motor Driven Auxiliary Feedwater (MDAFW)
Pump
Protective Relay Maintenance, Reserve Station Service
Transformer B
Functional test of L TC Controller
Freeze Seal downstream of 2-SI-MOV-2869B to Allow Testing
Charging Pump C Normal Feed Breaker PM
Remove/Reinstall Gland Steam Supply Strainer
Observations and Findings
All work had been properly approved by the operations department and was included on
the plan of the day (POD) or the outage schedule. The inspectors found that the work
performed under these activities was professional and thorough. Tagout number 2-99-
FW-0012 for the A MDAFW pump was reviewed and found to be properly prepared and
authorized. The tagged components were in the required positions and the tags were
properly installed. The work was performed with the work package present and in use.
Accompanying documents such as procedures and supplemental work instructions were
properly followed. Personnel were experienced, properly trained and knowledgeable of
their assignments.
Conclusions
Observed maintenance activities were properly performed. Personnel conducting the
activities were knowledgeable and properly followed work package instructions. The
tagout for the A motor driven auxiliary feedwater pump was properly implemented.
M1 .5
Periodic Test (PD Observations
a.
Inspection Scope (61726)
The inspectors observed the performance of the following PTs:
-*
OPT-SW-003
CAL-046
2-0PT-Sl-008
2-0PT-ZZ-002
2-NSP-RX-0014
Emergency Service Water Pump 1-SW-P-1C
Source Range Discriminator Voltage and High Voltage
Determination
Delta P Testing of 2-SI-MOV-2869A
ESF Actuation with Undervoltage and Degraded Voltage-
2J Bus
Rod Exercise Test
E1
12
b.
Observations and Findings
The inspectors verified that the tests were properly approved by management and
included on the POD. The inspectors checked selected components for their pre-test
and post-test positions to ensure that they were properly positioned and no
discrepancies were identified. The inspectors checked test instruments to ensure proper
calibration and that the due dates had not expired. When the tests affected TS
components, the inspectors ensured that appropriate TS action statements were
implemented. The inspectors also reviewed the test acceptance criteria to ensure they
were consistent with TS requirements. The inspectors reviewed selected test data after
the completion of the test to ensure component performance was satisfactory.
During test performance, the inspectors evaluated procedure adherence and worker
knowledge of the assigned activities. The inspectors found the testing work practices to
be satisfactory.
c.
Conclusions
Five routine periodic tests observed were properly performed. The tests were properly
approved by station management, test procedures were properly followed by
knowledgeable workers and Technical Specification requirements were satisfied .
Ill. Engineering
Conduct of Engineering
E1 .1
Unit 2 Containment Thermo-Lag Modification
a.
Inspection Scope (37551)
The inspectors reviewed the implementation of Design Change Package (DCP)98-007,
"Containment Radiant Energy Shields."
b.
Observations and Findings
C.
In correspondence to the NRC, the licensee committed to install non-combustible radiant
energy shields in the Unit 1 and Unit 2 containments during the 1998 Unit 1 refueling
outage and the 1999 Unit 2 refueling outage. The inspectors reviewed the associated
DCP and physically"verified in the field that the licensee installed the modification in Unit
2 during this refueling outage. The modification had previously been completed on
Unit 1 (See Section E1 .1 of NRC Integrated Inspection Report Nos. 50-280, 281/98-09).
Conclusions
The modification to resolve Thermo-Lag issues inside the Unit 1 and Unit 2 containments
has been completed .
13
E1 .2
Low Head Safety Injection (LHSI) Recirculation Line Modification
a.
Inspection Scope (37551)
The inspectors reviewed the implementation of DCP.98-053, "LHSI Recirculation Line
Relocation/Surry/Unit 2."
b.
Observations and Findings
The modification was implemented to address an issue with available recirculation flow
when both LHSI pumps were operating in parallel. Prior to implementation of the
modification, the pump recirculation line originated downstream of the pump discharge
check valve which could result in insufficient flow during periods of parallel operation with
RCS pressure greater than LHSI pump discharge pressure. The modification rerouted
the pump recirculation line upstream of the pump discharge check valve. The
modification also installed a small (~ inch) bypass line with a normally open* isolation
valve around the pump discharge check valve. This line was installed to provide a flow
path to the refueling water storage tank (which had previously existed prior to the
modification) for small amounts of leakage into the LHSI system from the RCS and
thereby preventing system pressurization. The inspectors verified that the
aforementioned bypass isolation valve was added to the system lineup procedure.
