ML20248E613
| ML20248E613 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 05/26/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20248E588 | List: |
| References | |
| 50-245-98-206, 50-336-98-206, 50-423-98-206, NUDOCS 9806030382 | |
| Download: ML20248E613 (117) | |
See also: IR 05000245/1998206
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U.S. NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
SPECIA6 PROJECTS OFFICE
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I Docket Nos.: 50-245 50-336 50-423 I
Report Nos.: 98-206 98-206 98-206 I
License Nos.: DPR-21 DPR-65 NPF-49
Licensee: Northeast Nuclear Energy Company i
P. O. Box 128
Waterford, CT 06385
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l Facility: Millstone Nuclear Power Station, Units 1,2, and 3
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f Inspection at: Waterford, CT
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Dates: January 1,1998 - February 28,1998
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inspectors: T. A. Eastick, Senior Resident inspector Unit 1
D. P. Beaulieu, Senior Resident inspector, Unit 2
A. C. Cerne, Senior Resident inspector, Unit 3
- P. Cataldo, Resident inspector, Unit 1
S. R. Jones, Resident inspector, Unit 2
B. E. Korona, Resident inspector, Unit 3
J. T. Furia, Senior Radiation Specialist, RI
l G. C. Smith, Sr. Physical Security Specialist, RI
l L. S. Cheung, Sr. Reactor Engineer, RI
! J. E. Carrasco, Engineering inspector, RI
! T. J. Kenny, Senior Operations Engineer, RI
l J. M. D' Antonio, Operations Engineer, RI i
! J. W. Andersen, Project Engineer, NRR
L. L. Scholl, Reactor Engineer, RI
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J. Higgins, Contractor, Brookhaven National Lab
P. Bezier, Contractor, Brookhaven National Lab
J. Cadwell, Contractor, Brookhaven National Lab
A. Fresco, Contractor, Brookhaven National Lab
S. M. Wong, Contractor, Brookhaven National Lab
R. G. Quirk, NRC Contractor
K. Kolaczyk, Engineering inspector, RI
F. Arner, Reactor Engineer, RI
G. S. Galletti, NRR
Approved by: Jacque P. Durr, Chief
Inspections, Special Projects Office, NRR
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9806030382 980526
0 ADOCK 05000245 (
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TABLE OF CONTENTS
EXECUTIVE SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
U1.1 Operations ..................................................1
U101 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
U 1. ll M aint en an ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
U1 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
U1 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . 6
U 1.lli Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
U1 E2 Engineering Support of Facilities and Equipment ............. 7
U2.1 Operations ..................................................8
U2 O1 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
U2 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . 10
U2 08 Miscellaneous Operations issues (9'2700) . . . . . . . . . . . . . . . . . 11
U 2.ll M aintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
U2 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 l
U2 M3 Maintenance Procedures and Documentation .... ......... 17
U2 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . 20
U3.1 Operations .................................................21
U3 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
U3 O2 Operational Status of Facilities and Equipment ............. 22
U3 07 Quality Assurance in Operations .......................30
U 3.11 M aintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 6
U3M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
U3 M2 Maintenance and Material Condition of Facilities and Equipment . 49
U3 M3 Maintenance Procedures and Documentation ..............53
U3M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . 55
U 3.Ill Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
U3 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
U3 E2 Engineering Support of Facilities and Equipment ............ 70
U3 E3 Engineering Procedures and Documentation ...............74
U3 E7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . 78
l- U3 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 90
IV Plant Support .................................................98
R1 Radiological Protection and Chemistry Controls . . . . . . . . . . . . . . . . . . 98
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R5 Staff Training and Qualification in Radiological Protection and Chemistry
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R8 Miscellaneous Radiological Protection and Chemistry issues . . . 102
S8 Miscellaneous Security and Safeguards issues .................102
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 3
X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
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EXECUTIVE SUMMARY I
Millstone Nuclear Power Station, Units 1, 2, and 3 I
Combined Inspection 245/98-206; 336/98-206; 423/98-206
Operations
e The management leadership team at Unit 1 identified a potential negative trend in I
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human performance as the result of three recent human performance errors. A self-
assessment team, consisting of a cross section of departmental plant workers, was
tasked with reviewing the issue and making suggestions to prevent future errors.
The team found that while there was no specific declining trend in human
performance, there were some barriers removed by "down sizing" of the
organization. Mansgement identified a problem area and has taken immediate action
to resolve it. In particular, the effort to involve the workers up front and get their
agreement and sponsorship of the solution, was noteworthy. (Section U1.01.2)
e At Unit 1, the inspector identified a violation of Technical Specification 6.8.1a. that
required procedures ba established and implemented for the control of plant
equipment. Specifically, the licensee failed to establish a process or procedure for
the control of rystem valve lineups following a revision. The licensee identified
additional process breakdowns, which will be addressed in the response to the
violation. (Section U1.01.3)
e At Unit 2, the licensee's corrective actions to address the final Safety Analysis
Report (FSAR) discrepancies discussed in eel 50-336/96-06-05 were incomplete in
that the FSAR has not yet been corrected. The two discrepancies involved the fact
that cold shutdown boron concentration was not attained prior to initiating
cooldown and the shutdown group of control rods were not fully withdrawn during
the cooldown evolution. The safety evaluations to support the needed FSAR
changes were reviewed by the NRC to support Technical Specification (TS)
Amendments 116 and 133 but the FSAR has not been updated to reflect the
amendments. The broader corrective action of changing the Design Control Manual ;
to require processing FSAR changes along with the TS amendment should minimize
future occurrences of this problem. Significant items List No. 9 remains open
pending licensee completion and NRC review of the necessary FSAR updates.
(Section U2.08.1)
e Unit 2 operations shift turnovers have been clear and thorough. In particular, the
inspectors noted good sensitivity to special evolutions and any work that could
affect shutdown safety equipment. Operations management has demonstrated
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rest in the conduct of shift turnovers by frequent observation. (Section
U2.J 1.1 )
e At Unit 2, the NRC found that the safety parameter display system (SPDS) displays
were inconsistent with the licensing basis in that there are no red and green
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indicators that reflect safety function status and the SPDS has not been displayed
during normal operations. The licensee committed to review their SPDS licensing
basis at Unit 2 and provide a letter to the NRC by April 30,1998, that provides their
plans for dispositioning identified deviations. This issue is considered unresolved
pending NRC review of the licensee's submittal. (Section U2.01.2)
- At Unit 2, the inspector found the emergency diesel generator (EDG) operating
procedure to be technically inadequate in that specified actions to reduce EDG
current using the " Auto Voltage Adjustment" were not physically possible. This
concern had minor safety significance because the EDG output breaker is designed
to interrupt large generator currents without creating unstable conditions within the
electrical distribution system and because previous steps of the operating procedure
had established EDG current at a low level. This concern was characterized as a
Non-Cited Violation. (Section U2.03.1)
- Unit 2 management demonstrated a high standard for the quality of operations in
questioning the level of procedural compliance during an evolution where, contrary
to the operating procedure, operations personnel decided to temporarily transfer
reactor building closed cooling water (RBCCW) flow to the "B" RBCCW heat
exchanger without supplying service water to the heat exchanger. This deviation
from the intent of operating procedures was permitted by the administrative l
procedure governing procedure usage and the omission of procedure steps.
Subsequently, the licensee revised the adminir: !ive procedure to prohibit the ,
omission of procedure steps if the omission ct eges the intent of the procedure. l
This concern was characterized as a Non-Citeo /iolation. (Section U2.08.2)
- The licensee's corrective actions to address the six issues where the Millstone Unit
3 FSAR was inconsistent with other licensing- and design-bases documents were
determined to be acceptable. The inspector also determined that Procedure RAC 03
contains adequate guidance to ensure that the FSAR is properly maintained.
(Section U3.07.2)
e NRC review of the Unit 3 implementation of NUREG-0737 TMI Action Plan
Requirements continued to identify FSAR compliance issues and other licensing i
basis questions. Similar problems have been documented in previous NRC
inspection reports. (Section U3 07.1)
- At Unit 3, the operators were trained on design changes and the results were
satisfactory. The Unit 3 simulator was updated to match the as installed
configuration of the facility. (U3 05.1)
- Unit 3 Plant Emergency Operating Procedures and other operating procedures
related to the design changes were updated satisfactorily. (U3 03.1)
- Operator training staffing was adequate and the licensee was in the process of
hiring additional people to meet Unit 3 f acility target staffing levels. (U3 08.7)
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e At Unit 3 a violation was identified for the failure to take prompt corrective actions
regarding a nonconformance with assumed operator performance time required to
isolate a steam generator upon a tube rupture. (U3 08.6)
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Maintenance
e The activities associated with the repair of the Unit 1 emergency diesel generator
(EDG) exhaust pipe were performed according to station procedures. The inspector
also found that the temporary modification package developed for the pipe repair
was technically sound. At the onset of the event, plant management was slow to
recognize the significance of the abnormally high level of exhaust fumes in the EDG
room. However, once the maintenance "Fix It Now" team was mobilized, the
problem was quickly identified. Maintenance and engineering worked expeditiously I
to develop and implement a repair plan. (Section U1.M1.1) !
e At Unit 2, the performance of Nuclear Oversight in raising concerns associated with
the service water liner repairs has been outstanding. Oversight's efforts, which
included a detailed vertical slice review of service water maintenance, revealed a
number of concerns that prompted line management to suspend the liner repair
activities for a few days to address the identified concerns. These concerns !
included inconsistencies with project specification, missed OC hold points, and l
inadequate receipt inspections of ARCOR. (Section U2.M1.1) !
e As part of a site-wide inspection, the NRC raised a concern whether the surveillance i
procedures associated with digital liquid and gaseous effluent radiation monitors j
satisfied the technical specification (TS) definition for a Channel Functional Test. l
This issue was considered unresolved oending review by an NRC regional specialist
inspector of the licensee's position paper that concluded they are in compliance with
TS. For Unit 3, the NRC concluded that the surveillance procedures associated with
13 radiation monitors were inadequate in that the method used to satisfy the TS
Channel Functional Test for digital radiation monitors was contrary to the TS
definition for an Analog Channel Operational Test. Although Unit 3 actions are
complete, this issue is also considered unresolved at Unit 3 to allow NRC review of
the Unit 2 position paper to ensure a consistent NRC approach is taken. (Section l
U2.M3.1)
e Unit 3 personnel have clearly redressed their original approach to the issue of
restraint of temporary equipment, specifically as applied to seismic II/l issues.
Through a unit-wide stand down and emphasis on training, management has
succeeded in conveying their expectations regarding and importance of the issue.
(Section U3 M3.1)
Engineering
e Unit 1 management has taken a proactive approach to the issue of system layup for
the current extended maintenance mode on Unit 1. The use of a multi-disciplined
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team is an effective method of handling such a broad area as plant-wide system
layup. (Section U1.E2.1)
e The inspectors identified several items that were inappropriately included on the
deferred issues list, including two that may have challenged system operability.
Additional licensee actions appear to be necessary to ensure all deferred items are
appropriate. (Section U3.E7.1)
e The root cause investigation to address ARCOR coating failures was performed in an
adequate manner, key pertinent docurnents were effectively considered in the
assessment, and an effective use of Probabilistic Risk Assessment (PRA) fault tree
approach has enabled a better understanding of the issues. The inspector
concluded that the licensee has implemented effective corrective and preventive
actions that address several ARCOR repair failures. (Section U3.E7.6)
e Unit 3 Corrective action for an ACR was determined to be inadequate because 21
solenoid operated valves important to safety and related cables located in a harsh
environment were not included in the EEQ Program. This could have resulted in
improper future maintenance activities. Resulting failure of these components in an
unsafe position would result in diversion of ECCS flow to nonsafety related piping
and is identified as a violation of 10 CFR 50.49. Other issues associated with
safety-related valves controlled by nonsafety-related equipment was subject to
enforcement discretion pursuant to Vll.B.2. (Section U3.E7.4)
Plant Support
e The inspector reviewed corrective actions for a previously identified violation and
performed additional inspection of a previously identified inspector follow-up item.
The previously identified violation will be closed, based on review of implementation
of corrective actions and the inspector follow-up item will be closed, based on
review of additionalinformation developed by the licensee. At the conclusion of
this inspection there were no open items in the area of security. (Section VI.S8)
e Effective programs for radiation protection during extended outages have been
established at all three units. Additionally, Units 2 and 3 have prepared plans for
restart as they related to changing radiological conditions. Unit 1 has established
effective controls for long-term shutdown. (Section IV.R1.1)
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Report Details
Summarv of Plant Status
Unit 1 remained in an extended maintenance mode for the duration of the inspection
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period. Personnel focused their efforts on performing corrective and preventative
maintenance in order to maintain the plant in a safe shutdown condition.
U1.1 Ooerations
U101 Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing
plant operations. Control room panel walkdowns were performed to identify whether
significalit plant parameters and indications were at expected values for current plant
conditions; whether any significant trends exist; or whether the safety and risk significant
systems including their support systems are appropriately aligned and operable. In general,
the conduct of operations was professional with an appropriate focus on shutdown risk.
The inspectors also attended the licensee's plan of the day meetings, and other meetings
as appropriate to obtain the overall status of the plant and cd the licensee's activities that
were planned or in progress. Noteworthy observations are detailed in the sections below.
01.2 Human Performance Self-Assessment
a. Insoection Scoce (71707)
in response to three recent human performance errors at Unit 1, management determined
that immediate intervention was needed to assess any negative trend in this area, and
formulate a corrective action plan to address human performance. The errors involved an
inadvertent start of the emergency diesel generator, a valve positioning error on the reactor
building closed cooling water system (while draining the system), and a missed fire
protection system valve lineup surveillance performed one day past its due date. The
inspector reviewed a self-assessment of human performance, which was completed in
response to the recent human errors,
b. Observations and Findinas
The purpose of the self-assessment was to review and help prevent issues relating to
human performance at Unit 1. A team was assembled that consisted of a cross section of
departments including operation, maintenance, and engineering, with the radiation
protection manager as the team facilitatory. The team was asked to review previously
documented condition reports (CRs) dealing with human errors, two quarterly CR trend
reports, and interview personnel.
During the week, the team expanded their review to include procedure use, pre-job
briefings, management and oversight worker observations, and previous self-assessment
findings and corrective actions. The engineering representatives also developed and used a
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questionnaire for the technical support group to assist in identifying reasons for a decline in
human performance. The team also relied on support from licensing, experience
assessment, and the human performance enhancement system (HPES) coordinator.
The inspector attended two team meetings and found that the team members were very
enthusiastic and worked well together. There appeared to be appropriate representation
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management's concerns with the apparent increasing trend in the rate of events associated
with human error.
On March 4,1998, the inspector reviewed the team's findings. The team found that after
reviewing the statistical data, a specific trend in the decline of human performance could
not be identified. However, they did identify specific areas in which management focus
and attention was needed to eliminate future issues. The team noted that protective
barriers that were in place to help maintain human performance standards have been
removed by the "down sizing" of the organization. For example: loss of people to other l
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units; loss of specific skill sets needed in technical and trade areas; and a reduction in the
l work force. The team gave management suggestions to preclude a further reduction in
human performance. The team determined that the unit needed to make " safety" and j
" human performance" a priority. In addition, standards should be reinforced by the highest :
levels of management, pre-job briefings need to be more effective, and plant workers I
should be trained on the practical training mock-up used for supervisor work observation l
training.
Following the completion of the initial review, the team was tasked with developing an
implementation action plan for their suggestions. Additionally, the management leadership
team developed their own action plan in an effort to use a two-prong approach to human
performance improvement. The focus will be on the main effort and initiative coming from
the work force and the support and backing coming from management. At the end of the
inspection period, the implementation action plans were completed and responsible
individuals were assigned.
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c. Conclusions
The management leadership team at Unit 1 identified a potential negative trend in human
performance as the result of three recent human performance errors. A self-assessment
team, consisting of a cross section of departmental plant workers, was tasked with
reviewing the issue and making suggestions to prevent future errors. The team found that
while there was no specific declining trend in human performance, there were some
protective barriers removed by "down sizing" of the organization. The team also developed
a two-prong approach to human performance improvement with the main effort coming
from the work force and support and bucking coming from management. An
implementation action plan was developed by both groups. The inspector concluded that
i management identified a problem area and has taken immediate action to resolve it. In
l particular, the effort to involve the workers up front and get their agreement and
I sponsorship of the solution, was noteworthy.
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01.3 Plant Svstem Valve Lineuos
a. Insoection Scone (71707)
On February 24,1998, during a twning tour of the Unit 1 control room, the inspector
learned about a problem with a low service water (SW) system pressure indication, which
was being investigated by the operators. The inspector accompanied the shift manager to
the SW intake structure during his investigation of the indication problem, and a report of a
mis-positioned SW root valve (1-SW-120). The inspector reviewed the impact of the mis-
positioned valve and the processes used to control both plant configuration and plant
system valve lineups.
b. Observations and Findinas
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Based on local pressure indications, the shift manager determined that the problem with the I
lowering SW header pressure was a result of a blocked sensing line and a trouble report
was initiated to document the problem. The shift manager also verified that 1-SW-120,
isolation root valve to pressure instrument PI-4-61 was closed. The instrument was a local
pressure gage that provided pressure indication for the seal header line that feeds the "B"
SW pump. The valve was opened after verifying the correct position against the SW valve i
lineup. The inspector was informed later that day that when the SW valve lineup was I
checked, operations noted that the valve had been previously verified in the closed position
in accordance with revision 16 of the valve lineup in June of 1997. However, in July
1997, the valve lineup was revised (revision 17) and the valve was required to be open,
but the actual valve position was not changed in the plant. Apparently, revision 17 of the
lineup was placed in a master file and the new required open position for 1-SW-120 was
not recognized at that time. l
The following day, the inspector discussed the issue with the operations procedure group
lead. Apparently, there was no process or procedure in place that would direct an operator
to reposition a valve when the valve lineup was revised and the required position was
changed. The operations department immediately began an extensive review of the valve
lineups for all of the operating and shutdown risk credited systems. Initially, six of the y
twenty previously completed valve lineups could not be found, so complete valve lineups
were preformed by the operators. By the end of the week, all but one of the system
lineups (condensate transfer system) were found. As a result of performing the additional
valve lineups and reverifying the proper revisions, a number of problems were identified by l
operations that included mis-positioned valves, and incorrect valve lineups. The operations'
reviews also identified process problems with configuration control, the control of valve !
lineup updates, and an issue with the lack of quality record retention for the completed
valve lineups. Operations prepared a matrix that listed all the valve discrepancies, process {
breakdowns, and any possible effects on the plant. The inspector verified that none of the
discrepant issues had a detrimentalimpact on the safe operation of the plant.
Technical Specification (TS) 6.8.1a. requires that written procedures be established,
implemented and maintained covering the activities referenced in Appendix A of Regulatory
Guide 1.33, February 1978, item 1c, Administrative Procedures, " Equipment Control." The
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failure to establish and implement a procedure for equipment control to process revisions
to system valve lineups and thereby ensure that the appropriate changes are communicated {
to the field, constitutes a violation (VIO 50-245/98-206-01) of NRC requirements. In
addition, the response to this violation should address the process problems identified with
configuration control, valve lineup updates, and quality record retention for completed valve
lineups.
c. Conclusions
The inspector identified a violation of TS 6.8.1 that required procedures be established and
implemented for the control of plant equipment. Specifically, the licensee failed to
establish a process or procedure for the control of system valve lineups following a
revision. The licensee identified additional process breakdowns, which will be addressed in
the response to the violation.
U1.ll Maintenance
U1 M1 Conduct of Maintenance
M 1.1 Emeroency Diesel Generator (EDG) Exhaust Pine Reoair
a. Insoection Scoce (62707)
The inspector observed various phases of the identification and repair of the EDG exhaust j
pipe. The review included the initial investigation by the maintenance "Fix-It-Now" (FIN) I
team, the technical evaluation for the temporary patch, and observations of the work l
planning meetings as the work was planned and executed. In addition, the inspector j
observed organizational critiques of the repair work after the fact. The repair was
performed under AWO M1-98-OO713 and temporary modification 1-98-1. j
b. Observations and Findinos
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On the evening of February 6,1998, while performing SP-668.1, " Diesel Generator
Operational Readiness Demonstration," the operators noted a large concentration of
exhaust fumes in the EDG room. Site fire protection was called to perform an air test in
the room, at which tirie the carbon monoxide (CO) meter had alarmed and continued to
l increase, which prompted them to evacuate the room. About one hour later, fire protection
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personnel wearing self-contained breathing apparatus, tested the area and found a reading
of 55 ppm CO: the alarm limit is 35 ppm. Operations initially thought that the condition
was the result of a combination of reduced ventilation in the diesel room (HVS-6, the
l switchgear area supply fan, was off for the winter), and some exhaust leaks. Monday
I morning, February 9, the management team reviewed the CR that documented the event
and the inspector discussed the event with the shift manager during the contial room tour.
At that time, it did not appear to the inspector that. management had any specific concern
with the event or with the EDG availability for shutdown risk consideration. The inspector
! noted that the shift manager was making inquiries for the operations manager to determine
if actions were being taken to investigate the event. Unfortunately, no actions had been
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taken, and it was not until the following day that the FIN team identified a hole in the
exhaust pipe in the elbow upstream of the exhaust silencer. The inspector observed the
FIN team during the troubleshooting and investigation of the exhaust leak and was present ,
when the exhaust pipe lagging was removed, revealing the corrosion and through-wall leak '
in the pipe. The inspector noted that the FIN team immediately recognized the impact that
the leak would have on the EDG availability and notified the control room.
Engineering and maintenance worked together to identify the extent of the corrosion and
develop a plan for a temporary repair patch that would make the EDG available until the
permanent repair could be planned. The apparent cause of the corrosion was a plugged
drain line leading from the elbow to the outside of the turbine building. The drain line was
cleared to prevent a future occurrence. Two plans were deve!oped and worked for repair 1
and replacement of the exhaust pipe. Some difficulties were identified in determining the
pipe material. However, the inspector attended various work planning meetings and found
that the organization remained focused and adjusted the plans as information became
available. The inspector reviewed the technical evaluation for the temporary modification,
which consisted of a saddle fabricated of carbon steel and welded to the exhaust pipe.
The pipe was ultrasonically tested to determine the extent of the corrosion in order to
correctly size the patch. The inspector also attended the PORC meeting where the
temporary modification was reviewed. PORC performed a thorough review of the package,
and the modification was approved with minor comments. The duration of the temporary
modification will be six months from the date of PORC's concurrence to allow time for
engineering to implement design change request (DCR) M1-98-005, which will replace the
entire exhaust pipe. I
Following the completion of the repair work, plant management determined that a critique
of the organization's response to the event was needed. The inspector attended the
engineering department critique and found that the people were very candid and open. The
identified areas for improvement were management's impact on the engineering staff with
respect to schedule pressure; consistency in setting priorities and communicating those
priorities with the other two units; procedural compliance difficulties with respect to
"available" vs. " operable" and the applicability of 10CFR50 Appendix B criteria; and the j
initialinterface between operations and engineering when the problem was first identified.
A multi-discipline critique followed the engineering critique and common issues were
discussed. These issues will be captured as a condition report and the process
enhancements will be tracked and implemented.
c. Conclusions
,
l The inspector concluded that activities associated with the repair of the emergency diesel
l generator exhaust pipe were performed according to station procedures. The inspector
also found that the temporary modification package developed for the pipe repair was
technically sound. At the onset of the event, plant management was slow to recognize the
significance of the abnormally high level of exhaust fumes in the EDG room. However,
once the maintenance FIN team was mobilized, the problem was quickly identified.
Maintenance and engineering worked expeditiously to develop and implement a repair plan.
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U1 M8 Miscellaneous Maintenance issues
M8.1 - (closedl Unresolved team (URll 50-245/97-207-01: Emeroency Diesel Generator
(EDG) I uhe Oil Sumo Level
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On November 3,1997, plant operators investigated a " Lube Oil Sump High" alarm received
on the local panel for the EDG. The level was 17/8" above the full mark on the "not
running" side of the lube oil sump dipstick, which was an unexpected increase. At the end
of the inspection period, the licensee was conducting troubleshooting that included a -
historical data review and actual level trending with operations taking sump level readings
every four hours. The unresolved item was opened pending further troubleshooting and
investigation by the licensee.
l The inspector reviewed the completed condition report (CR), associated with this concern,
and the corrective action plan developed following the licensee's review of the issue. The
licensee discovered a letter from the vendor dated August 12,1983, which stated, "It is
l important that the proper lube oil leveling procedure is followed. Lube oil in the crankcase
_
must be leveled to the " running" mark on the dipstick while the engine is operating at rated
speed. Leveling while the engine is down is subject to too many variables including system
capacity and rate of oil drain back which occurs over the period of several days." Trending
of the sump level through January 1998, showed that level will continue to rise for up to
14 days after pre-lubrication or engine operation. The licensee concluded after extensive
troubleshooting, that the most likely cause of the high level was overfilling the engine
following maintenance.
As a result of this investigation, two procedures were revised. Maintenance procedure MP
743.13, " Diesel Engineer Oil Addition," was revised to say that the preferred method for
determining the lube oil level was with the engine running. Operations Form 668.1-3, had
l' a note added to inform operators that the " running level" should be recorded on the trouble
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report if tube oil is needed to be added to the engine.
An additional corrective action came out of the licensee's review concerning the pre-
. lubrication air roll procedure. The object of the air roll is to remove the lube oil that collects
in the upper inverted pistons following engine operation or the pre-lubrication of the engine,
causing it to drain back to the sump. Troubleshooting of this issue indicated that the
existing instructions in surveillance procedure SP 668.1B, " Diesel Generator Prelube and Air
Roll," are not adequate to evacuate the lube oil from the upper inverted pistons. During a
telephone conversation between the licensee and the vendor, the vendor stated that the
- more time between the engine operation and the engine air roll, the more effective the air
_
L roll will be. This delay requirement was incorporated into the steps of SP 668.1, " Diesel
Generator Operational Readiness Demonstration." However, SP 668.1B, had no delay time
between the pre-lubrication operation and the air roll, so oil could potentially drain down the
oil ways of the connecting rod to the sump, as well as the exhaust manifold. To maintain
consistency between procedures SP 668.1 and SP 668.1B, it was determined that the
delay following pre-lubrication or engine operation will be 30 to 60 minutes.
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in addition, during the review of this issue, the licensee also conducted a survey of other
Opposed Piston EDG owners, which showed an inconsistency with a Unit 1 operating
I practice. The majority of owners have incorporated " slow starts"into their surveillance
l testing. As a corrective action for the CR, engineering will initiate a technical specification
change to allow slow starts to be performed for those surveillance permitted by the
l.
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standard technical specification. The unresolved item 50-245/97-207-01 is considered
closed.
U1.lli Enaineerina l
U1 E2 Engineering Support of Facilities and Equipment
E2.1 Plant Systems Lavuo Proaram
a. Insoection Scooe (37551)
The inspector reviewed procedures and documents related to the Unit 1 plant systems
layup program. The review included the Millstone Unit 1 Layup Assessment Plan
completed in October 1997, and the recent recommendations for additional layup items
,
from the Unit 1 Layup Team.
1
b. Observations and Findinas
l In October 1996, the Nuclear Safety Assessment Board discussed the layup status of plant
systems at Units 1 and 3 and was concerned that the recommendations of procedure NUC
CHM 04, Rev. O, " Plant Systems Layup Recommendations," were not being implemented. ,
This concern was documented in two adverse condition reports (ACR) M1-96-0768 and
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M3-96-1067. As a corrective action for the ACR's, a layup assessment plan was
developed and implemented to identify those systems or components that were not placed
in an effective layup condition in a timely manner. The plan also recommended a course of
action to assure that no corrosion or material deterioration had occurred that would affect
.
the operational safety and reliability of the systems. The assessment was completed on
l October 31,1997, and included layup requirements, status, and required actions.
Additionally, during that period, the chemistry department developed the " System and
Equipment Layup Program Manual," Revision 0, that will be effective on March 31,1998.
This is a sitewide program manual, which defines the minimum requirements for an
effective system, component, and equipment layup program at Millstone. The program
was designed to meet the industry requirements for the acceptable preservation of systems
while idle during outages of various length. The program manualis comprehensive and
includes program instructions covering such areas as, layup planning and practices, layup
surveillance, returning systems to service, environmental requirements, and personnel
qualifications and training.
In January 1998, a Unit 1 Layup Team was formed consisting of a multi-disciplined group
from operations, chemistry, and engineering, with an engineering supervisor as the team
lead. The team continued the efforts that began with the layup assessment plan and
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incorporated the information contained in the new layup program manual. The team has
been meeting weekiy and has given three update presentations at the Unit 1 morning
meeting. To date, the balance of plant systems including main steam, feedwater,
condensate, and the main turbine, are dry and dehumidified. The reactor building and the
turbine building closed cooling water systems are being maintained / operated with chemical
inhibitors. Additional closed cooling systerrs are being evaluated for chemical inhibitor use.
At the end of the inspection period, the layup team presented layup recommendations to
plant management for additional systems considering the current extended maintenance
mode on Unit 1. These systems included core spray (CS), low pressure coolant injection
(LPCl), standby liquid control (SBLC), the isolation condenser, shutdown cooling and the
torus. The team recommended that CS and LPCI be placed in dry layup and dehumidified;
SBLC tank should be maintained at greater than 65 degrees F and pump testing performed
quarterly; the isolation condenser and shutdown cooling should be maintained as is; and
the torus should be maintained as is, inerted with a nitrogen atmosphere. The team is
currently developing an implementation plan and procedures to support the layup plans.
Following the completion of the system layups, the team will review component lovel layup
for such components as large motors.
c. Conclusions
The inspector concluded that management has taken a proactive approach to the issue of
system layup for the current extended maintenance mode on Unit 1. The use of a multi-
disciplined team is an effective method of handling such a broad area as plant-wide system
layup.
Reoort Details
Summarv of Unit 2 Status
Unit 2 entered the inspection period with the core off-loaded. The unit was initially shut
down on February 20,1996, to address containment sump screen concerns and has
remained shut down to address the problems outlined in the Restart Assessment Plan and
an NRC Demand for Information [10 CFR 50.54(f)] letter requiring an assertion by the
licensee that future operations will be conducted in accordance with the regulations, the
license, and the Final Safety Analysis Report. ;
U2.1 Ooerations .
1
U201 Conduct of Operations
01.1 General Comments (717071
l
Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing
plant operations. Shift turnovers observed by the NRC have been clear and thorough. In
particular, the inspectors noted good sensitivity to special evolutions and any work that
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could affect shutdown safety equipment. Operations management has demonstrated a
high level of interest in the conduct of shift turnovers by frequent observation.
01.2 Safety Parameter Disotav Svstem
a. Insoection Scone (71707)
The inspector evaluated the safety parameter display system (SPDS) to determine if the
current system is consistent with the licensing basis,
b. Observations and Findinas
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In a letter dated October 8,1983, the licensee provided information regarding the SPDS to
support the NRC staff's review to verify the system satisfied Supplement 1 to NUREG
0737 " Clarification of TMl Action Plan Requirements." This letter, in part, was used as a
basis for the NRC approving the acceptability of the Unit 2 SPDS. NUREG 0737,
Supplement 1, Section 4.1.a, states that:
l
The SPDS should provide a concise display of critical plant variables to the control i
room operators to aid them in rapidly and reliably determining the safety status of j
the plant. Although the SPDS will be operated during normal operations as well as
during abnormal conditions, the principal purpose and function of the SPDS is to aid
the control room personnel during abnormal and emergency conditions in i
determining the safety status of the plant and in assessing whether abnormal
conditions wanant corrective action by (control room) operators to avoid a degraded
Core.
Two examples were identified where the current design of the SPDS was not consistent
with the information provided in the licensee's October 1986 letter. The first example
involved the statement "The status of each of the six safety functions for the selected
procedure is indicated by one of two colors. The green color indicates that the safety
functions are not exceeded. A red color indicates that the limits are exceeded." However,
the inspector found that the licensee changed the SPDS display to no longer use the colors
(or any other alerting mechanism) to continually indicate the status of the six safety
functions. The current SPDS display provides the operators with the plant parameters that
are used to assess each safety function but relies on operators (or the shift technical
advisor) to evaluate the parameters at least once every 10 minutes to determine whether
any of the six safety functions are not satisfied.
The second example was identified by the licensee and is discussed in Condition Report
M2-98-OO21. The licensee's October 1986 letter stated that "Although some parameters
are not monitored at power operation, the SPDS is "on" at all times during operating modes
1,2, and 3. During normal operation, all safety functions are green and are displayed at all
times." The letter also states that "At least one control room CRT [ cathode-ray tube) will
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continuously monitor the status of all safety functions during modes 1,2, and 3." As
stated above, NUREG 0737, Supplement 1, Section 4.1.a, specifies that SPDS be operated
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during normal operations. However, Unit 2 operators have been trained to display SPDS
only upon entry into the emergency operating procedures (EOPs).
c. Conclusions
The NRC concluded that the current SPDS displays are inconsistent with their licensing
basis in that there are no red and green indicators that reflect safety function status and
the SPDS has not been displayed during normal operations. The licensee committed to
review their SPDS licensing basis at Unit 2 and provide a letter to the NRC by April 30,
1998, that provides their plans for dispositioning identified deviations. This issue is
considered unresolved pending NRC review of the licensee's submittal. (Unresolved item
50-336/98-206-02)
U2 03 Operations Procedures and Documentation
O3.1 Local Shutdown of Emeraencv Diesel Generator
a. Insoection Scoce (71707)
The inspectors observed operator performance in the control room during the local
shutdown of the "A" emergency diesel generator (EDG) using Section 4.9, " Local
Operation of "A" DG in "A" DG Room," of procedure OP2346A, " Emergency Diesel
Generators." The inspection activities included review of procedure OP2346A and
discussions with control room operators and the cognizant procedure owner.
!
b. Observations and Findinas
During shutdown of the "A" EDG on December 31,1997, the control room operators were
unable to perform Section 4.9 of procedure OP2346A as written. In accordance with the
procedure, tha local operator had placed the "A" EDG at a load of approximately 1400kW
and a current of approximately 200 Amperes. From this condition, Step 4.9.43 of I
procedure OP2346A specified lowering generator current to approximately 100 Amperes j
using the "A" EDG " Auto Voltage Adjustment." However, the local operator was only able
'
to lower generator current to approximately 200 Amperes using the "A" EDG " Auto
Voltage Adjustment." The Unit Supervisor, who was unaware at that time that the
procedure was incorrect, directed the local operator to continue with the procedure and
place the "A" EDG in a safe, shutdown condition.
The inspector reviewed procedure OP2346A and determined that the physical design of the
EDG would not permit a reduction in generator current to approximately 100 Amperes
using the automatic voltage regulator as specified in Step 4.9.43. Attachment 2 to
procedure OP2346A is a nomograph entitled " Generator Real Load (Watts) vs. Reactive
Load (VARs) for Local DG Operation," which indicated that a generator current of 100
Amperes was unattainable at a load of 1400kW. The inspector calculated that the
minimum EDG current to achieve a realload of 1400kW was greater than 150 Amperes.
