ML20149L575
| ML20149L575 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, McGuire  |
| Issue date: | 07/28/1997 |
| From: | Mike Franovich, Scott Shaeffer, Marvin Sykes NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20149L565 | List: |
| References | |
| 50-369-97-09, 50-369-97-9, 50-370-97-09, 50-370-97-9, NUDOCS 9708040119 | |
| Download: ML20149L575 (42) | |
See also: IR 05000369/1997009
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-369. 50-370
Report No: 50-369/97-09, 50-370/97-09
Licensee: Duke Power Company
Facility: McGuire Nuclear Station Units 1 & 2
Location: 12700 Hagers Ferry Rd. l
Huntersville, NC 28078 l
Dates: May 18 - June 28, 1997
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Inspectors: S. Shaeffer Senior Resident Inspector
M. Sykes Acting Senior Resident Inspector
M. Franovich, Resident Inspector )
R. Moore, Regional Inspector (Sections E2.2. E2.3) ;
H. Whitener, Regional Inspector (Sections M4.2, M6,
D. brbe bg n Inspector (Section R1)
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Approved by: K. Landis, Acti,1g Chief. Projects Branch 1
Division of Raactor Projects
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Enclosure 2
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9708040119 970728
PDR ADOCK 05000369
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EXECUTIVE SUMMARY
McGuire Generating Station. Units 1 & 2
NRC Inspection Report 50-369/97-09. 50-370/97-09
This integrated inspection included aspects of licensee operations, engineer- i
ing, maintenance, and plant support. The report covers a six-week period of
resident and Region inspection. l
Operations
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. Unit 2 control room operator response to the loss of main turbine
hydraulic oil system fluid inventory was good, minimizing the potential
for a turbine trip and subsequent reactor trip that could have l
challenged safety systems. (Section 01.2)
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. The licensee reported operational events in accordance with the
requirements of 10 CFR 50.72. (Section 02.1)
. The overall Unit 2 shutdown for identified steam generator leakage was
well controlled. The active monitoring of the identified steam ,
generator leakage and the management decision to shutdown the unit to l
repair existing leakage was conservative. As a result, no l
administrative or Techriical Specification limits for reactor coolant j
system leakage were exceeded. (Section 02.2) !
. The resolution of the low reactor coolant system loop 'A' temperature
indication reading (input to the Unit 2 Operator Aid Computer) was
adecuately addressed. Alert operator identification of the issue was a
gooc example of maintaining a questioning attitude and attention to
detail. (Section 02.3)
. The licensee exhibited superior safety focus in preparing for midloop
o]erations and was proactive in reducing shutdown risk. Enhancements to
t7e procedure for loss of decay heat removal and emergency core cooling
system equipment availability were considered good shutdown risk actions
with appropriate consideration for Low Temperature Over Pressure (LTOP)
restrictions. A pre-job brief was performed with excellent focus on the
low thermal margin and examples of operator related industry shutdown i
events. Reactor coolant system drain down was effectively conducted
with good procedural compliance, outstanding communication among reactor l
operators, and strong oversight. Overall. the licensee's shutdown risk
management was a strength. (Section 4.1)
. Control of overtime for plant personnel during this review was adequate.
In addition, the licensee's assessments performed on the control of
overtime were detailed and provided good oversight. Licensee postings
of notices to workers was also adequate. (Sections 06.1 and 06.2)
Enclosure 2
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Maintenance
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In general, the post maintenance test program was satisfactory with good
procedures in place to perform retest tasks. (Section M1.2)
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Licensee self assessmerit and reassessment of retest problem issues
resulted in improved performance in this area. (Section M1.2)
- Post maintenance testing program implementation weaknesses were
identified related to completeness of the Retest Manual. documentation
of the justification for not performing a retest, and retest evaluation
with no oversight review. (Section M1.2)
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The licensee had develo)ed, documented and implemented a Planning ?.nd
Scheduling process whic1 was functioning well. (Section M1.3)
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Monitoring and trending performance data indicated that the Planning and
Scheduling process had been effective. (Section M1.3)
- . Operators' response to the inadvertent engineered safety feature
actuation, which occurred on May 27, 1997, during emergency diesel l
gerierator load sequencer testing, was adequate and complied with TS '
requirements. Operator actions were adequate. A Violation was I
identified for an inadequate test procedure. (Section M2.1) )
. The licensee's final repairs to the Unit I high pressure (HP) turbine l
blade ring locating pins were adequate. However, the repetitive HP ,
turbine steam leaks were identified as an example of incomplete root I
cause reviews on secondary components. (Section M2.2)
. A weakness was identified concerning the isolation of the instrument air
supply to heater drain valves during turbine building cleaning
activities due to ineffective vendor oversight. The vendor personnel
1 did not receive sufficient guidance prior to the start of the activity.
As a result. the contract workers initiated an operational transient by
manipulating Operations controlled equipment. (Section M2.3)
. Unit 1 restart testing following the Steam Generator (SG) Replacement
Outage was adequately planned and executed to verify SG design and
ensure reliable operation of the Unit 1 control systems. (Section M3.1)
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. SG tube inspection and leak repairs were adequately performed. However,
the followup to an earlier SG indication in the area of the identified
leak led to a missed opportunity to prevent this event. Actions to
correct the problem and ensure that other oversights did not occur were
good. This problem was identified as an Unresolved Item pending further ,
review of the root cause of the SG inspection process. (Section M4.1) l
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Enclosure 2
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Enaineerina
. Once identified. the licensee initiated appropriate actions to address
the potential for non-conservative Technical Specification (TS) for
inoperable main t. team safety valves (MSSV). Although adequate
administrative controls were in place and no actual MSSV inoperability
occurred, the licensee did not immediately pursue a TS Amendment, which
led to delays in final resolution and identification of all pertinent
issues. (Section El.1)
. The addition of a second auxiliary feedwater condensate storage tank
(AFWCST) was a timely and positive action to increase auxiliary
feedwater supply inventory and improve pump suction reliability.
Installation of vortex suppressors was a conservative management
decision following detailed engineeririg analyses. (Section E2.1)
. The modifications completed during the Unit 1 outage demonstrated
appropriate control of the design control process at McGuire.
Performance was good for modifications, procedures. 50.59 evaluations
and screening. (Section E2.2)
. Engineering's upgrade and validation of Design Base Document (DBD) Test
Acceptance Criteria (TAC) sheets for Inservice Test (IST) valves was an
example of good engineering support to operations. The TACs provided a
good design reference for Operations to maintain system operability when
safety-relai.ed valves were out of service for testing. (Section E2.3)
. Initial Unit 1 fuel assembly K-45 reconstitution work activities were l
well controlled and good communication and oversight existed between the j
station and contract employees. Reactor engineering personnel were i
knowledgeable and the 10 CFR 50.59 evaluation was adequate. Appropriate
reactor engineering oversight was present and adequate radiation
protection coverage was provided. (Section E3.1)
. The inspectors concluded that the licensee developed adequate procedures
and controls for replacement of the battery / charger EVCA. Modification
packages for installation of the temporary battery were adequate.
Contingencies were established to identify necessary actions in the
event of a loss of the temporary battery or the spare charger while
replacement was in progres.s. The licensee delayed return of the battery
to service to minimize potential plant impact during Unit 2 draindown ,
and midloop operations. The replacement activities were completed l
within the authorized TS allowed outage times. (Section E4.1)
Plant Suonort
. At the time of the inspection. the inspectors determined that the
licensee was in the process of developing procedures and work practices
to maintain effective contamination controls and to maintain exposures
ALARA during work evolutions on two removed SGs. (Section R1)
Enclosure 2
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. Emergency preparedness practice drill scenario was adequate to
effectively test the Emergency Res)onse Organization (ERO) participants.
The ERO performance was adequate; lowever, additional management
emphasis of ERO expectations was necessary. (Section Pl.1)
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Based on the inspectors concerns. the licensee initiated the development
of additional testing for the fire suppression system interior loop
piping. The inspector concluded that the enhanced testing would provide
additional indications of system degradation. The inspectors also
concluded that the administrative processes for long-term monitoring of
the fire protertion system for degradation could be improved. An IFI
was identified to evaluate the future enhanced system testing.
(Section F3.1)
Enclosure 2
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Report Details
Summary of Plant Status
Unit 1 began the inspection period in MODE 3 (Hot Standby) returning from
MODE 5 (Cold Shutdown) following replacement of a failed intermediate range
power detector. On May 18. the unit was taken critical. On May 20 with the
unit at ap3roximately 6 percent power, an unplanned turbine trip occurred
during tur)ine trip testing. After the apparent cause of the turbine trip was
identified, the turbine was again latched and power escalation continued. On
May 23. after successful completion of a 10 percent load reduction test from
38 percent power, the unit reduced power to approximately 10 percent to repair
a failed seal weld on the high pressure turbine blade ring locating pins.
Once repaired power escalation continued. On May 25. a second 10 percent
load reducto test was successfully completed at approximately 78 percent
power. Unit pt.ser was then increased to approximately 99 percent to allow for
performance of secondary heat balances to verify primary and secondary
parameters. On May 30. a rapid downpower was performed following
identification of a hydraulic fluid leak on the C low 3ressure turbine
intercept valve. At approximately 17 Jercent power t1e operators tripped the
main turbine and reactor power was sta)ilized at approximately 12 percent. On
May 31, after leak repairs were completed, power escalation continued. On
June 1. a second unanticipated turbine trip occurred during turbine trip
testing. The cause of this and the May 20th turbine trips were determined to
be equipment malfunctions. Power escalation continued to approximately 100
percent. On June 2. unit power was reduced to approximately 12 percent to
repair a repetitive steam leak on the high pressure turbine casing. After
repairs were completed, unit power was increased to 100 percent. The unit
operated at approximately 100 percent power for the remainder of the
inspection period.
Unit 2 began the inspectian period at approximately-100 percent power. On May
22. a small secondary transient occurred when vendor personnel inadvertently
isolated instrument air to moisture se)arator reheater (MSR) valve
controllers. Unit load decreased slig1tly. On May 27. an inadvertent
Engineered Safety Feature (ESF) actuation occurred in Unit 2 during emergency
diesel generator (EDG) sequencer testing. On June 2. 1997, both units entered !