The inspectors reviewed the associated DCP and physically verified field implementation
of the modification. The inspectors also observed the post modification testing
associated with completion of the DCP. During parallel operation of the LHSI pumps
after completion of the modification, recirculation flow was below the pump vendors
recommended 150 gpm flow rate per pump. The A pump developed approximately 122
gpm and the B pump developed approximately 148 gpm. Both pumps developed greater
than 150 gpm when not operating in parallel. The licensee determined that the flow rates
achieved were adequate and documented the results in an engineering transmittal. The
inspector's evaluation of the measured flow rates versus the vendor's recommended flow
rate is discussed in section EB.2. The inspectors noted that the modification improved
the pump recirculation flow during parallel operation for the weaker pump and decreased
the flow for the stronger pump. The inspectors questioned whether a future modification
would be considered to improve recirculation flow rates during parallel pump operation
and was informed by licensee management that no further modification would be
considered.
During field observation *of pump performance after implementation of the modification to
the recirculation piping, the inspectors observed and heard vibration in the recirculation
piping. The licensee was aware of the vibration, and made acceleration/velocity readings
at a point having the highest observable amplitudes. The licensee's engineering
mechanical group reviewed the vibration data and concluded that the maximum pipe
stresses were below the endurance limit of the material, with adequate margin for
discontinuities in the piping, such as welds and branch connections. Engineering
concluded that the structural integrity of the piping system would not be challenged by
the observed vibrations. Inspection followup item (IFI) 50-281/99003-03 was opened to
C.
14
review the licensee's structural integrity conclusions concerning vibration of the LHSI
pump recirculation piping.
- Conclusions
The Unit 2 low head safety injection (LHSI) pump recirculation lines were modified to
improve recirculation flow for the weaker pump during parallel pump operation. While
the recirculation flow for the weaker pump increased from previous values, the flow rates
for both LHSI pumps were below the vendor's recommended values. The licensee
determined the achieved recirculation flow rates were acceptable.
E1 .3
Review of Design Changes
a.
Inspection Scope (37550)
The inspectors reviewed a sample of design changes implemented during the current
refueling outage on Unit 2. The basic requirement applicable to this area of inspection
was 10 CFR Part 50, Appendix B, Criterion Ill, Design Control. Regulatory Guide 1.64,
"Quality Assurance Requirements for the Design of Nuclear Power Plants," (ANSI
N45.2.11) was also applicable.
b.
Observations and Findings
Sixty-seven design changes were implemented on Unit 2 during the current refueling
outage. Thirty of the design changes were classified as safety-related. The following
safety related DCPs were reviewed:
97-030 98-006
98-023 98-044
98-053 98-056
98-092
Residual heat - FCV/HCV support removal
Containment floor plug elimination
Motor operated valve replacement, SW 2048, 204C and 204D
Pressurizer level transmitter spans revised
Turbine driven auxiliary feedwater pumps steam supply valve logic
change
Low head safety injection pumps reroute recirculation piping
Inside recirculation spray pumps and low head safety injection
pump overcurrent trip device replacement and reset
Reactor protection system test circuit surge suppressors
The inspectors found that the safety evaluations for all the design changes reviewed
adequately demonstrated that the changes would maintain the design basis. The
objective of each change was clearly stated in the design change package, and the
inspectors agreed that the changes met the stated objective. The inspectors noted that
the safety evaluations included Year 2000 computer considerations where appropriate.
For one design change, the inspectors confirmed that a relevant 10 CFR Part 21 report
had been evaluated by the licensee. The inspectors observed that the specified post-
modification tests were adequate to demonstrate that the design objectives of the
changes were met and that the systems were operable. Where available during the
'( *
15
inspection, the test data was reviewed and found acceptable. The cognizant engineers
were able to satisfactorily answer questions posed by the inspectors concerning the
design changes. The design changes reviewed were prepared by four different
organizational groups, so they were seen as representing the work of a large percentage
of the engineering organization.
c.