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Steps 4.9.42 and 4.9.43 of procedure OP2346A had been changed under Revision 21,
which became effective on June 23,1997. The procedure owner stated that the objective
of this change was to allow the local operator to complete the procedure using only local
indications. The previous revision of the procedure specified use of control room
indications, which required communication with control room operators that may not be
available to the local operator for some emergency conditions. The inspector did not
identify previous instances where the revised Section 4.9 of procedure OP2346A had been
used to locally secure the "A" EDG.
Because the voltage regulator has a negligible effect on the real load carried by the EDG,
the adjustment of the voltage regulator changes generator current by changing the reactive
load sharing between the EDG and parallel generators on the utility grid. The procedure
owner stated that the purpose of Steps 4.9.42 and 4.9.43 was to minimize reactive
current prior to opening the EDG output breaker.
i
As a corrective action, the licensee changed procedure OP2346A, Sections 4.9 and 4.20
(" Local Operation of "B" DG in "B" DG Room"), on January 12,1998, to specify that the i
operator reduce real EDG load to 100kW using the active governor before reducing l
generator current to 100 Amperes using the EDG " Auto Voltage Adjustment."
c. Conclusions
Millstone Unit 2 Technical Specification 6.8.1.a requires the licensee to establish written
procedures for operation of each EDG. Contrary to this requirement, procedure OP2346A
was technically inadequate in that the physical design of the EDG would not permit a
reduction in generator current to approximately 100 Amperes as specified in Section 4.9 of
procedure OP2346A. However, this concern had minor safety significance because the
EDG output breaker is designed to interrupt large generator currents without creating l
unstable conditions within the electrical distribution system and because previous steps of
procedure OP2346A had established EDG current at a low level. Therefore, this failure
constitutes a violation of minor significance and is being treated as a Non-Cited Violation,
consistent with Section IV of the NRC Enforcement Poliev. j
U2 08 Miscellaneous Operations issues (92700)
08.1 - (Uodated) Escalated Enforcement item 50-336/96-06-05: Reactivitv Controls Durina
Plant Cooldown (Uodated - Unit 2 Significant items List No. 91
a. Insoection Scoce
Escalated Enforcement item (EEI) 50-336/96-06-05 involved the following two examples of
where operating procedures were inconsistent with the Final Safety Analysis Report
(FSAR): (1) Section 9.2.3.3 of the FSAR states that "the boron concentration is increased
to the cold shutdown value prior to the cooldown of the plant. This is done to assure that
the reactor has an adequate shutdown margin throughout the cooldown." However,
i procedure OP 2207, " Plant Cooldown," Step 4.1.3, states that "it may not be possible in
l all situations to borate to cold shutdown concentration before commencing cooldown." It
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is the licensee's normal practice to borate to cold shutdown concentration concurrently
with a plant cooldown. (2) Section 9.2.3.3 of the FSAR states that "the operator does not
insert the shutdown group of [ control element assemblies] CEA's until the cooldown is
completed and until he verifies the concentration of boron in the reactor coolant by sample
analysis." However, procedure OP 2206, " Reactor Shutdown," Step 4.3.3, inserted all
control rods in the shutdown group, Procedure OP 2207, Section 2, " Prerequisites," step
2.1.1, specifies that the reactor is shutdown with all control rods fully inserted. The FSAR
was also not consistent with Technical Specification 3.1.3.7 which states that the control
rod drive mechanisms shall be de-energized in modes 3,4,5 and 6 whenever the reactor
coolant system (RCS) boron concentration is less than the refueling concentration.
NRC Inspection Report 50-336/96-06 discussed a third concern regarding the fact that in
situations where borating the RCS required more than the volume of one boric acid storage
tank (BAST), it was the licensee's practice to make batch additions of boron to the BAST
while injecting from that tank. Therefore, following the first BAST tank addition,
subsequent BAST additions would not be recirculated and sampled and proper
concentration verified prior to injection into the RCS. The inspection report requested that
the licensee also address this concern as part of the violation response.
b. Observations and Findinas
The licensee's evaluation of the first concern indicated that the practice of borating the
RCS during cooldown rather than prior to cooldown was evaluated as part of Technical
Specification Amendment 133 but the FSAR was not updated to reflect the TS
amendment. TS Amendment 133 involved decreasing the required boron concentration in
the BAST to allow the removal of heat tracing from the piping concentrated boric acid
solution. The licensee's safety evaluation associated with the TS amendment discusses
that RCS boration would be performed concurrently with plant cooldown. Prior to TS
amendment 133, the required boric acid concentration in the BAST was based on achieving
the required RCS boron concentration assuming letdown was not available. Therefore, the )
available pressurizer volume limited the amount of BAST water that could be added to the
RCS. TS amendment 133 involved reducing the required boron concentration in the BAST
by allowing RCS boration to occur concurrently with plant cooldown and therefore,
sufficient pressurizer volume would be available due to coolant contraction. The inspector
reviewed the licensee's closure package that addressed this item and found that FSAR
Change Request 97-MP2-196 had been prepared but has not been reviewed and approved
and therefore, the FSAR has not been updated to correct this discrepancy.
Similarly, regarding the second concern, the practice of inserting all CEAs, including the
shutdown group, prior to cooldown was evaluated as part of TS Amendment 116 but the
FSAR was not updated to reflect the TS amendment. This amendment changed TS
3.1.3.7 to require that all CEAs be deenergized in Modes 3 (with exceptions),4, 5, and 6
whenever boron concentration is less than refueling concentration. This change was made I
to assure that the consequences of an uncontrolled CEA withdrawal from a subcritical
condition were bounded by the safety analysis. The inspector reviewed the licensee's
closure package that addressed this item and found that FSAR Change Request 97-MP2-
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196 had been prepared but has not been reviewed and approved and therefore, the FSAR
has not been updated to correct this discrepancy.
The two concerns discussed in eel 50-336/96-06-05 each involved the failure to update
the FSAR to reflect TS amendments, in the past, FSAR changes were prepared and
reviewed after the design change, such as a plant modification or TS amendment, had
occurred. Using this "efter-the-fact" approach, the necessary FSAR changes often did not
occur. As part of the licensee's broader corrective actions to address this type of concern,
the licensee changed the Design Control Manual and Nuclear Group Procedure 4.03,
" Changes and Revisions to Final Safety Analysis Reports," to now require that FSAR
changes be processed with the parent document such as design change records, minor
modifications, and procedures.
To address the third concern, the practice of injecting from the BAST before sampling, the
licensee changed procedure OP 2304C, " Makeup (Boration and Dilution) Portion of the
Chemical arid Volume Control System." Procedure OP 2304C, Rev.19, Step 4.13,
specifies that the BASTS must be recirculated and sampled prior to placing them in service
or injecting their contents into the RCS.
1
c. Conclusion
The licensee's corrective actions to address the FSAR discrepancies discussed in eel 50-
336/96-06-05 were incomplete in that the FSAR has not yet been corrected. The two l
discrepancies involved the fact that cold shutdown boron concentration was not attained
prior to initiating cooldown and the shutdown group of control rods were not fully
withdrawn during the cooldown evolution. The safety evaluations to support the needed
FSAR changes were reviewed by the NRC to support TS Amendments 116 and 133, but
the FSAR has not been updated to reflect the amendments. The broader corrective action
of changing the Design Control Manual to require processing FSAR changes along with the
TS amendment should minimize future occurrences of this problem. Licensee cocrective
actions to address the third concern, the practice of injecting from the BAST before
sampling, were determined to be acceptable. eel 50-336/96-06-05 and Significant items
List No. 9 remain open pending licensee completion and NRC review of the necessary
FSAR updates.
08.2 (Closed) Unresolved item 50-336/97-207-02- Temocrarv Swaonina of the In-Service
Reactor Buildina Closed Coolina Water Heat Exchancer Without Swaonino Service
Water
a. Insoection Scoce (92902)
l
i This unresolved item involved an event where, contrary to the operating procedure,
operators temporarily shifted the in-service Facility 2 reactor building closed cooling water
I (RBCCW) flow from the "C" RBCCW heat exchanger to the "B" heat exchanger without
supplying service water to the "B" RBCCW heat exchanger on September 1,1997. This
inspection involved review of the approved condition report (CR) evaluation for CR M2-97-
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- 1972, interviews with licensee personnel, and reviews of the associated operating and -
administrative procedures.
b. Observations and Findinas
While filling the Facility 1 RBCCW header following maintenance, operations personnel
identified a packing leak on valve 2-RB-4.1E, the "C" RBCCW heat exchanger outlet valve
to the Facility 1 RBCCW header. To evaluate whether repair of the valve packing would be
necessary, operations personnel desired to cycle the valve to try to reduce the leakage prior
to completely filling the header. In order to cycle valve 2-RB-4.1E with the Facility 1
header partially filled while maintaining RBCCW flow in the Facility 2 header, the "C"
' RBCCW heat exchanger must be removed from service, and the "B" RBCCW heat
exchanger must be placed in service.
l Section 5.2.4 of procedure OP2330A, "RBCCW System," provides instructions for
swapping from the "C" RBCCW heat exchanger to the "B" RBCCW heat exchanger. Step
5.2.4.1 of procedure OP2330A instructs operators to refer to procedure OP2326A,
" Service Water System," and establish service water flow to the "B" RBCCW heat
. exchanger. However, operations personnel understood that establishing service water flow
.
to the "B" RBCCW heat exchanger was undesirable because service water piping at the
outlet from this heat exchanger was degraded by corrosion.
. Operations personnel decided to temporarily transfer in-service Facility 2 RBCCW flow to
the "B" RBCCW heat exchanger without supplying service water to the heat exchanger and
without completing a procedure change. This decision was based on (1) a concern that the
introduction of service water flow to the "B" RBCCW heat exchanger would further !
degrade service water system piping, (2) an assessment that the spent fuel pool )
temperature increase for the expected duration of the evolution would be very small, (3) an
assessment that the planned contingency actions would adequately address potential
problems, and (4) a conclusion that a procedure change was not required to perform
selected procedure steps from an approved operations procedure. ,
i
The inspector reviewed the licensee's administrative procedures that govern the use of
procedures and the modification of procedures. Procedure DC4, " Procedural Compliance,"
Rev. 3, Section 1.5, "Use of Procedure Sections," stated, "It is acceptable to use portions
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of procedure section(s) or instruction step (s) to complete a specific task or operational
evolution identified in the procedure." Step 1.5.1 of procedure DC4 stated that the work
supervisor shall identify the procedure sections, or portions of sections, that v/ill safely
achieve the expected results. The second bullet of Step 1.5.4 of procedure D04 stated
that,' for operations procedures, the work supervisor shall obtain authorization from the
shift manager or unit supervisor to perform applicable sections or portions of sections.
Procedure DC1, " Administration of Procedures and Forms," provides administrative
instructions for modifying procedures. Procedure DC1, Attachment 1, " Definitions,"
includes the following information: (1) a "one-time" change is a process to modify a
document on a temporary basis to compensate for a plant condition or situation that differs
from the' conditions or situations the document was originally intended to address; and (2)
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an " intent" change includes procedure modifications that change the basic method of task
performance, the scope of the procedure, or the applicability of the procedure.
Millstone Unit 2 Technical Specification 6.8.1.a requires that procedures recommended in
1
Appendix A of Regulatory Guide (RG) 1.33, " Quality Assurance Program Requirements
(Opercion)," be established in written form, implemented, and maintained. Operating
procedures for closed cooling water systems are included in Appendix A to RG 1.33.
Technical Specification 6.8.2.c requires that changes to procedures required by Technical
Specification 6.8.1 be reviewed and approved prior to implementation. Technical
Specification 6.8.3 provides an exception for temporary procedure changes provided that:
(1) the intent of the procedure is not altered; (2) the change is approved by two individuals
prior to implementation; and (3) the change is documented, reviewed, and approved within
14 days after implementation.
Unit 2 management directed operations to initiate a condition report to assess the
operators' decision to omit the procedure step to align service water to the "B" RBCCW
heat exchanger without a procedure change. The operations department initiated CR M2-
97-1872 to document the condition, and the corrective action department assigned the
operations department to conduct a root cause evaluation of the operator's actions. The
l licensee's condition report evaluation for CR M2-97-1872 attributed no root cause to the
operator's actions based on the following conclusions: (1) the operators used a proper
decision making process to plan the evolution and to justify not aligning service water to
the "B" RBCCW heat exchanger; (2) no adverse conditions resulted from the operators'
I actions on September 1,1097; and (3) the operators complied with procedure DC4 by
l performing selected steps of the operating procedure. However, the evaluation concluded
that unit management needed to establish consistent expectations related to procedure
compliance and the procedure change process, and the evaluation noted that the station
administrative procedure group had been revising procedure DC4 to tighten provisions for
performance of only selected parts of approved procedures.
Revision 4 to procedure DC4 became effective on October 31,1997. Procedure DC4, Rev.
4, Step 1.6.3, describes the actions that should be taken if a step or sub-step cannot be or
should not be performed as a result of plant conditions. Step 1.6.3 allows a first line
supervisor or shift manager / unit supervisor to omit a procedure step without a procedure
l change as long as omitting the step does not: (1) change the intended objective of the
task or evolution as specified by the procedure; (2) create an unsafe plant condition; (3)
violate technical specifications; or (4) result in a deviation from a license basis document.
Implementation of revision 4 to procedure DC4 included station-wide training prior to the
effective date of the procedure,
c. Conclusions
l
The NRC concluded that the temporary transfer of RBCCW flow from the "C" to the "B"
RBCCW heat exchanger without supplying service water flow to the "B" RBCCW heat
exchanger had no actual safety consequences and the potential safety consequences were
remote or of minor significance. Neither the Millstone Unit 2 Technical Specifications nor
the Final Safety Analysis Report (FSAR) specify continuous heat removal from the RBCCW
-
e
.
!*- ,
,
l
l 16
heat exchangers to the ultimate heat sink in the existing operating condition of the reactor
plant (i.e., reactor defueled with all irradiated fuel in the spent fuel pool).
The NRC concluded that the operators' decision to omit performance of step 5.2.4.1 of
procedure OP2330A complied with Section 1.5 of procedure DC4, Rev. 3. However, the
failure to supply service water to the in-service "B" RBCCW heat exchanger was not i
consistent with the intent cf Section 5.2.4 of procedure OP2330A to shift service to a fully l
'
l functional RBCCW heat exchanger, and this action violated the requirements of Technical
Specification 6.8.1.a to implement written procedures for operation of the RBCCW system.
l The procedure change process required by Technical Specification 6.8.2 and governed by
l procedure DC1 provides a formal structure for review of safety concerns associated with
changes that affect the intent of procedures. l
l
l Unit 2 management demonstrated a high standard for the quality of operations in
questioning the level of procedural compliance during the evolution. The condition report
evaluatiun was of good quality and appropriately identified the procedure DC4, Rev. 3, as a
principal factor in the operators' decision to omit a procedure step that changed the intent
l of a procedure section. The licensee initiated Revision 4 to procedure DC4 corrected this
condition by specifically prohibiting omission of procedure steps that change the intended
objective of the task or evolution as specified by an approved procedure.
This non-repetitive, licensee-identified and corrected violatior. is being treated as a Non .
Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev.
Unresolved item 50-336/97-207-02 is closed.
U2.ll Maintenance
l
U2 M1 Conduct of Maintenance
M 1.1 Maintenance Observations
The inspectors observed and reviewed selected portions of preventive and corrective
maintenance and surveillance tests and reviewed test data to verify: adherence to
regulations, and administrative control procedures, and technical specification limiting
l
conditions for operation; proper removal and restoration of equipment; appropriate review I
and resolution of test deficiencies; appropriate maintenance procedures in use; adherence
'
!
to codes and standards; proper QA/QC involvement; proper use of bypass jumpers and
safety tags; adequate personnel protection; and, appropriate equipment alignment and
retest. Work activities that were inspected included the "B" service water liner repairs and
procedure SPROC 97-2-19, "RBCCW Flow Balance."
The inspector found that performance of r.uclear Oversight in raising concerns associated i
with the service water liner repairs has been outstanding. Oversight's efforts, which I
included a detailed vertical slice review of service water maintenance, revealed a number of
concerns that prompted line management to suspend the liner repair activities for a few
days to address the identified concerns. These concerns includ. , inconsistencies with
project specification, missed QC hold points, and inadequate re 'ipt inspections of ARCOR.
l
_. _ _ _ _ _ _ _ - - _ _ _ _ - _ _ _ - _ _ _ _ - - - _ _ _ _ - _ - - . - . - . .
.
.
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17
U2 M3 Maintenance Procedures and Documentation
M3.1 Channel Functional Test of Radiation Monitors
a. Insoection Scone (61726)
The inspector reviewed the surveillance procedures associated with the dig:tal radiation
monitors at Units 1,2, and 3 to evaluate whether the procedures satisfied technical
specification requirements.
b. Observations and Findinas
Unit 2
}
At Unit 2, the inspecto. evaluated whether the surveillance procedures associated with
digital liquid and gaseous effluent radiation monitors satisfied the Technical Specification
1.11 definition for a Channel Functional Test. Technical Specification 1.11 states that "a
CHANNEL FUNCTIONAL TEST shall be the injection of a simulated signalinto the channel
as close to the primary sensor as practicable to verify operability including alarm and/or trip
functior s." The inspector reviewed the following surveillance:
e Procedure SP 2404AA, " Aerated Liquid Radwaste Process Radiation Monitor RM
9116 Functional Test,"
e Procedure SP 2404AC, " Clean Liquid Radwaste Process Radiation Monitor RM-9049
Functional Test,"
e Procedure SP 2404AP, " Waste Neutralization Sump Radiation Monitor
(2CNDRlY245) Functional Test," and
e Procedure SP 2404AR, " Unit 2 Stack Gaseous High Range Radiation Monitor, RM-
8168, Functional Test."
Prior to 1996, the above surveillance procedures clearly satisfied the TS 1.11 definition in
that a pulse generator was used to inject a " simulated signal" in place of the primary
detector to increase the indicated radiation level to verify that the alarm and tripping of the
effluent trip valve occurs at the required setpoint. However, in 1996 the licensee changed
procedures SP 2404AA, SP 2404AC, and SP 2404AP to perform the Channel Functional
Test using a two step process. In one step, background rediation is used to cause an alarm
and tripping of the effluent trip valve. This is accomplished by lowering the digital setpoint
to a value slightly below background. When the test is complete, the setpoint is restored
to its original value. The second part of the test involves using a check source to verify the
detector response to increased radiation and is verified on the radiation monitor count rate
display. The licensee also changed procedure SP 2404AR to specify setting the Rad
Conversion Factor to one (1) via the keyboard which causes the displayed background
radiation to increase above the existing setpoint value which causes an alarm.
_ _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ - --
.
.
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18
The inspector had concerns whether using the check source as the " simulated signal"
satisfied the TS 1.11 definition because the strength of the check source is not sufficient
for the radiation monitor te reach its alarm / trip setpoint. This necessitates lowering the
radiation monitor setpoint below background, or changing the Rad Conversion Factor,
rather than increasing the simulated signal frequency to verify the alarm and trip functions
at the established setpoint. The licensee's method tests the functioning of the digital
software portion of the circuit but does not fully test channel operability because the ability
of the analog-to-digital portion of the circuit to process the count rate signal at the higher
pulse frequency is not verified. After evaluating the inspector's concerns, the licensee
prepared a Millstone Unit 2 Position Paper that indicates that they believe they are in
compliance and also meet the intent of TS definition 1.11.
Unit 3
When the inspector learned that Millstone Unit 3 performed the surveillance for their
radiation monitors in a similar manner, the licensee was requested to write a site-wide
condition report to document the concern. As reported in Unit 3 Licensee Event Report
(LER) 50-423/97-62, the surveillance procedures associated with 13 radiation .nonitors
were found to be inadequate in that the method used to satisfy the TS Channel Functional
Test for digital radiation monitors was contrary to the TS definition for an Analog Channel
Operational Test (ACOT). TS definition 1.36 specifies that an " ANALOG CHANNEL
OPERATIONAL TEST wall be the injection of a simulated signal into the channel as close to
the sensor as practicable to verify OPLAABILITY of alarm, interlock and/or trip functiors.
The ANALOG CHANNEL OPERATIONAL TEST shall include adjustments, as necessary, of
the alarm, interlock and/or Trip Setpoints such that the Setpoints are within the required
range and accuracy."
LER 50-423/97-62 specified that the radiation monitors that are affected are those for
when ACOT surveillance has been implemented in a manner where the test does not
perform a setpoint verification within a required range and accuracy. For the affected
equipment, the ACOT is implemented by performing a sourco check, and then increasing
the conversion factor until the alarm trips. The setpoints are therefore not verified within
required range and accuracy using a simulated signal.
The following is a list of equipment and the associated TS section affected.
Eauioment: Acolicable TS Section and Descriptions:
3 CMS *RlY22A & B TS 3/4.3.3.1, " Radiation Monitoring for Plant Operations, " Table 4.3-
3, item 1.b, "RCS Leakage Detection," 4.4.6.1.a.
3CND-RlYO7 TS 3/4.3.3.9, " Radioactive Liquid Effluent Monitoring
Instrumentation" Table 4.3 8, item 1.a, " Waste Neutralization Sump
Monitor - Condensate Polishing Facility."
3DAS-RlY50 TS 3/4.3.3.9, " Radioactive Liquid Effluent Monitoring
Instrumentation"is ' Turbine Building Floor Drains."
- - _ _ _
_ _ - _ _ _ . _ _
.
.
..
19
3HVC"RlY16A TS 3/4.3.2, " Engineered Safety Features Actuation System
Instrumentation," Table 4.3-2.7.e Control Building Outside Air inlet
Radiation Monitoring.
3HVC*RlY16B TS 3/4.3.2, " Engineered Safety Features Actuation System
,
Instrumentation," Table 4.3-2.7.e Control Building Outside Air inlet
l Radiation Monitoring.
3HVQ-RlY49 TS 3/4.3.3.10, " Radioactive Gaseous Effluent Monitoring
Instrumentation," Table 4.3-9, item 3a. ,
3HVR*RlY10B TS 3/4.3.3.10, " Radioactive Gaseous Effluent Monitoring j
instrumentation," Table 4.3-9, item la. Venti!ation Vent Stack '
(Turbine Building) Effluent Radiation Monitoring.
3RMS*RlY41 &42 TS 3/4.3.2.1, " Engineered Safety Features Actuation System
! Instrumentation," Table 4.3-2, item 3.c, " Purge Isolation."
Containment Area Purge and Exhaust isolation Radiation Monitoring.
Fuel Drop Radiation Monitors.
3RMS-RlYO8 & 36 TS 3/4.3.3.1, " Radiation Monitoring for Plant Operations," for " Fuel
Storage Pool Area Monitors."
3LWS RlY70 TS 3/4.3.3.9, " Radioactive Liquid Effluent Monitoring
l Instrumentation" for " Liquid Waste Monitor."
3SSRBlYO8 TS 3/4.3.3.9, " Radioactive Liquid Effluent Monitoring
instrumentation" for " Steam Generator Blowdown Monitor."
As a result of this condition, the affected radiation monitors were declared inoperable. The
radiation monitoring system ACOT procedures have since been revised to utilize a pulse
generator. Tile licensee stated that the revised surveillance tests have been performed
satisfactorily and that the affected radiation monitors are now considered operable.
Unit 1
l l
The inspector reviewed all channel functional tests for radiation monitors and found that
the procedures specified using a pulse generator. Therefore, the inspector found the Unit 1 ;
surveillance to be acceptable. !
c. Conclusions
The NRC concluded that the Unit 1 surveillance that perform a Channel Functional Test of
radiation monitors were acceptable. For Unit 2, the inspector's concern whether the
, surveillance procedures associated with digital liquid and gaseous effluent radiation
I
monitors satisfied the TS 1.11 definition for a Channel Functional Test is considered
unresolved pending review of the Millstone Unit 2 Position Paper by an NRC regional
specialist inspector. For Unit 3, the NRC concluded that the surveillance procedures
associated with 13 radiatiun monitors were inadequate in that the method used to satisfy
the TS Channel Functional Test for digital radiation monitors was contrary to TS definition
1.36 for an ACOT. Although Unit 3 corrective actions are complete, this issue is also
considered unresolved at Unit 3 to allow completion of the NRC review of the Millstone
Unit 2 Position Paper. (Unresolved items 50-336:423/98-206-03)
i - _ _ _ _ _ _ . _ _ _ _ - _ _ _ - - _ . _ ___ _ _ -
. _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ______ - __-____ - - - _ - --- - --
.
.
..
20
U2 M8 Miscellaneous Maintenance issues
M8.1 (Closed) URl 336/90-18-01 & URI 336/90-18-03: Closure of Past Persennel
Performance issues
!
'
This writeup documents the closure of two open items that were generated in 1990 that
were never formally closed in an NRC inspection report. Unresolved item 50-336/90-18-01
concerned a reacar trip that occurred on August 27,1990, when a reactor operator did
not follow the surveillance procedure for the reactor protection system (RPS) in that he did
not bypass the RPS channel as specified. Unresolved item 50-336/90-18-03, was opened
for the licensee to address collectively a number of personnel performance errors that
occurred in 1990. These items are being administratively closed because followup of the
specific personnel error events that occurred in 1990 would not be of value in assessing
- urrent licensee performance. More recent personnel performance issues are captured on
the Unit 2 Significant items List and will be assessed by the NRC prior to restart.
Reoort Details
Summarv of Unit 3 Status
Unit 3 remained in cold shutdown (Mode 5) status throughout this inspection period.
Licensee recovery efforts, Independent corrective Action Verification program (ICAVP)
inspection activities, NRC team inspections and review of Significant items List (SIL)
closure packages all continued during this period. The licensee began addressing Mode 4
equipment operability issues and, near the end of this inspection period, preparing the unit
for heat-up to higher modes, utilizing a reactor coolant pump as the augmented reactor
coolant system heat source.
On January 8,1998, the licensee declared Unit 3 " physically ready for restart", a major
milestone defined as successful completion of the integrated leak rate test (ILRT) o' the
containment building. Over the next several weeks, the licensee continued operational
readiness efforts, as well as supporting an NRC Tier 1 In-scope system design and licensing
bases inspection of ICAVP activities, conducted from January 5 through February 6,1998,
and a NRC Corrective Action (reference: NRC inspection procedure 40500) inspection,
conducted from February 9 through 20,1998. Other significant NRC team inspections
(e.g., emergency preparedness, motor operated valves) were conducted during this period
and will be documented in separate NRC inspection reports. The NRC also dedicated
several inspection resources to the review of SIL packages, as is reflected in the update
and closure of several SIL items documented in the following report sections.
On February 26,1998, Mr. B. Kenyon, the Northeast Nuclear President and Chief
Executive Officer, announced that Mr. D. Goebel had resigned as Vice President of Nuclear
Oversight and that Mr. J. Streeter, who had been serving as the Manager of Projects for
the Employee Concerns Program (ECP), would become the Nuclear Oversight Recovery
Officer, effective March 9,1998.
___-
.
.
..
21
On March 2,1998, shortly after the conclusion of this inspection period, the licensee
submitted a Reply to the Notice of Violation (NOV) and Proposed imposition of Civil
Penalties (CP) issued by the NRC on December 10,1997. In its docketed response letter
(B16996), the licensee did not contest the violations or the civil penalty proposed by the
- NRC. Closure of several escalated enforcement items (Eels) are documented in the
following sections of this inspection report. These closed Eels are identified with a NOV
letter unique identifier that was listed for each violation in the NRC NOV/CP letter. While
certain Eels have been technically closed, the associated NOVs, each with its own five-
digit unique identifier, currently remain administratively open until the NRC reviews the
licensee's response letter and determines the need for additional inspection review.
U3.1 Operations
U3 01. Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspector conducted frequent reviews of plant
operations, including witness of operational evolutions in the control room; walkdowns of
the main control boards; inspection-tours of equipment in the various plant buildings;
observation of maintenance planning, plan-of-the-day, and shift turnover meetings; and
{
review of the operations decision-making process involved with operability determinations .
,
- (ODs), reasonable expectation of continued operability (RECO) determinations, and shift
l management decisions related to the conduct of ongoing tests potentially impacted by
equipment problems. Specifically, the inspector observed operational protocol, procedural
adherence, and the control of shutdown risk during normal and backshift hours during
routine Mode 5 operations; as well as the conduct of the ILRT, loss-of-offsite-
l power / engineered safety features testing, recirculation spray system modification /in-service
testing, and configuration management plan (CMP) activities related to readiness of the
plant for Mode 4/3 heat-up implementation. ,
!
The inspector noted effective interfacing between operations shift management and the l
l technical engineering group, the Nuclear Oversight department, and the Plant Operations
l Review Committee (PORC), relative to a matter affecting emergency diesel generator (EDG)
(' operability. This problem involved a question on the adequacy of EDG relief valve testing, l
l as documented in condition reports, CRs M3-98-0366,98-0585, and 98-0679. While j
l Nuclear Oversight personnel raised some valid concerns, and technical support personnel !
worked with the appropriate vendor to identify an adequate disposition, the responsible- I
operations shift manager sought the advice of the Unit 3 PORC with respect to an ongoing i
EDG RECO. The Shift Manager retained responsibility for the final decision, but
appropriately sought input from various expert sources. Subsequently, OD MP3-014-98
was issued and approved by PORC to address the identified nonconforming condition and
specify the necessary corrective and compensatory measures.
i
The inspector also reviewed the minutes for over 20 PORC meetings conducted in January
and February,1998; and examined and discussed with the cognizant manager a PORC
_ _ . _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ - _ - _ -
.
1
I
..
22
l presentation of system readiness reviews for Unit 1 systems required to support a Unit 3
l mode change. The Nuclear Safety Assessment Board (NSAB) minutes for Meeting 98-02,
conducted January 28 and 29,1998 were specifically reviewed to determine the NSAB
perception of the Nuclear Oversight department interface with unit line organization on j
operational work control, and outage management issues. Overall, a positive relationship !
was noted, but efficiency and scheduler goal implementation were noted to be challenges
to the operational readiness of the unit.
The inspector noted the Nuclear Oversight surveillance activities of the Conduct of
l
Operations, including control room protocol and the status of main control board
deficiencies. The Nuclear Oversight monthly reports for January and February,1998 were
reviewed to keep current with the Nuclear Oversight Restart Verification Plan status,
including the Unit 3 readiness assessments, progress toward Mode 4, and acceptability of
the Startup and Power Ascension Program. On February 2,1998, the licensee submitted j
to the NRC the Unit 3 Operational Readiness Plan (Revision 5), which provides for the unit {
management's assessment of restart readiness with the evaluation of five major restart
elements.
The inspector noted that several assessment programs and activities are in progress tc
evaluate the readiness of Unit 3 systems, organizations, and overall operational status, as
the unit gets ready for transition from a predominantly engineering and maintenance
oriented outage to an operational plant. While progress has been demonstrated and
l
Nuclear Oversight involvement is clearly in evidence, the backlog of documentation and
work items continues to present a challenge to daily operations and emerging problems
have presented obstacles to operational readiness. Despite scheduler setbacks, the
l operators on shift, supported by plant management, have controlled shutdown risk well and
have conservatively approached identified problem areas in the conduct of routine
, operations and planned tests and operational evolutions.
l
l U3 02 Operational Status of Facilities and Equipment
O2.1 (Closed) Insoector Follow-uo item. IFl 50-423/96-08-15 and LER 97-041: Reauired
Number of Service Water Pumps (Update - SIL ltem 75) i
, a. Insoection Scone (92901)
l
l The NRC staff reviewed Final Safety Analysis Report (FSAR) change request 95-MP3-62,
which documents the evaluation of an event affecting the design basis of the spent fuel
pool. Specifically, the FSAR change would have documented a "what if" question
regarding the consequences of intentionally removing one service water pump from service
i to perform maintenance. The licensee, at the time, believed that the analyzed event
I
represented a situation beyond the design basis of the plant and the recommended changes
did not reflect an unreviewed safety question. In inspection Report 50-423/96-08, dated
December 3,1996, the staff reviewed FSAR change request 95-MP3-62 and indicated that
the questions involving the need for more service water pump flow capacity than could be
provided by one pump needed to be addressed by the licensee before plant startup and
considered the issue an inspector follow-up item (IFl 50 423/96-08-15). In a voluntary
.
s
..
23
Licensee Event Report (LER 97-041), dated June 10,1997, the licensee stated that when
an individual service water pump was removed from service for maintenance, the service
'
water system may have been placed in a condition where, following a design basis loss-of-
coolant accident (LOCA) and with a single failure, the service water system may not have
been able to support the assumed spent fuel pool load several hours after the accident.
Therefore, the licensee stated that an operable service water train will be defined as two
pumps per train. Although the licensee has canceled FSAR change request (FSARCR) 95- !
MP3-62, the staff reviewed the licensee's past documentation to assess the consistency of
the plant Technical Specifications (TS) with its design basis, the adequacy of the licensee's
10 CFR 50.59 safety evaluation, and the technical adequacy of the supporting licensee
analysis.
b. Observations and Findinos
The service water system is designed with two pumps per train. TS 3.7.4 requires at least
two independen+ service water trains be operable in Modes 1, 2,3, and 4. The Bases for
TS 3.7.4 states at operability of the service water system ensures that sufficient cooling
l capacity is available for continued operation of safety-related equipment during normal and
l accident conditions. The redundant cooling capacity of this system, assuming a single
l failure, is consistent with the assumptions used in the safety analysis. Neither the TS or
the TS Bases specify the number of pumps required for a service water train to be
considered operable. A licensee deportability evaluation (90-049) evaluated this question
l and determined that only one service water pump is necessary to maintain a service water
l train operable. However, under post-LOCA conditions and a single failure of the redundant
service water train, one service water pump does not have sufficient flow capacity to cool
both th's emergency core cooling system loads and the reactor plant component cooling
water system. Since the rector plant component cooling water system provides cooling to
the spent fuel pool, spent fuel pool cooling is considered unavailable for a period of time -
under these postulated event conditions.
Both the FSAR (Section 9.1.3.3) and the original 1984 cafety evaluation report (Section
,
9.1.3) state that following a design-basis accident with loss of power. the reactor plant
! component cooling water system will not be available to cool the spent fuel poo1 coolers
.
until approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the accident. Power from the emergency dies ~e l
generators is not immediately available due to loading considerations. If possible, pool
cooling will be reinitiated at this time. In the event pool cooling is not available, it would
l take 12-15 hours before the spent fuel pool would reach its design temperature of 200
degrees. This provides sufficient time to initiate pool cooling. However, both the FSAR
- (Section 9.2.1.1) and safety evaluation report (Section 9.2.1) also state that each service
!
water pump can supply the minimum cooling water requirements during a design basis
accident with loss of power and during cold shutdown with loss of power. These
statements appear inconsistent and although it appears the staff reviewed the possibility of
one service water pump being operable following a design-basis accident with loss of
power, it does not appcar the staff addressed possible outage times for the secc,nd service
water pump in each loop.
l
L
_ . . _ . _ _ . ____ . _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ - _ - - _ - - - - - - - -
- -
.
.
..