TS 3.0.3 due to an auxiliary building ventilation boundary door being open. I
which caused both trains of control room ventilation system to be declared
inoperable. Subsequent testing determined both trains were operable.
During the inspection rariod, primary to secondary leakage on the 2A steam ;
generator (SG) increa',ed from approximately 10 gallons per day (GPD) to '
a) proximately 65 GPD. On June 13, 1997. plant management decided to shutdown
t7e unit to identify and correct the primary to secondary steam generator
leakage. On June 15. the plant entered MODE 5 (Cold Shutdown) to support the
steam generator work. Two periods of midloop operation were recuired to
support the leak repair and inspections. The unit was restartec on June 28
from the SG repair outage. At the close of the period, the unit was in MODE 1
(Power Operation), with preparations underway to place the unit on-line.
Enclosure 2
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Review of Vodated Final Safety Analysis (UFSAR) Commitments
While performing inspections discussed in this report the inspectors reviewed
the applicable portions of the UFSAR that were related to the areas inspected.
The inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures. and/or parameters.
I. Doerations
01 Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. In general, the conduct of
operations was professional and safety-conscious; specific events and
noteworthy observations are detailed in the sections below. Operators'
transition to dual unit operations was conducted in a safe manner.
Various Unit 1 power changes due to equipment problems were adequately
performed. Operator awareness of primary to secondary leakage on the 2A
SG was heightened and plant chemistry sampling of the leak was
conservative and frequent, The shutdown and restart of Unit 2 to repair
the identified the SG tube leakage was conducted in safe manner, which
included periods of reduced reactor coolant system (RCS) inventory
conditions.
01.2 Unit 2 Hydraulic Fluid Leak
a. Inspection Scone
The inspectors responded to notification of a hydraulic fluid leak from
the Unit 2 Main Turbine Hydraulic Oil (LH) System.
Observations and Findinas
On May 30. 1997. the licensee reduced power after identification of a
main turbine hydraulic oil system leak. Control room operators began a
controlled downpower in accordance with abnormal operating procedure
AP/2/A/5500/04 Rapid Downpower. With the unit at approximately 17
percent reactor thermal power the main turbine throttle valves moved to
the closed position after hydraulic fluid inventory was depleted.
Operators manually tripped the turbine and generator. The reactor
remained at appproximately 17 percent power.
The licensee determined that a hydraulic fluid system fitting failed
releasing the hydraulic fluid inventory to the Unit 2 turbine deck and
subsequenth into the turbine building drains. The drain system was
isolated preunting the release of the material to the environment. The
licensee conducted immediate repairs of the fitting and completed a
thorough cleanup of the turbine building and turbine building sump.
Enclosure 2
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l Because the hydraulic fluid was identified as a hazardous chemical, the
licensee isolated the turbine building sump discharge until cleanup of
the chemical was completed. The unit was subsequently returned to rated
power.
l c. Conclusions
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The inspectors concluded that the Unit 2 control room operator response
to the loss of main turbine hydraulic fluid was prudent, minimizing the
l potential for a turbine trip and subsequent reactor trip that may have
challenged safety systems.
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02 Operational Status of Facilities and Equipment (71707) {
l 02.1 10 CFR 50.72 Notifications
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l a. Insoection Scooe
During the inspection period, the licensee made the following
notifications to the NRC as required for information purposes. The
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inspectors reviewed the events for impact on the operational status of I
the facility and equipment. !
b. Observations and Findinas
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On May 20. 1997, the licensee made a report in accordance with 10 CFR
50.72 regarding non-conservative Technical Specification (TS) ACTIONS l
l associated with postulated inoperable main steam line safeties. This l
report was considered a followup to an earlier report on March 20. 1997
describing postulated situations where TS ACTIONS may not require the
most limiting power levels for inoperable main steam line safety valve
configurations (see Section El.1 for details). The licensee has
submitted a Licensee Event Report (LER) on the issue.
On May 27, 1997, the licensee made a report in accordance with 10 CFR
50.72 due to an ESF actuation which occurred during testing of the Unit
2 EDG sequencer logic (see Section M2.1 for details). The licensee
plans to submit an LER on the event.
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On June 2.1997.. the licensee made a report in accordance with 10 CFR
50.72 after declaring both trains of auxiliary building and control room
ventilation inoperable (TS 3.0.3). 03erability of the systems was
questioned during ventilation system 30undary alterations to support
vital battery modifications. However, subsequent testing verified that
the systems were operable. The notification was retracted on June 11.
On June 9. 1997, the licensee made revisions to a previous report in
i accordance with 10 CFR 50.72 due to additional information identified
j regarding potential operability concerns on the auxiliary feedwater
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(AFW) suction supply (see Section E2.1 for details). .
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c. Conclusions
The inspector concluded that the licensee reported the above events in
accordance with the requirements of 10 CFR 50.72.
02.2 Unit 2 Shutdown for Identified Steam Generator Tube Leakaoe
a. Insoection Scooe
The inspectors reviewed the shutdown of Unit 2 for identification and
repair of SG tube leakage.
b. Observations and Findinas
Du,'ing the beginning of the inspection period, the licensee had been
actively monitoring a primary to secondary leak on the Unit 2 A SG.
Monitoring of the leakage was established in February 1997 with an
indication of approximately 2 Gallons Per Day (GPD). The TS operational '
limit for SG primary to secondary leakage is 500 GPD: however, the
licensee had established a more conservative administrative limit of 100
GPD for the Unit 2 SGs. Throughout in the inspection period, the
identified leakage had increased to approximately 65 GPD. On June 13. l
the licensee decided to initiate a forced outage to identify and repair
the Unit 2 primary to secondary leakage. The Unit 2 SGs were scheduled i
to be replaced during the next Unit 2 refueling outage scheduled to '
begin in September 1997. The Unit 1 SGs have already been replaced ;
during the Unit 1 End of Cycle 11 refueling outage. l
The inspectors observed portions of the planned unit shutdown and
verified SG 1eakage limits did not increase during the evolution.
Operators involved in the shutdown evolutions were attentive and
maintained TS parameters within limits. Shift briefing prior to the
shutdown highlighted potential problems during the downpower, what
contingency measure were required, and stressed monitoring key
parameters. The inspectors noted that specific measures were in place
to heighten communications between the operating shift and the secondary
chemistry staff to monitor the SG leakage for adverse change. On June
15. the unit entered MODE 5 (Cold Shutdown) to establish conditions to
support the SG repair work.
c. Conclusions
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The inspector concluded that the overall shutdown evolutions were well '
controlled. The inspector also concluded that the active monitoring of I
the identified SG leakage and the management decision to shutdown the i
unit to repair existing leakage was conservative. As a result, no
administrative or TS limit for RCS leakage was challenged or exceeded.
Enclosure 2
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02.3 Unit 2 Low RCS Looo Temoerature Readina
l a. Insoection Scope
The inspector reviewed the circumstances involving a Unit 2 low RCS loop
'A' temperature reading and the potential impact on calculation of
primary thermal power.
b. Observations and Findings
During the inspection period, a Unit 2 operator identified a low RCS
temperature indication during a review of inputs into the primary
thermal power calculation. At the time, primary thermal power was
indicating 103.3 percent and the loop A Tcold was reading 549 F when it
should have been reading 558 F.
According to the licensee, above 50 percent power, primary power best
estimate calculations are based completely on secondary parameters.
Differential temperature inputs for the reactor protection system did
not appear to be affected. The licensee's review indicated that this
input point to the Unit 2 operator aid com) uter (OAC) had fluctuating
readings between May 21 and May 31. A worc order was written; however,
no corrective action was required because the indication was found to be
correct (i .e. , not fluctuating). The licensee plans on monitoring this
OAC data point through the system health monitoring program and replace
the isolator board (only component that could cause the fluctuations) if
any drift is observed. This issue was documented in PIP 2M97-2169.
c. Conclusions
The inspector concluded that the resolution of the low RCS loop ' A'
temperature indication reading (input to the Unit 2 OAC) was adecuately
addressed. Alert operator identification of the issue was a gooc
example of maintaining questioning attitude and attention to detail .
04 Operator Knowledge and Performance
04.1 Unit 2 Reduced Inventory Ooerations
a. Insoection Scoce (71707. 40500)
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During the inspection period. Unit 2 was shut down in response to
l identified steam generator (SG) tube leakage. Before the unit entered :
l reduced inventory operations to facilitate SG tube repair, the inspector ,
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reviewed the operations and SG inspection schedules to identify any l
potential periods of increased shutdown risk. The inspector reviewed ,
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the forced outage plans to drain down the reactor coolant system (RCS). ;
enter midloop operations install and remove SG nozzle dams, and re- '
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flood the RCS. l
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Enclosure 2
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The inspector reviewed station shutdown and abnormal procedures: ,
reviewed pre-job briefing materials: attended a midloop pre-job !
briefing: witnessed portions of the draindown and midloop operations;
confirmed TS compliance: reviewed recommendations from the McGuire i
Independent Review Team (IRT) assessment of outage risk: and attended
the associated PORC meeting on procedure enhancements for coping with a
loss of residual heat removal (RHR). The inspector also reviewed
Generic Letter No. 88-17. Loss of Decay Heat Removal: the licensee's
response to GL 88-17: various plant drawings, control room log books.
forced outage schedules, containment integrity controls, and RCS makeup
capability. i
b. Observations and Findinas
Midloop operations were performed on two occasions during the Unit 2 )
forced outage. Both midloo) windows of operation were entered with fuel l
in the reactor vessel and tie vessel head remaining tensioned. The
licensee did not off-load the core during the outage.
The first reduced RCS inventory evolution occurred approximately 5 days I
after reactor shutdown. On June 18 the licensee: (1) drained down the
RCS to 28 percent of pressurizer level: (2) calibrated RCS level
instrumentation: (3) positioned a video camera for control room
monitoring of RCS level on a sight glass: and (4) drained the RCS to
aaproximately 10 inches above the centerline of the RCS hot leg piping.
T1e unit remained in midloop conditions for approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> until i
SG nozzle dams were installed. Upon a postulated loss of Residual Heat !