Conclusions
The inspectors reviewed a sample of design changes implemented on Unit 2 during the
current refueling outage and concluded that the licensee's design change process met
the requirements in the area of design control.
E1 .4
Review of Safety Evaluations
a.
Inspection Scope (37001)
b.
The inspectors reviewed a sample of recently completed safety evaluations which had
been prepared pursuant to 10 CFR 50.59, "Changes Tests and Experiments."
Observations and Findings
The licensee submits to the NRC a list of facility, procedure or method of operation
changes each month as part of the Monthly Operating Report. These changes required
licensee evaluations to determine whether they represent an unreviewed safety question
as defined in 1,0 CFR 50.59. The inspectors obtained the lists submitted for the months
of November 1998 through February 1999, and they indicated a total of 46 safety
evaluations had been performed during those months. The inspectors chose the
following safety evaluations for review:
Changes to Electrical Corrective Maintenance Procedure O-ECM-
0103-02, "Station Battery UPS System Maintenance." The
procedure was revised to provide for connecting a test load and
other temporary changes for the purpose of conducting
maintenance tests.
Changes to Operations Procedure 1-0P-RC-001A, "Reactor
Coolant System Valve Alignment." The procedure was changed
to require operating with a certain drain valve closed rather than
- the open position.-
Evaluate the reduction in containment wall thickness from that
specified in UFSAR, Section 15, while work is in progress to
remove and repair spalled/loose concrete from the Unit 2
containment exterior wall.
The inspectors found that the reviewed safety evaluations addressed whether the
changes would alter the performance or integrity of any structure, system or component
16
important to safety through the answering of detailed questions on the formal evaluation
form. The potential effect of the proposed change on the ability of the operators to
control and monitor the plant was considered. The inspectors found that the safety
evaluations addressed potential failure modes and electrical loading. The inspectors
noted that TS were discussed in relation to each proposed change. The inspectors
observed that any impact on special programs or equipment was considered through a
24-question form. The inspectors noted in particular that the unreviewed safety question
portion of the review specifically discussed the design basis accidents considered in the
review. The inspectors found that the safety evaluations reached correct conclusions
with regard to the considerations mentioned above.
The inspectors examined the work in progress covered by Safety Evaluation 98-124 and
verified that the safety evaluation adequately described the changes to containment wall
thickness while concrete repairs were in progress. The licensee's conclusions in the
safety evaluation were acceptable.
The documentation of the safety evaluations included written statements for all the
considerations mentioned in the previous paragraphs. Documentation included a listing
of all the identified applicable UFSAR sections. The documentation included statements
of limiting conditions and special requirements together with the relevant formal tracking
mechanism. There were signatures by the evaluators of certain individual considerations
such as reactivity, radiation control, emergency preparedness, etc., where those persons
were different than the overall reviewer. The inspectors also noted that the safety
evaluations were readily retrievable from records storage.
c.
Conclusions
The inspectors reviewed a sample of recently completed safety evaluations performed
pursuant to 10 CFR 50.59. The safety evaluations reached correct conclusions
concerning whether the proposed change would compromise safety and whether an
unreviewed safety question was involved. Documentation of the safety evaluations was
complete.
E1.5
Review of DRs
a.
Inspection Scope (37550)
The inspectors reviewed a sample of DRs generated during the current Unit 2 refueling
.. outage and followed up on deficiency DRs discussed in previous inspection reports. The
basic requirement applicable to this area of inspection is 10 CFR 50, Appendix B,
Criterion ~VI, "Corrective Action".
b.
Observations and Findings
As of May 12, 1999, there were about 216 routine level DRs generated during the
current Unit 2 outage and there were 15 potentially significant (i.e. second highest of the
three levels) DRs generated. There were no significant level reports generated. The
.