24
Therefore the key issue is whether removal of a service water pump for maintenance
,
'
constitutes an activity which needs analysis for some allowable outage time defined by the
Millstone Unit 3 TS. The current TS only define an allowable outage time for one service
water train out of service, but does not specify the number of pumps required per train.
The licensee's proposed FSARCR 95-MP3-62 would have added a licensee-defined beyond
design basis sequence of events where the spent fuel pool would have exceeded 200
degrees and boiled for approximately 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> before cooling back down to 150 degrees.
This would have further justified that only one service water pump per train needs to be
operable and that an allowed outage time for the second service water pump in each train
was not needed.
The staff reviewed FSARCR 95-MP3-62 and noted that in the discussion concerning
whether the proposed change, test, or experiment shall be deemed to involve an
unreviewed safety question (USQ), the licensee stated that the design changes do not
increase the calculated peak clad temperature and does not significantly increase the
offsite doses due to a design-basis LOCA. Section 50.59 of 10 CFR states that the holder
of a license authorizing operation of a production or utilization facility may (1) make changes
in the facility as described in the safety analysis report (SAR), (ii) make changes in the
procedures as described in the SAR, and (iii) conduct tests or experiments not described in
the SAR without prior Commission approval, unless the proposed change, test, or
experiment involves a change in the TS incorporated in the license or a USQ. A proposed
change, test, or experiment shall be deemed to involve a USO, in part, if the margin of
safety as defined in the basis for any technical specification is reduced. Since the
licensee's safety evaluation seems to imply that the margin of safety would be reduced in
that the offsite doses due to a design-basis LOCA would increase, it does not appear this
criterion is met. Therefore, the staff would have needed more information on why this was
not a USQ. However, as stated above, the licensee has canceled the FSARCR and
committed, in LER 97-041, to define an operable service water train as two pumps per
train.
On January 14,1998, the Millstone Unit 3 Plant Operations Review Committee approved a
change to the Millstone Unit 3 Technical Requirements Manual (TRM). The change requires
that a service water train have two pumps in service to be declared operable. Therefore, if
one pump is out of service, the licensee would be required to enter TS Limiting Condition
for Operation (LCO) 3.7.4 and either restore at least two service water trains to operable
status (two pumps operating per loop) within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or be in at least hot standby within
the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. This change ensures
that for a design-basis LOCA, sufficient service water flow will be available for cooling both
accident mitigating equipment and the spent fuel pool.
The licensee has also committed to change the Millstone Unit 3 TS to reflect the TRM
change. This would clarify that two service water pumps are needed per train for the * rain
to be declared operable.
. _ _ _ _ _
-_
,
-.
.
...
l 25
i c. Conclusions
The staff has reviewed the licensee's corrective actions regarding voluntary LER 97-041
and the subsequent TRM change and finds them conservative and appropriate. The i
licensee has committed to submit a TS change in the future to add allowable action times '
for the service water pumps to be out of service. Therefore, based on the above, the staff
- finds the licensee's resolution adequate. Based on these findings, both IFl 50-423/96-08-
l 15 & LER 97-041 are considered closed. The Office of Nuclear Reactor Regulation will
track the licensee's commitment to submit a TS change. SIL ltem 75 is hereby updated.
t
l U3 03 Operations Procedures and Documentation - Unit 3 (Closed - SIL 86)
l
l 03.1 Procedure Review Reaardina Desian Chanaes
j a. Insoection Scone (37700. 37701) i
l'
'
The inspector reviewed the design changes identified for training and a listing of
other changes for potential impact on Westinghouse Owners Group (WOG) related
Emergency Operating Procedures (EOP). A sampling of changes to other
.
emergency / abnormal and normal opeiating procedures were also reviewed. This
distinction between "WOG" and "other" EOPs was made because Millstone uses the
term Emergency Operating Procedure for more procedures than those addressed by
.
the WOG emergency response guidelines. A sampling review of changes to l
l procedures for reasons other than plant modification was also performed. The
.
! inspector verified by telecon that pending procedure changes were completed as of
the date of this report.
b. Observations and Findinas
l Of the changes reviewed, the inspector focused on the following changes that
warranted procedural revision.
L
l e Recirculation Sorav System (RSS) Desian Chanaes
The inspector reviewed c,even design changes related to the RSS and
determined that only one EOP rated a change to plant operation was
necessary. This change was that the procedure no longer required shutting
the spray header isolation valves for two of the four RSS pumps during the
l swapover to cold leg recirculation. Prior to changes of the RSS, the
procedure for swapover would align two RSS pumps to the suction of the
charging and SI pumps, and leave two RSS pumps dedicated to containment
spray. This was no longer acceptable because the modifications reduced
RSS pump maximum flow; and, in the event of a single failure of one of the
dedicated spray pumps, the remaining pump would no longer provide
adequate spray. flow.
_ - _ - _ _ _ _ _ _ _ - - _ - _ - _ - _ _ - _ - _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ - - - _ - - - _ _ _ _ _ _ _ _ _
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!
l The inspector performed a step by step comparison of ES-1.3 " Transfer to
l Cold Leg Recirculation" Revision 6 and Revision 7. The new procedure
revision leaves all spray header isolation valves open during and after the
alignment for cold leg recirculation, resulting in two RSS pumps dedicated for
- spray and two pumps simultaneously providing both spray and SI/Chg pump
! suction flow. Leaving these valves open during the realignment avoids
l having the plant transition through a lineup where a single failure could result
l in inadequate spray flow. The remaining changes to the procedure consisted
I of reordering of steps, moving actions out of cautions, and clarity
I
enhancements. The net effect was fewer required manipulations since the
RSS spray header isolation valves are no longer operated during the
alignment.
i
'
e Reduction in Cold Overpressure Protection SvstemiCOPPS) Enablina
Temperature.
This was a technical specification change, not a physical plant modification.
The inspector reviewed changes to the following procedures involving plant
l
cocidown and determined these changes were adequate: _
ECA 3.2 SGTR with Loss of Reactor Coolant Saturated Recovery Desired, j
FR-P1 Response to imminent Pressurized Thermal Shock,
ES-3.2 Post SGTR Cooldown Using Blowdown,
'
ES-1.2 Post LOCA Cooldown and Depressurization,
EOP-3509 Fire Emergency, and
OP3208 Plant Cooldown.
i
l
e Station Blackout / Instrument Air
Current procedure ECA-0.3, Loss of All AC Power - Recovery with the
Station Blackout Diesel, assumes that instrument air will be available from
! the shutdown instrument air compressor. This procedure has the operator
start the compressor, then supply cooling water when sufficient air pressure
is available to operate the necessary valves. As a result of a design basis
t
review, the facility determined that, if this was actually done, the shutdown
instrument air compressor would probably be damaged by the sudden supply
of cooling water to the hot compressor.
The inspector reviewed the facility station blackout coping study and the
revised ECA-0.3 to ensure that equipment assumed to be available was
addressed. The inspector verified that the new procedure charging lineup
does not require instrument air, and those areas indicated in the coping study
as having HVAC available still do have HVAC available through motor
operated dampers or dampers that fail to the required position.
_ _ _ _ _ - _ _ _ _ _ _ - - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ - _ _ _ _ _ _ - _ - _ -
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27
e Main Feed Pumo Trio on Reactor Trio
The facility changed the main feedwater pump trip logic to incorporate a
pump trip on reactor trip from greater than 25% power. The purpose of this
trip was to alleviate water hammer resulting from the existing reactor
trip / low T-ave feedwater isolation. The inspector verified that this trip was
addressed in ES-0.1 Reactor Trip Response.
c. Conclusions
The facility reviewed plant modifications installed during the outage. Existing
procedures were appropriately evaluated and changed where necessary.
05 Operator Training and Qualification - Unit 3
05.1 Ooerator Trainina Reaardina Desion Chanaes
a. Insoection Scone (37700. 37701)
The inspector assessed the training requirements for the design changes installed in
unit 3 since the outage began; The inspector selected design changes based on
their impact on operations and in particular those with the greatest impact on
safety. The inspectors reviewed the methodology used by Training Department in
determining what were appropriate to conduct operator training. The inspector also
assessed the current upgrades to the unit simulator to insure the operators were
training on an up to date facility.
b. Observations and Findinos
Overall the inspector chose 43 design changes to assess. For 26 of the changes
operators had received training. The training given on each of the changes was
determined by MP3 OTBI-9 Revision 2 " Operator Training Branch Instruction, Plant ,
Design Change Training." Within this instruction, Figure 7.1 esks a series of
questions in order to evaluate the type of training. The auestions require a yes or
no answer and there are three sets of questions. The first is a series of seven
questions where, if one is answered yes, then a shift briefing is required. The
second is a series of four more questions where, if one is answered yes, then formal j
classroom and/or simulator training is required. And the third is one question "Does
the change involve new skills and knowledge" which, if answered yes, requires
training prior to taking the shift.
The inspector used the above criteria to assess the changes that did not receive
training (17 of 43) and concluded that training was not required in all but one
change. Although none of the questions could be answered yes, the inspector
questioned if a complete change to the internals of the service water pumps should
l not be brought to the operators attention. The pumps would start the same way as
! prior to the change, however, the newly renovated pumps had improved
.
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28
characteristics for more reliable operation. The inspector had discussions with the
training department representatives regarding this type of change. They agreed to
re-assess the current criteria regarding training on equipment that has been
upgraded, but operates the same overall. During the period of preparing this report,
the licensee sent documentation showing shift briefings, conducted for the
operators, on the above subject.
Training in the classroom consisted of the reason for the change, and its impact on
plant operations. Instructors used written text with the aid of revised plant
drawings and in plant pictures, (taken before and during the installation of the
components) to discuss the changes. The Instructors then discussed changes
made to the procedures. Required hands-on simulator training was then conducted
reinforcing the classroom training. The inspector noted that not all training required
I simulator training, however, training was given on the complex changes. These
included the seven design changes required to the recirculation spray system due to
l the resolution of an unresolved safety question involving the single failure of the
l loss of service water to one of the recirculation spray coolers.
l
l- Ths simulator training consisted of static observations and hands-on training. The-
simulator would be set to an operating condition; and, depending on the change, the
operators would manipulate the controls for the change being demonstrated, or
assess static conditions created by stopping the simulator at key points throughout
l the demonstration. Each session was followed by pertinent questions related to the
change.
Shift briefings were conducted when called for by the training department
l assessment of the design change. The inspector concluded, by interviews, that the
material was getting to the shifts via this method, but noticed a decline of the
actual briefincs and a substitution of read and sign being used by the shifts.
Discussions with operations management brought about a self assessment which
showed the probable cause to be attributed to the additional work being performed
in preparation for plant start up. Prior to the end of the inspection, the operations
manager sent a memo to all shift managers directing them to conduct shift briefings
in person rather than by read and sign.
The inspector reviewed written testing, that was being conducted at the time of the
inspection, and determined that the questions were in keeping with good
requalification type questions and were indicative of the training conducted for the
l design changes.
During the review of the above mentioned design changes, the inspector reviewed
documentation that showed the simulator had been upgraded to the plant "as
installed" conditions. The instructor also had discussions and a walkdown of the
simulator to verify the simulator changes. Interviews of an operating crew
substantiated the effectiveness of the training.
l
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29
c. Conclusions
The operators at unit 3 were receiving good training on design changes to the
facility. Training was being conducted in a timely manner with detailed input from
the training department. A minor problem was noted with shift briefings used for
training. The unit simulator was upgraded to the present plant configuration
regarding the design changes inspected.
07. . Quality Assurance in Operations - Unit 3
07.1 ' Ooeratina Exnerience Review
. a. Insoection Scone (92901)
The inspector reviewed the licensee's status of actions in response to inspection
Notice (IN) 97-78, " Crediting Operator Actions in Place of Automatic Actions and
Modifications of Operator Response Actions, including Response Times," dated 1
October 23,1997, to determine what actions the licensee was taking to review the i
notice.
b. - Observations and Findinas
The inspector discussed the licensee's disposition of IN 97-78, with members of the
Licensee's Nuclear Safety Engineering (NSE) and Unit 3 Operator Training l
' departments. ' The inspector reviewed licensee procedure (NSE Instruction 3.01
" Operating Experience Review," Revision 5) and the licensee's tracking system for
the disposition of items identified by the NSE. These reviews showed that the.
licensee had initiated a program to review the Unit 3 Conduct of Operations
Procedure, Form 3260, and the Unit 3 Final Safety Analysis Report (FSAR) Chapter-
15, Accident Analysis, to determine what timed dedicated operator actions were
defined for plant operation and what operator actions have been credited in the
accident analysis. The licensee's intentions are to perform engineering analysis on
the findings, then use the analyzed information to upgrade the operating and training
procedures for operator information and realistic approach to the times indicated in
the FSAR. The inspector determined this was to take place over the next two
months.
c. Conclusions
.The licensee considered the information provided in IN 97-78, and was in the
process of reviewing operator actions associated with Unit 3 for applicability to the
IN. The licensee indicated this would take approximately two months. No
deficiencies associated with the licenseo's review to date were identified.
07.2 Disposition of Independent Corrective Action l
a, insoection Scoos (92901)
The inspector reviewed the licensee's disposition of two condition reports (CRs)
generated by the licensee's Independent Corrective Action Verification Program
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.
.
...
30
(ICAVP) pertaining to the crediting of operator actions for specific FSAR accident
analysis mitigation strategies (i.e., CR-M3-98-0328 - isolation of auxiliary feedwater
to a faulted steam generator within 30 minutes, and CR-M3-98-0329 -isolation of
a steam generator following a locked rotor event within 20 minutes). The CRs were
written as a result of the ICAVP determining that the operating procedures and
training materials did not mention the assumed times, and the operators were
therefore not cognizant of the need to perform the required actions within the
assumed time frames,
b. Observations and Findinos
. The inspector discussed the licensee's disposition of the CRs, with members of the
Licensee's Nuclear Safety Engineering (NSE) and Unit 3 Licensed Operator Training
departments. The licensee had completed a preliminary review of the Unit 3 Final
Safety Analysis Report (FSAR) Chapter 15, Accident Analysis, to determine what >
operator actions have been credited in the accident analysis. The licensee noted .
that when the list wt.s completed, a process would be implemented (in accordance
with the Unit 3 Nuclear Training Manual (NTM), Sections 2.01, 2.02, 3.01, and
3.02), to evaluate and develop job performance data and task selection data for
each of the credited operator tasks. The NTM process will then be used to
determine if any additional information regarding the credited operator tasks must be
incorporated into the licensed operator training program and which actions will be
added to the current list of critical operator tasks. In addition to the training effort,
the licensee was planning to review the completed list to ensure the chapter 15
accident analysis as well as other FSAR assumptions for crediting operator actions
were still valid and to ensure applicability to the IN 97-78.
c. Conclusions
The licensee considered the CRe in response to the ICAVP findings and had taken
reasonable actions to disposition the concerns. No deficiencies associated with the
licensee's actions regarding these issues were identified.
U3 07 Quality Assurance in Operations
07.3 Review of NUREG-0737. TMl Action Plan Requirements (Update - SIL 38) ;
1
l
The NRC originally reviewed the implementation status of the NUREG-0737 items in the
MP3 Safety Evaluation Report (SER), in its supplements (SSERs), and in inspection reports
prior to and subsequent to the issuance of the original license in January,1986. In j
inspection reports 423/97-207 and 208 NRC reviewed the current implementation status of l
certain NUREG-0737, TMl items. That review is continued herein.
The inspector noted in the above reports that FSAR Tab!e 1.10-1 and a number of the ;
referenced FSAR sections are not completely up-to-date with respect to the TMI items. l
The licensee stated that Table 1.10-1 and the specific referenced FSAR sections would be
updated to reflect the current status of each TMl item. Relative to the items reviewed ,
i
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1
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31
below, Table 1.10-1 needs to be updated for items ll.B.4, ll.E.1.1, ll.E.4.2, and ll.K.3.9.
For : tem II.B.4 the Position column of the Table is the only place in the FSAR where the
current status of the item is noted; and the sections noted in the FSAR Reference column
do not exist anymore.
As a summary of the review performed to date on this SIL item, the licensee performed a
detailed review of the current implementatic,n status of each NUREG-0737, TMI item, as
documented in Engineering Report, ME-ERP-970013, Rev. O,10/6/97. The licensee's
review found that Unit 3 was in compliance with 49 of the 56 items. CRs were written for
, . the other seven items that required action to bring the unit into compliance. These seven
l were thus considered not ready for NRC rr, view when review of this SIL began and none
had been submitted for review by the end of the inspection period. As part of the SIL 38
review the NRC has to date reviewed 36 items and closed 27, leaving 9 items with open
issues. Five of these 9 were previously reported. The remaining four of 9 are discussed
- below. Five other items were separately reviewed by NRC inspectors or teams.
NUREG 0737 II.B.4 Trainina for Mitiaatina Core Damaae
Per this item, licensees are required to train personnel in the use of installed equipment and .
systems to control or mitigate accidents in which the core is severely damaged. Personnel l
to be included in the training are from operations, I&C, health physics, and chemistry. !
This item was initially reviewed and closed in inspection report 423/85-52. The inspector
l discussed the current core damage mitigation training with training department personnel
and reviewed the lesson plans. There is an 80 hour9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> series of lessons for this topical area
- with an additional two hours for inadequate Core Cooling (ICC) system training. The core
l mitigation lesson plans are based on generic Westinghouse PWR training and that training
l
is followed by four weeks of Unit 3 specific EOP training. This is acceptable. ,
1
NUREG 0737 II.D.1 Testina Requirements for Reactor Coolant Svstem Relief and Safetv
Valves
This item required a demonstration that the pressurizer power operated relief valves
l
(PORVs), safety valves, and block valves will function adequately under design basis
accident and transient conditions. Testing was performed by the Electric Power Research !
Institute (EPRI) for the licensee and reports were submitted to the NRC. The NRC reviewed
j and approved these in the SSER as part of original licensing. The block valves were l
l- somewhat different from those tested by EPRI, and Millstone was requested to perform
l ' insitu tests of the block valves. This was performed as part of initial startup testing end
documented in a letter to the NRC, B12607, Question #6, dated July 21,1987.
. Additionally in 1990, the NRC issued Generic Letter (GL) 90-06, " Resolution of Generic
issue 70, ' Power-Operated Relief Valve and Block Valve Reliability,' and Generic issue 94,
' Additional Low-Temperature Overpressure Protection'." As a result of the Generic !ssue
- 70 aspects of this GL, the licensee committed to treating the PORVs and block valves as i
Category 1 components, to include the valves in the inservice test program, to include the
block valves in the GL 89-10 motor-operated valve test program, and to modify the
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32
Technical Specifications (TS) for the PORVs and block valves. The TS were modified in
Amendment 88. Subsequently, as part of the GL 89-10 reviews and tests performed for
the block valves, the licensee identified potential design limitations and issued LER 96-019.
This resulted in a design modification to replace the valves with an upgraded design. This
LER and issue are being tracked by SIL ltem 26. l
Unit 3 states in the FSAR that the Anticipated Transient Without Scram (ATWS) testing 1
portion of this item did not apply. The inspector noted that, at the time of the issuance of
the ATWS rule, the NRC dropped this portion of NUREG-0737 Item II.D.1.
The inspector also reviewed the PORV vendor manual, the inservice testing program,
procedures, and recent test results for the PORVs, SVs and the block valves. No
discrepancies were noted.
e This information acceptably addresses this item.
NUREG 0737 II.D.3 Relief and Safetv Valve (SV) Position Indication
This item calls for positive indication in the contrci room for the RCS relief and safety
valves. This should include both valve position indication (PI) and flow in the discharge
pipe.
This item was originally reviewed and approved in the SER and Inspection Report 423/85-
62. The inspector observed the valves and Pl devices in containment in the pressurizer
cubicle, observed the valve indications and related alarm windows in the main control
room, and reviewed the pertinent annunciator response procedures. This review included
. PORV and SV open and closed lights, discharge line temperature indications, and alarms for
high discharge temperature and discharge flow. The PORV PI lights are derived from
magnets that sense valve movement. The SV PI lights are based on heated junction
thermocouple that sense flow downstream of the SVs. The inspector also reviewed
surveillance test results for the Pl of the PORVs and block valves and noted that test
results were satisfactory. However, the procedure did not provide for specific
documentation of the Pl, but rather relied on inferred information from operator training and
satisfactory operation of the valve itself. The licensee initiated a procedure change to add
the specific documentation. This is acceptable.
NUREG 0737 II.E.1.1 Auxiliarv Feedwater (AFW) Svstem Evaluation
This item called for an evaluation of the AFW System to ensure appropriate reliability and
to ensure that it complies with the pertinent sections of the Standard Review Plan (SRP)
and Branch Technical Positions.
1
The licensee provided this information to the NRC in FSAR Section 10.4.9, which was )
reviewed and accepted by the NRC in SER Section 10.4.9 and Inspection Report 423/86- !
08. The inspector reviewed this information, the current FSAR description, and relevant
procedures. The inspector also discussed the system operation with operations personnel ;
and observed the AFW instrumentation controls, displays, and alarms in the main control j
!
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33
room. The current arrangement agreed with the FSAR and the SER. No discrepancies
were identified; this is acceptable.
! NUREG 0737 II.E.1.2 Auxiliary Feedwater System Automatic Initiation and Flow Indication
This item addresses the automatic initiation signals, circuitry, and flow indication for the
AFW system. It specifies a number of areas that must be addressed and states further
that the objective of the initiation portion of the item can be met by providing a system
that meets all the requirements of the Institute of Electrical and Electronics Engineers (IEEE)
Standard 279-1971.
The licensee addressed this item in FSAR Tables 1.10-1 and 1.8-1 and in Sections 7.3 and
10.4.9, which was reviewed and accepted by the NRC in SER Section 7.3.3.1 and
Inspection Report 423/85 62. The inspector reviewed this information, the current FSAR
description, and relevant procedures. The inspector also discussed the system operation
with operations personnel and observed the AFW instrumentation controls, displays, and
alarms in the main control room. The current arrangement agreed with the FSAR and the
SER with the exception of manualinitiation in accordance with paragraph 4.17 of IEEE
Standard 279 and Regulatory Guide 1.62. The licensee does not have a system level
manualinitiation of AFW as specified in the IEEE Standard and Regulatory Guide (RG).
Some places in the FSAR take partial exception to portions of IEEE 279 and the RG and
also describe the AFW initiation arrangement. However, they do not all clearly state what
the exceptions are and what is required for AFW manual initiation, including all actions that
are accomplished by the automatic initiation. The inspector verified through discussions
with the NRR Project Manager that the current physical design was acceptable. This item
remains open pending correction of the FSAR descriptions.
NUREG 0737 II.E.3.1 Emeroencv Power Sunolv for Pressurizer Heaters
This item calls for some pressurizer heaters to be supplied from redundant emergency
power sources in order to be used for natural circulation cooling. The heaters' motive and
control power interfaces should be safety grade. There should also be appropriate
procedures and training. Cont ol of these heaters should be available in the main control
room. The heaters must be shed from the emergency buses on a safety injection actuation
signal.
This was initially reviewed and verified in the SER and SSER and in Inspection Report
423/86-08. The inspector verified that two banks of pressurizer heaters (3 RCS*H1 A and
3 RCS*H1B) of sufficient capacity were powered from redundant 480 volt emergency
buses (32S and 32V). These two heater banks are classified as safety-related and are
supplied from Class 1E buses with safety grade control power. The inspector reviewed
MEPL determination MP3-CD-1000, which clearly stated that the functions of these two
heater banks were credited for safe shutdown and hence were safety related. The
inspector noted that Table 8.3.3 of the FSAR incorrectly lists these two heater groups as
non-safety-related. The inspector also raised this question for other components in the
Table. At about the same time, the licensee identified a similar problem and issued CR M3-
98-0411. The emergency procedures (including natural circulation cooling) address the
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34
pressure control in various circumstances, which may include use of heaters. The
inspector observed the heater controls in the main control room and discussed their use
with control room operators. Calculations have been performed for the EOPs that verify
sufficient loading capability on the emergency diesels to power the pressurizer heaters
when needed. This item remains open pending correction of FSAR Table 8.3.3.
NUREG 0737 II.E.4.1 Dedicated Hydroaen Penetrations
This item calls for dedicated containment penetration systems for external hydrogen
recombiner systems or as an alternative a containment penetration system that is single
failure proof for containment isolation purposes and for recombiner operation. The
components supplied for this requirement must also be safety grade.
The Unit 3 design is discussed in FSAR Sections 6.2.4 and 6.2.5 and was initially reviewed
and accepted in the SER Section 6.2.5, SSER-3 Section 6.2.5, and in Inspection Report
423/85-62. FSAR Section 6.2.5 states that the recombiners are redundant and satisfy
single-failure criteria. Section 6.2.4 describes the recombiner containment penetrations as
each containing two containment isolation valves, ensuring isolation in the event of a single
active failure. Both the Hydrogen Recombiners and the Hydrogen Penetration containment
isolation valves are designated as Category 1, safety-related items for Unit 3. The
inspector observed the inside and outside containment isolation valves in the plant and
noted that the outside containment valves did not all have the new correct valve tags
attached at the valve location. The licensee investigated this and found that new tags had
been prepared but not yet hung. A number of new component tags are still in the process
of being installed. The inspector also reviewed the procedures for Hydrogen Recombiner
operation and the relevant Technical Specifications. No discrepancies were identified. This
is acceptable.
NUREG 0737 II.E.4.2 Containment isolation Dependability
This item addresses several aspects of containment isolation that are described in seven l
sub-items, related clarifications and an attachment. These were initially reviewed and j
accepted in SER, Section 6.2.4, SSER-2, Section 6.2.4, and inspection report 423/86-08. !
Each of the seven items is discussed below. l
i
item 1 of II.E.4.2 calls for diversity in the parameters sensed for containment isolation
initiation. The design for Phase A isolation was accepted as having initiation signals of
high containment pressure, low steamline pressure, low pressurizer pressure, or manual
initiation. Phase B isolation initiates on high-3 containment pressure and manually. The l
current Technical Specifications Table 3.3-3 still requires these parameters. l
Items 2 and 3 call for the definition and specification of non-essential (NE) systems and the
automatic isolation of these systems or that they be sealed closed. The FSAR in Section
6.2.4.1.1 and Table 6.2-65 defines and lists the essential and NE systems and containment i
isolation valves (CIVs). The FSAR states that all NE valves which may be open during i
normal operation are automatically isolated, while the remaining NE lines are isolated with ,
manual valves, locked closed during normal operation. The inspector reviewed the lists and i
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35
selected NE CIVs without automatic signals for verification that administrative controls
exist for sealing the valves closed. The licensee presented procedure OP 32608,
Equipment Control, and OPS Form 32608-1, Locked Component Checklist, that established
the controls to ensure that required valves are properly locked / sealed in position. All
selected valves were contained in the Checklist with two exceptions. For penetrations 1 -
4 for the Main Steam lines, valves 3 MSS *PV20A - D and vaives 3 MSS *MOV74A & B are
listed as NE, normally shut (and shut for accident conditions), and do not automatically
isolate, but they are not on the locked valve checklist. The NRC SRP has different criteria
for Essential and NE valves. The licensee investigated and identified FSARCR 97-MP3-530
which had been approved 12/5/97 but not yet entered in the FSARs. This changes the
penetrations to Essential. The inspector questioned the implications of this reclassification
I in light of the SRP 6.4.2 criteria about provisions for leakage detection for essential
l
penetrations. The NRC staff is pursuing this issue further.
Item 4 requires that the design of the CIVs be such that resetting the isolation signal will
not cause the valves to automatically reopen. For MS-3, after a containment isolation, two
operator actions are required to reopen any CIV, namely: resetting of the isolation signal
and then individually opening any desired valve.
Item 5 calls for the containment setpoint pressure, that isolates non-essential penetrations,
be reduced to the minimum compatible with normal operating conditions. For MS-3 this
signal is the Phase A isolation that by TS must be set at less than 3.0 psig. This value of
- 3.0 psig was determined and approved at initial licensing and is still the value used in the .
current TS.
Item 6 calls for the containment valves to be operable during design basis accidents and,
under certain conditions, to be maintained closed during operation. The SSER-2 verified the
operability of the valves and specified that all purge and vent valves greater than three
inches in diameter be sealed closed during normal operations and verified closed
periodically. ' TS 3.6.1.7 requires the 42 inch purge valves to be locked closed in Modes 1 -
4 and TS 4.6.1.7.1 requires them to be verified closed every 31 days. The containment
vacuum ejector suction valves for penetration 37,3CVS*AOV23 and 3CVS*V20, are eight
inch valves and are required to be locked closed by TS 3/4.6.5.1 in Modes 1 - 4. This is
addressed by procedures SP 36128.1 and 36128.2 which specify locking, removal and
venting of air, and periodic verification checks.
Item 7 calls for the purge and vent isolation valves to close on a high radiation signal.
l_ Currently, MS-3 purge and vent isolation valves do close on high radiation. This area was
separately reviewed and closed as part of SIL 70.
In summary for ll.E.4.2, the licensee has acceptably addressed all of the seven subitems,
except for the question, raised above, regarding the NE valves for the MS lines.
NUREG 0737 II.F.2 Instrumentation for Detection of Inadeaunte Core Coolina
This item calls for instrumentation that will provide unambiguous, easy-to-interpret
indication of inadequate core cooling (ICC). The instrumentation should: include reactor
,
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"
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36
water level indication, give advanced warning of the approach to ICC, cover the full range
from normal operation to complete core uncovery, be reliable, have appropriately human-
factored displays and alarms, and be integrated into procedures and training.
This item was initially accepted in the SSER and in inspection report 423/86-08. The
licensee has selected three systems to address ICC: a subcooled/superheat monitor (SSM),
core exit thermocouple (CETs), and a Combustion Engineering heated junction
thermocouple (HJTC) system. These systems are described in FSAR Section 4.4.6.5 and
are addressed in TS 3/4.3.3.6 and TRM 3/4.3.3.6. The inspector noted that nine of the 50
CETs were currently inoperable, but that the design basis, as documented in the TS, was
for only 16 total CETs or four per quadrant. The inspector reviewed plant procedures
associated with these three ICC systems, observed the systems in operation in the plant on
the SPDS, on the plant computer, and at the ICC panels behind the control room. The
inspector also discussed and observed operation of the systems and displays with
engineering, operations, and l&C personnel. A minor discrepancy was noted in OP3301K
regarding the display for subcooled margin having a (+) sign, which it does not have. The
licensee agreed to revise the procedure. Also, an inconsistency was noted between the
subcooling margin setpoints for the main board annunciator (at 15 degrees) and for the
SPDS (at 32 degrees). The licensee was unable to provide a basis for the 15 degree
setpoint, and CR M3-98-0935 was issued. No other discrepancies were identified.
NUREG 0737 II.G.1 Power Sucolies for Pressurizer Relief Valvec Block Valves and Level
Indicators
This item calls for the PORVs and block valves to be powered from safety related sources
capable of being supplied from either offsite power or onsite emergency power.
Additionally, the pressurizer levelindication instrument channels should be powered from -
the vital instrument buses.
The FSAR states that the emergency power for pressurizer equipment meets the
requirements of this item. The power for the PORVs and block valves was initially
reviewed and accepted in the SSER and IR 423/85-74.
The inspector reviewed the pertinent drawings and verified the appropriate power supplies
for the PORVs and block valves. The inspector also toured the plant and observed the
breakers were located on safety related panels. The inspector reviewed the drawings for
the pressurizer level instruments and observed the indicators and instruments in the control
room. Drawing show that all pressurizer level indicators (even though some are non-
safety-related) are powered from vital power supplies. This is acceptable.
l NUREG 0737 II.K.2.19 Seauential AFW Flow Analvsis
l
This item related to performance of a benchmark analysis of sequential AFW flow to the
'
steam generators following a loss of main feedwater. The MP-3 SER determined that this
l was not needed for inverted U-tube steam generator designs such as Unit 3 has. This is
acceptable.
L._-___ _ _ _ _ _ _ . _ _ _ _ . _ _ _ . _ _
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NUREG 0737 ll.K.3.1 Installation and Testina of Automatic Power-Onerated Relief Valve
isolation Svstem
i:
This item recommended an automatic Pressurizer PORV block valve isola' tion in the event of
a stuck open PORV. Millstone determined and documented in the original FSAR, Table
1.10-1, that this modification was not needed at Unit 3 due to the analysis and
modifications made pursuant to iterr ll.K.3.2 (and WCAP-9804) below. This is acceptable.
NUREG 0737 II.K.3.2 Reoort on the Overall Safetv Effect of PORV isolation Svstem
This item called for a report on actions taken to decrease the probability of a small break
loss of coolant accident (SBLOCA) caused by a stuck open PORV. This report should show
how these actions constitute sufficient improvements in reactor safety.
NU submitted a Westinghouse report, WCAP-9804, that is referenced in the FSAR and i
which addresses this item. The SER notes that Millstone has submitted WCAP-9804 for
, staff review. Millstone, also, states in the FSAR that they have implemented modifications
! discussed in the report, in order to decrease the probability of SBLOCA caused by a stuck
l open PORV. The modifications listed in the report are: the PlO controller modification, a
setpoint change on PORV interlock bistables, direct indication of PORV and SV position,
l changes to Emergency Operating Procedures (EOPs), and training / simulator exercises. The
inspector reviewed the PORV calibration data to verify the PID controller modification (see
ll.K.3.9 below), reviewed the direct indication in ll.D.3 above, and reviewed and discussed
l procedures and training with licensee personnel. These were all found to be acceptable.
I Section 3.4.2 of WCAP-9804 states that the setpoint change on PORV interlock bistables
only applies to 4-loop plants that have "2 out of 3," low pressurizer pressure, Si actuation
logic. Since Unit 3 has "2 out of 4" Si actuation logic, this modification does not apply.
The inspector noted, however, that Unit 3 still maintains the PORV interlock with a
setpoint of 2200 psig. If a PORV inadvertently opened at the normal operating pressure of
about 2250 psig, this interlock would close the valve when pressure had dropped to 2200
psig. This is acceptable.
NUREG 0737 ll.K.3.3 Reoortino of SV and RV Failures and Challenaes
This item calls for the prompt reporting of safety and relief valve (SV or PORV) failures and .
for the annual reporting of challenges. The licensee committed to these requirements.
Specifically f ailures will be reported in an LER and challenges will be reported in the annual
report in accordance with TS 6.9.1.2.c.
- The licensee stated that there have been no failures of the PORVs or SVs to date. The l
1990 Annual Report documents a PORV challenge during a reactor trip that occurred on
December 31,1990, where the PORV successfully opened. The inspector questioned how
valve performance is documented and tracked. The system engineer provided summary
.
deta for the SVs and the PORVs that summarized and trended valve test and performance
data. The SVs appear to be functioning as designed. The PORVs have had some problems
with position indication and minor leakage. These have been addressed by work l
!
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performed, valve replacement, indication replacement, and design changes. This is
! acceptable.
NUREG 0737 II.K.3.7 Evaluation of PORV Ooenina Probability
l
This item applies only to B&W design PWRs and hence is not applicable to MP-3. This is
acceptable.