Removal (RHR), the margin to core boiling was 10 minutes. ;
The second RCS reduced inventory evolution occurred approximately 9 days ;
after reactor shutdown. The unit remained in midloop (11 inches above
centerline) for approximately 43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> until completion of remaining SG
repair activities, removal of nozzle dams, and installation of SG i
manways. For this period, upon a potential loss of RHR. the margin to l
core boiling was 26 minutes during the second midloop.
Before these reduced RCS inventory evolutions. the licensee completed an
independent review of proposed shutdown operations. The licensee's
Nuclear System Directive 403. Shutdown Risk Management, requires that an
independent review team (IRT) assess proposed outage schedules and i
operations to identify any periods of reduced defense-in-depth for '
safety functions. The IRT identified reduced defense-in-depth for the ,
RHR function due to the low thermal margin of the first midloop and
proposed several contingency actions.
A significant IRT proposal involved enhancement of the loss of RHR
abnormal procedure to improve operator response time. To achieve this,
operators would immediately initiate RCS feed-and-bleed using a charging
pump and safety injection pump. Under a loss of RHR event, this
operator action would be taken if a themal margin of less than 20
Enclosure 2
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minutes existed. To im] rove res)onse time the PORC also approved the
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proposal to have availaale one clarging pump and one safety injection
pump in opposite electrical trains with power racked in pricr to
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commencing the initial drain. This system configuration required entry
into the Action Statement for Technic.1 Specification 3.4.9.3. Low
Temperature Overpressure Protection ,LTOP). and was appropriately
discussed in the PORC meeting.
Through control room board walkdowns and discussions with the operators,
the inspector verified the Emergency Core Cooling System (ECCS)
alignment approved by PORC and that controls were in place for RCS
venting during reduced inventory conditions. The inspector also
verified that the conditions of the LTOP technical specification were
satisfied. This included verification of appropriate RCS LTOP vent
paths. The ins)ector also confirmed availability of instrumentation and
RCS makeup capa]ility.
Licensee management conducted are-job briefings before the unit entered
a reduced inventory to prepare t1e operating shifts for the infrequently
performed evolution. Management expectations and safety concerns were
i emphasized during the briefing. Planr. status was reviewed with
particular interest on RCS inventory, decay heat removal capability,
containment integrity. and power scarce and ECCS availability.
Excellent attention was given to the fact that the first hot midloop was
- an infrequent operating condition with low thermal margin. The pre-job
- briefing material and presentation placed heavy focus on industry
shutdown events with emphasis on multiple examples of operator actions
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that contributed to the events. The inspector also noted a good
discussion among the briefing attendees with regard to equipment
. behavior from past plant experience. This was especially evident during
i discussion of RCS level instrumentation behavior and which type of
instruments provided conservative level indication. The inspector also
witnessed a good shift turnover and good communication between outgoing
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and incoming reactor operators. Operator knowledge and abilities were
excellent.
Offsite and emergency power sources were confirmed to be available.
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Switchyard work and round-cell station battery replacement activities
- were postponed until after reduced inventory operations. Operators used
core exit thermocouples and RHR system inlet temperature to monitor RCS
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temperature. Operators used RHR heat exchanger outlet temperature for
Low Temperature Over Pressure (LTOP) TS restrictions.
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The inspector observed the following operations practices to minimize
shutdown risk:
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. Minimize time in midloop conditions and use of an IRT to assess
outage risk
Enclosure 2
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. PORC approved enhancement of AP/2/A/5500/19. Loss of ND (RHR) or
ND System Leakage, to allow for earlier operator action to feed-
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and-bleed the RCS with ECCS equipment
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One charging pump and one safety injection pump in opposite
electrical trains available with power racked in, the associated
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Refueling Water Storage Tank (RWST) flow path available, and
adequate RCS venting
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Gravity feed capability from the RWST to RCS (and other makeup
sources) remained available
. Thorough Significant Operating Event Report (SOER) 91-01. Pre-job
Briefing
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Minimization of control room traffic and other potential operator
distractions
. Appointment of an RCS drain down coordinator - Senior Reactor
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Operator (SRO)
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. Excellent SR0/R0 discussion of past level instrumentation behavior
. Deferral of all Unit 2 work activities such as periodic tests or
maintenance during the drain down
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Deferral of Unit 1 work that could affect Unit 2. such as
Performance Tests (pts) on shared nuclear service water systems
. Full emergency power availability
. Clear management expectations for operators to stop work if
abnormal conditions are present
. Clear explanation of roles, responsibilities, and command and
control for the drain down
Shutdown risk information was reviewed and discussed routinely during
the licensee's plan of the day meetings. The inspector verified the
accuracy of the information during daily control room visits.
c. Conclusion
For the reduced inventory evolutions, the inspector determined that
there was outstanding communication among reactor operators. A good
pre-job brief was performed with excellent focus and examples of
operator related industry shutdown events. Pre-job briefing materials
were clear and concise. Plant conditions, the low thermal margin, and ;
contingency actions for a loss of RHR were appropriately stressed. l
There was good participation of operators in pregob discussions of
Enclosure 2 .
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plant equipment, drain down rates.. and reliability of level
instrumentation. Operations managers promoted licensed and non-licensed
operators to maintain a questioning attitude during the evolutions.
Operator heightened awareness and attention to details were evident for
reduced inventory and midloop operations.
Overall. the inspector determined that the licensee exhibited superior
safety focus in preparing for midloop operations and was proactive in
reducing shutdown risk. Enhancements to the procedure for loss of RHR
and ECCS equipment availability were considered good shutdown risk
actions with appropriate consideration for LTOP restrictions (good
balance between shutdown risk and LTOP restrictions). Further, the
licensee's actions to drain the RCS were effectively conducted with good
procedural compliance and with strong oversight. The inspector
concluded that the licensee's shutdown risk management was a strength.
06 Operations Organization and Administration
06.1 Overtime Control
a. Insoection Scope (71707) ,
The inspector performed a review of approved overtime during the most
recent months for the plant operations and maintenance groups. The
inspector also overviewed licensee records of all personnel overtime
exemptions for hours in excess of established limits. Control of '
overtime for plant personnel is required by Technical Specification 6.2.2.e and NSD 200. Overtime Control. These documents require the ;
licensee to document and properly authorize work hour extensions. l
b. Observations and Findinas
The inspector reviewed work hour extension documentation for the subject ;
groups and determined that the forms, in general, were properly filled i
out and reasons for the work hour extensions were appropriate for the
circumstances. The inspector verified that the station manager was
reviewing a monthly site overtime report to determine that the use of
overtime was warranted and not being abused.
The ins]ector noted that in an overtime control report dated March 21,
1997, t1e licensee's evaluation of the data identified several
discrepancies regarding the timeliness of the required forms. The
inspector verified that the appropriate corrective action documents were
initiated to address the concerns.
c. Conclusion
The inspector concluded that control of overtime for plant personnel
during this review was adequate. In addition, the licensee's i
Enclosure 2 !
!
-
l l
'
! 10
i assessments performed on the control of overtime were detailed and !
provided good oversight.
06.2 Posting of Notices to Workers
, During the ins)ection period, the inspector reviewed the licensee's l
l compliance wit 1 the requirements of 10 CFR Part 19.11. Posting of ;
i Notices to Workers. The licensee implements these requirements via NSD l
l 205. Posting Requirements. This procedure identifies three locations l
l where required postings are to be maintained. The inspector verified
that the licensee conspicuously posted current copies of NRC Form-3 and
l
other required materials such as escalated enforcement and radiological
l violations in the areas. No problems were observed by the inspectors
during this review.
'
II. Maintenance l
M1 Conduct of Maintenance
i
M1.1 General Comments (61726 and 62707)
.
! a. Insoection Scope
l
'
The inspectors observed all or portions of the following work
activities:
. PT/1/A/4206/1B Safety Injection Pump 2B Performance Test
. PT/1/A/4200/20A Unit 1 Airlock Operability Test
. PT/2/A/4600/01 RCCA Movement Test
. IP/0/A/3250/128 Train B Diesel Sequencer Timer Calibration
. WO 96089566 Temporary Vital Battery Installation l
b. Observations and Findinas l
l
The inspectors witnessed selected surveillance tests to verify that i
approved procedures were available and in use, test equipment in use was '
l calibrated test prerequisites were met, system restoration was
completed, and acceptance criteria were met. In addition, resident
'
l
inspectors reviewed and/or witnessed routine maintenance activities to
verify. Where applicable that approved procedures were available and in
use, prerequisites were met, equipment restoration was completed, ana
maintenance results were adequate.
l
Enclosure 2
. _ - - - . . - . - _ - - _
- - - . - - - - - - - . - -
-
, .
s
l 11
c. Conclusion
'
The inspectors concluded that routine maintenance activities were
! performed satisfactorily.
j M1.2 Review of Post Maintenance Testina
- a. Scooe (62700) !
!
'
During this inspection period, the inspectors reviewed the work process
I
for controlling post maintenance testing (PMT) and the licensee's
corrective actions for failure to perform PMT adequately on a number of
occasions in the past 18 months.
b. Observations and Findinos 1
l
Post maintenance testing was controlled through the Corporate Nuclear
System Directive. NSD 408, " Testing," Revision 4: Work Process Manual .
(WPM) Section 501 " Post Maintenance Testing." Revision 0, " Post
l
Maintenance Testing Guidance Document," Revision 0: and Post Maintenance !
Test " Retest List," Revision 0. In general, these documents provided a i
sound basis for maintenance activities including post maintenance l
testing. Responsibilities of management, groups, and crafts were '
described; processes to be followed were specified; and retest
requirements were delineated.
In 1996. the licensee identified several cases of missed or near missed
retests. Problem investigation Process (PIP) reports were written to
determine the causes and to track specified corrective actions for these
events. Assessment of the PIPS showed that nearly all retest :
deficiencies identified in 1996 fell into one of three broad categories i
as follows: i
1
-
Retest Designations: failure of the planner to properly plan a ;
retest into the work plan (human error). i
l
-
Retest List Discrepancies: failure of the retest list to
encompass all components requiring retest leading to no retest
task in the work plan.
l
-
Execution of retest tasks in a timely manner: the work plan was
adequate but the retest was not performed in a timely manner. ;
This problem was two fold. First on occasion tasks were removed I
from the Technical Specification Action Item List (TSAIL) before
retest was performed. TSAIL was an electronic log to identify
active maintenance work orders and tasks. Second, a work status
communication problem between the craft and operations test group ,
caused unnecessary delays in performing retests. '
Actions taken to correct these conditions included the following:
'
Enclosure 2
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. _ -. _ _ _ . . __ _ _ _ . _ _. _._ _ _ __ _
l
12
-
All work plans received a peer review before issuance.