17
inspectors obtained a summary statement for each DR. The inspectors evaluated,
inspected or discussed with the cognizant engineers all of the potentially significant level
reports. The inspectors reached the conclusion that all of these problems were either
resolved by the licensee or significant progress had been made to give confidence that
the problem would be resolved in a timely manner. The inspectors reviewed the
summary statements for about 30 percent of the routine level DRs. The inspectors found
that all of these had been correctly classified and the initial assessments and corrective
actions were appropriate to the circumstances. DR S-99-1067 documented an
evaluation for a case where the running amperes for a motor operated valve measured
during a routine valve diagnostic test was higher than the criterion in the test process.
The inspectors reviewed this DR in detail, discussing various aspects with electrical
design engineering and the MOV coordinator. The inspectors concluded that the
reasons for accepting the higher than expected current were valid.
NRG Inspection Report No. 50-280/98-09 discussed a case where work scheduling and
planning had not replaced a degraded arcing contact in a safety-related 4160 V circuit
breaker at the earliest opportunity, even though there were two previous opportunities to
do so. During this inspection, the inspectors confirmed that the cracked arcing contact
was replaced by Work Order 395596 on February 16, 1999.
The inspectors reviewed DR numbers S-99-1007, -1033, and -1055. These DRs
addressed testing of the setpoints for the Unit 2 main steam safety relief valves which
were slightly outside the Technical Specification plus or minus 3 percent limits. The test
data were as follows:
Valve Number
TS Limits (psig)
As-found Test Results (psig)
2-MS-SV-203C
1077 - 1143
1143.8
2-MS-SV-201 C
1053 - 1117
1127
2-MS-SV-204C
1087 - 1153
1084
The licensee's corrective actions were to readjust the setpoints for the three valves
which failed the surveillance tests and test the remaining 12 valves. The remaining 12
valves were within the TS acceptance limits. The inspectors determined the resolution
for the three valves which failed the surveillance tests and the expanded test sample size
were acceptable.
DRs S-99-0921, -0982, and -1071 were also reviewed. These DRs were initiated by the
licensee to document and disposition the results of snubber visual inspections which did
not comply with Technical Specification acceptance criteria. DR numbers S-99-0921
and -0982 concerned six snubbers which had low fluid levels in their reservoirs. These
snubbers were functionally tested in accordance with the TS requirements and found to
be operable. DR S-99-1071 was initiated to document that two snubbers on the
feedwater line were found to be fully compressed in their cold set position. The licensee
issued Engineering Transmittal S-99-093 to evaluate this problem. The licensee's
18
engineering evaluation showed that upon piping heatup, the piping would move outward
which would relieve any binding of the snubbers when the snubbers extended.
Therefore the snubbers were operable during plant operation. Additional corrective
adions included -modifications to the pipe support to shorten the snubber support
brackets so that the snubbers would not be fully compressed when they were in the cold
position.
c.
Conclusions
The inspectors reviewed deviation reports generated during the spring 1999 refueling
outage and concluded that the licensee's corrective action program Was meeting the
- requirements of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action."
E2
Engineering Support Of Facilities and Equipment
E2.1
Review of Program for Visual Inspection of the Reactor Containment Structures
a.
Inspection Scope (37500)
The inspectors examined the licensee's program for inspection of the
containment structure.
b.
Findings and Observations
The inspectors reviewed the licensee's in service inspection manual, Section 7 .22,
Revision 1, dated February 1, 1999, for visual inspection of the reactor containment
buildings. This procedure specifies the requirements for performance of visual
inspection of the containment structures in accordance with Article IWE of ASME Section
IX. 10 CFR 50.55a requires the licensee to implement the requirements of IWE Section
IX by September 9, 2001. In preparation for implementation of the containment
inspections, licensee engineers have performed inspections of the containment buildings
to identify and repair deficiencies in protective coatings, the containment building steel
liner, penetration areas, and in other areas in the containment. These visual inspections
have also included the exterior concrete surface of the containments. The inspectors
reviewed the following records which documented the results of the licensee's
inspections:
Summary of results of Unit 1 containment walkdown performed on May 14, 1998.
DR S-98-2606, S-98-2980, and S-99-0955
Summary of results of Unit 2 containment walkdown performed on April 21, 1999.
On May 12, 1999, the inspectors performed a walkdown inspection of the Unit 2
containment building on elevations -27', -3.5', 18.5', and 47'. The inspectors identified
the following deficiencies which the licensee had not identified during their inspections:
19
The coatings on a ventilation duct near Column line 7 at' elevation 9' had loose
(delaminated) coatings. The ventilation duct was in close proximity to the reactor
building sump.