NUREG 0737 II.K.3.9 Proportional intearal Derivative Controller Modifications
This item calls for modifications to the PID controllers for the PORVs to preclude derivative
action. MS 3 has turned off the time derivative constant for their PORVs in accordance
with Westinghouse recommendations. This was found acceptable in the SER and in irs
423/86-08 and 423/86-33.
The inspector reviewed the most recent PORV controller calibration and confirmed that the
derivative rate value was set to zero as required by the procedure. This is acceptable.
M). BEG 0737 II.K.3.11 Justifv Use of Certain PORVs
This item calls for justification for the use of PORVs manufactured by Control Components, ;
,
Inc. (CCl). MS 3 uses PORVs supplied by Garrett, not CCl, and the NRC was so notified at j
l the time of originallicensing. Garrett has subsequently been acquired by Crosby, but the j
same valves are still in use. The inspector also reviewed the PORV vendor manual, l
l Operation and Maintenance Instructions for Solenoid Power Operated Relief Valve, Crosby I
Valve & Gage Co., original manufacturer Garrett, Rev. F,8/9/94 and noted that it was
l
being appropriately controlled. This is acceptable.
07.4 Final Safety Analvsis Reoort (FSAR) Adeousev (Update - SIL 2)
a. Insoection Scoce (370011
In inspection report 50-423/96-201, the team noted six instances in which the Millstone
Unit 3 FSAR was inconsistent with other licensing- and design-beses documents,
l procedures, operating practices, or the as-built plant configuration (eel 96-201-01). As
part of the NRC's review of the Millstone Unit 3 FSAR, the inspector reviewed the
I
licensee's corrective action for these specific issues, as well as ten other FSAR changes.
The ten additionalissues were selected from letters dated October 29 and November 21,
1997, in which the licensee submitted Revision 10, Addenda 2 and 3 to the FSAR.
b. Observations and Findinas
The inspector reviewed the licensee's corrective actions for the six instances in which the
FSAR was not maintained up-to-date did not reflect the actual plant configuration or ;
'
operating practices. The inspectors findings are as follows:
(1) FSAR Section 9.4.8.1, " Circulating and Service Water Pumphouse Ventilation System"
_ _ _ _ _ - . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ -
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FSAR Section 9.4.8.1 describes the operation of the service water pumphouse ventilation
system in the summer and winter modes. The team found that the FSAR description and
the actual plant design and operating practice differed with respect to the position of the
access door and exhaust flows during the winter and summer months. In response to the
team's finding, the licensee initiated an adverse condition report (ACR) to document the
inaccuracy, and a Final Safety Analysis Report Change Request (FSARCR) was prepared to
correct the discrepancy. The inspector reviewed the change to Section 9.4.8.1 and found
it adequate in that it accurately described the actual operation and as-built design of the
service water pumphouse ventilation system.
(2) FSAR Section 8.3.1.1.6, " Alternate AC System Description"
This issue will be reviewed as part of the NRC's overall review of SIL ltems #37, 67, and
78 as they relate to Station Blackout issues, discussed, in part, in other sections of this
inspection report.
(3) FSAR Section 10.4.9.2, "AFW System - System Description"
FSAR Section 10.4.9.2 specifies a minimum recirculation flow of 45 gpm for the two
motor-driven auxiliary feedwater (MDAFW) pumps and 90 gpm for the turbine-driven
l auxiliary feedwater (TDAFW) pump. The team found that the surveillance procedures for
,
the pumps included recirculation flow acceptance criteria that were less than the minimum
I flow specified in the FSAR. In addition, the team noted that Amendment No.100, dated -
l January 27,1995, revised the technical specification surveillance test frequency for the
l
'
AFW pumps from monthly to quarterly; however, the licensee failed to initiate an FSARCR
to reflect this change until March 1996, contrary to Procedure NGP 4.03, " Changes and
Updates to Final Safety Analysis Reports for Operating Nuclear Power Plants" (NGP 4.03
has since been superseded by RAC 03).
In response to the team's findings, the licensee performed a technical evaluation to verify
the surveillance procedure recirculation flow acceptance criteria with respect to AFW pump
minimum flow requirements. The licensee determined that, based on discussions with the
pump vendor concerning the design and operation of the pumps, and the fact that the
FSAR reflected the required minimum flow values, the surveillance procedures should be
changed to reflect the FSAR requirements. The inspector verified the surveillance
procedures and found that the values listed for AFW pump minimum flow requirements
were consistent with the FSAR values,
j 4) FSAR Section 8.3.1.1.4.2.e, " Electrical System Protection - Motor Feeder, Emergency
j - Switchgear"
FSAR Section 8.3.1.1.4.2 identifies protective relay settings for electrical equipment, such ,
as panelboards, generators, transformers,6.9kV and 4.16kV buses,480V load centers, I
. and motor control centers.1 The team found that the protective relay setting criteria for ;
safety-related motors prescribed in the FSAR were inconsistent with the control setting j
sheets and criteria used in calculations. The licensee's corrective actions included a review l
of the applicable documents and resolving any discrepancies. The licensee determined that j
l
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l
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the settings in the FSAR were not correct and processed a FSARCR to correct the errors.
. The licensee also updated Specification SP-EE-269 to reflect actual instantaneous settings.
l The inspector reviewed the licensee's corrective actions and FSARCR and determined that
l the corrective actions were appropriate and that the new FSAR wording was adequate in
.
describing the intent of the protection criteria.
!
5) FSAR Section 8.3.1.2.4, " Cables and Routing Analysis"
FSAR Section 8.3.1.2.4 and Table 8.3-2 specify the allowable electrical fill for safety-
l related cable trays. The team identified five safety-related L-service cable trays that had
, electrical fill greater than the allowable one-layer depth (one-layer depth equates to 100-
'
percent fill) specified in the FSAR. The team also identified four safety-related C-service
cable trays that had electrical fill greater than 157-percent (the analyzed allowable limit). In
addition, FSAR Table 8.3-2 had not been updated to reflect the 157-percent allowable fill
l criteria for C-service cable trays.
In response, the licensee prepared an analysis that demonstrated that the installed cable
configuration for the trays was acceptable and a safety evaluation to justify the as-installed
deviations in tray fill. The licensee also initiated an FSARCR to update the FSAR to resolve
the discrepancies and to reflect the approved tray fill conditions for L-service and C-service
cable trays. The inspector reviewed the licensee's corrective actions and the FSAR change
and found them adequate. The FSARCR and associated 10 CFR 50.59 evaluation were
adequate and the FSAR properly reflects the as-installed configuration.
6) FSAR Table 6.2-65, " Containment Penetration"
FSAR Table 6.2-65 lists the AFW flow control valves'as motor-operated valves, and also
indicates that the valves fail "as-is." FSAR Section 6.2.4, " Containment isolation System,"
states that, "all air and solenoid-operated containment isolation valves f ail in the closed
position." The piping and instrumentation drawings correctly indicate that the valves are
solenoid-operated valves and that they fail open. In response, the licensee initiated a
FSARCR to correct the FSAR. The inspector review the change and its associated 10 CFR
50.59 safety evaluation and found the new wording and the table description adequate.
In addition to the corrective actions for the individual items, the licensee revised NGP 4.03
to make the following improvements: (1) FSAR changes are documented up-front when
changes to the plant design, analysis, etc. are initiated; (2) a 10 CFR 50.59 safety
evaluation screening form for FSARCRs is used to correct FSAR descriptions which are in j
conflict with plant configuration or other FSAR sections; (3) the instruction section was
clarified regarding tasks and responsibilities; and (4) a corrective action document is
initiated when FSAR errors are discovered to ensure appropriate resolution. Procedure NGP
4.03 establishes the licensee's requirements, responsibilities, and instructions for
,
processing and apprc. vino changes to the FSAR. A FSARCR is the primary form the
I licensee uses to docume * orr,'osed intent or non-intent change to the plant. Procedure
! NGP 4.03 states that any , ,; .c the FSAR requires a safety evaluation, or a 10 CFR
'
50.59 safety evaluation screening form to ensure that the basis on which the operating
license was issued is not invalide ed. The inspector reviewed NGP 4.03 and the procedure
!
,
_ _ - _ _ _ - _ _ _ _ _ _ _ - _ . _ . - - _ _ _ - - - _ _ - _ _ - _ - _ _-__-___
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41
that superseded it (Regulatory Affairs and Compliance RAC 03) and determined that
adequate guidance exists to evaluate whether a safety evaluation is needed and the areas
it must address.
l
In addition to the six instances found during the 1996 inspection where the Millstone Unit
3 FSAR was inconsistent with other licensing- and design-bases documents, procedures,
operating practices, or the as-built plant configuration, the inspector reviewed ten recent
FSAR changes documented in licensee letters dated October 29 and November 21,1997.
The inspector reviewed the FSARCRs to ensure that the proper safety evaluation (10 CFR
50.59 evaluation) was completed where appropriate, that the licensee adequately
addressed the three questions in 10 CFR 50.59, and that the licensee followed the internal
l guidance. For the FSARCRs reviewed, the inspector determined that the licensee
j adequately addressed 10 CFR 50.59 for the intent changes to the FSAR, and that the
-
classification of non-intent changes was appropriate. The inspector determined that each
specific intent change was properly addressed in the 10 CFR 50.59 safety evaluation and,
therefore, no unreviewed safety questions were identified.
!
I c. Conclusions
l
The licensee's corrective actions to address the six issues where the Millstone Unit 3 FSAR
was inconsistent with other licensing- and design-bases documents were determined to be
acceptable. The inspector also determined that Procedure RAC 03 contains adequate
guidance to ensure that the FSAR is properly maintained. Thus, eel 96-201-01 is
considered closed. However, continued review of future FSARCRs which resulted from
modifications and changes made during the current outage, review of the FSAR during
future NRC team inspections, and review of the FSAR by the independent contractors is
necessary, in part, prior to closing this issue. Therefore, SIL ltem 2 will remain open and is
hereby updated.
08 Miscellaneous Operations issues (92700) - Unit 3
08.1 Use of the Technical Requirements Manual (TRM)
a. insoection Scone (Tl 2515/130)
The TRM is a supplement to the Technical Specifications (TS) that was intended to
clarify TS requirements without changing the intent or the written requirement. The
.
document also serves to document and specify additional requirements committed
!
to by plant management. The inspector reviewed the use of this document and how
it pertains to operations.
b. Observations and FindjDER
The inspector noted that the TRM is maintained in accordance with procedure OP
3273 Revision 8 " Control of Technical Requirements - Supplementary Technical
Specifications." All changes to the TRM are 10 CFR 50.59 reviewed, then reviewed
by two senior licensed operators (one being the operations manager) prior to
l
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implementation. When a TS change was proposed, the process for review prior to
being sent to the NRC requires a review to the TRM for updates if required. The
inspector reviewed changes to the TRM as a result of TS changes. In this review
the inspector noted that TRM portions were deleted because the TS changes were
clearer and no longer needed clarification. The inspector reviewed all of the TRM
clarification chapters, compared them to TS, and did not find any conflicts.
c. Conclusions
The TRM is a clarification document, for the operators, that is designed to be used
in conjunction with the TS. ,
)
08.2 LER Reviews The three LER's that follow all contain violations of TS's. These non- i
repetitive, licensee identified and corrected violations are being treated as Non-Cited I
Violations, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (As
applicable to LER's 96 043, 97-04, and 97-19).
1'
08.3 (Closed) LER 96-043-00: Misinterpretation of Technical Specifications (TS) action
statement requirements for continuing discharges of radioactive liquid effluents
during periods of radioactive liquid monitor in operability. The root cause of this
event was the operators misunderstanding and interpretation of TS that was self
identified by the licensee by an internal audit. During discharges of radioactive
effluent through discharge monitor 3LWS-RE70, the monitor frequently indicated
high activities and shut the corresponding discharge valve 3LWS-HV77. The l
operators thought that the monitor was unreliable because they could reset the
alarm and reopen the valve and continue the discharge. This was contrary to TS's
which should have prompted operators to stop the discharge. Due to the
conservative setting of the alarm (20% of TS), the licensee confirmed that no
releases exceeded TS limits.
The corrective actions taken by the licensee was timely and thorough. The
inspector verified the following: Each shift was briefed on the circumstances and i
corrective actions concerning the event. Procedures were revised to give
operational guidance regarding liquid effluent discharges. The operators received
l
classroom training on TS understanding and, in particular, how they related to this
event.
l The licensee has discussed the event in the Annual Radioactive Effluent Report
L submitted May 21997.
08.4 (Closed LER 97-04-00: Lack of verbatim compliance with TS surveillance
requirements for molded case circuit breakers (WCCB). The licensee tested 480
Volt MCCB's by selecting 50% of the population then tested. When a breaker did
not pass the single pole instantaneous test it was replaced with a new one,
however, the replaced breaker did not receive the required two pole combination
test (these breakers were subsequently tested satisfactorily). There was never an
increase in sample size due to the failure of a breaker and only 50% of the breakers
__ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _
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43
were tested. TS requires a sample size of 10%. If a breaker fails then another 10%
must be tested for each failure. This selection continues until the sample size has
no failures or 100% testing is performed. The surveillance was subsequently
completed according to TS and the status of the breakers was in conformance with
TS's.
During the root cause evaluation, the licensee recognized a trend of operetor
violations with this TS. The licensee revised the surveillance vs. TS relationship and
changed TS and surveillance accordingly. All of the licensees' actions regarding this
LER were reviewed by the inspector, however, the following corrective actions were
noteworthy:
- The Unit Director circulated a memorandum with his expectations on
compliance with TS's. The memorandum delineated the need for
understanding and complying with TS's, how to deal with TS's that are not
fully understc,od, and performance of an operability determination if
operability was in question.
e All maintenance procedures (mechanical and electrical) were reviewed for
verbatim compliance with TS's with appropriate changes being made to
conform to the TS's.
e TS's were reviewed, by an independent assessor to identify any areas similar
to the molded case circuit breaker issue and appropriate changes were made
to TS's for clarification and ease of understanding.
- The licensee developed a plan to define and ensure TS compliance, and a
manager was assigned to be responsible and accountable for timely changes
to TS's.
The inspector confirmed that the operators have received training on all of the
actions listed above, and the items have been completed and documented in the
licensee's tracking system.
08.5 (Closed) LER 97-019-00: A violation of TS occurred as a result of failure to account
for instrumentation uncertainty in demineralized water storage tank (DWST) level.
The licensee determined that, due to the instrument error of the DWST level
detector, the tank, on occasions, may not have had the required 334,000 gallons of
water. Reviewed calculations show that the condition would not be significant if
the plant experienced a totalloss of off site power because there would be enough
water to insure the plant could be brought to 350*F as required by TS.
The licensee d6ictmined that the original calculation did not take into account the
instrument error in the DWST level detector. The licensee has recalculated the
DWST water volume incorporating the instrument error and has made a TS change
to correct the DWST volume. The inspector verified that the TS change has been
i.
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44
made and that training has been received by the operators regarding the event and
changes to TS's.
08.6 (Closed) URI 96-08-1fi This URI addressed a problem where the Unit 3 FSAR
steam generator tube rupture accident analyses assumed the total time from break
initiation to safety injection (SI) termination is 30 minutes, but facility crews were
unable to routinely accomplish this on the simulator. This affected two analyses -
margin to steam generator overfill and offsite dose calculation. The facility
performed anotner analysis using operator actic,n times measured in the simulator
l and calculated plant response times totaling 46.5 minutes and showed they still had
l - margin to steam genrstor overfill; however, at the time of the URI crew
! performance was once again slower than the times in the new analysis.
i
l
'
in combined NRC inspection report 97-85, the inspector documented that the
facility had retrained their crews, timed them to verify they could respond to a
SGTR within the times in the overfill analysis, and made these times a scenario
l critical task. This still left an apparent discrepancy between the times assumed in
l the overfill vs the offsite dose analyses. The facility had a plant specific offsite
dose analysis and an updated overfill analysis in progress which they stated would -
resolve this discrepancy.
These analyses, a draft FSAR update, and the associated safety analysis were i
provided to the inspector at the beginning of this inspection. The inspector verified
that applicable operator action times are the same in both analyses. There was still
l a 30 minute assumption in the new dose analysis, but it is a different 30 minutes.
l The new analysis assumed, as a single failure, the ruptured steam generator
! atmospheric relief fails open, and the operators would manually isolate this valve
within 30 minutes. The original analysis did not evaluate single failure effects. This
failure assumption resulted in an extended time to terminate break flow due to the
depressurization of the ruptured steam generator.
To evaluate the timeliness and adequacy of facility resolution the inspector reviewed
the chronology of this issue:
!
e Following a SGTR at Ginna on January 1,1982, the Westinghouse Owners
Group submitted WCAP-10698 "SGTR Analysis Methodology to Determine
the Margin to Steam Generator Overfill" and a supplement for evaluation of
- offsite doses. The NRC requested five items of plant specific information
from near term operating license plants prior to authorizing use of this !
methodology. These items included operator response times and an offsite
dose analysis using SRP methodology with single failure assumptions from
the WCAP. Millstone was licensed in 1985 with this issue still open.
'
o On January 22,1988, the licensee submitted the requested information.
This submittal contains an overfill analysis using operator action times
greater than 30 minutes.
(
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45
- On April 28,1992, the licensee submitted additional operator action times
derived from simulator scenarios, and an overfill analysis using these times.
These times were 30.5 minutes for operator actions with 16 minutes for
plant response. This was the current analysis at the time of this URI and
these times were used in the most recent analysis completed in November,
1997.
e On November 7,1994, the licensee submitted another set of measured
operator response times. This submittal documented that one operations
crew took longer than the analysis times on two scenarios. An evaluation
was provided which concluded that margin to overfill still existed. This
submittal committed to further evaluation of operator response times.
- On December 22,1994, The NRC issued a Safety Evaluation Report (SER)
which discussed and accepted the facility submittals, including the
conclusions of margin to overfill adequacy even with the crew that did not
meet the assumed times. This SER also gave the facility permission to apply
WCAP-10698 methodology for site specific analysis.
e in April,1995 the most recent operator performance data are that the
average crew was taking approximately ten minutes longer to perform SGTR
response than was assumed in the analysis.
e in November,1996 an NRC requalification program inspection determined
that no facility reanalysis or corrective action had been taken for the longer
response times. Subsequent evaluation using the same extrapolation
methodology in the 1994 submittal determined that all operating crews
maintained margin to overfill, although in one case this was as little as 88
cubic feet of steam generator volume vs the 354 cubic feet in the analysis.
This evaluation was submitted on December 12,1996.
e By February,1997 all crews were retrained and demonstrated the ability to
implement SGTR response within the analysis times.
e By December,1997, updated site specific offsite dose and overfill analyses
had been completed with consistent operator action times.
Although the facility had measured operator response times in April,1995
which exceeded the times assumed in the overfill analysis and the times
submitted to the NRC, the facility was unable to document any evaluation of
the effects of these extended times or any action to reduce these times until
after the November 1996 requalification program inspection. The licensee
did not take prompt corrective actions, and, only when questioned by the
NRC inspector, did corrective actions begin. The failure to take prompt
corrective actions regarding assumed operator performance time to isolate a
steam generator upon tube rupture is a violation of 10 CFR 50 App. B
Criterion XVI (VIO 50-423/S8-206-04).
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"
08.7 (Undated) Unresolved item 97-85-03: This unresolved item was opened to evaluate
the consequences of training resource problems at Unit 1 and to evaluate the
possibility of similar problems at Units 2 and 3.
The inspectors reviewed operator training staffing levels and the status of the
facility Training improvement Plan items related to staffing. The facility training
iml$rovement plan includes items to evaluate facility staffing levels and develop
plans for personnel retention, rotation, and succession. These items were
completed. The staffing analysis continues to be upgraded on a monthly basis by
the licensee.
l
The facility staffing goals in the January,1998 analysis were 15 fully qualified
instructors per unit, with 80% in house personnel. All of the units had at least 13 .
Instructors either fully or partially qualified. Unit 1 was the most dependent on )
contractors, with 5 contract instructors out of 15 total qualified.- The facility (
expected to meet the stated goals within the next year t;y qualification of instructor
'
[ staff in training.
l
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Interviews with operators, who attended training, indicated the training was
appropriate. Some personnel commented that few of the training instructors are
former Millstone license holders and therefore are not as familiar with the details of
~ the Millstone plants as are their students. However, the inspector verified that the
' instructors were considered competent in their presentation of lesson plans, and
l
'
experience at other plants was considered beneficial in simulator critiques. The
facility was attempting to address the issue of plant specific instructor experience
by developing a plan to rotate instructors and operators between the plant and
operations.
The inspector evaluated requalification training in preparation for plant startup.
Inspection 50-424/97-85 also evaluated crews taking simulator exams. Based on
l these two factors adequate requalification training has been ongoing. The inspector
!
concluded that Unit 3 ctaffing levels were appropriate to support licensed operator
l requalification training The inspector, however, did not evaluate Unit 2 other than
l to note that Unit 2's staffing level is closer to the facility goal than Unit 3's.
. U3.11 Maintenance
U3M1 Conduct of Maintenance
M1.1 Containment intearated Leak Rate Test
a. insoection Scone (81726)
The inspector reviewed the licensee's procedures for the containment integrated leak rate
test (ILRT) to determine compliance with the technical specifications and the final safety
_ _ - _ _ _ _ - - _ - _ _ - - _ _ _ _ _ - _ _ - _ . _ - _ _ _
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l 47
l
analysis report (FSAR), observed selected portions of the test, accompanied the test
engineer during a plant walkdown during the test, discussed the test procedure and results
with test personnel, and reviewed the preliminary test results.
l b. Observations and Findinas
1'
'
The ILRT was conducted by knowledgeable personnel in accordance with special
procedures SP 31103, Containment Integrated Leak Rate Test (ILRT) - Type A, Revision 3,
and SP 31104, ILRT Valve Lineup, Revision 1. These procedures appropriately
implemented and verified the requirements for the test contained in TS Sections 3/4.6.1.2.
No discrepancies with the ILRT description in the FSAR were identified. Any exceptions to
the test were noted and planned to be included in the final calculation of containment leak
rate when the penalties were assessed. This had not been performed at the end of the
report period as all the final leakage numbers for excepted penetrations and components
had not yet been obtained,
in-plant walkdowns during the evolution were successful in identifying leakage paths which
were appropriately dispositioned. One such leakage path was a leak on the "A" RSS pump
casing vent. Although final pena:N had not yet been included in the test results at the
,
and of the report period, the preliminar, data indicated leakage would be within technical
l specification limits after these penalties were imposed.
c. Conclusions
l
l The containment integrated leak rate test was conducted by knowledgeable personnel in
accordance with approved procedures, TS, and the FSAR. In-plant walkdowns during the ;
evolution were successful in identifying leakage paths which were appropriately !
dispositioned. Although final penalties had not yet been included in the test results at the l
end of the report period, the preliminary data indicated leakage would be within technical l
specification limits after these penalties were imposed.
l
l-
M1.2 Loss of Offsite Power / Enaineered Safetv Features (LOP /ESF) Actuation Test 'l '
?
l a. Insoection Scone (61726)
i
The inspector attended the pre-test briefing for the "B" LOP test, observed the "A"
LOP /ESF test (special procedure SP 3646A.17, Train A ESF with LOP Test), discussed the
test procedure and anomalies encountered during the test with the test engineer and
operators, and verified appropriate overlap testing, for portions of the test which were not
completed during the test, was identified and planned. In addition, the inspector verified
that the test was performed within applicable technical specifications requirements.
b. Observations and Findinas
.The."B" LOP - LOP /ESF pretest briefing was thorough, and included the sequencing of the i
LOP /ESF test with the LOP test and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> diesel run completed before it. The briefing
also included multiple industry examples of poor tests and provided lessons learned for the
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operators and test personnel. After the briefing, operators ran through portions of the
prerequisites for the LOP, which were similar to that for the LOP /ESF. This provided a
good opportunity for operators to become familiar with the test and sequencing needed.
Operators also identified that prestaging various operating procedures used during the test
would be helpful.
Prior to the "A" LOP /ESF test, the inspector verified portions of the prerequisites and
equipment lineups were complete. Any exceptions noted had been previously identified by
the licensee, including a control room ventilation lineup required due to an active TS LCO. 3
During the first portion of the test, the "A" control building chiller, and its associated loads, -l
did not auto start from the sequencer, as expected. The shift manager maintained control
of the test and consulted electrical engineers to assist in evaluating the condition. An
operator used trainina material for the ventilation systems to eventually help explain the
problem. In conjuncton with this activity, the shift manager went to the associated chiller
area, next to the contr.I room, and identified that the "B" chiller had not been secured
.when it was placed in pull-to-lock (PTL) as directed by the procedure. It was discovered
that the ESF signal was input by an operator at another board before the chiller operator
stopped the "B" chiller. He had placed the control switch in PTL, however the chiller did
i not stop. The ESF signal prevented the "B" chiller from being tripped, therefore the "A"
l' chiller logic did not require it to be placed on the bus. Operators, with approval of the test
engineer and management test lead, returned the equipment to the test configuration and
proceeded with the test.
l The shift manager later terminated the test when switchgear ventilation could not be
credited and therefore shutdown risk was increased. This problem traced back to the reset
of the ESF signal earlier in the test. The inspector ncmd that the nuclear oversight
,
inspector observing the test raised questions of whether the test should have been
l terminated earlier on the basis of too many procedure changes. An open discussion was
observed between oversight, operations, and the management test lead. The inspector
determined that 'he test was properly controlled and terminated when shutdown risk was
threatened.
The post-test briefing w;;. effective in identifying several test discrepancies which needed
to be resolved. In addition, the inspector noted critical self-assessment on the part of the
operator at the chiller control room board. The inspector verified that the reason for the
out-of-sequence equipment manipulations was a combination of a note in the procedure
which was read to indicate parallel and not sequential performance of steps combined with
operators' attempts at efficiently performing the procedure.
a
CR M3-98-0903 was written to document the abnormal conditions identified during the
test and determine appropriate corrective actions. Corrective actions, which included field ;
work and ratests, for these items were appropriately identified. The inspector confirmed 1
that the retest performed for the "A" chiller and associated components, using the l
sequencer test circuits, was appropriate and overlapped the requirements for the test.
Although all retests required for this test had not been completed before the end of this
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report period, they had been planned and were being appropriately tracked to completion,
at which time the ESF/ LOP test will be signed off as complete.
c. Conclusions
!
l Use of the control room simulator to prepare the operating crews for the LOP and LOP /ESF
l
tests was a good initiative which resulted in increased operator cognizance of steps to be
l performed and additional copies of operating procedures to be staged in the control room.
l Operators properly evaluated active LCO action statements and took exceptions to the "A"
l LOP /ESF lineups, as required. Proper command and control was observed during the test,
l which included test termination before completion. A misleading note in the test procedure
l coupled with operator attempts at efficiency led to the performance of steps in the
l procedure out of sequence. Operators took appropriate actions and conferred with system
l design engineers and walked down system components to understand what occurred and
'
proceeded with the test in a deliberate manner. Nuclear oversight asked appropriate t
questions and interfaced well with test personnel. Anomalies during the test were noted,
discussed at a post-test brief, and recorded in a CR. Associated field work and ratests
were scheduled and in progress at the end of the report period.
U3 M2 Maintenance and Material Condition of Facilities and Equipment
.
M2.1 (Closed) ACR M3-97-0317: Containment Foundation Erosion (Update SIL ltem 12)
l
a. Insoection Scone (92902)
l
I
,
The inspector reviewed the licensee's root cause assessment and the corrective actions
l taken to address clogging of the Unit 3 subcontainment drainage piping, documented in
!
Adverse Condition Report, ACR M3 97-0317.
l
b. Observations and Findinas
The licensee has been sampling the liquid and solid effluents from the subcontainment
drainage piping, in their efforts to monitor the erosion / leaching of cement from the porous
l concrete subcontainment drainage layer. During a visual inspection, conducted in January
l 1997, the licensee observed that the subcontainment drainage system piping was partia!!y
l: clogged with a residue in four discharge pipes, and fully clogged in two discharge pipes.
l The licensee issued ACR M3-97-0317 to assess the cause of the clogging, perform a
l deportability evaluation and develop corrective measures to address the issue and assure
the future functionality of the system.
l~
t
l The licensee contracted Construction Technology Laboratories (CTL) to investigate the root
cause. CTL concluded that the deposits were the degradation products of the reaction of
subsurface and/or subterranean groundwater, which seeped into the porous concrete layer,
with the High Alumina concrete of this layer. The inspector considered the expert opinion
of CTL to be correct.
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50
Regarding deportability, the licensee concluded that since the drainage system continues to
be functiona!, design requirements are met and there were no violations of Technical
Specifications. The condition was thus determined to be not reportable to NRC.
As corrective measures, the licensee proposed and implemented actions to assure that the
subcontainment drainage system would remain functional. These included establishment of
a minimum flow area requirement (maximum permissible clogging), implementation of the
necessary actions to bring the system into compliance with those requirements, and the
development of a monitoring procedure to assure future compliance with the requirement.
To date, the arsa criteria has been established and the monitoring procedure has been j
' developed. Regarding bringing the system into compliance with criteria, a rotary tube
cleaning machine for this purpose was investigated with a test pipe section, and later .
applied successfully in the field.
The inspector reviewed the calculation that is the basis for the flow area criteria. This
includes a consideration of flow through an orifice and flow through a partially clogged q
perforated pipe. Of these, the inspector sees little value in the orifice calculation, since it is
unreasonable to ignore length effects for a system that is 770 feet long. The perforated
pipe calculation is, however, informative, it demonstrates that only a short length of 95%
clogged pipe can satisfy the flow requirements. Based on this, the recommended minimum
length of bore cleaned pipe appears to be conservatively chosen. The weakness in the
recommendation is the fact that it is predicated on an assumption (the degree of plugging)
[ that is not verified.
l The inspector reviewed the procedure, MP 3710FB, Revision 0, that has been developed to
monitor and clean, as necessary, the subcontainment drainage system. Both flow rate and )
discharge pipe plugging are monitored. Cleaning is based on the use of the rotary tube
cleaning machine used in the trial tests. The machine was effective in restoring and
improving flow in the clogged sump pipes in the first cleaning, performed in February 1998. 1
-The inspector considers the procedure to be straightforward and appropriate for the
purpose. The inspector discussed the drainage system problems with the licensee
representative responsible for monitoring and maintaining the system. Drainage flow rate i
has been essentially constant at 1000 gal / day with slight variations with rainfall. The
distribution of flow is uneven, with the smaller flow coming from the sump with plugged
pipes. However when it was necessary to block flow at the clear sump, the clogged sump
pipe (one pipe with approximately % inch flow diameter) did pass all the flow, no doubt as
a result of a greater driving head. When sump pumping was completely shutdown, the
water level in a cored hole in the ESF building mat was observed to just exceed the -34'
elevation, indicating the water level in the subcontainment drainage system.
The fact that the drainage flow rate is constant and only slightly affected by rainfall
supports the licensee's conclusion that the source of the water is primarily subterranean.
The inspector concurs with this conclusion and makes the additionel conclusion that the
water proofing membrane must then be leaking. Further, the observed capability of the
system to pass the usual flow through the plugged sump, coupled with the current low
water level in the system (large margin in driving pressure head), indicates that greater
degrees of clogging could be tolerated without compromising functionality. The inspector
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concludes, therefore, that the system is functioning and loss of functionality is not
imminent.
!
l c.' ' Conclusions
l
The licensee's corrective actions associated with this ACR are considered sufficient and
,. acceptable. The first cleaning of the clogging deposits improved the system flow and the
j system is now functioning. .The implementation of the monthly monitoring, in accordance
with maintenance procedure MP 3710FB, should give indication of any reduction in system
performance and allow the initiation of corrective measures. The continued effectiveness 1
. of the pipe cleaning procedure remains to be demonstrated. However, if the cleaning
l becomes unsuccessful, more aggressive cleaning procedures could be implemented. In this
rsgard, the simple coring of large diameter holes through the ESF slab intc, the porous
concrete layer should provide an adequate drain point for the contained water. ACR M3-
- 97-0317 is considered closed. SIL ltem 12 is hereby updated.
l
l
M2.2 (Closed) FFI 98-201-19. Rosemount Transmitters (Update - SIL ltem 18)
a. Inanection Scone (405QQ1
During inspection 96-201, the NRC identified Rosemount transmitters with plastic shipping
. caps in spare conduit ports and with spare ports open to the environment. The licensee
! 'then found that this was not an isolated instance. Apparently, some' shipping material had
l been left since original construction and other material was left installed when
i instrumentation was returned from offsite calibration. Inspection Reports 423/97-203 and -
l - 423/97-208 updated this Sllitem and identified which aspects had been corrected and -
which remained. This update addresses the remaining aspects of the item for Units 2 & 3.
l 'b. Observations and Findinos
Unit 2
The specific corrective actions to address the findings relative to this item for Unit 2 were
reviewad and found acceptable in IR 97-203. The Unit 2 broader corrective actions only
l addressed transmitters in the plant and not other items with problems such as switches
(e.g., flow and pressure switches). Unit 2 established a detailed listing of all instruments
and performed inspections during the fall of 1997 and early 1998. Some problems were
found during these inspections and AWOs were issued to perform and document the work.
The work has been completed acceptably. The inspector reviewed the completed
documentation and selected a sample of instruments for observation in the plant. Those
selected and a number of others in the plant were observed with no discrepancies
,
. iden'.ified. The Unit 2 aspects of this item are closed.
l
Unit 3
The specific corrective actions to address the findings relative to this item for Unit 3 were
reviewed and found acceptable in 97-203. The broad corrective actions and preventive
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52
actions were found acceptable in 97-208. The licensee completed the additional remaining
actions, which included training for operations personnel on shipping plugs, work on a
temperature detector, and corrective' actions related to improper closure of a CR
assignment. All actions associated with CRs M3-96-0708 and M3-97-2718 have been
completed. Additionally, the inspector performea independent walkdowns to observe the
condition of installed instruments in Unit 3. No discrepancies were identified. eel 96-201-
19 is closed; no violation was issued with respect to this inspection issue.