-
Revision of the Retest Manual. Two source documents for required
retests were combined into one Retest Manual. This reduced
confusion and
Additionally, potential
identifiederrors
components in the planning
requiring process.
retest, which were ;
not listed in the Manual, were incorporated into the manual.
l -
A change was made in the electronic format of TSAIL to prevent
!
entry of tasks. Only work orders could be entered. Therefore,
operators were required to review all tasks associated with a work .
l
order for completeness prior to removing the work order from the
list.
No corrective action directly addressed the communication problem
between the craft and the operations test group.
In May 1997, Work Control Assessment 97-1 was performed to determine if
corrective actions taken had been effective. The licensee determined
that the corrective actions had not been totally effective as follows:
-
Retest Designations: Assigning a peer review of planr.ing work had
been effective. No additional cases of failure to include retest
tasks in the work plan had been observed.
-
Retest List Discrepancies: Revision of the retest list had ;
l improved this document. All source information was incorporated
l into one retest list.
l
-
Execution of retests in a timely manner: A change made to the ;
electronic program allowed only a work order number to be entered i
! into TSAIL. In order to remove completed work from the TSAIL log
l the operators must verify completion of all task assignments
i associated with a work order. This resolved the issue of tasks
being removed from TSAIL before the work was completed. However,
rapid communication of test status between the craft and the
operations test group remained a problem.
The inspectors considered that the self assessment and re-assessment of
the retest problem issues resulted in improved licensee performance.
During the review the inspectors made several observations regarding
program implementation weaknesses, as follows:
-
In some instances where the Retest Manual required a retest,
planners had issued a task in the work order for the operations
- test group to evaluate the need for a retest after review of the
actual maintenance activities rather than specifying retest
l required.
.
1
Enclosure 2 i
<
_-
_ _ _ .
-
.
l
13 l
4
-
Operations group Jersonnel involved in retest evaluations were
highly trained. lowever, one individual typically reviewed the
maintenance activities that had actually been performed and made a
determination if retest was required. There was no further
oversight of these decisions.
-
For some work orders, there appeared to be inadequate
documentation in the work management system on why a retest was
not required.
-
The completeness of the Retest Manual has not been verified by a
structured or formal review. ,
The inspector discussed these items with the licensee.
Tne licensee indicated that a Quality Improvement Team would be
initiated to review the retest manual and identified weaknesses.
In additicn to review of the above documents, the inspectors reviewed
four work packages which contained several work orders and numerous task
descriptions as follows:
-
Replace Upper Motor Bearing on Residual Heat Removal Pump 1A.
-
Repair Safety Injection Valve 1NI-120B Actuator Oil Leak and Seat i
Leakage.
!
-
PM on freedom of motion of Mechanical Snubbers.
-
Repair 1B Main Feedwater Pump Inboard Bearing.
The inspectors determined that the work plans contained adequate
instructions for the tasks to be performed; appropriate, ap] roved l
procedures were identified and used to accomplish these tascs: and
procedure references to vendor manual and technical information were
included. Retest tasks were performed as required.
c. Conclusions
In general, the post maintenance test program was satisfactory with good
procedures in place to perform retest tasks.
Licensee self assessment and reassessment of retest problem issues
resulted in improved performance in this area.
Post maintenance testing program implementation weaknesses were
identified related to completeness of the Retest Manual, documentation
of the justification for not performing a retest, and retest oversight
review.
Enclosure 2
l
.
.
i
14
M1.3 Review of Planning and Schedulina
a. Scope (62700)
During this ins 3ection period the inspectors reviewed the licensee's
Planning and Scleduling Process.
b. Observations and Findinas
The licensee was using a totally electronic work order / task system. The
process for planning and scheduling work under the Work Management
System (WMS) was described by the Work Process Manual (WPM). Section
500." Planning," Revision 5. Responsibilities of management. Planners.
Schedulers, groups, and crafts were described; processes to be followed
were specified; and interface with the electronic system was detailed.
Planning was performed by Central Planning (process and WMS expertise)
or Field Planning Technicians who are assigned to the execution teams.
Central Planning performed the more complex work planning and provided
oversight, consistency, and assistance as needed to the Field Planners.
Field Planners performed work history reviews and job site walkdowns.
They also determined the workforce requirements, need for support
functions, and the scope of work to be performed.
McGuire used the concept of system work windows (SSW) to schedule and
Execute on-line maintenance. In this process important plant systems
were logically grouped and assigned to an execution week within a twelve
week rotation. The groupings were designed to:
-
eliminate PRA risk due to critical system combinations.
-
maximize system / component availability.
-
optimize maintenance by consolidating maintenance on components.
,
Work activities were slotted into the System Work Windows through
several paths. Repetitive work such as preventive maintenance (PM) and
periodic tests (PT) were controlled through the PM/PT program. These
activities were populated directly into the schedule. in a repeating
fashion, at prescribed intervals. A minimum of 16 weeks of future
System Work Windows were kept populated with PM/PT activities.
Corrective maintenance was identified through the work request / work
order system. All new work orders were reviewed in the daily Work Order
Scoping Meeting for confirmation that the scope was appropriate and for
assignment to the appropriate system work window. These meetings were
attended by representatives from all departments. When an item reached
the seventh week before scheduled execution. it would undergo an intense
review process until execution. Emergent corrective work orders which
were written to address urgent plant deficiencies, were immediately
added to the schedule by the Work Window Manager. These items were
Enclosure 2
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'
.
! 15
reviewed for Risk and sometimes required rescheduling some work
activities.
~
The ins)ectors also reviewed a number of performance indicators such as
the num)er of planning errors, number of schedule errors, and total
reschedules. These indicators showed that the Planning and Scheduling
process was working effectively.
4 Based on review of plant documents and interviews with ex)erienced
l Planners and Schedulers the inspectors determined that t1ere were a
4
number of checks and balances in the system to ensure that proper
verifications and reviews were performed.
.
,
c. Conclusions
4
The licensee had develo)ed, documented and implemented a Planning and
Scheduling process whici was functioning reasonably well.
Monitoring and trentiing performance data indicated that the Planning and
Scheduling process had been effective.
M2 Maintenance ana Material Condition of Facilities and Equipment (62707)
M2.1 Inadeauate Emeroency Diesel Generator (EDG) Load Secuencer Testina
Resultina in ESF Actuation
a. Insoection Scope
The inspector reviewed an inadvertent ESF actuation which occurred on
May 27, 1997, during EDG load sequencer testing.
b. Observations and Findings
Unit 2 was at 100 percent power at the time of the event with the 2B
EDG tagged out of service for performance testing in accordance with
IP/0/A/3250/012B, Train B Diesel Sequencer Timer Calibration. Train B
ECCSs were also tagged out for testing, but were available. During
performance of the EDG sequencer relay testing, a partial Train B
sequencer actuation (blackout) occurred which resulted in an autostart
of the Turbine Driven (TD) Auxiliary Feedwater (AFW) pump and the
standby nuclear service water (NSW) pump, as well as the realignment of
various NSW system valves. Operators responded to these indications and
instructed the involved test personnel to discontinue the test. While
in process of verifying a sliding link position, previously opened by
the test procedure, a partial Train B safety injection (SI) actuation
occurred. Operators entered appropriate procedures to control the
event. The ECCS pumps started and ran in recirculation as designed. No
ECCS injection into the RCS occurred as a result of this event. The
train A EDG and ECCS systems remained operable throughout the event.
The unit remained at approximately 100 percent power.
Enclosure 2
. .. . - _ . - - --. - . - . ~ - - . - - - - - - . - - - - - . . - - . -
-
.
16
After the inadvertent SI actuation, the TD AFW pump auto-start signal
was still present while engineering personnel reviewed the cause of the
event. Operators locally tripped the TD AFW pump following report of a
burning smell in the pump area. Tri
non-safety AFW supply source usage. Thepping
smell the
wasTD AFW
later pump also
determined to limited
be from recently installed insulation and not a challenge to the pump.
The trip)ing of the TD AFW pump, coincident with the Train B motor
driven A W pump being technically inoperable, resulted in the unit
entering the TS ACTION requirements of 3.7.1.2. Several hours later, it
became apparent that the troubleshooting would extend beyond the TS
limits for o]eration: therefore, the operators restarted the TD AFW pump '
and exited t1e shutdown Limiting Condition for Operation (LCO). Early
on May 28 troubleshooting of the sequencer circuitry was completed and
the system was reset. At that time, all ECCS components were returned
to standby readiness.
The inspectors reviewed the root cause of the event with the licensee.
The train B EDG sequencer timer calibration procedure. IP/0/A/3250/012B,
had been revised to incorporate enhanced testing of safety-related logic
circuits pursuant to NRC Generic Letter 96-01. Specifically. the
existing test incorporated testing of the sequencer test circuitry to
ensure that the sequencer would come out of test and begin sequencing if
a valid SI or blackout signal occurred. The revised procedure had
incorporated the manipulation of a sliding link to maintain a test timer
relay de-energized, such that the portion of the circuitry under test
would be isolated. However, engineering personnel failed to identify a
circuit interaction which bypassed the function of the sliding link.
The oversight prevented adequate isolation of the test circuitry and
allowed partial sequencer logic to be satisfied when the blackout signal
was introduced for the test. Subsequent review also determined that the
partial SI occurred when test personnel were attempting to verify the
position of the sliding link. The licensee concluded that the nut
driver being used to verify the position of the sliding link contacted
both sides of the terminal. This caused a momentary SI signal which
energized the sequencer loading relays, resulting in the Train B ECCS
pump starts.