The grating which covers the drain trench in the containment basement (elevation
-27') were not secured in any manner to prevent the gratings from being
dislocated. Several of the gratings were overlapped with other gratings, bent, or
had gaps between adjacent gratings. The concern was that the trench bypasses
the reactor building trash rack and leads to the reactor building sump. If the
grating is dislocated during accident conditions, it would be possible for debris to
bypass the sump trash racks and partially clog the sump screens.
The concrete floor in the area of RHR pump 2-RH-P-18 (elevation -13') has been
damaged by boric acid solution leaking from the pumps and associated piping
and fittings. The cementitious material has been dissolved resulting with an area
approximately 20 to 25 square feet with exposed aggregate. A trench
approximately 8 feet in length, approximately 1 to 1.5 inches deep extends
between the pump and floor drain. The concern is that the concrete reinforcing
steel and embedded plates in the area could be degraded from corrosion caused
by the boric acid.
The licensee initiated DR S-99-1316 to document and disposition the above
discrepancies. Prior to containment closeout the grating which covers the drain trench
was repaired and reinstalled. This resolved the issues of the grating being bent and
having gaps between adjacent sections. The licensee reviewed the design of the trench
grating and determined the grating did not need to be secured to perform its function.
During the walkdown inspection the inspectors also identified the presence of corrosion
on the steel liner plate at the intersection of the concrete.slab and liner at elevation -27'.
The corrosion appears to extend below the concrete slab for an unknown distance.
There is evidence that, although the coatings in this area had been previously repaired,
the coatings are starting to fail in this zone. A similar situation existed in Unit 1
containment and was addressed by DR S-98-2606. Based on the DR evaluation and the
licensee's May 14, 1998, summary of inspection results, the Unit 1 liner was
dispositioned as being adequate. The licensee stated that the Unit 1 disposition also
adequately addressed the Unit 2 liner corrosion. The licensee's inspection results stated
that the gap between the liner and concrete slab was sealed by a "tight" rust scale which
would prevent moisture intrusion and corrosion of the liner plate below the slab.
However, the inspectors questioned the basis*for this conclusion. The presence of the
corrosion will inhibit the application of protective coatings to prevent additional corrosion
of the liner plate. It is well established that the principal purpose of coatings is to seal the
surface of the steel liner and reduce the rate of corrosion of the metal. The presence of
the corrosion will not inhibit additional corrosion, but may actually accelerate the
corrosion rate.
The inspectors noted that licensee inspections performed to comply with Article IWE and
10 CFR 50.55a will require determination of the extent of corrosion (flaw size) by
20
measurement, evaluation of the flaws, and repairs if necessary. The licensee's current
evaluation will not satisfy the requirements of 10 CFR 50.55a and Article IWE which are
effective September 9, 2001. The extent and depth of the corrosion are unknown at this
time. On June 15, 1999, a conference call was held with the inspectors, the licensee and
participants from the Region II office and NRR to further discuss the licensee's actions
on containment liner corrosion. The licensee stated that work orders exist to repair Unit
1 liner corrosion located above the slab and that engineering will examine the condition
of the liner before coatings are reapplied. The licensee is planning to perform a liner
inspection per Article IWE during the next Unit 1 and 2 refueling outages. In addition,
engineering is reviewing their overall effort for resolving liner corrosion to determine if
addition actions are needed and to elaborate on their evaluation which accepted the Unit
1 liner corrosion. Inspection Followup Item 50-280, 281/99003-04 was opened to review
engineering's additional reviews and resulting actions to resolve containment liner
corrosion.
c.
Conclusions
The licensee's program for maintenance, inspection and repairs to containment coatings
was adequate. Containment liner corrosion at the basement slab/liner intersectiqn was
observed. The licensee is continuing to review their efforts to resolve the liner corrosion.