M2.3 (Closed) eel 98-201-32: Hioh Pressure Safety Iniection (HPSI) Thermal Relief Vals
Discrepancies (Closed - SIL ltem 81)
a. Insoection Scone (62707.92902)
Three relief valves 3-HPSI"RV8853A,3-HPSI'RV8853B and 3-HPSl*RV8851 developed a
history of spurious openings.,These valves were observed to lift following HPSI pump start
during surveillance testing. The HPSI pump is rated for a discharge pressure of 1750 psig
and has been observed to produce 1800 psig. The relief valves were opening in response
to pressure spikes thought to be originating from some source downstream of the relief
. valves, if more than one relief valve lifted and remained open or failed to reseat, the ECCS .
operability could be compromised by diverting flow from the reactor core in excess of that
assumed in the LOCA analysis,
b. Observations and Findinas
To prevent these spurious openings the set point pressure of these valves was changed
from 1750 psig to 2235 psig. The piping and associated systems in the area of the relief
'
valves are built to NUSCO Class 1502 which is 1,500 LB,316 stainless steel piping with a
pressure rating of 3,415 psi at 300 degrees F. After reworking the valves and resetting
the setpoint of the relief valves, the licensee performed a hydrostatic test of the section of
piping in the area of the relief valves. The licensee misinterpreted the ASME Code and
performed this hydrostatic test at 1.1 times the design pressure of 2235 psig. This
l' misinterpretation by the licensee came about because the system being tested was thought
to be at a design temperature of 200 degrees F instead of 250 degrees F. Noticing their
l
error, the licensee re-hydrostatic tested the system at 1.25 times the design pressure of
2235 psig.
l The inspector reviewed eel 96-201-32 along with other associated documentation and j
engineering drawings. The inspector reviewed the corrective items that the licensee l
implemented. These corrective actions were.: 1) retest the system at the higher pressure of l
1.25 times the design pressure of 2235 psig and 2) retrain / counsel the individuals '
responsible for performing the original hydrostatic test. j
Documentation reviewed by the inspector indicated that the individuals involved with the .
original hydrostatic testing were re-trained by being provided materials for self study. The !
inspector reviewed the Piping and Instrument Diagram (P&lD) drawing No.12179-EM-
113B-24 and compared the P&lDs to the licensee work order M3 9619113. The Millstone
Nuclear Power Station Engineering Procedure EN 31090, Elevated Pressure Test, Rev. 3, in j
l
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the referenced work order, correctly specified the piping lines to be hydrostatic tested at
1.25 times the design Pssure of 2235 psi; however the valve line up specified in the EN 31090 incorrectly excluded line 3-HPSI-750-47-2. The inspector noted the need to
l hydrostatic test the referenced line to the new test criteria of 1.25 times design pressure I
l instead of the 1.1 criteria. The licensee agreed and issued CR M3-98-0214. The licensee
l then successfully hydrostatically tested the line 3-HPSI-750-47-2. The inspector reviewed
the design pressures and ratings of piping connected to the lines which were
i hydrostatically tested and found the retest to be acceptable. The failure to include 3HPSI-
750-47-2 in the higher testing regime is a minor violation and is a Non Cited Violation
j
l pursuant to the NRC Enforcement Policy, NUREG 1600,Section IV.
l
c. Conclusions
The training and hydrostatic testing completed by the licensee were deemed to be
adequate. The technical issues associated with this issue are resolved and eel 96 201-32 is {
considered closed. The NRC Notice of Violation (NOV -letter unique identifier 04093)
currently remains administratively open. With the closure of LER 96-032 in inspection
report 50-423/97-02; and in consideration of the open status of SIL ltem 36 to address eel
96-201-34, no further technical concerns remain in this area and SIL ltem 81 is hereby
closed.
!
l U3 M3 Maintenance Procedures and Documentation
M3.1 (Closed) CR M3-97-0850: (Undate) Insoector Follow-uo item. IFl 423/97-01-07:
Seismic 11/l (Closed - SIL ltem 33)
l a. Insoection Scooe
Procedural controls, management attention and worker awareness of the requirements for
the proper storage, restraint and use of temporary equipment within the plant have been
l the subject of numerous Condition Reports, including CR M3-97-0850, Licensee Event
Report 96-003-00 and inspector Follow item (IFI) 423/97-01-07. The inspector reviewed I
the licensee's corrective actions to address CR M3-97-0850 and the timeliness and
adequacy of further corrective actions in this area.
b. Observations and Findinas
l
l During an NRC inspection team tour of MP3, in March 1996, the team found I-beams with
l temporary anchorages installed above recirculating spray (RSS) heat exchangers and
l valving. The beams had the potential to render one heat exchanger in each train inoperable
- and to breach the containment during a seismic event. The licensee issued LER 96-003-00
l to report the issue that procedural controls for " incomplete work" were not being followed
l and ACR M3-96-10382, to document and address the concern. One year later, in the
performance of a Work and Test Control Audit M3-97-A04-01, a licensee team reviewed
the corrective actions related to LER 96-003-00 and performed audit walkdowns of safety
related areas. The audit found that the corrective actions related to the LER had not been
implemented. This conclusion was supported by the finding of new instances of improperly
I
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controlled temporary equipment during the walkdowns. The licensee issued CR M3-97-
0850 to address this concern and the NRC inspector issued IFl 423/97-01-07 to evaluate
j the timeliness and adequacy of further corrective measures in this area.
{
Subsequent licensee investigations, under CR M3-97-0850, revealed that the corrective l
actions of ACR M3-97-0563 had been performed but that they were inadequate and not
timely. The inadequacy of the corrective actions were determined to be due to the
inconsistency and poor documentation of the plant walkdowns that were performed and I
the inadequacy and lack of documentation of the training provided to comply with the
requirements of the Millstone housekeeping and maintenance standard OA 8 regarding the
restraint of temporary equipment. As corrective actions, the licensee; revised procedure
OA 8 to clarify requirements, changed Work Control Process WC-1 to reference OA 8,
implemented and documented new training, and clearly defined management expectations,
regarding the restraint of temporary equipment. Regarding management expectations, the
licensee included a discussion of the requirements of OA 8 for temporary equipment in the f
Unit wide stand down, held on May 6,1997, and stressed the areas of walkdown l
requirements, frequencies and responsibilities to maintenance department personnel and l
first line supervisors.
The inspector reviewed Station Procedure OA 8, Work Control Process WC-1 and Unit
Instruction 3-Ul-2.01 for requirements regarding temporary equipment. The revisions and
changes to OA 8 and WC-1, recommended in the corrective actions, had been made. OA 8
provides an adequate description of temporary equipment, their potential interaction zones,
and acceptable methods for their restraint. This includes a specification of strength criteria
for the restraint devices as a function of equipment weight. The Unit Instruction makes
appropriate references to OA 8 and defines those responsible for " Material Condition" as a
function of areas. Taken together these documents provide an adequate definition of
requirements and responsibilities for temporary equipment.
The inspector evaluated the adequacy of the strength criteria for restraint devices provided I
in Attachment 3 of OA 8. Specifically, it states for heavy weight items, "Use cable, strap,
rope, nylon sling or chain with clasps rated to minimum of 70% of secured item weight."
The 70% value was changed from 150%, with Revision 2 to OA 8, in response to CR M2- ,
97-0168. The inspector determined that although the 70% criteria envelopes the peak I
horizontal seismic acceleration for any rigid equipment in Unit 2, it does not envelope such I
seismic accelerations for Unit 3. With this deficiency, station procedure OA 8 may not be
appropriate for Unit 3. The licensee issued CR M3-98-0339 to address this concern.
The inspector reviewed the corrective actions for training. The documentation states that
Mechanical Maintenance, Stone & Webster, Performance Contracting and Cannon & Sline
personnel received familiarization briefings on OA 8. Further, supervisors were briefed on
their responsibilities regarding pre-job briefs and worker oversight. Lastly, all Unit 3
personnel were advised of the requirements regarding temporary equiptrent through the
unit wide stand down. The inspector concluded that the licensee had met its commitment
regarding training.
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The proper restraint of temporary equipment impacts directly on the seismic il/l issue. Prior
. lax attention to the restraint of temporary equipment resulted in numerous findings of II/I
deficiencies and the open IFl. The inspector reviewed CRs for the last two quarters for
new temporary equipment - seismic ll/l findings. There were several findings in each
category. This shows that unit personnel are remaining vigilant and reporting infractions
as they are found. Evidence of the improved attitude regarding these issues is the fact that
no new infractions have been identified during recent NRC field inspections.
- c. Conclusions
The licensee has clearly redressed its original approach to the issue of the proper restraint
of temporary equipment. Through the unit wide stand down and its emphasis on training,
management has succeeded in conveying to the unit personnel their expectations
regarding, and the importance of, the issue. The inspector concluded that the corrective
actions taken by the licensee are appropriate and CR M3-97-0850 is considered closed.
The acceptable resolution of the temporary equipment issue and the scaffolding issue
l (Inspection Report 423/97-208) addresses the most common sources for seismic il/l
l infractions. Coupled with an improvement in the quality and consistency of the design
l control process, provided with the Design Control Manual, the licensee has taken positive
l and practical steps to minimize the occurrence of seismic 11/1 issues. SIL ltem 33 is .
,
considered closed.
Although the licensee's actions to control the use of temporary equipment is considered
acceptable, the specification of load design criteria appropriate for Unit 3 must still be
made (reference: CR M3-98-0339). IFl 423/97-01-07 remains open pending acceptable
resolution of this issue.
U3M8 Miscellaneous Maintenance issues
.
M8.1 (Undate) LER 97-047-00: Failure to Comoletelv Test the Thermal Overload Bvoans l
Protection Loaic of Safetv-Related Motor-Coerated Valves that Receive Multiole l
Actuation Sionals !
a. Insoection Scone (92700)
i
l
LER 97-047-00 identified the inadequate testing of the safety-related motor-operated
l
valves (MOVs) which receive multiple r,ctuation signals, may not ensure that the thermal
overload protection was properly bypt.ssed upon receipt of each individual signal. This
problem was due to deficiencies in the initial development of the applicable surveillance
procedures for testing the thermal overload bypass functions of safety-related MOVs. The l
inspector reviewed the licensee's corrective actions to address this above concern.
b. Observations and Findinos j
CR M3-97-2613 documented that safety-related MOVs (e.g., SWP'MV71 A/B,
CCP'MV222-229, and SWP'MV115A/B) with multiple actuation signals were not
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adequately tested to verify proper operation of the thermal overload bypass circuitry.
Inadequate testing of these MOVs was not in compliance with TS 4.8.4.2.1. Failure to
ensure complete testing of the thermal overload bypass logic would result in testing
inadequacies that constitute missed TS surveillance.
The licensee's corrective action for this LER was to revise the applicable surveillance
procedures and perform testing to verify proper operation of the thermal overload bypass
function for safety-related MOVs. A review of MOVs with multiple actuation signals for
l thermal overload protection bypass circuitry was completed. It was found that MOVs
CCP'MV222-229 and SWP'MV115A/B receive multiple accident signals which would be
- bypassed by the thermal overload protection logic. Revisions to procedure SP 3674.1 for
the appropriate testing of CCP*MV222-229 and SWP*MV 115A/B are still ongoing, and
thus, operational testing of these MOVs have not been performed yet. This issue will
- remain open pending the completion of the procedural revisions and proper testing of the
MOVs CCP'MV222-229 and SWP'MV115A/B.
c. Conclusions j
l
The inspector verified the corrective action described in the LER to be reasonable. j
However, the procedural revisions and appropriate testing of the MOVs CCP'MV222-229 j
and SWP'MV115A/B have not yet been completed. Therefore, LER 97-047-00 is hereby - i
updated, but remains open.
. M8.2 (Closed) LER 97-051-00: Desian Deficiency of 4.16kV Feeder Fadt Clearina Times
a. Inanection Scone 1927001
,
LER 97-051-00 identified that the overcurrent protection design for the 4.16kV feeder
circuits (non-Class 1E and Class 1E) may not clear a short-circuit in sufficient time to
provide adequate cable protection under faulted conditions. This event was due to an
inadequate design control process during original design implementation, and a lack of l
verification and validation of calculation design inputs by the architect / engineer and the l
utility engineering organizations during plant construction. The inspector reviewed the
licensee's corrective actions to address this concern.
'b. Observations and Findinas !
l
ACR M3-97-3413 documented the discovery of a discrepancy between the installed
'4.16kV system protective relays and the required fault clearing times. The installed
4.16kV overcurrent protective relay scheme was using electrically reset General Electric
(GE) "HFA" relays, rather than the hand-reset instantaneous GE "HEA" relays which were
specified in the original switchgear design. The fault clearing time of each installed HFA
relay was 10.5 cycles which would not clear the most severe three-phase bolted fault l
'
short-circuits in sufficient time to provide adequate protection of 4/O aluminum cables
under short-circuit conditions. The electrical design basis calculations (i.e., SWEC 178E, i
Revision 1) for evaluating the thermal capability of 4.16kV cables under faulted conditions
-
used the 6-cycle clearing time of HEA relays. This discrepancy affected seventy-one !
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4.16kV system feeder circuits, which were 20 feeder cables on electrical bus 34A, and 17
cables each on buses 34B,34C, and 34D.
The licensee's corrective action for this LER was to restore the electrical protection relaying
scheme for the affected 4.16kV feeder circuits to conformance with the design basis prior
to entry into Mode 4 operating conditions. Specifically, the previously installed HFA relays
12HFA154B22F were replaced with the faster electrically resettable lockout relays
12HFA154B25F. Each replacement relay was a similar style relay with a 24 Vdc coil
which would operate in 30 milliseconds or less, and thus achieve shorter clearing times.
The inspector verified that the new HFA relays were installed in the affected electrical bus
cubicles located in the east and west switchgear rooms per DCR M3-97095. These
replacement relays would reduce the total circuit clearing time from 10.5 cycles to 7.4
cycles. The clearing time of 7.4 cycles was determined to be adequate for 63 of the 71
circuits per NU Calculation SWEC 178E, Revision 1. In the case of 8 circuits with
extremely low thermal capacity due to cable length and size, wiring modifications were
implemented with the relay replacement to allow the circuit breaker and lock-out relay to
trip in parallel that would reduce the clearing time to 5.5 cycles. Esch wiring modification
consisted of a diode and capacitor arrangement, which prevents system trips from
generating a lock-out, and a diode installed in parallel with the 24Vdc HFA relay coil, which
limits voltage transients when the HFA relay coil de-energizes. The installation of diodes
in parallel with DC coils i' a common industry practice. The inspector did not have any .
additional concerns.
c. Conclusions
The inspector verified the corrective action described in the LER to be reasonable and
complete. This issue was self-identified by the licensee staff and corrective actions were
implemented in a timely manner. LER 97-051-00 is closed, but will receive additional
attention as an Appendix R issue during the conduct of the fire protection team follow-up
inspection (reference: IR 50-423/98-81). This non-repetitive, licensee-identified and
corrected violation of design control is being treated as a Non-Cited Violation, consistent
with Section Vll.B.1 of the NRC Enforcement Poliev.
l
M8.3 (Closed) LER 97-055-00: Area Temperature Monitorina Element Mounted in Wrona j
Location Resultina in No Area Temperature Monitorina Within the B & D RSS Pumo
l
Cubicles i
i
1
a. insoection Scone (92700)
LER 97-055-00 identified that the area temperature monitor 3ECS-TE098 was not installed
within the area intended to be monitored. This event was due to inadequate validation of
design documents by the architect / engineer and the NU engineering staff. The inspector
reviewed the licensee's corrective actions to address the above concern.
l
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! er
...
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58
b. Observations and Findinos .
- .
L ACR M3-97-3896 documented the discovery of an area temperature monitor 3ECS-TEO98
. that was instal!ad in the HVAC and MCC area (environmental zone ES-01) rather than the
ESF Building B and D RSS pump cubicles (ES-05 zone) where it was intended for
monitoring the area temperatures. Surveillance requirement 4.7.14 of TS 3.7.14 required
[ . that the temperatures within the B and D RSS pump cubicle area should be determined to
l . be within limits on a weekly basis whenever equipment in the area is required to be
i
operable. The dislocation of 3ECS-TEO98 resulted in missed opportunities to perform TS
surveillance 4.7.14 in the B and D RSS pump cubicle area.
The licensee's corrective action for this LER was to relocate the area temperature monitor
3ECS-TEO98 within the area of the RSS B and D pump cubicles prior to entry into Mode 4
operating conditions. The inspector verified that the temperature monitor 3ECS-TEO98 was
installed on a wall within the RSS B and D pump cubicle area per MMOD M3-97617.
Additionally, the licensee conducted field walkdowns to verify that temperature probes in
all the EQ zones were monitoring temperatures in the correct locations. NU memorandum
MP3-TS-97-434 documented the results of the walkdowns which indicated that there were
- no other adverse conditions found. The inspector did not have any additional concerns.
l c. Conclusions
i
The inspector verified the corrective action described in the LER to be reasonable and
complete. This issue was self-identified by the licensee staff and corrective activities were
implemented in a timely manner. LER 97-055-00 is considered closed. This non-repetitive,
licensee-identified and corrected violation of the plant technical specifications is being I
' treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement
! Pokcy.
I
l M8.4 (Closed) URI 423/97-02-14: Deslan Chanoe Discrepancies for Pine Ruoture Whio
l Restraints i
'
a. Insoection Scone (62707.92902)
,
l- The inspector reviewed the licensee's actions to resolve the discrepancies identified for 1
pipe rupture whip restraint 3FWS-PRR6 and their assessment of causal factors.
l
b. : Observations and Findinas
As described in Inspection Report 50-423/97-02, NRC field inspection identified one series
of pipe whip restraints with the as-built configuration deviating from the existing design
details. The support,3FWS-PRR6, was a large dual function pipe support / whip restraint
located in the main steam valve building. The as-built structure was missing design
specified shims ~and had nonsafety-related electrical conduit supports welded to its main
structural beam. For the coniuit support attachment, no evidence of engineering approval
for the attachment was retrievable nor was a necessary evaluation for seismic 11 over I
performed. The licensee issued CR M3-97-1272 for the shim concern and CR M3-97-1461
!
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ee
t
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1
for the attached conduit supports. URI 423/97-02-14 was issued to track CR's M3-97-
1272 and M3-97-1461 to closure and to assess the licensee's causal problem linkage l
l
determination. i
The licensee concluded that the cause of the design discrepancies was communication
breakdown and human error. For the shims, personnel could recall discussions related to j
the shims but no documentation authorizing their deletion could be found. For the conduits i
it was conjectured that the shear size and extent of the support beam allowed it to be
mistaken for building steel. The licensee performed operability determinations for both
discrepancies. These design reviews demonstrated that the shims were not functionally l
required and the conduit supports could resist seismic loads. As corrective actions the
licensee performed walkdowns of a sample of pipe whip restraints, revised calculations and j
design drawings to agree with the as-built configuration, performed conduit support weld I
irispections to comply with ASME Section XI requirements and conducted training of
personnel in the approval requirements for conduit installations.
The inspector reviewed calculation 12179-NM(B)-425-JDE " Main Steam Valve Building -
i
Feedwater Bypass Pipe Rupture Restraints 3FWS-PRR6 & 3FWS-PRR7 Design". The
designs included redundant elements at the main beam to embedment plate anchorages.
Both anchor bolts and angle clip connectors were provided at these locations. In the l
original design calculations, credit was only taken for the anchor bolta to resist the lateral '
pipe rupture load.s. In that case, shims were necessary to react to compression loads at
the embedment. In the current revision, credit is only taken for the frictional / slip capacity )
of the clip connectors to resist the pipe rupture lateral loads. Since this mechanism can l
resist loads in either direction, no reliance on the shims is necessary. Although friction l
bonds are not normally relied on to carry structuralloads, they are accepted by both ASME I
and AISI as valid load reacting mechanisms. In any case, the capacity of the clip connector
bolts in shear exceeds the rupture load, adding extra margin to the anchor connections.
Regarding the conduit attachments to the bottom of the support beam, the weight of the
conduit is insignificant, as compared to the rupture loadc, and consequently the conduit
has no impact on the structural integrity of the support. The inspector concluded that the
revised calculations demonstrate the adequacy of the as-built configuration.
As a corrective action the licensee performed a walkdown of a sample of pipe whip
restraints. The sample included the only two remaining dual function pipe whip restraints
(3 MSS-PRR2 and 3FWS-PRR4) which have beam elements as large as those in the subject
restraint. No discrepancies were noted. The inspector performed a walkdown of the
subject restraint and the additional two large restraints and concurs with the licensee's
finding.
The inspector performed a review of the Plant Design Change Request (PDCR M3-89-002)
and automated work order (AWO M3-89-04459) that resulted in the attachment of non
safety related conduit onto the subject support. These documents confirmed that seismic
conduit support details were used for the conduit installations and that qualified welders,
using procedurer and weld fillers meeting ASME criteria, performed the welding. As a
corrective action the licensee completed a reinspection of the welds per the ASME Section
_ - - - - - - - _ _ _ _ _ _ _ - - _ _ _ _ - _ _
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60
XI Replacement and Repair Plan. The inspection verified the integrity of the support beam
and found the welds to be acceptable.
l The inspector considered the licensee's conclusion that a seismic il over i evaluation was
l not required for the conduit installation adequate. This position was, in part, validated by
I fic'd inspection noting that the area below the support and conduit is devoid of any
equipment except for insulated large bore pipe.
The licensee observed that the present Design Control Manual (DCM) would minimize the
possibility of similar occurrences in the future due to the detailed walkdown requirements.
The inspector reviewed the pertinent sections of the DCM and agrced that detailed pre / post
installation walkdown requirements are specified. However, the inspector noted that
similar walkdown and inspection requirements were stated to have been perforrned in the
design PDCR with the attendant poor results.
c. Conclusions
Licensee calculations and inspections demonstrated that the structural integrity of the as-
built configuration cf pipe whip restraint 3FWS-PRR6 is adequate. The inspector concurs
with this conclusion. The comprehensive definition of design requirements in the DCM
coupled with the licensee's corrective action training should reduce the likelihood of
recurrence. URI 423/97-02-14 is considered closed.
U3.Ill Engineering
U3 E1 Conduct of Engineering
i E1.1 (Uodate) eel-423/98-201-22: URI 98-08-20: ACR M3-98-0328: and ACR 13427:
RHR Flow Control Svstem Failures and CCP Overheating (Update - SIL 13)
l a. Insnection Scoon (37551.92903)
As identified in eel-423/96-201-22, the Reactor Plant Component Cooling Water (CCP)
system upper temperature limit of 115 degrees F was exceeded on September 9,1994 and
April 15,1995. This item was subsequently updated by URI 50-423/96-08-20. The NRC
has also issued a Notice of Violation and Proposed imposition of Civil Penalties by letter
dated December 10,1997 that includes this item with NOV letter unique identifier 04033.
On August 19,1996, in LER 96-013-01, the licensee reported a design deficiency in the
Residual Heat Removal System (RHR) that was outside the design basis of the plant. A
loss of control air could cause the HHR system control valves 3RHS*HCV606 and/or
3RHS*HCV607 to fail open. If this condition occurred during the initial phase of a plant
cooldown, the CCP temperatures could rise above the 125 degrees F used in the system
stress analysis. This item was updated in NRC Inspection Report 50-423/97-203, Section
04.1, in which the inspector evaluated modifications completed under DCR M3 96065 on
the RHS Train "A" to allow RHS to continue a normal cooldo'wn or safety grade cold
shutdown upon loss of instrument air without exceeding CCP piping design temperature
- _ _ - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ - _ _ _ - _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - - _ _ _ _ _ - _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _
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61
l limits. No adverse conditions were noted. Therefore, the modification of the Train "A"
l RHS control valves 3RHS*HCV606 is considered to be closed.
During this inspection, the inspector reviewed the licensee's design engineering activities to
i resolve the technical concerns associated with this issue and assessed the adequacy of the
l
resultant changes to plant operating procedures.
l
b. Observations and Findinas
DCR M3 96065 was prepared in response to ACR 13427. The ACR documented that,
upon a loss of non safety related instrument air to RHS flow control valves 3RHS*HCV606
and 607 (while in Safety Grade Cold Shutdown (SGCS) or during normal cooldown), the
control valves will fail open and the CCP piping return temperature from the RHS heat
exchanger may increase above the maximum operating temperature of 115 degrees F.
Regarding the RHS Train "B" modification, pertaining to valves 3RHS*HCV607 and j
3RHS*FCV619 under Design Change Record (DCR) M3 96065, the licensee issued an
engineering release form (DCM Form I dated 09/04/97) for the Train B affected
components restricting the plant to Modes 5 and 6 pending completion of DCRs M3
l 96075, M3 97015, and M3 96064, and also pending replacement of Barton Switches
3RHS'FIS610 and 611 due to enlarged flow orifices,
in memorandum MP3-DE-96-0604 to Ashton from Perkins, 11/18/96, the licensee re-
evaluated the response to FSAR Question No. 440.24 that, if control grade valves
'
3RHS'FCV618 and 619 fail, RHS pump runout is precluded by the use of pre-set throttling
valves located in the discharge lines to the RCS. The re-evaluation concluded that there
are no such throttling valves. The inspector also reviewed the applicable NRC
correspondence (NRC letter of 10/18/88 to E. J. Mroczka, NNEC, from D. H. Jaffe, NRC,
" Verification of Adequate Borated Water Mixing and Natural Circulation Cooldown,") and
determined that had the NRC had the proper information concerning the lack of pre-set
throttling valves, it did not appear that the conclusions of the evaluation would have been
affected significantly. Also, RHS pump runout is now precluded by the modifications j
made to the RHS under DCR M3 96065.
The inspector reviewed several calculations by a licensee consultant, Proto-Power, that
were referenced in DCR M3 96065, which identified the revised operating temperatures of ;
the RHS and CCP systems. The inspector found the calculations to be complete and !
comprehensive with the exception of Proto-Power Calculation 96-011, paragraph 6.08, for
the RHS Pump Seal Coolers, RHS*E2 A or B. In particular, the justification for the ;
acceptability of the RHS pump seals, which are cooled by the CCP system, when subjected l
to a revised, increased CCP temperature of 113 degrees F during safety grade cold
shutdown (SGCS), was questionable. The manufacturer strongly recommended that the
pumps be operated with an adequate supply of cooling water to the seal coolers, i.e., 5 to
i
'
10 GPM to the shell side of the cooler, and further stated that lack of coolant will greatly
increase the temperature of the mecF.onical seal unit, resulting in shorter seat life. The
inspector questioned whether seal failure might occur during the length of time ast,umed
I for SGCS and normal shutdown, as per Proto-Power Calculation 95-052 references of 66
1
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62
hours and 124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br />. The licensee then provided a memorandum dated 1/27/98 of a
phone conversation with the seal manufacturer in whir:h the manufacturer was quoted as
saying that the RHS pump seals could withstand temperatures above 200 degrees F. This
remains an open item, pending confirmatory documentation from the seal manufacturer.
The inspector also reviewed those procedures which had been identified as being affected
by the changes identified in DCR M3 96065 pertaining to the RHS and CCP interface and
the modifications made to the RHS system. Several procedures did not identify or include
any changes related to DCR M3 96065. Therefore, the issue of completion of changes to
operating procedures remains an open item.
The licensee indicated that all of the supporting stress analysis calculations for DCRs M3
96075 and M3 97015 had been completed. However, some of the calculations had not
yet been delivered from the architect engineer's offices (Stone & Webster in Boston) and
were not yet available for review.
The inspector performed a sample walkdown of piping support modifications in the
Auxiliary Building and the Fuel Building pertaining to these DCRs. To the extent that field
verification was possible, all modifications were completed as shown on the drawings. The ;
licensee indicated that all of the support modifications had been completed except three for
the CCP system and one for the SW system,
c. Conclusions
For the RHS Train "B" modification, pertaining to valves 3RHS*HCV607 and
' 3RHS*FCV619 under DCR M3 96065, the licensee issued an engineering release form for
the Train B affected components restricting the plant to Modes 5 and 6 pending completion
- of DCRs M3 96075, M3 97015, and M3 96064, and also pending replacement of switches
3RHS*FIS610 and 611. This remains an open item pending presentation of appropriate
documentation that all of the remaining changes have been implemented.
Also remaining open are: confirmatory documentation from the RHS pump seal
manufacturer that the seals can withstand temperatures above 200 degrees F final
changes to operating procedures which have been partially completed; and review of the
remaining stress analysis calculations that were not available for NRC review.
l
l Therefore, eel-423/96-201-22 & URI 96-08-20, as well as CR M3 96-0326 and ACR l
l 13427, remam open. !
l l
l E1.2 (Undate) LER 96-028-00 and 01: Overcooling of CCE Charoino Pumo Lube Oil
l Svstem Due to Loss oi instrument Air Concurrent with Low Service Water )
l Temperature (Update - SIL ltem 13) l
)
i
a. Insoection Scone (92700) {
i
in LER 96-028-00, the licensee reported that a loss of instrument air to temperature control
valves (3CCE*TV37A and B) in the component cooling water system serving the charging
i
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l pump lube oil coolers (CCE), coincident with 33*F service water (SW) temperature, could
l result in an overcooling of both trains of the charging pump lube oil system and challenge
charging pump operability. On December 13,1996, in supplemental LER 96-028-01, the
licensee reported the cause of the potential charging pump inoperability to be inadequate
initial design. Overcooling of the lube oil system below the minimum allowable temperature
of 60*F could occur following a failure of the non-QA instrument air system (IAS)
coincident with worst case minimum SW inlet temperature to the lube oil coolers and
maximum flow and maximum lube oil cooler cleanliness. The air-operated CCE valves
would fail open and excessive cooling of the lube oil system to 40*F would occur. During
this current inspection, the inspector reviewed the licensee's engineering activities to
resolve the technical concerns associated with this issue and assessed ongoing plant
design modification activities. In addition, the inspector reviewed the licensee's activities
concerning a similar issue for the safety injection pumps (3SlH'P1 A and B) and the safety
injection pump cooling system (CCl).
i- I
b. . Observations and Findinas
l
The inspector reviewed the licensee's engineering activities, which included installation in
February,1997 of a temporary bypass (Bypass Jumper 3-96-112) prior to the SW (Long
l
Island Sound) temperature falling below 39'F. The bypass was intended to divert 6 GPM
l of cooling water flow around the charging pump lube oil coolers to prevent overcooling of
the charging pump lube oil. Prior to the SW temperature exceeding 54*F, the bypass was
removed in May,1997. DCR M3-97085 described the permanent modification to the
charging pump lube oil system. This consisted of setting the lube oil pressure regulating
l
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valves (3CHS*RV8511 A/B/C) to control system pressure at the pump gearbox between 20
to 24 psig under normal conditions (as opposed to the current 15 to 18 psig) to provide
l assurance of adequate oil flow under low temperature, high viscosity operation. In
addition, the moc'ification included calculations performed by the charging pump-
manufacturer, Westinghouse (and Dresser Pumps), intended to justify 30 day operation of
the charging pumps with a lube oil temperature of 48'F, equivalent to a viscosity of 700
Saybolt Seconds Universal (SSU), at a minimum component cooling water (CCE)
temperature of 40*F, corresponding to a SW temperature of 33*F. The licensee presented
documentation, i.e., Form 3-21, " Engineering Release Transmittal," that on 12/01/97, for
Charging Pump C (3CHS*P1C), the lube oil pressure regulating valve 3CHS'RV8511C was
reset and the charging pump surveillance test was completed satisfactorily. Similarly, on
12/03/97, for Charging Pump B (3CHS*P1B), valve 3CHS*RV8511B was reset and the
pump surveillance test was completed satisfactorily. At the time of this review, Charging
Pump A was undergoing analogous modifications. Upon completion of the Pump A
modification, the temporary bypass jumper will no longer need to be installed as the Long
Island Sound temperature begins to decrease in the winter. The licensee presented a
jumper device control sheet (Form WC-10, Index No. 3-96-112) which was approved on
05/12/97 to close out the jumper requirement. The inspector also reviewed the temporary
operator log which the licensee was maintaining to record the Ll Sound temperature. The
inspector considered this acceptable.
Design Change Notice (DCN) DM3-OO-1466-97, " Revise Cooling Water Temperature and
Lube Oil Pressure for Charging Pumps," 10/14/97, included relevant portions of vendor
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technical manual VTM No. 25212-001-019, Rev. 019M, which stated under " Pre-Startup
Checks" that: " Westinghouse recommends that the oil inlet pressure to the gear unit be
monitored with a pressure switch and control room alarm. The low pressure alarm setting
should be JLDai." The inspector questioned whether a new alarm setting would be
required, in view of the upward adjustment in the pump gearbox pressure. The licensee
responded by providing the alarm response procedure, OP 3353.MB3A, Rev.1, which
indicated that the setpoint was less than 15 psig for greater than 15 seconds, not 8 psig.
However, a procedure change notice had not been issued to change the normal oil supply
pressure from 15-18 psig to 20-24 psig, as required by the design change. The licensee
revised OP 3353.MB3A to indicate the 20-24 psig normal oil supply pressure, as per a
memorandum from Berkman to BERGETR, 11/20/97, "DCR M3-97085-Related Required
Procedure Changes." The alarms for " Charging Pump Lube Oil Pressure LO" alarm in the
control room and the pressure switches appear.on the Master Setpoint List.
l The information provided to justify the upward adjustment of the lube oil pressure was !
sufficient and technically sound with respect to the design aspects of the change, such as
the heat exchanger performance and resulting temperatures, and the stress analysis which
had originally been performed for a SW temperature of 33*F prior to the initial plant startup
in 1985. According to Memo No. MP3-DE-97-1357,09/19/97, which identified the
various stress analysis calculations pertaining to the CCE and CCI systems, the piping in
the CCE system was originally stress analyzed by the A/E, S&W, for a minimum
temperature of 33'F. The inspector verified this on a sampling basis by referring to
Calculation No. 747XD. The results indicated that the stresses in the piping on the CCE
cutlet side of the CCE to SW heat exchanger, which would be the piping subjected to the
coldest temperature under the currently postulated scenario, were within the allowable -
limits.
1
As part of the operability determination of the charging pumps for the reduced oil
'
temperature occurring with a service water temperature of 33*F, the licensee presented
Westinghouse proprietary calculation number P-EC-329, Rev.1,10/08/97, " Evaluation of
Millstone 3 Charging Pump and Gear Unit Operation at Low Lube Oil Temperature." This
evaluation relied on proprietary related test data identified as Reference 7: Westinghouse
letter ME-AE-5819, PAR # 131 to P.O.169450,06/15/76, " Lube Oil Cooling Requirement
Tests," Pacific Pumps Order Y-628, which documented testing performed in April,1976 to
determine the performance of pumps similar to the MP3 charging and safety injection
_ pumps operating at low service water temperature, i.e.,37'F. The conclusion of the
evaluation was that although the tested equipment was not identical to the MP3 pumps,
the test results were expected to be generally representative of the MP3 equipment
capabilities.
Upon reviewing the test data, the inspector noted that the testing was conducted for a
period of two (2) hours and that the type of oil was not specified. Also, the oil viscosity
was not specified at 40*F, only as 150 SSU at 100*F. The DCN indicated that the pumps
could be run for 30 days (720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />) with SW temperature of 33*F, corresponding to a
CCE temperature of 40'F. From the results of the testing, it did not appear that the lower
l
SW temperature of 33*F would make any significant difference in pump performance as
compared to the 37"F used in the tested pump. The licensee's analysis indicated that the
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MP3 charging pumps would be operable under the postulated low service water conditions
for 30 days.
The inspector noted discrepancies in the analysis concerning the ambient temperature in
the charging pump cubicles. A minimum tube oil temperature of 50*F was assumed for
both the operating pump and the standby pump during the 30 day time period of
operability. FSAR Paragraph 9.4.3.1 indicated that the Auxiliary Building Ventilation
l
System maintains the ambient temperature in the charging pump cubicles above the
solubility temperature limit of 59'F for a 4% boron concentration. The licensee presented
a FSAR Change Request Form which proposed to change the FSAR to state that the limit
of 59'F is maintained except during an emergency bus single failure in the winter at which
time the temperature is maintained above 32*F. The licensee performed a 10 CFR 50.59
evaluation (So-EV-97-0519) on 12/3/97 and determined that all eight safety grade space
heaters are required to be available to maintain the 59*F temperature. Since four heaters
are powered by each of the two diesel gencrators, then both trains of diesels must be i
available.