Initial corrective actions for the event included initial
troubleshooting of the cause of the actuations, verification of the
expected ECCS and other components to the inadvertent signal, and
restoring the equipment to standby status. All equipment responded as
expected. The inspectors discussed the test procedure changes and
revision processes with engineering personnel and management. Based on
the discussions. the inspectors concluded that the reviews for the test
procedure (IP/0/A/3250/0128) were inadequate, and resulted in the
procedure being inadequate to perforn the enhanced test. The inspectors
also noted that the independent review also failed to identify the
procedure inadequacy.
1
!
! Enclosure 2
l
,
- . .
. - -
_. ._ ._. _ _ . . _ _ _ _ ._ _ ___ . . _ _ _ . ___
.
i
!
!
17 !
c. Conclusions
l
Operator response to the event was adequate and compliance with TS i
.
equipment operability was maintained. The inadequate test procedure is
.
a Violation (VIO) of TS 6.8.1 and will be identified as VIO 50-370/97-
l 09-01: Inadequate Test Procedure. During closeout inspection of the LER i
,
associated with this event, the inspector will continue to review i
- operator actions associated with securing the TDAFW pump per applicable
- procedures and appropriate logging of the event.
,
M2.2 Hiah Pressure (HP) Turbine Blade Rina Locatina Pin Weld Defects
a. Insoection Scone
l
'
The inspectors reviewed the corrective actions associated with weld
problems on the subject components and the extent of condition review.
l
b. Observations and Findinas 1
On May 23, with Unit 1 at approximately 38 percent power. operators
received a computer alarm on the high pressure turbine indicating a high
differential extraction zone temperature. A non-licensed o)erator (NLO)
was dispatched and reported that a small steam leak under t1e high
pressure turbine was condensing and running on the local area
thermocouple. Engineering management determined that a repair should be
completed and after adequate manpower resources were obtained, the unit
reduced power to ap3roximately 10 percent. The leak was determined to
be on one of eight iP turbine blade ring locating pins, which are
installed to hold the stationary HP turbine blades in place. These
smooth cylindrical pins are approximately 3.5 inches in diameter and 10
inches long. They are seal welded after installation to form the HP
turbine steam boundary and were recently replaced during the Unit 1 End-
Of-Cycle (EOC) 11 outage along with the installation of new HP turbine
blade rings.
The leaking pin had a one to two inch circumferential weld crack with
some evidence of porosity. Examination of the cracked weld and weld l
historical documentation identified that the eight pin welds had j
potentially been performed at a low preheat condition (200 vs 350 1
degrees F). The main steam sto) valves were closed for the repair and l
the HP turbine was under a slig1t vacuum. The non-code repairs of the
failed area were completed at the increased preheat level and irivolved
grinding of the original seal weld and refill. Additional grinding and !
weld build up were performed on other pins as needed. After visual
inspections were performed, the unit increased power.
On June 2. unit power was reduced to ap]roximately 12 percent to repeat
the repair of a similar steam leak on t1e high pressure turbine blade
locating ring pins. The second leak was on a different locating pin
than the first failure. Subsequent discussion with the pin sur 'ier
Enclosure 2
i
-
18
,
identified that the pin material was different than what was assumed for
the original seal welding. The difference in material specifications
resulted in the most ideal weld material not being chosen for the
application. An additional contributor to the problem was that a visual !
inspection was the only NDE performed on the work. Corrective actions :
for the repetitive problem included: !
.
Use of more suitable weld roa material (more ductile)
.
Review of the weld area to reduce the difficulty in making good
quality welds j
. Performance of a more thorough non-destructive examination (i .e. . l
magnetic particle testing and dye penetrant testing)
. Review of current non-code repair NDE inspection criteria to
determine their adequacy to identify these type of problems
The licensee's corrective actions were documented in Problem
Identification Process (PIP) reports 1-M97-2160 and 1-M97-2241. Final
repairs for the pin seal were completed and more rigorous NDE
evaluations were accomplished. An additional measure to assure proper l
weld material applications occur on Unit 2 was included in the PIP
corrective actions.
c. Conclusions
Based on the above. the inspectors concluded that the licensee's final
repairs to the HP turbine blade ring locating pins were adequate. The
inspectors also concluded that the repetitive HP turbine steam leaks
were an example of incomplete root cause reviews on secondary
components.
M2.3 Vendor Control
a. Inspection Scope
The inspectors investigated activities that resulted in the inadvertent
isolation of instrument air to the Unit 2 moisture separator reheater
drain valve controllers causing an unplanned reactor thermal power
increase and a reduction in main feedwater suction supply pressure. The
resulting valve realignments also caused a reduction in electrical power
output.
b. Observations and Findinas
On May 22, the control room operators. responding to various indications
and alarms of moisture separator reheater valve movement and decreasing
main feedwater suction pressure, started a standby hotwell pump to
maintain adequate main feedwater pump suction pressure and dispatched
Enclosure 2
._ -. --- - . . . . _- -
-
.
l
l
,
19
operators to the turbine building to identify the cause. The dispatched l
operators determined that the moisture separator reheater drain valves
had isolated due to a loss of their instrument air sup)ly. The
operators re-established instrument air and returned tie valves to the
normal operatin Main feedwater suction pressure, reactor
thermal power.andg positions.
electrical output were returned to normal. Reactor
thermal Jower momentarily increased to approximately 100.7 percent
during tais transient.
Further investigation identified that vendor personnel had inadvertently
'
isolated instrument air while performing routine turbine building i
cleaning activities. The vendor had been instructed to use station air
instead of instrument air when performing cleaning activities in the
turbine building. The inspectors discussed the event with the licensee ;
and reviewed station documentation and determined that the vendor crew !
! had not received adequate instructions to ensure that the work l
! activities were completed without technical errors. Although the use of '
instrument air was not authorized for the activity, the vendor did not
l receive sufficient instruction on the potential consequences of
repositioning operations controlled equipment. The licensee has
established plans to evaluate contract training requirements emphasizing
potential operational transients due to manipulating plant equipment.
Conclusions
l
l The inspectors concluded that the isolation of instrument air, which is
nonsafety-related at McGuire, was an example of ineffective vendor
oversight. The vendor Jersonnel did not receive sufficient guidance
prior to the start of t1e activity. As a result, the contract workers
initiated an operational transient by manipulating Operations controlled
equipment. This is considered a weakness in the area of vendor control.
M3 Maintenance Procedures and Documentation (62707)
l
l M3.1 Steam Generator Replacement Pro.iect (SGRP) Post-Installation Review and
Control System Doerability Verification
a. Inspection Scoce
l
The inspectors evaluated the results of the licensee's performance
testing of the Unit 1 operating characteristics and control system
,
response following replacement of the Unit 1 SGs. The inspectors
i
reviewed selected documentation to verify that Jost modification
activities such as drawing updates, procedure clanges, resolution of
outstanding issues, and training had been revised to reflect the
configuration changes associated with SG replacement.
'
b. Observations and Findinas
.
Post-Installation Insoections
- Enclosure 2
i
l
I
l
l
20
Inspections of the leak tightness of the system was performed at full
temperature and pressure in accordance with NRC approved ASME Code Case
N-416-1. SG secondary side hydrostatic testing was performed by the
manufacturer. The inspectors and the licensee conducted visual
inspections of the reactor coolant system and noted no external leakage.
Steady State and Transient Testina
l The licensee performed testing to confirm the SG design and to establish
l baseline measurements. The testing was conducted during steady state
l
'
and transient conditions. The performance tests were performed in Mode
1 (POWER OPERATION) with Unit 1 at approximately 38 percent and 78
percent power. Calibration and testing of instrumentation affected by
SG replacement was performed prior to testing.
i The performance testing was necessary to ensure proper operation of
l these systems:
l * Reactor Rod Control
. Steam Generator Level Control
. Main Feedwater Pump Speed Control
'
- Pressurizer Level Control
- Pressurizer Pressure Control
. Load Rejection Control (Tavg-Tref mode)
!
'
Testing included introduction of false level signals to verify main
feedwater control system performance and a 10 percent load reject test
was initiated to verify proper control system overall response. A
dedicated R0 and SRO were assigned to monitor the transient testing.
Prior to commencement of the transient testina, the operators were
instructed to intervene and abort the testing, if necessary, to preclude
l a unit trip or equipment damage.
The load drop change rate was set at 2400 MWe/ min or 200 percent rated
output / min. The total load reduction was 10 percent of rated electric
power output. All equipment operated as expected. No manual actions
were necessary to stabilize the station during the load rejection
testing. Steam Generator levels stabilized at the lower power level.
'
No instability with automatic control systems was experienced nor were
l there sustained or diverging plant parameters identified. Neither
l primary or secondary relief or safety valves lifted. No reactor trip,
!
turbine trip or Safety Injection occurred as a result of the load
reject
l
C. ConClU5 Wn
! The inspectors concluded that restart testing following the Steam
Generator Replacement Outage was adequately planned and executed to
verify steam generator design and ensure reliable operation of the Unit
1 control systems.
Enclosure 2
l
l
l
. _ . _ . --. . - . - -- - - - -. _. .. -- - .
i
l
l
i
l
21
M4 Maintenance Staff Knowledge and Performance
M4.1 Unit 2 Steam Generator Leakaae Inspections and Reoair
a. Insoection Scooe
The inspectors reviewed the licensee's actions regarding the forced
outage inspection of the 2A SG for primary to secondary leakage. Unit 2
was shutdown on June 13, 1997, with an indicated SG 1eakrate on the 2A
SG of approximately 60 to 70 GPD.
I
b. Observations and Findinas !
On June 19. with the Unit in MODE 5 (Cold Shutdown), the licensee I
performed a secondary pressurization test on the 2A SG to approximately l
650 psig using a condensate booster pump. The test pressure was held '
approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. Leakage results identified an approximate 10
drop per minute leak at the 7-60 tube location. No other indications
were identified. The licensee reviewed Unit 2 cycle 10 SG inspection
data and identified that initial bobbin coil inspections revealed a 2.68
volt non-quantifiable indication. This value did not meet repair
criteria: however, the indication received expanded inspection via
motorized rotating pancake coil (MRPC). The results were reviewed by
SG specialists and no defect was found. However, more in-depth review i
identified that the antici)ated tolerance range of the MPRC measurement
was not fully achieved. T11s problem may have resulted in the no defect
decision being based on incomplete data. Current testing confirmed the
100 percent throughwall leak just above the second support plate on the
cold leg side. All indications supported the conclusion that the crack
was axial . An in-situ pressure test was performed on the 7-60 tube
which concluded that the tube met structural acceptance criteria.