MB
Miscellaneous Engineering Issues (92903)
E8.1
(Closed) IFI 50-280, 281/98201-05: adequacy of 4160 V electrical cables to withstand
fault current. The licensee's rationale for accepting the 4160 V cables, even though they
are undersized in the traditional sense from the short-circuit viewpoint was described in
NRG Inspection Report No. 50-280/99-01, Section E8.1. After further review of the
licensee's rationale, the size of the 4160 V electrical cables is considered adequate.
E8.2
(Closed) IFI 50-281/99001-04: review the acceptability of reduced minimum flows for the
low head safety injection pumps after piping modifications. This item questioned whether
Unit 2 low head safety injection (LHSI) pump recirculation minimum flows would be
sufficient to preclude hydraulic instabilities after a piping modification.
The LHSI pumps are vertical two stage centrifugal pumps manufactured by Byron
Jackson. A letter from Byron Jackson to the licensee dated July 8, 1988, gave the rated
conditions for these pumps as 3000 gallons per minute (gpm). This letter also indicated
that the pumps could be operated at a minimum flow of 150 gpm. The licensee found
- that themanufacturer*considered*this minimum-flow sufficient to avoid pump damage
due to temperature rise and flashing during continuous operation but that it did not
preclude the possibility of damage due to hydraulic instabilities. Licensee documents
indicated that a minimum flow of about 900 gpm might be needed to preclude damage
due to hydraulic instabilities.
LHSI pump recirculation operation involves two cases. (1) parallel pump recirculation for
a maximum of 30 minutes or (2) single pump recirculation for an estimated 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> plus
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in piggyback mode (i.e. feeding the suction of the safety injection charging
e
21
pump). The licensee used pump recirculation flow measurements obtained following the
modification and estimated piggyback flow to evaluate both cases. These flows were as
follows:
Pump
Number
U2-1A
U2-1B
Parallel Pumps on
Recirculation
122 gpm
148 gpm
Single Pump on
Recirculation
171 gpm
217 gpm
Piggyback
Mode
400 gpm
400 gpm
The licensee evaluation found that the flows were adequate in both single and parallel
pump recirculation, as summarized below:
Parallel Pump Operation: The measured flows for the pumps in this operating mode
were below 150 gpm after the modification. Therefore, the licensee evaluated whether
unacceptable temperature rise, flashing, and hydraulic instabilities would result. The
Hydraulic Institute Standard (1994 Edition) indicates that the temperature rise across a
pump should be limited to 15°F and that there should be a safe margin against flashing.
The licensee calculated that the temperature rise would only be 9°F during the 30
minutes of operation and that the outlet temperature would be 53°F, which is well below
the flashing point at the given suction head. With regard to hydraulic instabilities, suction
and discharge recirculation resulting from low flow were of concern. The Hydraulic
Institute Standard indicated that suction recirculation is a potential problem in high-
energy pumps and can cause localized pitting. The licensee noted that the LHSI pumps
are not high-energy pumps, and that any pitting that may occur would be slow and not
cause significant mechanical degradation during the mission time. The standard states
that discharge recirculation can lead to mechanical vibration and bearing failure. The
licensee took vibration readings on the upper motor bearing after the modification, before
declaring the pumps operational. The vibration readings were unchanged from historical
levels, and the licensee concluded that the reduced minimum flow was not at a level that
would result in damaging discharge recirculation. Based on their above evaluations the
licensee concluded that parallel pump recirculation flow following the modification was
adequate.
Single Pump Operation: The single pump operation flows measured by the licensee
after the modification were above 150 gpm, such that ur:iacceptable temperature rise and
flashing were not a concern. However, flow was sufficiently low for possible hydraulic
instabilities. * Based on the vibration measurements referred to in the previous paragraph,
the licensee concluded that the single pump operation flows were adequate.
For both parallel and single pump operation the inspectors concluded that the licensee
had adequately demonstrated the acceptability of recirculation flows through their
evaluations.
In March, 1999, prior to the implementation of the recirculation line modification, the
inspectors performed a review of Engineering Transmittal CME 98-014, "Evaluation of
22
Operation of LHSI Pumps Recirculating to the RWST," Revision 3. The inspectors
generated an inquiry based on questions of lack of inclusion of uncertainty in the
calculation, the age of the test data used, and the validity of using the recent test results
made at a very flat portion of the curve for monitoring flow degradation. In reply the
licensee provided the inspectors with the position paper "Low Head Safety Injection
Pump 2-SI-P-1A Operability, Surry Power Station -Unit 2," a letter from Byron Jackson
dated April 15, 1999, concerning their review of the position paper, and "Virginia Power
Response to NRC Inquiry Regarding Engineering Transmittal CME 98-014," Revision 3.