The evaluation determined that there was no unreviewed safety question, although it was
not clear how the solubility temperature limit would be addressed if the area temperature .
would now be allowed to decrease to 32*F. Westinghouse Calculation No. P-EC-329
referenced another Westinghouse calculation, No. P-EC-276, Rev.1,12/03/92, " Evaluation
of the Millstone 3 Centrifugal Charging Pumps for Operation at Cold Ambient
Temperatures," which assumed that the ambient air temperature at the pump lube oil
reservoir is at least 30*F. However, CCE temperature was assumed to be at a minimum of
60*F, and it was assumed that the pumps (therefore, at least two of the three, the third
being a swing pump) are to be run continuously for 30 days, and that no standby modes
are available and no maintenance will be available. The licensee was asked to determine
whether this would affect the single failure assumption for the Safety Grade Cold
Shutdown (SGCS) issues being evaluated under the other portions of SIL 13.
The licensee referred to alarm response procedure OP 3353.VP1 A, "1-4: Aux Bldg Area
Temp Hi/Lo," Rev. OCHG19, step 4.6 which, in case the required number of heaters are
not operable, directs the operator to Technical Requirements Manual, Clarification 3.5.2,
Rev.1, " Emergency Core Cooling Systems - T., Greater Than or Equal to 350*F," and to
start the second charging pump. Step 4.9 of OP 3353.VP1 A states that if at any time, the
operating charging pump cubicle temperature is equal to or less than 59*F, the operator
should close and red tag 3CHS*MV8104, the emergency boration valve, and
3CHS*MV8507A, BAT A gravity boration, and 3CHS*MV8507B, BAT B gravity boration.
The step also states that, if at any time the outboard pump end area temperatures of the
operating charging pump (s) is less than 55*F, refer to the applicable TS action and declare
the charging pump (s) inoperable. In step 4.10, the operators are to process a bypass
jumper and install portable heaters to warm charging pump cubicles.
Since at least one boric acid tank is required to achieve cold shutdown boration
concentration levels and the installation of portable heaters would not constitute use of
safety grade equipment, the inspector questioned how the licensee could achieve SGCS
within 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br /> assuming a loss of offsite power and a single active failure such as loss of
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66
one diesel generator or one bank of charging pump cubicle heaters if the area temperature
drops below 59'F. The licensee indicated that this issue will be addressed as part of DCR
M3 96064. This is a new inspection issue relative to this Sll, and it will be tracked as part
of the resolution of unresolved item, URI 50-423/96-08-20, which remains open as
indicated in section E1.1 above.
l
The inspector also noted that the design engineer had not included El&C (Electrical
Instrumentation & Control) on the distribution for the design change notice. In addition,
AOP 3562, " Loss of instrument Air," Rev. 3, 04/12/96, did not directly address
overcooling of charging pump lube oil. Therefore, the licensee failed to change the CCE
temperature alarm setpoints. The alarm response procedure for Low CCE Temperature, OP 1 3353.MB3B, Rev. 4, indicated only that the operators should maintain CCE temperature
l above 80*F to prevent condensation in the charging pump lube oil. Operators had not been
'
trained to respond to this scenario where the temperature cannot be raised above 40*F.
The licensee then changed OP 3353.MB3B to direct the operators to contact the Condition
Monitoring specialists to monitor moisture content of the oil, as per a memo from Berkman
to BERGETR, 11/20/97, "DCR M3-97085-Related Required Procedure Changes."
In the event that a " Charging Pump Cooling Pump A (or B) Suction Temperature Low"
alarm occurs and cannot be corrected within one shift of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, OP 3260, Rev.10,
09/08/97 " Unit 3 Conduct of Operations" would be invoked. This procedure contains an
annunciator response general operating procedure which would lead the operators to report
l a problem and initiate a corrective action under RP 4 " Corrective Action Program." in step
1.8.5 of RP4, the operators would be instructed to establish evaluation due dates in the
AITTS (Action item Tracking and Trending System) of 30 days. The inspector considered
this course of procedural and programmatic actions to satisfy the licensee's design
condition limitation of 30 days for operation of a charging pump under low CCE water
temperature conditions adequate.
l
In a related issue, the licensee provided minor modification (MMOD) M3-97605, Rev. O,
1 10/15/97, " Safety injection Pump Cooling System (CCI) Low Temperature Design," This
MMOD lowered the CCI minimum design temperature, specified in vendor documents as {
60*F, to 40*F. ACR M3-96-0218 reported a lack of design documentation supporting
operation of the Safety injection Pumps (3SlH'P1 A and B) under a SW temperature l
condition of 33*F. The ACR corrective action required analysis and productidn of design l
documentation to assure SI pump operability under this condition. This issue was self j
identified in ACR M3-96-0218, "CCI Overcooling," 06/23/96, but the operability of the Si !
pumps under this condition was not confirmed until April,1997 upon completion of a study
by the pump manufacturer, " Lube Oil Temperature Study for Northeast Utilities System 3"
JHF Safety injection Pump - Pump Original S.O.: J49870 - Pump Serial Numbers:
51926/51927 - Job Number: NR 061721 - P.O. Number 02014932," by ingersoll-Dresser
Pump Co.,04/01/97. The analysis by the pump manufacturer did not provide a complete
l
description of the method of analysis. The licensee cbtained a letter from the manufacturer !
I dated 2/5/98 which indicated that the manufacturer had reviewed documentation by the
licensee of phone conversations describing the method of analysis used by the
manufacturer and that the manufacturer was in general agreement.
,
!
.
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67
c. Conclusions
Several issues were noted in the review: 1. There were several examples where the
resultant required changes in operational procedures were not made as a result of the
. design modification concerning the adjustment of the charging pump lube oil set pressure:
2. The licensee's operability determination for the charging pumps under low service water
temperature of 33'F as initially presented was incomplete. 3. The inspector noted ,
discrepancies in the analysis concerning the ambient temperature in the charging pump
cubicles. The licensee could not demonstrate that SGCS could be achieved within 66
hours assuming a loss of offsite power initiating event and a single active failure such as
loss of one diesel generator or one bank of charging pump cubicle heaters if the area
temperature drops below 59'F. This issue remains unresolved as part of URI 50-423/96-
08-20; 4. For the safety injection pumps, the analysis by the pump manufacturer did not
provide a complete description of the method of analysis. Therefore, LERs M3 96-028-00
and 01 remain open, as does URI 50-423/96-08-20.
E1.3 (Undate) LER 98-040-00 and ACR M3-96-0887: Potential Comoonent Coolina
System Overcooling Due to Loss of Instrument Air Svstem Concurrent with Low
Service Water Temperature (Update - SIL ltem 13)
. a. Insoection Scone (927001
l
In accordance with 10 CFR 50.73, on November 22,1996,'in LER 96-040-00, the l'censee i
L reported a failure scenario in which a loss of the non-Category.1 Instrument Air System
'
(IAS) would allow Reactor Plant Component Cooling Water (CCP) system heat exchanger i
outlet temperature control valves (3CCP'TV32A/B/C) to reposition to maximum cooling
configuration. Coupled with a low heat load and minimum Service Water (SWP) inlet
temperature, the CCP system could reach temperatures lower than values for which thy
are analyzed, thereby rendering the CCP system, and systems that it serves, potentially ,
inoperable. The licensee reported the causes of this event to be: (1) improper initial design '
[ of the CCP system wherein the plant's architect engineer did not analyze for extremely low :
' CCP heat loads concurrent'with very low SWP temperatures; and (2) inadequate review of
'
industry and Millstone 3 operating experience evaluations associated with the CCP system
and loss of the IAs. During this inspection, the inspector reviewed the licensee's
engineering activities to resolve the technical concerns associated with this issue and
assessed ongoing plant design modification activities.
b. Observations and Fir;dinas
The inspector reviewed the licensee's engineering activities which included issuance of
ACR M3-96-0887 to identify corrective actions. The corrective actions included:
temporary and permanent modifications to the three-way CCP heat exchanger temperature ;
control valves 3CCP'TV32A/B/C; review and update of CCP stress data packages; I
changes to operating procedure OP3353.MB1C; and training.
The inspector reviewed DCR M3 97015, Ref. 3.28, Proto-Power Calculation 97-129, Rev.
A, "CCP Heat Exchanger Process Temperature Results From 33*F CCP Temperature
a _ _ _ _______ _ _ - _ - _ - __ _ - - _ _ ___ ______ _ _ - - _ _ - _ _ - . _ _ _ - _
_ - _ _ - _ _ _ - - _-___ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ __ _ ____ _ _ _ - - _ _ _ _ - - _ - _ _ _ _ .
.
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68
Operations," dated 2/3/98. The conclusions of the calculation were that failure of the CCP
temperature control valves together with a 33*F CCP temperature will result in a process
side outlet temperature of 54*F from the RHR Heat Exchangers,52.5'F from the Spent
' Fuel Pool Heat Exchangers, and 40'F from the Seal Water Heat Exchangers. It was
j recommended that the RHR stress data package calculation SDP-RHS-01360M3, Rev (9), ,
Spent Fuel Pool stress data package calculation SDP-SFC-01363M3, Rev (4), and the j
Charging System stress data package calculation SDP-CHS-01336M3, Rev (12) all be j
,
updated, in Attachment D, the licensee enclosed letter 25212-ER-98-OO26, dated '
1/30/98, to Proto-Power which included design inputs for the calculation to determine the
effects of cooling the RHR heat exchangers (3RHS*E1 A/B), Spent Fuel Pool Heat
Exchanger (3SFC*E1 A/B), Letdown Heat Exchanger (3CHS*E2), Excess Letdown Heat
r Exchanger (3CHS*E1 A/B) and Seal Water Heat Exchanger (3CHS*E4) with 33*F cooling
i water resulting from a failure of the CCP temperature control valves (3CCP'TV-32A/B/C).
'
The licensee had not yet received a response.
The inspector performed a sample walkdown of piping support modifications in the
Auxiliary Building and the Fuel Building pertaining to these DCRs. To the extent that field
verification was possible, all modifications were completed as shown on the drawings. The
licensee indicated that all of the support modifications had been completed except three for
the CCP system and one for the SW system. Completion of the SW system support
modification would require switching to the alternate train of service water,
in view of potential changes to the stress analysis calculations which may result from the
recalculation of the CCP temperatures as called for by the letter of 1/30/98, and possible >
l changes to operating procedures for the numerous heat exchangers which are affected by
the lower 33*F temperature, LER 96-040-00 and ACR M3 96-0887 remain open pending
l. incorporation, as required, of any revised temperatures or stress analysis results into, and
l issuance of, the affected DCRs M3 96064 and M3 97015, verification of completion of
l modifications to CCP temperature control valves 3CCP*TV32A/B/C, documentation that
the remaining support modifications have been completed, and sample inspection of the
final stress analysis calculations following delivery from the offices of the licensee's
architect-engineer.
c. Conclusions
The inspector reviewed a calculation referenced in DCR M3 97015 concerning CCP heat
exchanger process temperature results from 33*F CCP temperature operations. Changes
- may be needed in the stress analysis calculations es a result of the recalculation of the CCP
l .- temperatures, called for by letter dated 1/30/98. There may also be changes to operating
procedures for the heat exchangers, which are affected by the lower 33*F temperature.
LER 96-040-00 and ACR M3 96-0887 remain open pending: incorporation, as required, of
any revised temperatures or stress analysis results into the affected DCRs, M3 96064 and
M3 97015; completion of modifications to CCP temperature control valves
3CCP*TV32A/B/C; documentation that the remaining support modifications have been
completed; and review of the final stress analysis calculations following delivery from the
offices of the licensee's architect-engineer. As a result of all the inspection issues
t.
i
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69
documented in Sections E1.1, E1.2, and E1.3 above, SIL ltem 13 remains open and is
hereby updated.
E1.4 (Closed) ACR M3-96-0685: Thermal Relief Valve Setooints (Closed - SIL ltem 58)
l
'
a. Insoection Scone (37551.92903)
i
The Reactor Plant Component Cooling System (CCP) Thermal Relief Valve pressure settings
were not in agreement with the piping design pressures shown on the Line Designation
Tables (LDT). The purpose of the thermal relief valve in each system is to provide a
pressure relief mechanism to prevent exceeding design pressure should several systems be
valved shut and continue to receive heat, causing the fluid to expand and thereby stressing
the system until the relief valve opens. The original vendor-supplied pressure calculations
failed to account for the elevation differences of system components. The CCP system
contains both ASME Class 3 and ANSI B31.1 (NU Class 4) piping. i
b. Observations and Findinos
The calculation for each of the 52 relief valve setpoints was made by noting the static
pressure difference caused by elevation differences between the relief valve and the !
component and then adding (sometimes subtracting) this pressure difference to the
manufacturers' limiting component design pressure. This new low-point calculated-system
pressure was then declared to be the "new system pressure" and is equal to the thermal i
relief valve set point. After reactor start up, the LDT will be changed to reflect the new l
design pressures. In accordance with code requirements, the Class 3 system components
had previously been subjected to a hydrostatic pressure test of 125% of the original
" design" pressure and Class 4 non-safety piping system components had been subjected to
a hydrostatic pressure test of 150% of the original " design" pressure.
The inspector reviewed ACR M3-96-0685 and calculation 97-ENG-01454-M3 Rev. O and
other associated engineering drawings and documents. The inspector compared the newly !
calculated design prossure, as tabulated in the 97-ENG-01454-M3, Rev. O, with the former l
design pressures. The calculated pressures agreed with the actual relief valve setpoint
pressures.
The Code of Record for MP3 for Class 3 piping is ASME Section XI,1983 Edition, Summer
83 Addenda. IWA -7000 of ASME XI calls for replacements and modifications to meet the
requirements of the original construction code which, per the MP3 piping design
specifications, is the ASME Section lll ,1971 edition, Summer 1973 Addenda. However,
there are no provisions in the cited construction code for the rerating of systems, only leak
testing. The 1983 Edition, Summer 1983 Addenda of ASME XI also does not address the
rerating of a system. lWA-4312 cf ASME XI 1995 Edition,1996 Addenda, provides rules
.
for rerating a system. Although the 1996 Addenda is not approved for use in 10 CFR 50,
I it is being used by the licensee for guidance in developing the repair / replacement plan. The
licensee regards the rerating requirements of this later 1996 Code Addenda edition as
enhancing and adding to rather than reducing the requirements to the original construction
Code of record. The cited later 1996 ASME Code prescribes a hydrostatic test of 1.1 times
1
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_ _ - - _ _ _ _ _ _ _ . --_ - - _ - _ - _ - _ _ _ - _ - - , _- - _ _ . - _ _ .
_ _ _ _ _ _ _
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1
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1
. the " design" pressure for systems with a design temperature equal to or less than 200 ;
i degrees F and a hydrostatic test of 1.25 times the design pressure for systems with a l
l design temperature over 200 degrees F.
The new design pressure times 1.1, is less than the original hydrostatic test pressures (the
l original design pressure times 1.25), thus eliminating the need for a new hydrostatic test of
l
all but three lines (3CCP-750-785-3,3CCP-OO6-159 3,3CCP-OO6-495-3). In response to
the inspector's inquiry, the licensee provided the design temperature of each of the lines in
question, discovering in the process three high temperature lines. Since these lines have a
design temperature of 200 degrees F or greater they thus required a new hydrostatic test
!' of 1.25 times the new design pressure. Subsequent to the inspection period, the
hydrostatic test of these three lines was satisfactorily completed. The previous
construction hydrostatic testing is deemed adequate for the other lines with a design
l
temperature below 200 F.
I
c. Conclusions i
The resetting of the setpoints of the thermal relief valves, to take into account the static
- head caused by elevation differences in the system, is deemed adequate. The licensee will
l- leak test the non-safety Class 4 lines, in accordance with the 1973 version of ANSI B31.1,
l the code of record. The licensee has hydrostatically tested the three high temperature lines
l
to at least 125% of the new design pressure of 180 psig. ACR M3-96-OS85 is closed.
Based upon. licensee corrective actions to address NRC questions in the closure of this
ACR; coupled with prior NRC inspections of this SIL item, documented in inspection reports
(IR) 50-423/97-02 and 97-207, both eel 96-201-33 & SIL ltem 58 are considered closed.
l
The NRC Notice of Violation (NOV - letter unique identifier 04083) currently remains
administratively open.
U3 E2 Engineering Support of Facilities and Equipment
E2.1 (Closed) URI 96-201-14: Station Blackout Diesel Generator Desion and Test issues l
(Closed - SIL ltem 67)
a. Insoection Scone (9290JJ
!
NRC Special Inspection Report 50-423/96 201 identified issues regarding the station
blackout (SBO) diesel generator (DG) starting and loading capability, and its surveillance l
testing program. Specifically, Unresolved item (URI) 96-201-14 addressed concerns !
regarding: (1) the consideration of the effects of inrush currents associated with electrical i
motor startup, (2) the potential loss of SBO DG start capability when SBO conditions occur
within 30-45 minutes after a loss of normal power supply to the computer, (3) the potential j
'
adverse effects of sustained operation of the SBO DG in an unloaded condition. (4) the
adequacy of the SBO DG surveillance program, and (5) the adequacy of current operator
log sheet acceptance criteria for SBO DG battery voltages.
!
l
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- _ -- --- _ - - - - - - - _ - - - - - - - - - - -
E
,
..
71
Additionally, NRC Letter (TAC M96054), dated 8/27/96, identified a concern regarding the
potential unavailability of the SBO DG after one hour of loss of offsite power (LOOP) due
to depletion of its dedicated battery power.
The inspector reviewed the licensee's corrective actions to address the above-mentioned
specific concerns.
b. Observations and Findinas
NU Calculation PA 90-050-0308E3, " Station Blackout Diesel Generator Loacing," Revision
1, has been revised to reflect changes to the SBO loads based on the equipment lists
j included in engineering specification SP-EE-363, " Millstone Unit 3 SBO Safe Shutdown
l Scenario Document," Revision 3. Procedure EOP 35 ECA-0.3, " Loss of All AC Power -
Recovery with the SBO Diesel," Revision 4, was revised to incorporate changes in the load
information from updated design data. Conservative assumptions of diversity factor for the
l motor control center (MCC) loads were used in the SBO DG loading analysis. Inrush (or
I pull-in) power or kW was added to the steady-state kW rating of the motor loads to
determine the peak kW at each step of the SBO DG loading sequence, it was noted that
,
the calculated peak kW for the " charging pump start" load step was about 101 percent of
i the SBO DG peak kW, and the impact of this transient condition was not fully evaluated in
l the revised calculations (i.e., Revision 2 of NU Calculation PA 90-050-0308E3). The
i licensee agreed to perform additional analyses to evaluate the worst case voltage drop
i during motor starting in the SBO DU loading sequence (AR #98003089 was initiated to
track this item). The steady state " running kW" after the last loading step was about 77
percent of the maximum SBO DG steady state kW rating. This indicates that there is
adequate margin of the SBO DG capability to supply AC power to the minimum required
equipment to cope with SBO conditions. The inspector did not have any additional
concerns with the revised calculations of SBO DG loading conditions.
l
l Revisions to EOP procedures were made to assure SBO DG availability during a postulated
eight-hour duration LOOP event. Section 8 of procedure EOP 35 ES-0.1, " Reactor Trip
Response," Revision 15, now provides guidance for operator actions to power the SBO DG
l
'
auxiliaries from the emergency bus within the first hour of LOOP conditions. If the
emergency bus is being powered by an emergency diesel generator (EDG) following a LCOP
event, plant procedures direc". the operators to start the SBO DG to power the auxiliaries to
ensure continued availability. Also, a modification was implemented to allow the SBO DG
j to power a nonsafety-related bus, while the EDG is powering a safety-related bus. With
l
this alignment, the SBO electrical load can be increased to avoid potential problems
l associated with extended operation of a DG under lightly loaded conditions. EOP 35 ES-
! 0.2 was revised to provide directions to the operators to add load to the SBO DG.
1
Revisions to procedure OP 3346D, " Station Blackout Diesel" (Revision 5) were also made
to prevent operation at low load for extensive time periods. The inspector verified that the
revised procedure included instructions to operate the SBO DG at 40 percent of full load for
at least 30 minutes whenever the SBO DG had been idling for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, or was operating for
l
l
__ _ _ _ _ . _ _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _
.'
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l
72
l 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> at less than 20% load. The revised procedure also included changes to operating
the SBO DG at higher load limits (i.e., between 2260 to 2360 kW, and between 1700 to
'
l
'
1800 kVAR loading) for surveillance purposes. In addition, procedure EOP 35 ECA-0.0,
" Loss of All AC Power," Revision 13 provided guidance to load the SBO DG once local
actions were taken to start the SBO DG. The procedural revisions were considered to be
acceptable.
As noted previously, procedure OP 3346D was revised to increase the operating load limits
(i.e., between 2260 and 2360 kW load) for the quarterly surveillance tests of the SBO DG.
This corrective action ensured that the SBO DG is tested at its continuous rating.
Therefore, the specific issue concerning the inadequacy of the SBO DG surveillance
program was considered resolved.
Regarding the operator log sheet acceptance criteria for SBO battery voltages, procedure
3786AB, "SBO Battery PM's and Equalize Procedure," Revision 0, was written to provide l
guidance for the weekly and quarterly inspection of the SBO DG 125 Vdc batteries. The
inspector verified that the procedure contained specific instructions for the weekly
verification of the pilot battery voltage and total battery voltage. The acceptable range of
the pilot battery voltage was between 13.5 and 13.8 volts, and the acceptable range of
total battery voltage was between 135 and 138 volts. This new procedure for weekly and
quarterly preventive maintenance of the SBO DG batteries ensured that battery life was ,
maintained per manufacturer recommended operating values. !
c. Conclusions
!
Licensee corrective actions to address all five concerns associated with the NRC l
unresolved item were determined to be acceptable. Based upon the foregoing inspection. l
results, other inspections (reference: IR 50-423/97-01), and other SBO equipment reviews
documented in other sections of this inspection report, URI 96-201-14 & SIL ltem 67 are
both considered closed. i
1
E2.2 (Closed) eel 96-201-08: Failure to Evaluate Station Blackout (SBO) Eouloment and-
Procedures in Accordance With 10 CFR 50.59 (Update - SIL ltem 78)
i
- a. Insoection Scone (92903) l
The inspectors reviewed licensee actions to address NRC findings that safety evaluations I
were not performed to determine that changes to station blackout equipment and !
procedures described in the FSAR did not involve an unreviewed safety question. The l
specific issues were.
- 4160 V cables were not installed as described in the FSAR in that a short section of
cable was exposed to the environment and not fully installed in duct banks or cable '
trays.
l
!
4
- _ _ _ - - - _ _ _ _ _ _ _ _ _ - _ _ - - _ _ _ - _ - - . _ _ _ _ _
l
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73
- The SBO diesel generator was not being tested at full load.
l
l
- Periodic maintenance and surveillance was not being performed on SBO support
equipment.
b. Observations and Findinas
The licensee performed a technical evaluation of the 4160 V cables and concluded that the
installation was acceptable. FSAR Change Request (FSARCR) 97-MP3-552 will correct the
FSAR and the change will be evaluated in accordance with 10 CFR 50.59. An action
request has been initiated to track the completion of this item and is scheduled to be
complete prior to plant restart.
The licensee has revised the SBO diesel generator procedures to specify operation at full
load during the quarterly test.
Procedures have been issued to accomplish recommended periodic maintenance and
surveillance testing of SBO support equipment and all activities are current.
c. Conclusions l
l
The inspector reviewed the corrective actions taken and planned, discussed the issues with
the system engineer and performed a walkdown the SBO diesel generator. The inspector
concluded that the licensee has appropriately addressed the technical aspects of the
issues. eel 96-201-08 is considered closed. The NRC Notice of Violation (NOV - letter
unique identifier 01222) currently remains administratively open. SIL ltem 78 is hereby
updated.
E2.3 (Uodate) eel 96-201-01: FSAR Accuraev - SBO Batterv (Update - SIL ltern 2)
a. Insoection Scoce (929031 ,
l
The inspectors reviewed actions taken by the licensee to address NRC findings that the
Unit 3 FSAR was not maintained up to date or did not reflect the actual plant configuration
or operating practices,
b. Observations and Findinas
in inspection report 50-423/96-201, the team noted that the Millstone Unit 3 FSAR was
inconsistent with the as-built plant configuration (eel 96-201-01). One of the six issues
identified as part of the violation concerned the alternate AC system description in the
FSAR. FSAR Section 8.3.1.1.6 states that the alternate AC system switchgear enclosure
contains a battery rack, a 60 cell battery, and a battery charger, which supplies 125
! Ampere-hours at 125 Vdc nominal. However, during a plant walkdown, the team observed
i
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u___--__- _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ ___ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _- _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -
__ __ ___ __ - _ _ _ _ _ _ _ _ - _ - _ _ _ ___ _ _ _ _ _ _ _ _
_ _ _ - -
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74
that the installed battery is a GNB type 6-MSB-2010 battery with a nameplate rating of 80
Ampere-hours.
Based on the team's finding, the licensee issued FSARCR 97-MP3-39 which changed FSAR
Section 8.3.1.1.6 to accurately reflect the as-built plant configuration.
1
c. Conclusions
The inspector reviewed the changes to the FSAa and found they appropriately addressed
this specific issue. eel 96-201-01 & SIL ltem 2 are hereby updated. As other examples of
FSAP/ plant configuration problems were identified as part of eel 96-201-01, the overall
issue of FSAR adequacy and the licensee's corrective actions to address the FSAR change
process will be addressed as part of the staff's continuing review of SIL ltem 2.
U3 E3 Engineering Procedures and Documentation
E3.1 (Closed) Unresolved item 50-245.336.423/97-203-09: Environmental Qualification
I (EQ) Proaram Procedures. Use of "DBE 50*C Eauivalent Life"
l
l
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a. Insoection Scoce (92903)
During the July 1997 inspection, the inspector reviewed the EQ program procedure and its
attachments effective at that time, " Electrical Equipment Qualification Program Manual,"
Revision 1, dated March 31,1994, and had three concerns in their use of "DBE 50*C
Equivalent Life" for post accident operating time extrapolations as discussed in the EQ
program procedures. These concerns were:
(1) Since the tested temperature profile was divided into many (75-100) short intervals,
the engineers could have unknowingly used this DBE 50*C equivalent life method
for some intervals to extrapolate to higher temperature with shorter duration instead
of extrapolating longer duration with lower temperature;
(2) There was no NRC technical guidance for using "DBE 50*C equivalent life" for post-
accident operating time extrapolation, especially for the duration just one hour into
the test. In many cases, the temperature at that time was still at the peak level,
and had not yet stabilized. The validity of this assumption was questionable,
because there was insufficient test data that could be provided by the licensee to
demonstrate that this usage was conservative; and
(3) The use of the Arrhenius equation was for constant temperature only. Its use for
cases where the temperature was continuously changing (negative ramp function)
must be supported by test data to demonstrate its validity. Such test data was not
available at the time of the inspection.
_ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ ._ -
_ _ _ _ _ _ _ _ _ _ _ .
. - - - -
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75
During this inspection, the inspector reviewed the newly revised EQ program
procedures, including all attachments, which the licensee stated had addressed the
above concerns.
b. Observations and Findinas
During this inspection, the inspector reviewed Revision 3 of the EQ program procedure,
which was issued on December 19,1997, and noted that Attachment PI-5.3,
" Methodology for Performing Thermal Aging Life and Test Profile Validation Analyses," was
revised as follows: Section 3.3.1, " Profile Enveloping," of the revised procedure states:
The test profiles for EQ devices located in a specific harsh zone are plotted
and super-imposed over the postulated plant accident profile. Qualification
of equipment for use in harsh temperature environments requires that the
tested temperature conditions envelope the postulated plant accident i
temperature conditions for the post-accident duration during which the
equipment must function. Any deviations must be justified.
The inspector determined that this provision addressed Concern #1.
Item 3 cf Section 3.3.2, " Post-Accident Operating Time," of the revised procedure states: l
I
l
The application of Arrhenius methodology in determining post-accident j
operating time is only valid when comparing the latter portions of the test i
and plant temperature profiles using the following criteria:
1. After 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,
2. The profiles are in a non-transient state (i.e., '.amperature is decreasing or in i
a steady state condition), and
3. The tested temperature conditions envelope the postulated plant accident !
temperature conditions for the post-accident duration used in the analysis.
Any deviations from the above criteria must be justified on a case by case basis.
The inspector determined that these criteria were reasonable for this application, and that
Concern #2 was addressed.
Item 3 of Section 3.3.2 of the revised procedure also states:
The use of Arrhenius methodology to compare transient conditions is not
acceptable because of the difficulty in establishing exactly how much
accelerated aging a given device actually experiences during transient
temperature conditions such that short test durations at high temperatures
!
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76
can dominate the exponential Arrhenius relationship and yield non-
conservative results.
Acceptable qualification requires clear identification of which portions of all
profiles are being extrapolated. Only steady state conditions are considered,
with down sloping portions of the profile modeled as steady state using the
lowest temperature of the downward slope at the time the down slope
occurs."
The inspector agreed that this procedure change addressed Concern #3.
In addition, the licensee had completed a volume of calculations (94-Eng-1015-E3) entitled,
" Determination of Required DBE 50'C life for EQ Areas at MP3 & Technical Basis for Lack
of Temperature Profile Enveloping," Revision 3, dated December 9,1997. The inspector
reviewed the calculations for three components and confirmed that the calculations were
based on the new criteria prescribed in the revised program procedure as discussed above.
c. Conclusions
The inspector concluded that the licensee's revised program procedure had adequately
addressed the concerns raised by the inspector, and that the licensee's new calculations
for justifying the post-accident-operating-time qualification were based on the new criteria
prescribed in the revised program procedures. Therefore, this unresolved item is closed.
Since the revised procedures also applied to Units 1 and 2, unresolved item 50-
245,336/97-203-09 are also closed.
There was no explicit NRC guidance governing the extent of use in applying the Arrhenius
methodology for post-accident operating time extrapolation prior to the July 1997
inspection. The use of this method by each utility was based on engineering justification.
Following the July 1997 inspection, NRR held several meetings with utility companies and
the Nuclear Energy Institute with the intention of establishing guidance acceptable to both
the NRC and the utilities. In addition, this unresolved iter" was identified when all three
units were shutdown. Therefore, the inspector concluded that no violations were involved.
E3.2 (Closed) Unresolved Item 50-423/97-203-10: Post Accident Samolina Valves inside
Containment
a. Insoection Scoce (92903)
During the July 1997 inspection, the inspector identified that the junction boxes of eight
Target Rock solenoid valves inside the reactor containment did not have weep holes.
These solenoid valves (3 SSP'SOV 1 A,1B,1C,1D, 2A, 28,3, AND 5) were post-accident
, sampling valves, and were required to function following a postulated design basis
accident. Generally, for electrical circuits inside the containment, weep holes were
i
required in the junction boxes to avoid condensate accumulation which could render the
i
_ _ _ - _ _ _ _ _ _ _ _ _ _ - - _ -
_ _ _ _ _ _ _
. _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ ___ .
.
..
77
terminations inoperable (due to short or grounded circuits). Initially, there was no clear
design basis for these solenoid valves, which the licensee stated were not safety-related.
However, in a letter that the licensee sent to the NRC on July 31,1997, the licensee
clarified the licensing basis for those valves as, "all remotely actuated PASS (post-accident
'.
sampling system) isolation valves that are not accessible after an accident are designed to
function under pressure, temperature, and radiation conditions which they will encounter."
The licensee could not demonstrate, at that time, that those solenoid valves as installed
could function post-accident. Therefore, the licensee agreed to make those valves
functional by: 1) providing environmental seats to the electrical connections; and 2) drilling
a weep hole at the bottom of each affected junction box. During this inspection, the
inspector reviewed: 1) licensee's corrective actions for resolving this issue to determine
their acceptability; and 2) licensee's evaluation to determine the deportability of this issue.
b. Observations and Findinas
Following the conclusion of the July 1997 inspection, the licensee issued CR M3-97-4688,
on December 17,1997, to document 11s deficient conditions. This condition report
identified the action items that needed to be completed before the report could be closed.
This condition report also indicated that similar situation might exist on the Unit 2 PASS,
and that Unit 2 had issued Evaluation M2-EV-970057, "EEQ SOV Evaluation for in-
containment," Revision 1, to deal with this issue at Unit 2.
During this inspection, the inspector reviewed licensee installation records and walkdown
reports. The reviewed documents confirmed that weep-holes and environmental seals
were installed. The inspector also walked down four solenoid valves (3 SSP *SOV 1 A,1B,
1C,1D) inside the containment and verified that environmental seals and weep holes were
properly installed.
The licensee stated that they had evaluated the deportability of this issue and determined
that this issue was not reportable. The determination was based on a document (M3-Ev-
97-0265), entitled " Engineering Evaluation for placement of weepholes in junction boxes
and conduits for EEQ equipment," Revision 0, dated November 20,1997. In the "in-
containment" section of this evaluation, the licensee documented a calculation which
indicated that, under a postulated loss-of-coolant accident (LOCA) condition, the maximum
accumulated condensate level in the junction boxes would not cause water to be drained to
the solenoid valve termination. Therefore, the licensee concluded that these solenoid
valves had never been inoperable. The inspector considered this evaluation acceptable.
c. Conclusion
The inspector concluded that the corrective actions taken by the licensee to resolve this
issue were acceptable. Therefore, this unresolved item is closed. The PASS was a
nonsafety-related system. The design basis for the affected solenoid valves was not
specified in the FSAR and the description in the safety evaluation report (SER) was
ambiguous. Although the design basis was later clarified in the licensee's July 31,1997,
_ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ . _ _ _ _ . _ _ _ _ - _ _ _ _ _ . _ _ _ _ _ _ .
_ _ - _ _ _ _ _ __ _ - _ _ _ - - _ _ - _ - _ _ _ - _ _ _ _ - _ _ _-_______ _
,..
..
78
. letter, Millstone Unit 3 was not in operation since then. No violations of NRC requirements
were involved.
U3 E7 ' Quality Assurance in Engineering Activities
E7.1 Review of items to be Comoleted After Restart
a. Insoection Scone (37550)
in a letter dated April 16,1997, the NRC requested, in part, that the licensee provide the
following information pursuant to 10 CFR 50.54(f):
- For each unit, the list of significant items that are needed to be accomplished prior
to restart;
l
l.
- For each unit, the list of items to be deferred until after restart; and,
e For each unit, the process and rationale used to defer items until after restart.
The letter also requested updates approximately every 45 days'for the first two items.
Inspection Report 50-423/97-202 documented the NRC review of the Unit 3 initial
submittal, dated May 29,1997, and the first update dued July 14,1997. The NRC found
. that the licensee determinations of items to be deferred was generally appropriate.
However, three items were removed from the deferred items list based on the inspection.
The inspectors concluded the items would not have had a significant impact on plant
operations had they not been completed prior to startup. ' The inspectors also identified q
problems with the completeness and accuracy of the submittal resulting in a Notice of
Violation for failing to comply with 10 CFR 50.9, " Completeness and accuracy of
information."