Specific repairs to the 7-60 tube included plugging and inspection of
six adjacent tubes with bobbin coil. No other problems were identified
in this area relating to the leaking tube.
On June 20. a conference call was held between NRC and the licensee to
discuss the details of the tube degradation and the proposed scope of
additional inspections. Based on the indicated root cause of the 7-60
leak, the licensee proposed additional inspections of all positive
bobbin indications which were considered to have no defect based on
additional MRPC inspections. This initial scope included 377 potential
tubes to be re-inspected which were distributed in all four SGs. This
total number was reduced to approximately 192 tubes based on review of
outage data. All of the subsequent MPRC inspections were performed over
the full free span to avoid any potential alignment concerns. These
inspections resulted in the additional plugging of 18 SG A tubes, 3 SG B
tubes. 3 SG C tubes and 0 SG D tubes. The additional tube plugging
could not be attributed to errors in the )revious outage SG inspections
j
.
due to the additional inservice time on t1e Unit 2 SGs. Licensee
,
Enclosure 2
l
-
,
4
.
l
l
I
22 1
reviews did not identify any tube degradation which exhibited abnormal
defect growth characteristics.
c. Conclusions
Based on the licensee's inspection 3rocess, scope, and completed
repairs, the inspectors concluded tlat the corrective maintenance was
adequately performed. However, the inspectors also concluded that
previous followup to a SG indication in the area of the identified leak
led to a missed opportunity to identify and prevent this event. At the
end of the inspection period, the licensee continued to review the root
cause of the SG inspection inconsistencies. Once identified, actions to
correct the problem and also ensure that other oversights did not occur i
were good. This problem will be identified as Unresolved Item (URI) 50-
- 370/97-09-02
- Steam Generator Inspection Process, pending further review
- of the root cause of the SG inspection process.
i M8 Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) Violation 50-369. 370/96-06-03: Failure to promptly I
incorporate vender recommended torquing guidelines for the Reactor Trip
Breaker (RTB) secondary contact assembly block prior to performing j
maintenance in September 1994. A new Westinghouse Maintenance Program
- ! Manual (MPM) for Reactor Trip Circuit Breakers was received in the
'
General Office (GO) by the Operating Experience Assessment (CEA) group
on February 14. 1994. OEA issued a General Office (GO) Problem
Investigation Process (PIP) report to assign actions for processing the
updated manual into the McGuire Document Control Syrtem. Due to lack of
accountability, assignment of low priority, and inadequate tracking the
Manual was not finally processed into the McGuire Document Control
Program until January 23. 1995. The new reactor trip breaker (RTB) .
Manual contained torquing values for the secondary contact block
'
assembly which were not included in the previous manual. In September
1994. a broken secondary contact block assembly was found on 1RTB DS-416
Reactor Trip Breaker during a routine outage PM and was replaced using
the then current procedure IP/0/A/2001/006. This procedure was based on
the older MPM and did not contain torquing values for the contact block
mounting bolts. Subsequently, on July 1.1996 during an inspection of
1RTB DS-416 Reactor Trip Breaker, the secondary contact block assembly
that had been re) laced two years earlier was found broken. Overtorquing
of the mounting Solts was a probable contributor to the failure.
In response to the violation dated Seatember 20, 1996, the licensee had
implemented a new MPM for RTBs into t1e Document Control System on
January 23, 1995. New procedure SI/0/A/2410/001." Westinghouse DS-416
Air Circuit Breakers Inspection and Maintenance." replaced the old
procedure on October 12. 1995. Additionally, training was provided to
site engineers and a Champion Tracking Report initiated to aide OEA in
tracking site assigned tasks.
Enclosure 2
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23
J The insp, ' tor reviewed the new 3rocedure and verified torque values for
mounting t.he secondary contact ] lock were included. Also, the training
lesson for engineering was reviewed and found to be acceptable and the
development of tne Champion Tracking Rep;rt was verified.
i
M8.2 (Closed) Violation 50-369. 370/96-04-01: Failure to perform performance
-
test PT/2/A/4350/03A." Electrical Power Source Alignment Verification."
prior to entering Mode 6. In the response to the violation dated July
. 31, 1996, the licensee indicated that other procedures had performed the
necessary alignments. The licensee committed to perform a procedure ,
review to determine if procedural changes were necessary. The I
i inspectors reviewed the documentation of these reviews. The licensee i
determined that no changes to the scheduling process or start up
checklists were necessary. However. Operations Management Procedure OMP
- 5-10." Routine Task List." was revised to require that any PT item on the
list not completed on schedule must be reported to the Operations
- Support Manager and entered into the Technical Specification Action Item
Log for tracking and close out. Licensee actions were considered 4
- acceptable.
i M8.3 (Closed) Violation 50-369. 370/96-07-01: Failure to demonstrate the
4 operability of the 1A emergency diesel generator (EDG) after EDG 1B was
declared inoperable. In response to the violation dated October 24,
'
1996, the licensee identified the cause as the operator's dependence on
memory rather than to adequately research the Technical Specification
requirement. Additionally, the procedure PT/1/A/4350/25." Essential
Auxiliary Power System Power Source Verification." did not clearly
s)ecify that th redundant train must be run. The inspectors verified
tlat PT/1/A/4360/25. Revision 10. clearly stated that if a EDG is
inoperable for reasons other than planned maintenance or testing the
other EDG will be run. The inspectors also determined that Management
Expectations that the Technical Specification be physically reviewed
versus relying on memory was promulgated in a letter to % 1or Reactor
Operators dated October 21. 1996.
III. Enoineerina
El Conduct of Engineering
El.1 Non-conservative TS for Inocerable Main Steam Safety Valves (MSSVs)
a. Insoection Scooe (37551)
The inspector reviewed the identification process of non-conservative TS
ACTION statements associated with the MSSVs.
Enclosure 2
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24
b. Observations and Findings
On March 20 and May 20. 1997, the licensee identified through 10 CFR
50.72 re) orts that TS Table 3.7-1. Maximum Allowable Power Range Neutron
Flux Hig1 Setpoint With Inoperable Steam Line Safety Valves During Four
Loop Operation specified non-conservative values. Specifically, when
one or more MSSVs may be inoperable, the TS identified Jower range
neutron flux high setpoints may be non-conservative. T1e purpose of the
setpoints are to assure that secondary system pressure will be limited
to within 110 percent of its design pressure during the most severe
anticipated system operational transient.
The inspector discussed with the licensee their historical response to
the issue. On January 20. 1994 Westinghouse issued a Nuclear Advisory
Letter informing utilities that the algorithm used to initially
calculate the power range neutron flux high setpoint for the MSSVs was
not correct. The basis for the advisory letter conclusions were modeled
from uniformly sized MSSVs. McGuire's MSSVs were not uniform, therefore
a plant specific study was necessary to determine if McGuire's TS was
also non-conservative. In early 1994, the licensee initiated a study
and issued a TS interpretation regarding the potential problem, which
provided further guidance to operators for operation with one or more
inoperable MSSV. In December 1995, the plant specific analysis was
completed, and concluded that the TS values for the inoperability of one
and two MSSVs allowed for reactor o)eration at non-conservative power
levels. During this time. McGuire las never operated in a condition
requiring plant operation to be restricted due to inoperable MSSVs.
The licensee chose to pursue a TS change via their improved TS project
plan to reflect the higher reactor power limits: however, during final
review for the submittal in early 1997, engineering questioned the bases
for the existing )ower level restrictions. It was subsequently
determined that t1e restrictions for operation with one or more
inoperable MSSVs was non-conservative. Once identified, the licensee
made the appropriate 10 CFR 50.72 reports, gave additional guidance to
operations, and submitted an LER on the subject. In addition, the
licensee initiated the TS revision process to revise TS 3.7.1. The
licensee stated that the change would be conducted outside of their TS
upgrade project,
c. Conclusions
The inspectors concluded that once the entire scope of the problem was
identified the licensee initiated appropriate actions to address the
issue. However, the overall resolution of the potential for non-
conservative TS ACTION requirements was not completed in a timely
manner. Although adequate administrative controls were in place and no
actual MSSV inoperability occurred during the issue resolution period,
the chosen TS Amendment process led to delays in final resolution and
identification of all pertinent issues. The inspectors will review
Enclosure 2 I
4
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.
i
l 25
other technical adequacies of the licensee's corrective actions during
close-out of associated LER 369/97-04.
E2 Engineering Support of Facilities and Equipment
- E2.1 Desian Modification of Auxiliary Feedwater (AFW) System Suction Suoolv
j a. Insoection Scooe (37551.40500)
1
The inspector reviewed the implementation of minor modifications to the
nonsafety-related suction supply of the AFW system. The inspector
reviewed the 10 CFR 50.59 evaluation, related FSAR and Design Bases
Document (DBD) sections, and witnessed portions of the field work to
4
modify the system. This is an update of IFI 50-369.370/97-08-04,
4
Potential Airbinding of AFW Pumps.
- The AFW air entrainment mechanisms include, but are not limited to.
j vortexing in the AFW condensate storage tank (AFWCST) and emptying of
the upper surge tanks (UST) with the AFW system in a recirculation mode.
In 1996, operators identified the AFW pump air binding issues as an
operator work around and the licensee initiated engineering analysis to
investigate the issue. NRC Inspection Report 97-08 documents the
>
'
issues, status of the hydraulic studies, and the licensee's compensatory
measures.
b. Dbservations and Findinas
During the inspection period, the licensee implemented two design
modifications to the AFW suction sup)1y in order to reduce the
likelihood of air entrainment into t1e AFW suction piping. The first
modification involved the conversion of an existing filtered water tank
(42.500 gallon capacity) into an additional AFWCST. This tank, AFWCST
'B', is located next to the AFWCST 'A' on the service building roof. 1
Combined, the two tanks have a capacity of 85,000 gallons of condensate
quality water and doubles the original AFWCST capacity available to
either Unit 1 or Unit 2. The second modification involved vortex
suppressors that were installed in the suction nozzles of each AFWCST.