The responses revisited the operability of the pump considering a dead-headed
condition. The licensee and a manufacturer's representative, based on calculation,
knowledge of pump characteristics, and test data indicated that the pumps are currently
not degrc1ded due to past operation at potential dead-headed conditions. Based on the
new evaluation, and the manufacturer's concurrence, the inspectors operability concerns
with the pump have been addressed.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1 .1
General Observations (71750)
On numerous occasions during the inspection period, the inspectors reviewed radiation
protection (RP) practices including radiation control area entry and exit, survey results,
and radiological area material conditions. No discrepancies were noted, and the
inspectors determined that RP practices were proper.
The plant primary and secondary chemistry logs were reviewed to ensure that plant
chemistry. was within the Technical Specification and procedural limits. No deficiencies
were noted.
On May 21, the inspectors observed the addition of hydrazine to the Unit 2 reactor
coolant system. The evolution was performed in accordance with the requirements
specified in procedure 2-0P-CH-008, "Chemical Addition to the RCS," Revision 5.
R1 .2
Tour of Radiological Protected Areas
a.
Inspection Scope (83750)
The inspectors reviewed implementation of-selected elements of the licensee's radiation
protection program as required by 10 Code of Federal Regulations (CFR) Parts 20.1201,
1501, 1502, 1601, 1703, 1802, 1902, and 1904. The review included observation of
radiological protection activities including control of radioactive material, radiological
surveys/postings, and radiation area/high radiation area controls.
23
b.
Observations and Findings
During tours of the turbine building,' reactor building, auxiliary building, and storage and
handling facilities, the inspectors reviewed survey data and observed activities in
- progress. Based on these observations the inspectors determined that the licensee had
effectively posted areas where radioactive material was stored and radioactive material
observed was labeled as required. Lock boxes containing keys to Locked High
Radiation Areas and Very High Radiation Areas were inventoried by the inspectors and
all keys were accounted for. During tours the inspectors observed that Locked High
Radiation Areas were locked and controlled as required by licensee procedures.
Radiological surveys reviewed were well documented and areas observed were posted
consistent with the survey documentation. Independent surveys were performed by the
inspectors in selected areas of the auxiliary building to 'verify licensee survey results.
Survey instrumentation and continuous air monitors observed in use within the
radiological controlled areas were operable and currently calibrated. The inspectors
determined the licensee had an adequate number of survey instruments available for
use during the outage and the instruments were being calibrated and source checked as
required by licensee procedures.
Selected radiation work permits (RWPs) were reviewed for adequacy of the radiation
protection requirements based on work scope, location, and conditions. For the RWPs
reviewed, the inspector noted that appropriate protective clothing and dosimetry were
required. During tours of the plant, the inspectors observed the adherence of plant
workers to the RWP requirements during the performance of work.
The inspector reviewed selected personnel contamination events (PCEs) and discussed
contamination control practices for selected outage operations. As of April 26, 1999,.
approximately 30 PCEs, had occurred. This number of PCEs included both particles and
dispersed contamination events for clothing and skin. Based on records reviewed, all
skin doses were well below regulatory limits. During tours of the Unit 2 reactor building
and auxiliary building the inspectors observed adequate contamination control practices.
Contaminated square footage was being maintained less than one percent of the total
RCA during non-outage periods and approximately three percent during the outage.
c.
Conclusions
The licensee was effectively maintaining controls for personnel monitoring, control of
radioactive material, *radiological postings, radiation area controls, and high radiation
area controls as required by 1 O CFR Part 20.
R1.3
Occupational Radiation Exposure Control Program
a.