The licensee provided the second deferred items list update for Unit 3 on October 21,
1997, and the NRC inspection of the update was documented in inspection Report 50-
-423/97-207. This inspection focused on the items added to the list since the previous
update. The inspectors had dmilar findings to those documented in previous deferred issue
reviews in that the licensee determinations of items to be deferred was generally
appropriate. As a result of this inspection, the licensee revised the status of four items
from deferred to required prior to startup. The inspectors again noted that if these items
had been deferred, they would not have a significant impact on the safe operation of the
plant.
The licensee provided the third deferred items list update for Unit 3 on January 9,1998.
This submittal added approximately 2000 items to the list. During this inspection, the NRC
reviewed the one line description of all the items added during this update and then
l
l
I:
l
..
)
,
79
selected approximately 175 for more detailed review. The inspectors identified the
following discrepancies with the deferred items list:
l
l * Three work orders were included on the list that did not meet the licensee deferral
criteria. These items involved alignment of a safety-related charging pump, testing
l of EDG enclosure dampers and installation of a plug to monitor the containment
- basemat. The inspectors noted that in each case the work was already completed.
l The licensee documented the incorrect inclusion on the deferred items list on CR
M3-98-0831.
- Engineering woIk request (EWR) M3-97132 involves the spurious cycling of the
residual heat removal recirculation valves following pump starts. The issue was
included for deferral based on the licensee determination that the condition did not
affect the system operability. As a result of the inspector's questions, the licensee
performed additional reviews and concluded that under certain conditions the
recirculation valves could continue to cycle closed and open until the valve would
frJI mechanically or the motor therma! overloads would trip. Depending on the valve
position when a failure occurred there could be inadequate cooling of the RHR pump
that could result in pump failure. The licensee reported this condition to the NRC in
- accordance with 10 CFR 50.72 and the item was removed from the deferred items
list. The licensee plans to implement a modification to resolve this issue prior to
entry into Mode 4. CR M3-98-0897 was initiated to document this issue. This item
is unresolved pending NRC review of the licensee corrective actions. (URI 50- l
423/98-06-05) :
!
!
- EWR M3-9714C and several work orders were issued to improve the pre-staging and
control of tools and equipment required in various areas of the plant to implement
actions contained in emergency operating procedures (EOPs). The inspectors
questioned whether measures had been taken to ensure all tools and equipment
l were readily available to operators in the interim until the improved controls were
implemented. The inspectors were informed that an audit of tools and equipment
had been performed and some discrepancies were identified. However, there were
l no specific plans to address the discrepancies prior to restart. The inspectors
concluded that the deferral of these issues was not appropriate unless adequate
interim actions were taken to address the issue. The licensee subsequently initiated
an action request to verify tools and equipment will be available prior to restart.
- CR M3-97-3729 identified a condition where a section of piping downstream of the
inboard containment isolation valve could be subjected to excessive pressure due to
thermal of expansion of the water in the isolated piping. The CR states that the
inboard containment isolation valve could potentially be damaged by the excessive ;
pressure. The inspectors questioned whether an operability determination had been '
performed to provide a basis for deferring the issue to after startup. The inspectors
I were informed that an operability evaluation had not been performed and concluded
that this issue should not have been included on the deferred issues list.
l
_ _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_______-__ - _ _ _ _ - _ _ _ _ - _ _ - _ _ _ _ _ - _ - _ _ _ _ - - _ - - _ _ _ _ _ _ _ _ _ . _ _ _ - _ _ _ _ _ _ . - _ _ _ _
e*
80
The inspectors also noted that the licensee's Probabilistic Risk Assessment group
performed a review of a significant number of action request items (approximately 2500 to
3000 items) to determine if the items were appropriate for deferral to after restart. Of the
items reviewed, the group identified eleven items that warranted additional evaluation to
ensure that deferral was appropriate.
c. Conclusions
The inspectors concluded that the licensee's evaluation of the issues to determine if they
could be deferred until after plant startup was not effective as evidenced by the above
findings. Since the inspector findings were based on a one-line review of all items and a l
more detailed review of only a sample number of items, additional actions appear to be
warranted by the licensee to ensure that all items on the list are appropriate. Violation 50-
423/97-202-08 remains open pendin'g NRC review of the licensee's actions to ensure the
list is accurate and additional NRC review of the deferred issues list. ,
E7.2 (Closed) eel 50-423/96-09-16 & ACR M3-96-0718: Analvsis of SOV Failure Modes
due to Maximum Ooeratino Pressure Differential (MOPD) (Update - SIL ltem 60)
1
a. Insoection Scone (40500. 92903) ,
Responding to NRC Generic Letter 91-15, which references NUREG-1275, the licensee
inspected Solenoid Operated Valves (SOVs) which control air pressure to air operated
valves (AOVs). The licensee initially reviewed the SOVs in the air control system and
determined that there were no issues. NRC Inspection report 423/96-09 determined that
the licensee's review of the SOVs and their MOPD design requirements were inadequate.
The NRC concern was that the SOVs could be subjected to an MOPD which was greater
than the design MOPD. Experience from other facilities as described in NUREG-1275,
Vol.6 indicated that the higher system pressure could cause the SOV to fail as-is and not in
the fail-safe mode. In addition, the application of full pressure can cause the unenergized
valve to lift or open. The failure to establish design controls a verify the adequacy of the
SOV design to operate properly when subject to full instrument air pressure was cited as
an apparent violation of the requirements of 10 CFR 50, Appendix B, Criterion lil, " Design
Controls" in Inspection Report 423/96-09. ,
I b. Observations and Findinos
The second licensee review of Unit 3 SOVs detailed their location, their MOPD, purchase
specifications and a review to determine if the SOVs were safety related. Forty eight SOVs
I in both safety and non-safety systems were found with a design MOPD of less than 110
psig.
The inspector reviewed eel 96-09-16, ACR M3-96-0718, and other associated engineering l
drawings and documents. Many SOVs found in the system had a typical design MOPD of
60 to 75 psig and could have been potentially subjected to the air operating pressure of
1
l
l
._ ____ _ _--__- __ _ ___ _ ___ _ - -_______ __ _ _ _ _ _ __
l
e-
81
110 psig. These SOVs are used to operate larger AOVs, most of which are safety related.
l TPe SOVs are provided air by an instrument air system through air regulators. Neither the
air system nor the air regulators, are safety related. The relief valves in the air supply
system are set at 125 psig, while the air regulators delivering air to the SOVs are set to
deliver air at a maximum of 110 psig. The air regulators are designed for a maximum air
inlet pressure of 250 psig.
Two separate walkdowns performed by licensee engineering and maintenance personnel
determined the quantity and identification of all SOV installation details. The data
collection was performed to an approved procedure. Databases of information collected for
safety related and non-safety related SOVs were created. Design documentation was
changed, where required, to reflect the data collected on the SOVs. Of the 48 identified
valves, seven were analyzed and determined to serve non-safety related AOVs and LCVs.
Thus, they were kept as Category 1 only for electrical separation and pressure boundary
purposes. Because these seven valves were not safety related their MOPD was thus not a {
concern, and no further action was required. The inspector reviewed Material Equipment l
Parts List (MEPL) evaluations for the remaining 41 valves and noted that the evaluations i
appeared proper. All of the 41 remaining safety related SOV's have been replaced with
new SOVs with an MOPD of 115 psig.
To address preventive actions, Station Procedure DC 18 "NRC Communications", Revision
0, Change 1, was written to implement a process for ensuring that NRC correspondence is !
reviewed for applicability to MP3 in a timely manner. Section 1.2 addresses processing of
incorning correspondence and Attachment 5 tracks NRC correspondence receipt and
distribution. A licensee Condition Report is to be generated by the licensee for items
requiring a response with corresponding individual Action Requests generated to track each
item to completion.
c. Conclusions l
Forty one SOVs have been remuved and replaced with upgraded SOV's with higher
MOPD's. The installation of upgraded SOV's is acceptable. The licensee effort which
implemented a new MP3 process to ensure that NRC correspondence is reviewed in a
timely manner is deemed acceptable. The technical issues associated with eel 50-423/96-
l 09-16 & ACR M3-96-0718 are considered closed. SIL ltem 60 remains open pending
I
review NRC review of one additio'nal ACR package, and is hereby updated. The NRC
Notice of Violation (NOV - letter unique identifier 01132) currently remains administratively
'
open.
l
E7.3 (Closed) LER 96-036 Safety Related Valves Controlled bv Non-Safetv Eauioment
l
a. Insoection Scoce (92700)
l A licensee engineering evaluation determined that the high pressure safety injection (SlH)
and low pressure safety injection (SIL) systems were subject to degraded performance due
- _ _ _ - _ _ _ _ - _ _ _ _ _ - _ _ __ . _ _ _ _ _ _
1 *
.=
82
l
l
to possible mis-positioning of normally closed safety-related air operated valves. The
licensee stated that mis-positioning of these valves is postulated to occur as a result of
possible failures related to non-qualified power and control circuits. The NRC staff
requested additionalinformation regarding this issue on February 12,1997, and January 2,
{
1998, to which the licensee responded on April 18,1997, and February 3,1998,
respectively. The licensee also provided updates to Licensee Event Report (LER)96-036 on
April 18 and July 25,1997. In the February 3,1998, letter, the licensee confirmed that
they reviewed approximately 114 valves which may be affected by the above condition at
Millstone Unit 3.
b. Observations and Findinas
The staff reviewed the disposition of the 114 valves which the licensee included in theic
review of LER 96-036. For 62 of the valves, the licensee performed an engineering
'
analysis and determined that the position of the valves is of no consequence during design
basis events. As such, an inadvertent opening of one of these normally closed valves
would not cause the associated safety system to lose its safety function during a design !
basis event. Therefore, the staff determined the licensee's disposition was adequate and l
had no further questions concerning these valves. The licensee's disposition of the !
remaining 52 valves is discussed below.
For 40 of the 52 valves, the licensee confirmed in the letter dated February 3,1998, that -
the valves are in the fail-safe position and must remain in the fail-safe de-energized position
during design basis events to support proper operation of the associated safety-related
system. The licensee stated that 32 valves are being modified to eliminate the potential
failures associated with exposure to harsh environmental conditions. For the high pressure
safety injection, low pressure safety injection, containment vacuum, and plant sampling
system valves, the circuit components are being qualified for the postulated harsh
I environmental conditions to preclude spurious valve operation. For the reactor coolant
system loop drain valves, the air supply to the air operators will be isolated, and the air ;
operator will be vented, precluding spurious valve operation. The licensee actions to
- address environmental qualification of these valves is addressed in Section E7.4 of this l
l inspection report. For the remaining 8 valves, the licensee stated that the valves are not
exposed to harsh environmental conditions during design basis events.
The NRC staff questioned why a single random failure of a raceway (or failure of one of the
circuits routed in the raceway) containing redundant nonsafety control circuits (in
conjunction with a design basis event) will not credibly cause failure (i.e., opening) of more
l than one of many fail-safe air operated valves located in safety systems,
in the letter dated February 3,1998, the licensee stated that with respect to random
l
failures of non-quality assurance control systems, the Millstone Unit 3 design basis as
i
described in the Final Safety Analysis Report (FSAR) is consistent with Westinghouse
i
positions. The licensee stated that the Westinghouse basis for assessing failures of these
nonsafety-related control systems was that the random control system malfunctions are
l
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_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . . _ _ _ _ _ _ _ _
.*
83
not postulated to occur prior to, concurrent with, or subsequent to anticipated transients of
design basis accidents. Random control system malfunctions may be an initiating event.
The licensee stated that this is consistent with Millstone Unit 3 FSAR Section 7.4 which
states that certain accidents and transients are postulated in the Chapter 15 safety
analysis which take credit for safe shutdown when the protection systems reactor trip
terminates the transients and the engineered safety features system mitigates the
consequences of the accident. In these transients, in general, no credit is taken for the
-control system operation should such operation mitigate the consequences of a transient.
Should such operation not mitigate the consequences of a transient, no penalties are taken
in the analysis for incorrect control system actions over and above the incorrect action of
the control system, whose equipment failure was assumed to have initiated the transient.
The inspector reviewed the licensee's response and the design basis as described in the
FSAR and had no further concerns in this area.
For 8 of the 52 valves which are in the post-accident sampling system (PASS), the licensee
is modifying the valves to eliminate potential failure modes associated with exposure to
harsh environmental conditions, to assure post-accident operability of the PASS system
function. The staff reviewed the licensee's corrective actions and had no further concerns
in this area.
For the final 4 valves, the licensee replaced the nonsafety-related controls with safety-
related controls. These modifications were reviewed by the NRC, as discussed in the
following report section.
c. Conclusions
The staff reviewed the licensee's corrective actions following LER 96-036 and the
. licensee's disposition of the 114 valves identified as being subject to possible mis-
-
positioning. The staff determined that the licensee's corrective actions were adequate. LER
96-036 is considered closed. The modifications and changes were reviewed by the NRC
during this inspection and found to be complete. Therefore, based on this review and the
l NRC's inspection documented in Section E7.4, SIL ltem 65 is considered closed, as
l discussed below,
i
l E7.4 Insoection of Safetv-Related Valves Controlled bv NonSafetv-Related Eauinment i
L (Closed - SIL ltems 65 and 66) !
L l
l a. Insoection Scone (37551.92700)
l The inspector reviewed two closure packages for SIL ltem 65 " Low Pressure Safety
injection (SIL)/High Pressure Safety injection (SlH) Valves Powered from Non-Safety Train"
and " Safety Related Valves Controlled by Non-Safety Related Equipment," and a similar
l package for SIL ltem 66 " Reactor Plant Component Cooling (CCP) and Charging Pump
l Cooling (CCE) Non-Q Components Cause Q-Components Not to Fail Safe." The first SIL
l Item 65 package is associated with ACR M3-96-0745 and LER 96-036-00. The second SIL
l
l
l
I
_ - _ _ _ _ _ _____ _ _ _ _ _ _ _
-.
.*
1
84
ltem 65 package is associated with follow-up CR M3-97-0742 and LER 96-036-01. SIL
ltem 66 is associated with ACR M3-96-0483.
The packages were reviewed for technical adequacy and the inspector conducted a
walkdown of plant equipment. Documents used in the inspection included piping and
instrumentation diagrams (P&lD), elementary wiring drawings (ESK), wiring diagrams,
Environmental Qualification (EQ) test reports, EQ Program list, operating procedures, and
j design change packages.
NRR completed a preliminary review of LER 96-036 and issued two Requests for Additional
Information (RAl). The RAls address safety and non-safety related separation issues and
were not included in the inspection scope.
b. Observations and Findinas
ACR M3-96-0745, dated September 10,1996, noted 21 safety related air operated valves
(AOV) in the SlH and SIL systems were controlled by non-safety equipment including non-
,
safety grade solenoid operated valves (SOV). In a letter dated October 25,1996, the
l licensee submitted LER 96-026-00 and committed to review safety related AOVs controlled
by non-safety grade circuits and to correct identified deficiencies prior to Mode 4 entry.
i
l The licensee review of these valves was documented in M3-ERP-97-OOO8 " Assessment of
Safety Related Air Operated and Solenoid Operated Velves with Nonsafety Related
Controis." The assessment was broader than committed by the licensee as it addressed i
both safety-related AOVs and SOVs with nonsafety-related controls. The inspector i
reviewed the assessment and had reasonable assurance it addressed the entire scope of
safety-related valves with non-safety related controls. ,
The number of licensee identified problems associated with use of nonsafety-related -
controls on safety-related equipment increased and was identified in LER 96-06-01 dated I
l' April 18,1997, and LER 96-06-02 dated July 25,1997. Necessary corrective actions
included:
- upgrading to EEQ qualified status limit switches and terminal blocks in junction ;
boxes and containment penetrations for the 21 SlH and SIL valves addressed in the
original ACR,
= implementing administrative controls to ensure unqualified nonsafety-related I
controls for RCS letdown drain lines 3RCS*AV8037A, 3RCS*AV80378,
3RCS*AV8037C and 3RCS*AV8037D are isolated in Modes 1,2, and 3; !
- upgrading to EEQ qualified status containment penetration and junction box j
terminations, and SOV seals for Reactor Coolant Hot Leg Sample valves ;
3SSR*SOV24A,3SSR*SOV24B and St Accumulator Sample valves
3SSR*SOV31 A,3SSR*SOV318,3SSR*SOV31C, and 3SSR.SOV*31D; q
l
.
.-
l-
85
- upgrading to EEQ qualified status containment penetration and junction box
terminations, and SOV seals for Reactor Coolant Cold Leg Post Accident Sample
valves 3 SSP *SOV1 A,3 SSP *SOV1B,3 SSP *SOV1C,3 SSP *SOV1D, and Reactor
Coolant Hot Leg Post Accident Sample 3 SSP *SOV2A, and 3 SSP *SOV2B;
- upgrading to a safety-related status AFW Turbine Silencer Drain 3 MSS *AOV65
controls;
- upgrading to safety-related status CCE Heat Exchanger 3CCE*TV37A and
3CCE*TV37B controls;
- upgrading to safety-related status CCP Heat Exchanger Outlet valves
3CCP*TV32A,3CCP*TV32B, and 3CCP*TV32C controls; and
a upgrading to safety-related status Emergency Diesel Generator (EDG) Jacket cooling 3
water temperature control valves 3EGS*AOV43A and 3EGS*AOV43B controls.
l l
L l
The corrective actions taken were inadequate because the SOVs and associated cables for -
the 21 valves originally identified in ACR M3-96-0745 were located in a harsh environment
but were not added to the EEQ program.10 CFR 50.49(b)(2) requires nonsafety-related
electric equipment whose failure under postulated environmental conditions could prevent
satisfactory accomplishment of safety functions to be within the scope of the regulation. l
The failure of these SOVs or cables dou to a harsh environment could prevent the AOVs
l
from fulfilling their pressure boundary safety function. Therefore the corrective action was 1
inadequate and is a violation of 10 CFR 50.49(a). 1
After this was identified to the licensee, they issued Design Change Notice (DCN) CM3-OO-
0153-98, entitled "10 CFR 50.49 B2 ASCO solenoid valves added to the EEQ program" on
February 18,1998. This DCN identified the corrective actions that had been taken by the
licensee to incorporate the 21 affected solenoid valves into the EEQ program. The
inspector reviewed a copy of this DCN that was transmitted to the inspector on February
25,1998, and verified the following:
a. These 21 solenoid valves (ASCO model NPK8320A184E) were added to the EQ
master list;
b. These 21 solenoid valves were added to Equipment Qualification Record (EOR) 111- i
0-1, on pages 16 and 17; and l
c. These 21 solenoid valves were included in PMMU, to ensure that any future cable
replacement must use environmental qualified cables.
The inspector concluded that the licensee completed their corrective actions for including
the affected 21 solenoid valves into Millstone Unit 3 EEQ program.
- _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
..
i
86
SIL ltem 65 and item 66 were both concerned with the use of nonsafety-related controls
on safety-related equipment. All of these issues were addressed by the licensee. Based on I
this, the SIL items can be closed.
c. Conclusions .
The licensee identified multiple examples where the original plant design improperly used
nonsafety-related controls on safety-related equipment. The failure to use safety-related
equipment to fulfill a safety function were multiple instances of a violation of 10 CFR 50,
Appendix B, Criterion lil, Design Control. These failures under certain conditions, could
have resulted in the loss of the emergency diesel generators, loss of high pressure safety
injection, loss of decay heat removal capability, and beyond design basis environmental
conditions in the ESF building. Enforcement discretion pursuant to Vll.B.2 is exercised
because: all of these problems were identified by the licensee's corrective action program
developed in response to an extended shutdown, they were the result of errors which j
l preceded the shutdown, they would not be treated as Severity Level 1, the errors were not '
willful, and NRC approval is required for restart.
The plant design also had multiple cases where the nonsafety-related controls on safety .
related equipment could fail in a harsh environment in a manner which, under certain
conditions would prevent the safety-related equipment from fulfilling safety functions,
l
These were failures to properly implement a 10 CFR 50.49 program, and is a violation with
L - multiple instances. These failures could have resulted in diversion of small quantities of
l
ECCS flows. All'of these problems were identified by the licensee's corrective action
i program and resolved. Enforcement discretion pursuant to Vll.B.2 is exercised because: all
of these problems were identified by the licensee's corrective action program developed in
response to an extended shutdown, they were the result of errors which preceded the
!
shutdown, they would not be treated as Severity Level 1, the errors were not willful, and
NRC approval is required for restart.
' Corrective action for ACR M3-96-0745 was inadequate because 21 important to safety
SOVs and related cables located in a harsh environment were not included in the EEQ
Program. The installed equipment is probably qualifiable and the installed SOVs were
,
classified as QA Category 1 but not including them in the EEQ program could have resulted ;
l in improper or inadequate future maintenance activities. Failure of these components in an
!- unsafe manner wtmid result in diversion of ECCS flow from both trains to nonsafety-related
'
piping. Unlike the violations noted above, this was not identified by the licensee and is a
i
.
violation of 10 CFR 50.49. (VIO 50-423/98-206-06). i
i
Corrective actions for SIL ltem 66 are complete and this item is considered closed.
Field work for SIL ltem 65 is complete. Operating and surveillance procedures associated
r with the MP3 Active Valve Reconciliation Project must be completed and issued. The l
licensee stated that these administrative changes would be made prior to Mode 4. Post
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modification testing associated with 14 RCS sample valves and one AFW exhaust drain line
cannot be completed until after plant heatup. SIL' Item 65 is considered closed.
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E7.5 (Closed) eel 50-42@/96-201-06: Turbine Driven Auxiliarv Feedwater Pumo
Automatic Start Feature Concerns (Update - SIL ltem 78)
a. Insoection Scone (92903)
In inspection Report 50-423/96-201, the team noted that the Millstone Unit 3 Final Safety
Analysis Report (FSAR) description of the automatic start features for the turbine driven
auxiliary feedwater (TDAFW) pump was changed to be consistent with the as-built plant in
Fir:al Safety Analysis Report Change Request (FSARCR) 95-MP3-12. However, a 10 CFR
50.59 evaluation was not performed for the change. The failure to perform a safety
evaluation to determine if a change in the FSAR description constituted an unreviewed
safety question was considered an apparent violation of 10 CFR 50.59. The licensee's
review of the apparent violation determined that (1) the 10 CFR 50.59 safety evaluation
screening process was ineffective and, (2) the FSAR change process did not adequately I
consider the impact of the correction on the NRC safety evaluation report. The licensee's
corrective actions included (1) performing a 10 CFR 50.59 safety evaluation of the as-built
starting feature for the TDAFW pump, (2) revising the FSAR change procedure, Nuclear
Group Procedure 4.03 to ensure the FSAR correctly reflects the actual plant configuration
and operating practices, (3) revising the 10 CFR 50.59 procedure to provide additional l'
guidance and requirements for the performance of safety evaluations, and (4) training on
the revised FSAR change and 10 CFR 50.59 procedures.' The licensee also committed to
perform a comprehensive review of the FSAR, including validation of the statements of fact
that it contains.
b. Observations and Findinas
,
'
During this inspection period, the inspector reviewed the licensee's corrective actions for
this apparent violation. FSARCR 97-MP3-23 was prepared to correctly describe the
operation of the TDAFW pump under a loss of all ac power in the FSAR. The inspector
reviewed the associated safety evaluation and determined that the licensee adequately
addressed the questions of 10 CFR 50.59 and that an unreviewed safety question did not ]
exist. The licensee showed that an automatic start of the TDAFW pump on loss of ac 1
power had no effect on the consequences of previously evaluated accidents, and there
- would be no reduction in the margin of safety.
In Inspection Report 50-423/97-208, Section U3 E1.1, the NRC reviewed the licensee's
changes to NGP 3.12, " Safety Evaluations," and determined that the procedure is clear and
includes screening check sheets to simplify and standardize the process. The NRC also ,
'
reviewed the training associated with the procedure changes and found it to be adequate.
To further evaluate the licensee's changes to NGP 3.12, the inspector randomly selected
ten 10 CFR 50.59 safety evaluations for a more detailed review. The inspector reviewed
. the plant changes to ensure that the proper safety evaluation was completed, that the
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licensee adequately addressed the three questions in 10 CFR 50.59, and that the licensee
followad its own guidance. For the safety evaluations reviewed, the inspector determined
that the licensee adequately addressed 10 CFR 50.59 and, therefore, no unreviewed safety
questions were identified. The staff's final assessment of the 10 CFR 50.59 safety
evaluation process will be addressed as part of the staff's final evaluation of SIL 78.
As part of the licensee's corrective actions for this issue, NGP 4.03, " Changes and
Revisions to Final Safety Analysis Reports," (NGP 4.03 was superseded by RAC 03) was
modified so that (1) FSAR changes are documented up-front when changes to the plant
design, analysis, etc. are initiated, (2) a screening form for FSAR change requests is used
to correct FSAR descriptions which are in conflict with plant configuration or other FSAR ,
sections, (3) the instruction section was clarified regarding tasks and responsibilities, and 1
(4) a corrective action document is initiated when FSAR errors are discovered to ensure
appropriate action. The inspector notes that Sll 2 addresses the adequacy of the FSAR
and the FSAR change process. Therefore, this part of the licensee's corrective action will
be reviewed separately under SIL 2.
c. Conclusions
The inspector concluded that (1) the licensee's safety evaluation in support of FSARCR 97-
MP3-23 was adequate and did not result in an unreviewed safety question, (2) the
licensee's safety evaluations in support of the ten randomly selected packages were l
adequate and did not result in an unreviewed safety question, and (3) the review of the
'
changes to the FSARCR process will be conducted as part of the staff's review of SIL 2.
Based on these findings, eel 50-423/96-201-06 is con.sidered closed. The NRC Notice of
Violation (NOV - letter unique identifier 01242) currently remains administratively open.
Since SIL ltem 78 addresses the overall adequacy of the 10 CFR 50.59 process and the
NRC has several inspections which include reviews of 10 CFR 50.59 evaluations, the
staff's final assessment will be included in a future inspection report. Therefore, SIL ltem
78 is hereby updated.
E7.6 ARCOR Coatino on Service Water System (SWP) Comoonents (Closed VIO 423/97- j
202-04) (Closed - SIL ltem 53)
a. Insoection Scone (37550)
The scope of this inspection included a review of corrective actions addressing a violation
involving ARCOR coatings installed to protect SWP piping from corrosion. The inspector
reviewed the root cause analysis and the corrective and preventive actions addressing
violation VIO 50-423/97-202-04.
Backaround
On July 25,1996, NU reported that pieces of ARCOR (an epoxy coating applied to the I
inside of SWP piping to minimize corrosion) and mussel shells were found in both 'A' train
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containment recirculation system (RSS) heat exchangers. Subsequently, during an NRC
inspection completed in July 21,1997, the NRC reviewed maintenance procedure MP
3710C and the associated maintenance records for ARCOR coating application and
concluded that NU had not followrd the applicable procedure, and that this represented a
violation. Specifically, maintenance procedure MP37100 stated that acceptable maximum
overcoat curing time was seven hours at a temperature of 72*F or thumb nail test with no
indentation, whichever was less. On several occasions in May and June 1997, the ;
maximum overcoat curing time had been exceeded by up to three hours. J
l
b. Observations and Findinos
l The inspector determined that the root cause investigation was performed in a thorough
l manner, key pertinent documents were effectively considered in preparing the root cause,
and the effective use of a PRA (Probabilistic risk assessment) fault tree approach enabled
better understanding of the issues to target the investigation with more precision. The root
cause evaluation identified sixteen specific issues plus seven general area findings which
i
required corrective actions. Each was entered into the facility corrective action program.
The inspector reviewed corrective actions for areas where ARCOR repairs were installed
upstream of safety related SWP heat exchangers due to the potential for coatings to
degrade and block the heat exchangers. The inspector determined that NU implemented
appropriate measures to assure that the thermal characteristics of the heat exchangers in
l the affected SWP train 'A' were not compromised by the April 4,1997 delamination of 15
square feet of the second coat of ARCOR from the SWP pump discharge piping. NU
ensured that the 'A' train was free of ARCOR loose pieces by flushing heat exchangers
which were able to accommodate high velocity flow. The remaining heat exchangers were ,
visually inspected under the scheduled routine inspection. These visual inspections did not !
reveal the presence of ARCOR loose pieces. '
The inspector determined that NU completed 100% inspection, including destructive
testing (cutting the liner), of the piping for both trains 'A' and 'B' without detecting any
loose ARCOR pieces. Some of the inspected areas required repairs and additional
destructive examinations were performed to validate the repairs. For areas that needed
repairs, facility personnel visually inspected the inside of the piping prior to the ARCOR j
application. Also, post-coating visual inspections confirmed that the repair work was 1
successfully implemented. Destructive examinations (X-cut testing) of a sample of spool
i pieces from Unit 3 SWP have been completed. The testing was documented in .
memorandums NME-WC-97-398 and NME-WC-97-371, both dated July 31,1997. The l
I
identified spool pieces had acceptable X-cuts, demonstrating proper cohesion between
' layers of the ARCOR coating.
To confirm the structural integrity of the heat exchanger tubing, NU performed eddy
current (EC) examination of the heat exchanger tubing. The EC showed that two tubes of
l the component cooling water heat exchangers (CCP) were damaged, and these two tubes
j. were subsequently plugged.
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The inspector reviewed procedure MP3710C, Revision 4, dated December 4,1997,
entitled, " Application of Lining to Plant Systems Subject to Salt Water immersion." The
inspector noted that this procedure was revised to incorporate lessons learned regarding
coatings, including:
e Added instruction for repair of defects.
e Added maintenance forms for mixing, chloride testing, environmental readings,
blotter testing and final inspection.
e Established the appropriate coating conditions through the use of physical testing ,
(thumb twist and thumb nail tests). j
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e Added sections for calculating the time window for the application of the prime and I
the finish coats within the recoat time window.
Regarding training, painters and facility inspectors were presented with an approved copy
of the revised procedure and given a step-wise review of the content and use of the forms l
associated with the procedure. During interviews conducted by the inspector, the painters
stated that pre-job briefings with personnel associated with the ARCOR project had been
conducted to cover the work scope, problem areas, and issues such as procedure
compliance.
c. Conclusions
The inspector concluded that the root cause investigation was performed in a thorough
manner. Corrective actions were appropriate and included heat exchanger flushing,100% : ;
piping visualinspection, and coating repairs. NU implemented appropriate measures to i
ensure that the thermal and structural performance of the SWP heat exchangers of train 'A'
are maintained. The inspector concluded that NU had implemented effective corrective and ,
preventive actions which addressed several ARCOR coating failures. Both VIO 50-423/97- l
202-04 & SIL ltem 53 are considered closed.
U3 E8 Miscellaneous Engineering issues l
E8.1 (Closed) eel 96-201-05: Turbine Driven Auxiliarv Feedwater Desian Concerns :
'
(Update - SIL ltem 70)
a. Insoection Scone (92903)
The past closure of the Turbine Driven Auxiliary Feedwater pump (TDAFW) 3FWA*P2 !
discharge valves 3FWA* HV36A,B,C,D at power levels less than 10 % was identified as a l
possible violation of Technical Specification (TS) 3.7.1.2 which states that, "At least three
independent steam generator auxiliary feed-water pumps and associated flow paths shall l
be operable." The 3FWA*HV36A,B,C,D valves were closed at power levels below 10%
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'because the TDAFW pump discharge piping was classified as moderate energy piping in the
MP3 FSAR. Past plant operations have used the TDAFW and the Motor Driven Auxiliary
Feedwater (MDAFW) pumps during startup causing a portion of the TDAFW pump
discharge piping to be subject to high pressure discharge from the MDAFW pumps during
startup and shutdown evolutions. Being subject to the MDAFW pump discharge pressure
would require the TDAFW discharge piping to be classified as High Energy Line Break
(HELB) piping which it was not.
Due to accident analysis assumptions related to HELB, operation of the AFW pumps during
accident conditions does not raise HELB concerns. This will address the licensee's option of
not using the TDAFW and MDAFW pumps during plant startup and shutdown, leaving the
subject valves open and thereby meeting the TS requirements.
b. Observation and Findinas
' The inspector reviewed eel 96-201-05, along with the associated documentation and
engineering drawings. The cptions originally considered by the licensee to correct the lack
of HELB qualification of the discharge line were: 1) install the required barriers and make
other changes required to qualify the line as an HELB fluid system line, 2) request a TS .
change allowing closure of the discharge valves 3FWA*HV36A,B,C and D when below
10% power, 3) developing an engineering justification that the TDAFW pump discharge
valves could be closed at power levels less that 10% without making a request to change
the TS and 4) using the main feedwater supply pumps instead of the Auxiliary pumps
during the plant startup and shutdown leaving the TDAFW pump discharge valves open.
The initial documentation reviewed by the inspector was based on the licensee's objective
of justifying that the TDAFW pump discharge valve could be closed without a change in
the TS or that a change of Technical Specifications could be obtained. However, as
described in a NU letter to the NRC dated July 14,1997, the licensee has elected not to
request a TS change. The licensee has changed procedures and completed training to allow
the plant operators to no longer use the AFW system during startups and shutdowns.
Furthermore, the licensee is no longer planning to close the TDAFW pump discharge valves
at power levels below 10%. The integrity of the TDAFW pump outlet line is designed to be
maintained by administrative controls to prevent the MDAFW pumps from being run during
normal plant operations.
The licensee has elected to continue the efforts to eventually qualify the line of interest as
a HELB line. However because of the lengthy process of qualifying the line as HELB, the
main feedwater pumps will be used by the licensee during normal plant startups and
! shutdowns.
c.- Conclusions
The licensee has provided training and changed procedures to require all p! ant startups and
shutdowns to be accomplished without using the MDAFW pumps or the TDAFW pumps.
As long as the administrative controls to not use the TDAFW and MDAFW pumps during
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normal plant operation are in effect, the discharge line of the TDAFW pumps will not be
subject to high pressure from the MDAFW pumps. The Main Feed Water Pumps will be
used to start up and shut down the plant. Using the Main Feed Water pumps temporarily
eliminates the requirement to make the lines of interest HELB qualified. The actions taken
by the licensee are deemed adequate. The technicalissues associated with eel 96-201-05
are considered closed, and SIL ltem 70 is hereby updated. The NRC Notice of Violation
(NOV - letter unique identifier 03082) currently remains administratively open.
- E8.2 (Closed) ACR 10780: Turbine Driven Auxiliarv Feedwater Desian Concerns
(Update - SIL ltem 70)
a. Insoection Scone (929011
The closure of-the TDAFW 3FWA*P2 discharge valves 3FWA* HV36A,B,C,D at power
levels less than 10 % was identified as a possible violation of Technical Specification 3.7.1.2 which states that "At least three independent steam generator auxiliary feed-water
pumps and associated flow paths shall be operable." The 3FWA*HV36A,B,C,D valves
were closed at power levels below 10% because the TDAFW pump discharge piping was
classified as moderate energy piping in the MP3 UFSAR. However during normal plant
operation a portion of the TDAFW pump discharge piping could be subject to high pressure
discharge from the MDAFW pumps during startup and shutdown evolutions. Therefore,
this TDAFW discharge piping should have been classified as HELB piping and was not. The
closure of TDAFW pump discharge valves was reported in ACR 10780 and related aspects
were also cited by NRC in Eels 96-201-04 and 05.