These modifications were completed on June 12. 1997.
Before completion of the modification. the licensee determined by
engineering analysis that a vortex in AFWCST 'A' did not affect past
operability of the AFW pumps. The issue involving the air slug from UST
interaction with nuclear service water and AFW pump recirculation
continued to be indeterminate, pending conclusion of other engineering
analysis. Compensatory measures remained in effect until plant !
orocedures affected by the design modifications could be updated and the
UST air slug issue dispositioned.
The inspector confirmed through daily control room visits that the
compensatory measures remained in-effect before. during, and after the
Enclosure 2
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modi fications. During implementation of the modifications. Unit 1 AFW
pumps were aligned to take suction from the Unit 1 UST. Unit 2
continued to be aligned to the Unit 2 UST.
c. Conclusion
The inspector concluded that the addition of another AFWCST was a timely
and positive action to extend AFW inventory and improve pump suction ,
reliability. Installation of vortex suppressors was a conservative ;
management decision, given the licensee's conclusions of their
engineering analysis. The associated field work was considered
adequate. However. IFI 369.370/97-08-04 remains open pending the
licensee's completion of engineering analysis and subsequent NRC review.
I
E2.2 Outaae Modifications (37550) j
a. Insoection Scooe
The inspector reviewed Nuclear Station Modifications (NSMs) implemented
during the current Unit 1 outage. The modification review included l
verification that design control requirements of Regulatory Guide 1.64 l
and ANSI N45.2.11-1974 Quality Assurance Requirements for the Design of '
Nuclear Power Plants, and licensee procedures were implemented. 1
Elements of the design process reviewed included post modification i
testing, procurement. procedure revision. 50.59 safety evaluation and !
screening, and field verification of plant hardware changes, as !
applicable. The following NSMs and minor modifications were reviewed:
)
. MG 12220/P2 Reroute Instrumentation and Control (I&C) Tubing
for AFW. Main Steam (MS), and MFW Systems j
. MG 12419 Replace Diesel Generator (DG) Train A Cooling I
(KD) Pumps
. MG 12467/P1 Replace Bussman FN0 Fuses
. MG 12473 Relocate DG Lube Oil (LO) Pressure Switches
. MGMM 8289 Replace Valves 1 NV-457 and 458 with Gate Valves
. MGMM 8676 Replace Valve INC-45
. MGMM 9101 Qualify Over-thrust of 1NI-147 l
. MGMM 9114 DG Engine Drive L0 pump Dowel Rcplacement
. MGMM 9255 Actuator Replacement on 1ND-19
l
l . MGMM 9269 Qualify As-left Thrust for 1NM-06 l
l
l Enclosure 2
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27
b. Observations and Findinas
,
Post modification testing performed was adequate to verify equipment and
I
system function folloving the modification. In general. 50.59 safety
evaluations were good, in that, responses to screening or evaluation
questions were detailed and adequately justified the conclusions.
t Procurement documentation demonstrated that the appropriate quality
l level material was used for installed equipment and materials.
c. Conclusion
The modifications completed during the Unit 1 outage demonstrated '
appropriate control of the design control process at McGuire.
, Performance was good for modifications, procedures. 50.59 evaluations
i
and screening.
E2.3 Enaineerina Sucoort to Doerations (37550)
'
a. Insoection Scone
'
The inspector reviewed the use and validation of Test Acceptance l
Criteria (TAC) which were developed in conjunction with the design base '
documents. Applicable regulatory requirements included 10 CFR 50
Appendix B.
l
l b. Observations and Findinas
l The TAC sheets were developed in conjunction with the Station Design
Base Documents and described the design function, operability
requirements and verification test criteria for safety-related
equipment. The TACs included compensatory actions to maintain system I
operability if a component was out of service. The station Modification !
Manual indicated that the TACs were to be used to document test
acceptance criteria for station modifications (NSMs) and equipment
performance tests. In practice. Operations used the TACs for verifying
, operability and establishing compensatory measures for systems during
on-line GL 89-10 testing of safety-related valves.
In 1996, the Operations and Engineering staffs noted that the TAC
compensatory measures had not been validated with 10 CFR 50.59 safety
evaluations to assure the alternate system configurations did not
introduce an unreviewed safety question. A February 5, 1997, memorandum
from the Station Vice President to the Station established parameters
for use of the TAC compensatory measures. The licensee recently 1
completed an upgrade of the TACs for Inservice Test Program (IST) valves !
l which standardized the format and validated compensatory measures with i
10 CFR 50.59 evaluations. Nuclear Station Directive NSD-203.
Operability Policy, was revised on March 26, 1997, to provide guidance
on the use of TAC sheets for IST valves.
+
'
Enclosure 2
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c. Conclusion
Engineering's upgrade and validation of DBD TAC sheets for IST valves
was an example of good engineering support to operations. The TACs
provide a good design reference for Operations to maintain system
operability when safety-related valves are out of service for testing.
E3 Engineering Procedures and Documentation
E3.1 Unit 1 K-45 Fuel Assembly Reconstitution
a. Insoection Scope (71707)
During the inspection period, reactor engineering personnel performed
fuel reconstitution of the K-45 assembly in the Unit 1 spent fuel pool.
The inspector performed field observations of the reconstitution and
discussed the activities with the cognizant engineer. The inspector
also reviewed the 10 CFR 50.59 safety evaluation for use of a crud
scrubbing device to remove crud from fuel rods and the use of single rod
diameter / oxide measurement equipment. Specifically, the inspector
reviewed calculation MCC 1553.26-00-211 which was the safety analysis
for mechanical, criticality, shielding, and thermal concerns associated
with use of the equipment.
b. Observations
Between June 5 - 9. eight experimental fuel rods were removed from the
K-45 lead test assembly for Post Irradiation Examination (PIE). The
eight rods are part of an advanced zircaloy cladding program. These
rods contained three different types of cladding materials, and the
assembly had a high burnup (i.e., over 40 GWd/mtu) with a cooling time
of approximately 18 months.
The inspector observed fuel rod removal and reconstitution of the
assembly. Stainless steel rods were used as substitutes in the assembly
for the removed rods. The fuel rods were loaded into a specially
designed basket and will be inserted in the R52 cask canister for
shipment. All eight rods will be shipped offsite for hot-cell testing
and destructive examination.
The licensee, with support from Framatome, used underwater surveillance
cameras to read rod serial numbers and accomplish the reconstitution.
Pool water clarity was good and serial numbers were clear and readable
on video monitors.
PIE work was also performed in the Unit 1 spent fuel 2001 to provide
baseline data prior to offsite testing. Using a scru)bing device. crud
was removed from the cladding of each of the eight rods. This was done
to improve eddy current testing to gauge oxidation layer thickness and
Enclosure 2
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!
29
clad wall thinning. The inspector determined that the licensee's safety !
analysis for use of the equipment was adequate.
c. Conclusion ,
I
The inspector concluded that the K-45 fuel reconstitution work
activities were well controlled and that good communication existed i
among the crew members. Reactor engineering personnel were l
knowledgeable and the 10 CFR 50.59 evaluation was adequate. Appropriate l
reactor engineering oversight was l
protection coverage was provided. present and adequate radiation l
E4 Engineering Staff Knowledge and Performance
E4.1 Vital Battery and Charoer Reolacement Modification
a. Insoection Scooe
The inspectors reviewed minor modification packages developed and
implemented for the replacement of the Bus A EVCA battery and associated
charger. The replacement was necessary to improve reliability of the
125VDC Vital Power System. The currently installed AT&T lineage 2000
series round cell batteries at McGuire have been degrading at a faster
rate than was initially antici]ated. Due to this unanticipated battery
degradation the licensee esta)lished prudent replacement schedules for
each of the four batteries and their associated chargers. The round
cell batteries from EVCA were replaced with conventional rectangular
cell GNB Type NCN stationary batteries. Prior to implementation of the
battery replacement modification, an increase in TS allowed battery
outage time to 30 days was approved by the NRC.
b. Observations and Findinos
The licensee completed replacement of vital battery EVCA and its
associated charger during this period. Completion of the remaining
three battery / charger reolacements was scheduled prior to December 1997.
The EVCA battery / charger replacement was conducted under Nuclear Station
Modification NSM-52483. Vital Battery EVCA Replacement and NSM-52488.
Vital Charger EVCA Replacement. The associated connectors and cabling
was replaced under separate modification packages.
Prior to the commencement of the maintenance activities, the inspectors
reviewed the modification packages to verify that the licensee's )lans
were in accordance with TS requirements and the McGuire UFSAR. T1e
inspectors confirmed that e temporary battery was installed under Minor
Modification MGMM-8847 and Work Order No. 96089566 on the affected bus
during the replacement. The temporary battery bank was composed of low
specific gravity AT&T round cells. The affected bus remained energized
by spare charger EVCS. backed by the temporary battery. Although the
temporary battery was sized to supply the same duty cycle as the normal
Enclosure 2
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30
batteries and configured to the full capacity spare charger, the
licensee did not consider the bus fully operable since the temporary
battery storage racks were not positioned in a seismically qualified
location.
-
Prior to being connected to the bus. the temporary batte y received a
full complement of surveillance measurements, including a service test.
Tem)orary ventilation equipment was necessary to prevent unacceptable ;
comaustible gas accumulation during temporary battery operation. The i
replacement EVCA battery was service tested. The factory acceptance I
test was used to satisfy TS 4.8.2.1.2e rather than performing an onsite
performance discharge test. Breaker and fuse upgrades were also i
conducted to ensure proper breaker coordination. ;
Contingency plans were also developed and implemented to provide
adequate fire, security, and radiological protection during breach of
the vital security battery room and RCA. Radiological surveys were
performed to ensure that the area could be re-classified as a non-
radiologically controlled area. Continuous security coverage was
established while vital area doors and fire barriers were disabled to !
allow equipment removal and replacement.
c. Conclusion
The inspectors concluded that the licensee developed adequate procedures l
and controls for replacement of the EVCA battery / charger. Modification
packages for installation of the temporary battery were adequate.
Contingencies were established in the event of a loss of the temporary
battery or the spare charger while in the degraded condition. Although
the licensee delayed return of the battery to service to minimize
potential plant impact during Unit 2 draindown and midloop operations.
the replacement activities were completed within the authorized TS
allowed outage times.