Inspection Scope (83750)
The inspectors reviewed the licensee's implementation of 10 CFR 20.1101 (b) which
requires that the licensee shall use, to the extent practicable, procedures and
e
24
engineering controls based upon sound radiation protection principles to achieve
occupational doses and doses to members of the public that are ALARA.
b. . Observations and Findings
The inspectors review of the licensee's ALARA program determined the licensee had
established a goal of approximately 97 person-rem for the Unit 2 refueling outage
scheduled for 36 days. At the time of the inspection on April 29, 1999, the licensee was
below target with daily projections based on work scope accomplished.
The inspectors reviewed and discussed ALARA initiatives such as shielding, reactor
coolant system micron filtration, reactor crudburst shutdown activities, use of video
monitoring and teledosimetry, hot spot reduction efforts, and outage planning. The
inspectors observed an ALARA committee meeting to address the replacement of a
safety injection valve. The meeting was well attended by plant management and was
interactive. The inspectors also attended the ALARA pre-job briefing for the safety
injection valve replacement. The pre-job briefing addressed all ALARA concerns and
safety aspects. Based on these discussions and observations, the inspectors
determined the licensee was maintaining programs for controlling exposures ALARA and
continued to be effective in controlling overall collective dose. All personnel radiation
exposures during 1999 to date were below regulatory limits.
c.
Conclusions
The licensee was maintaining programs for controlling exposures As-Low-As-ls-
Reasonably-Achievable (ALARA) and continued to be effective in controlling overall
collective dose. All personnel radiation exposures during 1999 to date were below
regulatory limits.
S1
Conduct of Security and Safeguards Activities (71750)
On numerous occasions during the inspection period, the inspectors performed
walkdowns of the protected area perimeter to assess security and general barrier
conditions. No deficiencies were noted and the inspectors concluded that security posts
were properly manned and that the perimeter barrier's material condition was properly
maintained.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on June 4, 1999. The licensee acknowledged the findings
presented. On June 15, 1999, a conference call was held with the licensee and NRC personnel
from the Region II office and Office of Nuclear Reactor Regulation to discuss containment liner
corrosion and actions the licensee have taken and are planning to take.
'
25
The inspectors asked the licensee whether any materials examined during the inspection should
be considered proprietary. No proprietary information was identified.
- PARTIAL LIST OF PERSONS CONTACTED
M. Adams, Superintendent, Engineering
R. Allen, Superintendent, Maintenance
R. Blount, Manager, Operations & Maintenance
E. Collins, Director, Nuclear Oversight
M. Crist, Superintendent, Operations
D. Llewellyn, Superintendent, Training
E. Grecheck, Site Vice President
B. Stanley, Supervisor, Licensing
T. Sowers, Manager, Nuclear Safety & Licensing
W. Thornton, Superintendent, Radiological Protection
IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707: *
IP 71750:
IP 83750:
INSPECTION PROCEDURES USED
10 CFR 50.59 Safety Evaluation Program
Engineering
Onsite Engineering
Effectiveness of Licensee Process to Identify, Resolve, and Prevent Problems
Surveillance Observation
Maintenance Observation
Plant Operations
Plant Support Activities
Occupational Exposure
Engineering Follow-up
ITEMS OPENED AND CLOSED
Opened
50-280/99003-01
Failure to place the load tap changer on the A
Reserve Station Service Transformer in automatic
following manual adjustment (Section 02.1)
50-281 /99003-02
50-281 /99003-03
IFI
50-280, 281/99003-04
IFI
Failure to properly de-energize the Unit 2 Hi CLS
logic circuitry (Section 02.3)
Review engineering's structural integrity
conclusions concerning vibration of the LHSI pump
recirculation piping (Section E1 .2)
Review engineering's additional reviews and
resulting actions to resolve containment liner
corrosion (Section E2.1)
Closed
50-280/99003-01
50-281 /99003-02
50-280, 281/98201-05
50-281/99001-04
IFI
IFI
26
Failure to place the load tap changer on the A
Reserve Station Service Transformer in automatic
following manual adjustment (Section 02.1)
Failure to properly de-energize the Unit 2 Hi CLS
logic circuitry (Section 02.3)
Adequacy of 4160 VAC electrical cables to
withstand fault current (Section E8.1)
Review the acceptability of reduced minimum flows
for the low head safety injection pumps after piping
modifications (Section E8.2)