In addition it was discovered that the Auxiliary Feedwater valves 3FWA*HV36A,B,C,D
would not remain closed when exposed to a differential back pressure greater than 5 to 7.
psig in possible violation of 10 CFR 50, appendix A, General Design Criteria (GDC) 57
requirements. These valves were not able to isolate reverse flow (flow out of the
containment) at a 45 psig containment design pressure. The inspector reviewed the
corrective actions taken to correct the deficiencies noted in the two ACRs. The Eels will
be addressed as separate reviews.
b. Observation and Findinas
l
l The inspector reviewed ACR 10780 along with the associated documentation and
engineering drawings. The options originally considered by the licensee to correct the lack
of HELB qualification of the discharge line are discussed in paragraph U3 E8.1 above. The
initial documentation reviewed by the inspector was based on Option 3. As a fall-back
position the licensee would request a Technical specification change to close the TDAFW
pump discharge valve at power levels less than 10% power. However, as described in NU-
NRC letter dated July 14,1997 the licensee will no longer use the AFW system during
startup and shutdowns. Furthermore, according to the licensee's system engineer, the
licensee is no longer planning to close the TDAFW pump discharge valve at power levels
below 10%, and is now in the process of determining the requirements necessary to
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qualify the TDAFW pump discharge line to HELB requirements. The licensee has elected to
administratively not use the AFW pumps during normal operation until the HELB evaluation
is complete.
The inspector reviewed ACR 10774 along with associated documentation and engineering
drawings. ACR 10774 refers to ACR 12215 where the details of the modification to
valves 3FWA*HV36A,B,C,D are described. The AFW pump discharge valves
3FWA*36A,B,C,D would not remain closed when exposed to a differential back pressure
greater than 5 to 7 psig. These valves are 3 inches in diameter, normally open, solenoid-
operated, modulating globe valves, which have now been modified to isolate reverse flow
up to 1355 psid differential pressure. The inspector reviewed the following: DCR M3-
9605, Rev. O, Modify Target Rock Solenoid Valves 3FWA%/36A-D; and Safety
Evaluation number M3-96059-mce. These describe how the valves have been successfully
modified and now await final testing during Mode 3. This aspect will be further reviewed
as part of SIL 18. The inspector also reviewed the valve drawings showing the new
configuration and compared the environmental qualification accident conditions with the
specifications for the valve seals. The inspector reviewed the documentation that showed
that the valves, in their new configuration, had passed their seat leakage test. The
l inspector observed the modified valves during a walkdown of the TDAFW system.
c. Conclusions
AFW pump discharge valves 3FWA*36A,B,C,D have been appropriately modified. ACR
10774 was previously inspected and closed, as documented in inspection report 50-
423/97-207. ACR 10780 addresses resolving the technical specification requirements.
The licensee has technically resolved the technical specifications conflict in the NU-NRC
letter dated July 14,1997 wherein the licensee has elected to not request a technical
specification change and not to use the AFW system during normal startups and ,
'
I shutdowns. The licensee has stated an intent to qualify the affected pipe lines for HELB at
some future time; another option, but one that does not invalidate the current licensee
course of action.~ The corrections by the licensee are deemed adequate. Thus, ACR 10780
is considered closed and SIL ltem 70 is hereby updated.
E8.4 (Closed) LER 96-033. Boraflex degradation durina a Seismic Event 1
(Closed - SIL ltem 59)
a. Insoection Scone (92903)
The inspection reviewed the corrective actions implemented in response to the potential
failure of the Boraflex material in the Spent Fuel Pool during a postulated Seismic Event.
Westinghouse Criticality Analysis Assumptions, Holtec International Blackness Testing
results for the Millstone Unit 3 Spent Fuel Pool, Coupon Test results, existing Spent Fuel 1
Pool Administrative procedures, Emergency Operating procedures, applicable Surveillance ,
Tests and Operability Determinations were reviewed. This issue was reported in i
accordance with 10 CFR 50.73 (LER 96-033), as a potential design basis concern, i
I
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b. Observations & Findinas
During a Northeast Utilities review of the corrosion and material degrading mechanisms
encountered in the Boraflex plates of an MP1 fuel cell, it was concluded that the Boraflex
L ' plates could exhibit loss of ductility and fracture toughness over time. This could lead to
I . fracture of the plates when subjected to dynamic impact loads such as those during a
seismic event.
A preliminary operability determination was performed with the conclusion that reactivity
l
compliance in the Millstone Unit 3 Spent Fuel Pool would be maintained considering the
i effect of a postulated seismic event. The contractor who assisted in this determination
!
utilized judgment of dynamic simulations in making this initial assessment. In addition, the
inspector noted that the results of IST 3-94-008, Rev. O, " Spent Fuel Pool Blackness
Testing", had shown that although gaps had been found in 11% of the fuel cells tested,
the average gap size was 1.1 inches, which was well within the acceptance criteria value
of 4.66 inches. Therefore, gaps in the Boraflex panels were within the assumptions used
.
in the criticality analysis. Coupon tests performed also had not shown any significant
dissolution damage or loss of neutron attenuation ability. Northeast Utilities concluded that
.because the criticality analysis allowed for numerous wide spread gaps in the panels,.the
additional gaps created from a seismic event would not lead to a loss of reactivity control.
However, Northeast Utilities asked the vendor to perform a comprehensive study and ~
analysis to support this conclusion.
On September 9,1996, the subsequent Holtec International analysis of Spent Fuel Rack
Boraflex behavior during a seismic event, concluded thr.t wide spread cracking of the
Boraflex was a credible consequence. Northeast Utilities accordingly reported this under
the requirements of 10CFR 50.72, and performed a revision to the initial Operability
- Determination with compensatory measures established to verify 1500 PPM boron
concentration every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and prohibit fuel movement in the Unit 3 Spent Fuel Pool.
Subsequently, this limit was increased to 1650 PPM, then 1750 PPM, due to further
analysis recommendations. The 1750 PPM boron concentration requirement contains
conservative assumptions, in that, K-effective would remain less than or equal to .95
L ving a seismic event if all of the following occurred; (1) no credit for any Boraflex, and
" a simultaneous worst case single misplaced / dropped fuel assembly, and (3) a loss of -
spent fuel pool cooling resulting in boiling conditions in the pool.
The inspector reviewed existing Emergency Procedures, EOP 3505A, Rev. 3, " Loss of
Spent Fuel Pool Cooling", and Seismic response procedure, AOP 3570, " Earthquake", and
verified that they contained actions consistent with the proposed License Amendment
Change (PTSCR 3-01-97). The Emergency Operating procedures in conjunction with the
Administrative Operating procedure, OP 3305, Rev.15, ensure makeup with non-borated
water sources to the pool after an event does not result in dilution greater than 1750 PPM.
Also, the seismic response procedure controls the use of non-borated water sources.
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The inspector noted that the Operability Determination of record (OD-MP3-210-96),
required a minimum boron concentration of 1650 PPM. This value was not consistent with
the 1750 PPM value requested in the License Amendment or the current Chemistry
l Surveillance test acceptance criteria of 1750 PPM. NU engineers stated that the
l. Operability Determination value of 1650 PPM had not been revised due to the requirement
I
that no fuel movement can take place as stated in the O.D. and procedure EN 31001, Rev.
4, " Supplemental SNM Inventory Control". Although the O.D. and Surveillance Test were
inconsistent, the inspector viewed this as acceptable, based on the fact that the 1750 PPM
requirement was predicated on the assumption of a fuel handling accident. In addition, the
i inspector walked down a recent NU modification which relocated the fuel pool purification
'
piping to ensure it would not fail in a seismic event and subsequently uncover the Fuel Pool
cooling suction pipe. The inspector also verified that NU had administrative controls in
place for the movement of heavy loads over the spent fuel pool to prohibit fuel rack
damaqa. A review of Chemistry surveillance test results showed that the pool has
remained above 2600 PPM since April of 1996 when the potential adverse consequences
[ of a seismic event were first identified. This value is well above 1750 PPM, and ensured
subcriticality requirements would have been met in any event.
l
l c. Conclusion
l
l Existing administrative controls have been established by NU to ensure that the
l subcriticality margin would remain less than or equal to .95 following a seismic event. >
l Appropriate controls were established in a timely manner considering the information that
'
was available to NU during the initial analysis of the effects of a seismic event. A License
Amendment request has been submitted by NU and is being evaluated by NRR. Both LER
96-033 & SIL ltem 59 are considered to be closed.
E8.5 Documentation of containment Svstem Discrepancies (Closed - SIL ltem 50)
! a. Insoection Scone (40500)
The status and effectiveness of corrective actions were reviewed in response to
discrepancies identified in a 1996 Millstone Containment System Assessment Report.
FSAR change requests, Integrated Leak Rate tests, Local Leak Rate Tests and Bypass
l Leakage calculations were reviewed along with the Containment System Assessment
Report. In addition, discussions were held with the cognizant Appendix J testing personnel
'
concerning corrective actions taken. A sample of 20 significant discrepancies documented
I
in Adverse Condition Reports M3-96-0446, M3-96-0324, M3-96-0114 and their associated
corrective actions, were reviewed,
b. Observations & Findinas
in July of 1996, the results of a Millstone Containment System Assessment idantified a
number of program discrepancies concerning the leakage mitigation and isolation provisions
,
of the containment.
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, The report identified that FSAR Table 6.2-70 contained a list of various penetrations that
I did not require venting and draining for the conduct of the Integrated Leak Rate Test (ILRT).
i Several of the penetrations had a note which implied that the penetrations were not open
directly to the containment atmosphere under post-accident conditions. This was incorrect
because these were not closed systems and would be open to the containment atmosphere
under post accident conditions. They were eligible to be exempted from venting and
draining for the ILRT as provided for in 10CFR50, Appendix J, Ill.A.1(d). However, if the
penetrations are not vented and drained during the test, the ILRT results must be corrected
for, by adding the penetrations Type C leakage rates. The 1993 and 1989 ILRT test
,
'
results were not adjusted to reflect this requirement during their performance. The
inspector reviewed the corrected results of the 1993 test and verified that the Technical
Specification leakage rate acceptance criteria for the Type A test had not been exceeded.
Northeast Utilities also performed corrections to the 1989 test results and verified that
adjusted leakage limits were within the T.S. limit. The 1985 pre-operational ILRT was not
subject to the same problem since the affected penetrations were vented and drained 1
during that test. The inspector noted that the affected penetration leakage numbers
amounted to a nominal 1.8% of the total ILRT leakage during the 1993 test and therefore,
did not contribute significantly to the test results. The inspector verified that the FSAR had
been revised and that, SP31104," Integrated Leak Rate Test", clearly identified that a
leakage penalty must be taken for the affected penetrations not drained and vented.
The 1996 assessment also had identified that the Fuel Transfer Bellows had never been
included in the Local Leak Rate Testing program for Type B penetrations. The bellows is a
primary containment leakage boundary and therefore required a Type B LLRT. In addition,
this penetration is a bypass leakage path, in that it does not communicate with the SLCR .
boundary. This penetration has since been tested and the results were added to the T.S. I
bypass leakage numbers. The inspector noted that although a Type B LLRT had never been )
performed for this penetration, its integrity had always been proven during the Integrated l
Leak Rate Tests, as it had always been part of the ILRT boundary. When tested, the Type !
B leakage number amounted to a nominal 1% of the total Containment bypass leakage )
results, and therefore did not result in a T.S. limit being exceeded. The inspector verified
that Operations procedure,3612B.4-1, Revision 10, was revised to include any leakage
from this penetration as bypass leakage.
Subsequent to the onsite inspection, the Licensee provided additional data, indicating that l
the revised Bypass Leakage Calculation (1150,R.0c.,CN1), which was initiated in response )
to the Containment Assessment Report, resulted in a historical deportability condition with j
respect to bypass leakage numbers. This revised calculation identified 13 Type C i
penetrations which were not previously classified as bypass leakage paths. l
Several of the FSAR change requests were reviewed and found to be effective in clarifying
the Appendix J program. j
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c. Conclusions
Northeast Utilities acknowledged previous noncompliance with several Appendix J
requirements discussed above. However, the significant errors and omissions identified by
their assessment, were inappropriate leakage summaries, in that Type C leakage had not
bean added to ILRT and bypass leakage results. The discrepancies were not indicative of a
programmatic failure to perform required Type B and C tests. A significant reconstitution
between the design basis information and the licensing basis was required in response to
the findings of Northeast Utilities' independent assessment. The corrective actions
implemented for the sample of discrepancies reviewed were adequate and complete. The
subsequent, potential historical deportability issue pertaining to the effects of the revised,
conservative Bypass Leakage Calculation, does not alter the conclusion that effective
corrective actions have been implemented. The 1996 assessment has resulted in an
improvement to the Appendix J program. These non-repetitive, licensee-identified and
corrected Appendix J violations are being treated as Non-Cited Violations, consistent with
Section Vll.B.1 of the Enforcement Policy. SIL ltem 50 is considered biog
E8.6 1 Closed) eel 50-423/96-201-23: Service Water Booster Pumo Jumner
(Closed - SIL ltem 52)
a. Insoection Scone
Inspection report 96-201, documented that bypass jumper (BJ) 390-20, which had
changed the starting circuit for the service water booster pumps that supply backup
cooling water to the Motor Control Center / Rod Control Area (MCC/RCA) air handling units,
had been installed since May 1990. The BJ modified the pump's starting circuit to supply
a direct auto-start signal to the booster pumps when a loss of Offsite Power (LOP) event
occurs. Before the BJ was implemented, on a LOP the booster pumps would start only
_
when the pump discharge valves, motor operated valves (MOV)s 130A/B, were open.
However, a special instruction to manually restart the booster pumps following a LOP,-
which was included in the original BJ documentation, was no longer incorporated in the
licensee's annunciator response procedures. Additionally, the NRC noted installation of the
BJ inadvertently deleted an automatic start feature of the booster pumps generated when
higi; temperature in the MCC/RCA ventilation duct occurred.
b. Observations and Findinos
Corrective action included removing the inadequate bypass jumper and implementing a
permanent design change, Plant Design Change Request (PDCR) MP3-94-099, to the
booster pump start circuit. The design change retained the booster pump starting
sequence outlined in BJ 390-20 and restored the automatic start feature of the booster
pumps when high temperature occurs in the ventilation duct that was inadvertently
deleted. System operating and alarm response procedures were revised to inform 1
operators of the expectcJ system response during a LOP condition and the Final Safety !
Analysis Report was revised to reflect the current system configuration.
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c. Conclusion
Based on an in-office review of the design change, the safety evaluation, the revised
procedures, and the revised FSAR, the inspector concluded that corrective actions had
resolved the technical concern regarding the bypass jumper. eel 50-423/96-201-23 is
closed technically. The NRC Notice of Violation (NOV - letter unique identifier 02112)
currently remains administratively open. A related LER 50-423/96-05 with supplement 1,
was closed in inspection report 50-423/96-09. SIL ltem 52 is hereby closed.
U3 E8.7 ERRATA TO INSPECTION REPORT 50-423/98-82
During the Millstone Unit 3 motor operated valve inspection, documented in Inspection
Report 50-423/98-82, the power operated relief valve replacement activity was reviewed
.
and evaluated. As a result of this inspection, the inspector follow up item (IFI) opened
during the conduct of inspection 50-423/97-203 was closed. However, the applicable IFl 3
97-203-15 that had been closed was incorrectly documented as IFl 97-203-01 (which, in i
fact, is a number assigned to a Unit 1 Unresolved item). This error is hereby corrected by
noting that IFl 97-203-15 was the affected open item, regarding the PORV block valves,
that was reviewed and closed in Inspection Report 50-423/98-82.
IV Plant Suonort
(Common to Unit 1, Unit 2, and Unit 3)
R1 Radiological Protection and Chemistry Controls
l
R1.1 Radiological Protection and Chemistry Controls I
!
a. insoection Scone (83729)
The inspector reviewed the licensee's programs for radiation protection during an extended
shutdown at all three units. The inspector also reviewed the proposed goals for
maintaining occupational exposures as low as is reasonably achievable (ALARA) and the ,
licensee's bioassay program for determining internal uptakes of radioactive material utilizing )
! whole body counters.
!
b. Observations and Findinas - 1
Unit 1 !
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l The unit has been shutdown since October 1995. Recently, the licensee announced that it
would remain in an extended shutdown condition throughout the remainder of 1998.
Previously, the licenses planned to resume significant radiological work in mid-1998.
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The inspector reviewed current radiological surveys of the unit radiological control areas
j (RCAs), and toured accessible areas of the turbine and reactor buildings as part of this
'
inspection. Discussions with unit radiation protection personnel revealed that a number of
reviews have recently been undertaken to establish appropriate survey locations,
l frequencies and techniques to be utilized while in the extended shutdown. No
discrepancies with NRC radiological regulations regarding the centrol, posting and
surveillance of the facility were noted.
!
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In late 1997, the unit had established a goal of 344 person-rem for occupational exposures
l in 1998. Due to the decision to maintain the unit in a shutdown mode, a new ALARA goal
l has to be established. Discussions with the licensee indicated that such a goal revision
was to be discussed at an ALARA Committee meeting scheduled for late February 1998.
For 1997, the unit exposure was 173.76 person-rem. In general, effective ALARA controls
were in place during 1997, although comparisons between the actual exposure and the
i various goals established are of limited value as the scope of work performed in the unit
changed significantly several times in 1997.
l
The licensee recently named a new unit R$diation Protection Manager, and, as part of this
inspection, the individuals qualifications ' re reviewed against the requirements I
l established in Technical Specification . s.c. The individual selected met this qualification
criteria.
l
Unit 2
Unit 2 remained in an extended shutdown throughout 1997, and into the current inspection
l period. The inspector toured accessible areas of the auxiliary and containment buildings as
part of this inspection. All areas observed were controlled and posted in accordance with i
applicable regulations. The inspector discussed with licensee personnel, plans for unit
restart, as they related to changing radiological conditions. The licensee has begun to
formulate a plan of action to ensure appropriate radiological surveys are conducted during
restart to assure appropriate postings and boundaries are established in the RCA to protect
radiological workers. In general, the preliminary plans call for a significant increase in the !
l frequency of surveillance, together with the use of remote monitoring devices on key
I
pieces of equipment to monitor for changing radiological conditions.
For 1997, the unit's occupational exposures was 139.748 person-rem. To support ALARA
,
performance, the licensee has established an ALARA Committee and designated ALARA
l coordinators for each major work group. Clear lines of ownership and responsibility have
! been established and are reinforced on a regular basis by the Unit Director. The
effectiveness of changes in the work control and work planning area remains to be
l
j evaluated pending the conduct of significant radiological work. For 1998, the unit has
established an exposure goal of 124 person-rem.
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Unit 3
The inspector conducted tours of the accessible RCAs located in the containment,
auxiliary, radwaste and fuel buildings as part of this inspection. All areas observed were
appropriately posted and controlled, and the radiological surveys of the areas were
determined to be accurate. As at the other two units, due to the extended shutdown,
radiological conditions are significantly mcre benign than what is expected during
operations. The inspector reviewed plans for radiological controls and surveys during plant
restart. The unit has maintained an extensive data file of surveillance results and locations
of postings prior to shutdown that are planned to be the basis for establishing initial
postings and controls during startup. As at Unit 2, increased surveillance frequencies will
be required during restart to ensure 1Ast the effects of changing radiological conditions are
reflected in controls established in tne RCA.
For 1997, the unit occupational exposure was 92.064 person-rem. For 1998, the unit has
established a goal of 51 person-rem. Responsibility and authority for the ALARA program 1
are clearly defined and an ALARA Committee has been established.
Chemistrv Technical Sucoort
The inspector reviewed the calibration, quality assurance and maintenance records ,
associated with the licensee's bioassay program utilizing whole body counters, as part of l
this inspection. The licensee maintains three whole body counters, interfaced through a j
common mainframe computer. Two of the counters utilize sodium iodide detectors, and i
are used on an almost daily basis for initial scans of new employees, and annual and
routine scans. Due to resolution limitations inherent with these types of detectors, a third j
counter utilizes an intrinsic germanium detection system. The significantly improved '
resolutien capabilities of this system allow the licensee to differentiate among the various
potential isotopes personnel can be exposed to at the site. ;
The inspector reviewed the licensee's control charts, quality assurance cross checks, ,
instrument maintenance records, and isotope library to ensure that these systems provide j
an appropriate means of surveillance for potential uptakes of radionuclides. No '
discrepancies in the licensee's program were noted. 1
l Conclusions
c.
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The license has established an effective program for radiological controls during extended
shutdown of the units. Improvements in the ALARA program were observed at both Units
2 and 3. An effective bioassay program utilizing whole body counting systems has also
been established.
R1.2 Elevated Radiation Levels at Greco Football Field
On February 11,1098, the NRC was notified by the licensee that during a radiological
survey of the Greco Football Field on February 10,1998, the State of Connecticut had
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identified an area approximately two feet in diameter with radiation levels approximately l
i twice background. Previously, in October 1997, the licensee had conducted a radiole gical
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survey of this facility, located on owner controlled property east of the main plant site, and
provided written documentation to support that no licensed materials were at the field.
The region-based inspector accompanied licensee and State of Connecticut representatives
to the field on February 11,1998, to investigate the source of these readings. Results of
this investigation revealed the presence of a rock, approximately two feet in diameter
buried approximately 3-4 inches below the surface, which was the source of the elevated -
radiation levels due to the presence of natural occurring radioisotopes in the rock. Soil
samples taken from above and to the sides of the rock were counted by the licensee and
revealed only normal background levels of radioactive isotopes.
R5 Staff Training and Qualification in Radiological Protection and Chemistry
l R5.1 Staff Trainina and Qualifications
I
a. Insoection Scone (83729)
,
The inspector reviewed the training provided to health physics technicians through the
l technical training program, and discussed proposed changes to the General Employee
Training (GET) program. This inspection was accomplished by discussions with cognizant
licensee personnel and reviews of pertinent records,
b. Observations and Findinos
The licensee's technical training program providec periodic training to health physics
technicians, as established by plant procedures, in accordance with these procedures, the
scope and depth of training is established by a curriculum advisory committee (CAC),
'
which includes representation from the radiation protection departments of each Millstone
unit. The inspector reviewed the courses and topics presented to the health physics
technicians during the later half of 1997, and discussed with technical training personnel
the training to be provided during the first half of 1998. Of particular note is the
! incorporation of fundamentals refresher ' sining topics into the training matrix.
The licensee has also established a training requirement and program for contractor
technicians assigned to Millstone for more than six months. For 1997, the same training
topics and lesson guides used for Millstone employees was utilized for the contractors.
l
Discussions with Training Department personnel also revealed that they plan to relocate
and fully refurbish the radworker training and mock-up facility during 1998. This training
has been a portion of the licensee's program to address previously identified deficiencies in
radworker practices.
c. Conclusions
i
The licensee has established an effective technical training program for both licensee l
employee and long-term contractor health physics technicians. l
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R8 Miscellaneous Radiological Protection and Chemistry issues
R8.1 (Closed) Violation 50-245: 336: 423/97-203-13: Failure to Follow Procedures / Poor
Radiological Worker Practices
The inspector reviewed the licensee corrective actions, including a review of cond: tion
reports for 1997 and 1998. Increased licensee awareness, augmented training, and
additional postings and barriers appear to have been effective in preventing recurrence of
these problems. This item is closed.
R8.2 (Closed) Violation 50-245: 50-336: 50-423/97-203-14: Radiation Levels in Excess
of Regulatorv Limits on a Limited Quantity Shioment
The licensee completed programmatic changes, including the addition of a second, )
independent survey of radioactive material packages prior to shipment, incorporating these
into licensee procedure RW-46047. No additional occurrences have been identified. This
item is closed.
R8.3 (Closed) Unresolved item 50-423/97-208-05: Imoroner Discosal of Licensed
Material
The licensee has retrieved the silt / sand previously removed from the Unit 3 intake structure
and improperly disposed at the Waterford Town Landfill. Due to the very low levels of
radioactivity found in the materia!s (typically less than 0.15 picocuries per gram for cobalt-
60 and cesium-137) there was no negative effect from this event on the public health and
safety or the environment. This licensee-identified and corrected violation is being treated
as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev.
This item is closed.
S8 Miscellaneous Security and Safeguards issues
S8.1 (Closed) eel 50-245:536:423/97-03-02: Failure to Control Vehicles in the Protected
Area (Closed - Unit 1 SIL 8 & Unit 3 SIL 84: Undated - Unit 2 SIL 13)
The inspector reviewed the program for control of onsite vehicles that was implemented in
July 1997. The program, as implemented, appeared to be effective in controlling vehicles
and has resulted in a decrease of approximately 30% in the number of vehicles onsite.
This violation is closed. The closure of the above open items in this inspection report and
the closure of open security items in inspection report 97-203 closes significant item list
(SIL) No. 8 for Unit 1 and SIL No. 84 for Unit 3 and updates SIL No.13 for Unit 2.
S8.2 (Closed) IFl 50-245:336:423/97-207-04: Review of Licensee's Investigation into a
Discrecancv on the Dates an Individual was not Procerly Logaed into the Protected
Area
'
During inspection 97-207, the inspector conducted a review to determine why an
authorized individual had properly entered the protected area (PA) and not been logged in
by the security computer. The inspector's review concluded that authorized individuals
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using valid badges had entered the PA without being logged on the security computer as a
result of a mechanical malfunction in the turnstiles. Testing of the system disclosed that
only badges of authorized personnel would access the turnstiles during this condition,
therefore, no security vulnerability existed.
However, the inspector's review during inspection 97-207 also disclosed that the security
computer indicated that the individual who identified this condition was not properly logged
into the PA by the security computer on September 10,1997, and the individual recalled
that the incident occurred on September 23,1997. The inspector interviewed the
individual involved, two co-workers who exited the PA with the individual on September
23,1997, officers on duty in the guard house on both dates in question, and reviewed
security computer printouts for the month of September and determined that the individual
had interacted with security on September 23, but this was not documented in security
computer records. The licensee agreed to conduct further interviews and review additional
documentation to attempt to resolve this discrepancy. During this inspection, the inspector
reviewed the additional information developed and determined that the licensee had done a
thorough investigation of the incident, including re-interviewing security officers and other
persons involved, re-reviewing the security computer data and validating that the security
computers were fully functional and sound on both dates in question. The licensee's
investigation concluded that there was interaction between the individual who identified
the turnstile problem and the security organization on September 23,1997, and that
interaction was not documented in security records. The investigation also concluded that
the individual properly entered the PA on September 10,1997, and was not logged in the
security computer as a result of a malfunction of the turnstile. Upon exiting the PA, an
alarm was caused because the person was not logged into the PA. This transaction is
documented in the security computer records.
Based on interviews and reviews done during inspection 97-207 and review of the
licensee's investigation and all supporting documentation, the inspector concluded that a
positive determination of the nature of the individual's interaction with security on
September 23,1997, could not be made. Inspector Followup Item 50-245;336;423/97-
207-04 is closed.
V. Manaaement Meetinas
I
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at I
separate meetings in each unit at the conclusion of the inspection. The licensee i
acknowledged the findings presented.
X1.1 Final Safety Analvsis Reoort Review i
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A recent discovery of a licensee operating their facility in a manner contrary to the updated l
l final safety analysis report (UFSAR) description highlighted the need for additional
l
verification that licensees were complying with UFSAR commitments. All reactor
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inspections will provide additional attention to UFSAR commitments and their incorporation
into plant practices, procedures and parameters.
While performing the inspections which are discussed in this report the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected. An inconsistency
was noted between the wording of the UFSAR and the plant practices, procedures and/or
parameters observed by the inspectors, as is documented in Sections U2.08.1, U3.07.1,
U3.07.2, U3.E1.2, and U3.E8.5 of this inspection report.
INSPECTION PROCEDURES USED
IP 37550: Engineering
IP 37551: Onsite Engineering
- IP 37001
- 10 CFR 50.59 Safety Evaluation Program
IP 37700 : Design Changes and Modifications
IP 37701: Facility Modifications
IP 40500: Licensee Self Assessments Related to Safety issues Inspections
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
j IP 71001: Licensed Operator Requalification Program Evaluation
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IP 71707: Plant Operations
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IP 81700: Physical Security Program for Power Reactors
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lP 83729: Occupational Exposure During Extended Outages
IP 92700: Onsite follow-up of Written reports of Nonroutine Events at Power Reactor
Facilities
IP 92901: Follow-up Operations
IP 92902: Follow-up Maintenance
IP 92903: Follow-up Engineering
Tl 2515/
130: Improved Standard Technical Specification Implementation Audits
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ITEMS OPENED, CLOSED, AND DISCUSSED
I
ITEMS OPENED:
!
Item Number Description Section
VIO 245/98-206-01 Plant System Valve Lineups U1.01.3
URI 336/98-206-02 Safety Parameter Display System U2.01.2
URI 336/423/98-206-03 Channel Functional Test of Radiation U2.M3.1
Monitors
VIO 50-423/98-206-04 Failure to take prompt corrective U3.08.6
actions on nonconformance to
steam generator tube rupture
analyses assumptions.
URI 423/98-206-05 Restart items U3.E7.1
VIO 423/98-206-06 ECCS Flow U3.E7.4
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ITEMS UPDATED: l
Item Number Section
eel 336/96-06-05 U2.08.1
IFl 423/97-01-07 U3.M3.1
eel 423/96-201-22 U3.E1.1
URI 423/96-08-20 U3.E1.1
eel 423/96-201-01 U3.E2.3
l URI 97-85-03 U3.08.7
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ITEMS CLOSED:
Item Number Section
URI 245/97-207-01 U 1.M8.1 l
URI 336/97-207-02 U2.08.2
IFl 423/96-0815 U3.02.1
URI 423/96-08-16 U3.08.6 ,
eel 423/96-201-19 U3.M2.2 j
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eel 423/96-201-32 U3.M2.3 j
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IFl 423/97-01-07 U3.M3.1 I
URI 423/97-02-14 U3.M8.4
eel 423/96-201-33 U3.E1.4
URI 423/96-201-14 U3.E2.1
eel 423/96-201-08 U3.E2.2
URI 245/336/423/97-203-09 U3.E3.1
URI 423/97-203-10 US.E3.2
eel 423/96-09-16 U3.E7.2
eel 423/96-201-06 U3.E7.5
VIO 423/97-202-04 U3.E7.6 .
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eel 423/96-201-05 U3.E8.1
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eel 423/96-201-23 U3.E8.6
VIO 245/336/423/97-203-13 IV.R8.1
VIO 245/336/423/97-203-14 IV.R8.2
URI 423/97-208-05 IV.R8.3
eel 245/336/423/97-03-02 IV.S8.1 1
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IFl 245/336/423/97-207-04 IV.S8.2
URI 336/90-18-01 U2.M8.1
URI 336/90-18-03 U2.M8.1
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IFl 423/97-302-15 U3 EE.7
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l LERs CLOSED:
l 423/97-004 (Section U3.08.4)
i 423/97-019 (Section U3.08.5)
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423/97-041 (Section U3.02.1)
423/97-051 (Section U3.M8.2)
423/97-055 (Section U3.M8.3)
423/96-008 (Section U3.08.6)
l 423/96-033 (Section U3.E8.4)
'
423/96-036 (Section U3.E7.3)
423/96-043 (Section U3.08.3)
r LERs DISCUSSED:
, 423/97-047 (Section U3.M8.1)
423/96-028-00 & 01 (Section U3.E1.2)
423/96-040 (Section U3.E1.3)
,
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LIST OF ACRONYMS USED
ACOT analog channel operational test
ACR(s) adverse condition report (s)
AITTS action item tracking and trending system
ALARA as low as reasonably achievable
AOV(s) air-operated valve (s)
ATWS anticipated transient without scram
AWO(s) automated work order (s)
BAST boric acid storage tank
CAC(s) curriculum advisory committee (s)
CCE charging pump cooling
CEA(s) control element assembly (s) 1
CET(s) ' core exit thermocouple (s)
CFR Code of Federal Regulations
l CIV(s) containment isolation valve (s)
l CMP- configuration management plan
CR(s) condition report (s)
DCN(s) design change notice (s)
DCR design change record
ECP Employee Concerns Program
EDG(s) emergency diesel generator (s)
l eel (s) escalated enforcement item (s)
EEQ electrical equipment qualification
EOP(s) emergency operation procedure (s)
EPRI Electric Power Research Institute
EQ environmental qualification
EOR (s) equipment qualification record (s)
l ESF engineered safety feature
EWR engineering work request
l FSAR Final Safety Analysis Report ;
l FSARCR(s) Final Safety Analysis Report Change Request (s) j
GDC general design criterion / criteria
GL Generic Letter
gpm gallons per minute
HELB high energy line break
i HPES human performance enhancement system
HPSI high pressure safety injection i
L
HJTC heated junction thermocouple
l HVAC heating ventilation and air conditioning
l&C Instrumentation & Control
ICAVP Independent Corrective Action Verification Program
IFl inspector follow item
ILRT integrated leak rate test
IR(s) - Inspection Reports (s)
'LCO limiting condition for operation
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LCV(s) level control valve (s)
LDT(s) line designation table (s)
LER(s) licensee event report (s)
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LLRT localleak ratt test
LOCA loss of coolaat accident
LPCI low pressure .oolant injection
MCC motor control center
MDAFW motor-driven auxiliary feed water
MEPL(s) material, equipment, and parts list (s)
MOPD maximum operational pressure differential
MOV(s) motor-operated valve (s)
NGP(s) nuclear guidance procedure (s)
NI nuclear instrumentation
NOV(s) Notice of Violation (s)
NRC Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation
NSAB nuclear safety assessment board
NSIC Nuclear Safety hformation Center
NUREG Nuclear Regulation
NUSCO Northeast Utilities Service Company
OCA Office of Congressional Affairs
OEDO Office of Executive Director for Operations
PAO Public Affairs Office
PDCR plant design char.ge record
PDR Public Document Room
PMMS production maintenance management system
PORC plant operation review committee
PORV(s) power operated relief valve (s)
PRA probabilistic risk assessment
PTL pull-to-lock
PWR pressurized water reactor
QA quality assurance
QC quality control
RAI request for additional information
RBCCW reactor building closed cooling water
RECO reasonable expectation of continued operability
RG Regulatory Guide
RSS recirculation spray system
SBLOCA small break loss of coolant accident
SBO station blackout
SER(s) safety evaluation report (s)
SGCS safety grade cold shutdown
SIL significant item list
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SOV(s) solenoid-operated valve (s)
SPDS safety parameter display system
SPO Special Projects Office
SPROC special procedure
SRP Standard Review Plan
SSER supplemental safety evaluation report
SSM subcooled/superheat monitor
SSU saybolt seconds universal
SV(s) safety valve (s)
SWEC Stone & Webster Engineering Corporation
TDAFW turbine driven auxiliary feedwater
TMI Three Mile Island
TRM Technical Requirements Manual
TS(s) technical specification (s)
URl(s) unresolved item (s)
USO(s) unresolved safety question (s)
Vdc volts, direct-current
VIO violation
VTM vendor technical manual
WC work control