IV. Plant Support
R1 F.adiological Protection and Chemistry Controis
R1.1 Tour of Radioloaical Areas
a. Insoection Scooe (83750)
The inspectors discussed with licensee representatives the planning and
preparations underway for a site project to remove selected pieces of
steam generator tubes and tube sheet components from two removed steam
generators (SGs) B and D. This project was contracted through Duke
Engineering Services (DES) and Argonne National Laboratory in su) port of
a contract between the Nuclear Regulatory Commission (NRC) and t1e
Department of Energy. Licensee preplanning activities for the evolution
Enclosure 2 ,
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31
was reviewed to determine the adequacy of licensee planning efforts in
the area of radiation protection. including: dose estimates, as low as
reasonably achievable (ALARA) planning and implementation, and
contamination control practices.
l b. Observations and Findinas
The inspectors discussed specific work preparations to assist qualified
radiation protection technicians in planning for survey coverage.
l radioactive material control and storage, contamination controls, and
< exposure controls for SG tube and tube sheet removal. The inspectors
'
determined the licensee's plans were to sequence work activities in
order to maximize the use of shielding while maintaining exposures
ALARA. At the time of the inspection, the inspectors observed
i preparations being made to construct tent containments with High
Efficiency Particulate Air (HEPA) filters around the SGs to be worked.
The use of wireless communications, teledosimetry, cameras and other
work practices being developed were also discussed as methods the
licensee was planning to use to maintain exposures ALARA. Specific work
procedures and radiation work permits (RWPs) to support the work
evolution had not been finalized at the time of the inspection.
c. Conclusion
.
At the time of the inspection, the inspectors determined that the
! licensee was in the process of developing procedures and work practices
( to maintain effective contamination controls and to maintain exposures
l ALARA during work evolutions on two removed SGs.
P1 Conduct of EP Activities
Pl.1 Emeraency Preoaredness Drill
a. Insoection Scooe
On April 16 the licensee conducted a station emergency preparedness
practice exercise. The practice exercise scenario involved a dropped ,
fuel assembly in the spent fuel transfer canal area during refueling i
followed by a 30 gpm reactor coolant leak from the available train of
'
residual heat removal. The scenario progressed to a General Area
Emergency, exercising major components of the McGuire Emergency Plan.
l b. Observation and Findinas
The inspectors evaluated the practice drill critique. The inspectors
noted a number of deficiencies identified concerning Emergency Response
'
Organization (ERO) performance throughout the drill. Concerns were also
- identified with station security processes and equipment during the Site
! Assembly portion of the drill. Based on the findings identified in the
t
critique on procedural use and adherence. the inspectors determined that
'
Enclosure 2
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additional emphasis on management expectations was necessary to improve 1
, ERO performance. The inspectors also noted that increased management '
involvement in the critique process was necessary to ensure that
, corrective measures identified during the critique were appropriately )
e'aluated and resolved. The licensee recognized that adjustments were
necessary and have formulated working groups to correct the licensee-
, identified concerns.
.
Conclusion
The inspectors concluded that the practice drill scenario was adequate
, to effectively test the Emergency Response Organization (ERO)
i participants. The ERO performance was adequate: however, additional
i
management emphasis on ERO expectations was necessary.
-
i
'
F3 Fire Protection Procedures and Documentation !
l
F3.1 Adeauacy of 3 Year Fire Protection System Flow and Pressure Test (71750) I
1
- a. Insoection Scooe
The inspector reviewed the licensee's implementation of commitments to l
,
perform 3 year fire protection system flow testing. I
i b. Observations and Findinas
The Selected Licensee Commitments (SLC) Manual. Section 16.9. requires
.
that the fire suppression water system be operable at all times. The i
- system is demonstrated to be operable through a series of tests listed !
4
in the SLC Manual. Section 16.9-1. The subject test is a system flow
test which was last performed in July 1995. The inspectors discussed
with licensee fire protection personnel their performance of the 3 year i
fire protection system flow and pressure test, and whether any
performance degradation had occurred from previous tests. No '
significant degradation was noted: however, trending of the data was
minimal. In addition, the acceptance criteria for the test data was not
well established. The inspector raised an additional concern regarding
the scope of fire protection piping actually tested. Specifically, the
McGuire station was not performing this type of testing on the interior
loop piping within, for example, the auxiliary building. The licensee
was performing this type of testing on overall yard loop piping:
however, with this ap3 roach, interior loop piping degradation may not be
apparent. In 1995. tie licensee's Catawba facility identified problems
in this area (see PIP 0-C95-1908) via the performance of more specific
flow testing: however. the McGuire facility testing had not incorporated
similar testing.
Based on the inspectors concerns, the licensee initiated PIP 0-M97-1849
to evaluate what corrective action may be required. By the end of the
inspection period the licensee was preparing a special test which would
Enclosure 2
_
.
.
33
incorporate additional key sections of the interior loop aiping to
provide baseline information of system degradation. It s1ould be noted l
that the McGuire fire protection system, historically, has not exhibited i
evidence of significant corrosion in the auxiliary or reactor buildings. l
Based on the reviews, this issue will be identified as an Inspector ;
Followup Item (IFI) 50-369.370/97-09-03: 3-year Fire System Testing. 1
pending completion of the additional testing being developed by the ;
licensee. '
c. Conclusions
1
The inspectors concluded that the development of additional testing for
the interior loop piping was prudent and could provide additional
indications of system degradation. The inspectors also concluded that i
the administrative processes for long-term monitoring of the fire I
protection system for degradation could be improved.
V. Management Meetinas .
l
X1 Exit Meeting Summary
The inspectors ] resented the inspection results to members of licensee ,
management at t1e conclusion of the inspection on June 26, 1997. The licensee l
acknowledged the findings presented. No proprietary information was
identi fied. j
l
X2 Management / Organizational Changes l
On June 18, 1997, the proposed Duke Power and PanEnergy merger became
official . Additionally, the following McGuire management changes were
announced:
- A. Bhatnagar to become Operations Superintendent at McGuire, effective
July 1. 1997
- L. Loucks to assume the position of McGuire Chemistry Manager, effective
in November 1997.
Enclosure 2
.
l
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34
i
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Barron B., Vice President. McGuire Nuclear Station
Boyle J., Civil / Electrical Systems Engineering
Byrum. W. Manager. Radiation Protection
Cline. T., Senior Technical Specialist. General Office Support
Cross. R. Regulatory Compliance
Davison. Valve Supervisor
Dolan. B., Manager. Safety Assurance
Geddie. E., Manager. McGuire Nuclear Station
Harley, M. , Engineering Supervisor
Herran, P. , Manager. Engineering
Jones. R., Superintendent. Operations
Michael. R., Chemistry Manager
Jamil. D., Superintendent. Maintenance
Cash. M.. Manager Regulatory Compliance
Thomas. K. , Superintendent. Work Control
Travis. B. , Manager. Mechanical / Nuclear Systems Engineering
Tuckman. M., Senior Vice President. Nuclear Duke Power Company
NRC
S. Shaeffer. Senior Resident Inspector. McGuire '
M. Franovich. Resident Inspector. McGuire {
M Sykes Resident Inspector. McGuire
R. Moore. Regional Inspector
H. Whitener. Regional Inspector
D. Forbes. Regional Inspector
4
i
"
Enclosure 2
_ _ _ . _ . ._ ._ _ _ _ _ - . _ _ _ _- _ . _ _ . _ _ _ _ _ _ . _
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35
INSPECTION PROCEDURES USED
IP 71707: Conduct of Operations
IP 71750: Plant Support
IP 62700: Maintenance Program Implementation !
IP 62707: Maintenance Observations
IP 61726: Surveillance Observations i
IP 37551: Onsite Engineering '
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IF 40500: Self-Assessment
IP 37550: Engineering
l
ITEMS OPENED. CLOSED, AND DISCUSSED
OPENED
VIO 50-370/97-09-01 Inadequate Test Procedure (Section M2.1)
i
URI 50-370/97-09-02 SG Inspection Process (Section M4.1)
IFI 50-369.370/97-09-03 3-year Fire System Testing (Section F3.1)
CLOSED
VIO 50-369.370/96-06-03 Failure to Incorporate Vendor RTB Information
Into Plant Procedures (Section M8.1)
VIO 50-369.370/96-04-01 Surveillance Not Performed Due to Inadequate
Procedure Guidance (Section M8.2)
VIO 50-369.370/96-07-01 Failure to Perform Surveillance on Emergency
Diesel Generator (Section M8.3)
DISCUSSED
IFI 50-369.370/97-08-04 Potential Airbinding of AFW Pumps (Section E2.1)
LIST OF ACRONYMS USED
AFW -
AFWCST - Auxiliary Feedwater Condensate Storage Tanks
ECCS - Emergency Core Cooling System
EDG -
GL -
Generic Letter
HP -
High Pressure
IFI -
Inspector Followup Item
IRT -
Independent Review Team
Enclosure 2
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1
.
l
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36
LER -
Licensee Event Report
MOV -
Motor-Operated Valve
MPM -
Motor Power Monitor ;
MRPC - Motorized Rotating Pancake Coil J
MSR -
Moisture Separator Reheater
MSSV - Main Steam Safety Valve
NCV -
Non-Cited Violation
NLO -
Non-Licensed Operator
NRC -
Nuclear Regulatory Commission
NRR -
NRC Office of Nuclear Reactor Regulation
PIP -
Problem Investigation Process
PMT -
Post Maintenance Test (Retest)
PORV - Power Operated Relief Valve
PRA -
PT -
Performance Test !
RCS -
RHR -
R0 -
Reactor Operator !
RV -
Reactor Vessel !
RWST - Refueling Water Storage Tank
SG -
SGRP - Steam Generator Replacement Project
SI -
Safety Injection
SRO -
Senior Reactor Operator
TI -
Tem)orary Instruction
TS -
Tec1nical Specifications
TSAIL - Technical Specification Action Item List
UFSAR - Updated Final Safety Analysis Report
URI -
Unresolved Item
UST -
Upper Surge Tanks I
VIO -
Violation
WO -
Work Order
i
I
\
Enclosure 2
_