ML20216E819
| ML20216E819 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/09/1998 |
| From: | Meyer G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20216E791 | List: |
| References | |
| 50-334-98-80, 50-412-98-80, NUDOCS 9803180171 | |
| Download: ML20216E819 (33) | |
See also: IR 05000334/1998080
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
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Docket Nos. 50-334,50-412 I
Report Nos. 98-80,98-80
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Licensee: Duquesne Light Company (DLC)
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Facility: Beaver Valley Power Station, Units 1 and 2 j
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Location: Post Office Box 4
Shippingport, PA 15077
Dates: January 5,1998 through February 12,1998
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Team Leader: Paul D. Kaufman, Senior Reactor Engineer
Division of Reactor Safety (DRS) l
Inspectors: Ram Bhatia, Reactor Engineer, DRS
t Don Brinkman, Senior Project Manager for Beaver Valley, Ni;H
Don Haverkamp, Reactor Engineer, DRP
Stephen Pindale, Resident inspector, Oyster Creek
l. David Silk, Senior Emergency Preparedness Specialist, DRS
Christopher Welch, Reactor Engineer, DRS j
Approved by: Glenn Meyer, Chief
Civil, Mechanical and Materials :
I Engineering Branch
Division of Reactor Safety
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9803180171 980309
~PDR ADOCK 05000334
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EXECUTIVE SUMMARY
Beaver Valley, Units.1 & 2
NRC Inspection Report 50-334/98-80,50-412/98-80
Introduction
An on-site engineering team inspection was conducted at the Beaver Valley Power Station
during the period of January 5 to February 12,1998. The overall objective of the
inspection was to determine whether engineering was providing proper support for safe
l plant operations. The inspection included evaluation of the implementation of the 10 CFR
50.59 safety evaluation program relating to changes, tests or experiments at the plant.
The team included five inspectors, the NRC's Office of Nuclear Reactor Regulation (NRR)
Beaver Valley Project Manager, and a team leader.
Enaineerina
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DLC's engineering programs had the essential elements to provide good engineering
g performance. However, much engineering work was backlogged, and this backlog had
- increased in 1997. DLC had plans to address the backlog and, in most cases, had
effectively prioritized the work. Also, certain areas of engineering activities were not being
l effectively implemented and resulted in NRC-identified deficiencies. For example,
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corrective actions to resolve a degrawd RHR valve had not been implemented adequately
or timely and represented a violation.- Over the past year the engineering staff has
. aggressively identified significant old design deficiencies and this was considered
l notsworthy. This is an indication of the engineering staff's strong technical knowledge
and aggressive pursuit of issues in the Beaver Valley design basis.
10 CFR 50.59 Safety Evaluation Proaram
Overall, the inspection determined that the 10 CFR 50.59 process was well defined and
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was being implemented generally satisfactorily. However, the inspectors identified a faulty
l safety evaluation from December 1994 and found that a 10 CFR 50.59 determination had
not been performed in related to an operational procedure change made in December 1997.
Both of these issues represent violations, and the latter issue appeared to question the
effectiveness of ongoing corrective actions to a DLC QA audit.
Overall Conclusions
Engineering support for safe plant operations was acceptable, as evidenced by the promt
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response to a number of emergent design deficiencies. The engineer'ng staff had a strong
technical knowledge into the station's design basis. Plant and design deficiencies were !
properly identified, root causes determined, and corrective actions were generally initiated i
in a timely manner. The engineering backleg increased over the past year primarily due to l
unexpected emergent design issues. The work backlog was adequately screened for i
safety significance and appropriate n.Tanagement steps are being taken to reduce the
backlog. The 50.59 program was being implemented satisfactorily, however some
weaknesses were identified.
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TABLE OF CONTENTS
. EX EC UTIVE SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
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TABLE O F CO NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
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- lil . Enginee ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ._ 1
E1.1 Plant Design Change Modifications Review . . . . . . . . . . . . . . . . . 1
E1.2. Temporary Modifications Review . . . . . . . . . . . . . . . . . . . . . . . . 3
E1.3 Engineering Backlog and Prioritization Program . . . . . . . . . . . . . . 3
! E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . 5
E2.1 Plant Problem Identification and Resolution Review . . . . . . . . . . . 5
! E2.2 Longstanding RHR Valve Degradation ....................9
~E3 10 CFR 50.59 Safety Evaluation Program -lP37001 ...................11
E3.1 Engineering Procedures and Documentation . . . . . . . . . . . . . . . 11
E3.2 Implementation of 10 CFR 50.59 Program ................ 12
E3.3 10 CFR 50.59 Applicability Determinations . . . . . . . . . . . . . . . . 15
L E4 System Engineer Knowledge and Performance .................. 15
04.1 Technical Knowledge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
E4.2 Improper implementation of Procedure Change Process . . . . . . . 17
E5 Engineering Staff Training and Qualifications . . . . . . . . . . . . . . . . . . . . 20
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E5.1 10 CFR 50.59 Safety Evaluations Program Training
and Qualifications ................................20
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E7 Quality Assurance in Engineering Activities . . . . . . .............21
E7.1 Quality Assurance (QA) Audit of 10 CFR 50.59 Program . . . . . . 21
E7.2 Onsite Safety Committee . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
E7.3 Offsite Review Committee . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
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E8 Miscellaneous Engineerir.;; Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 i
l E8.1 (Closed) Violatiev. 50-334(412)/95-05-04 . . . . . . . . . . . . . . . . . 23
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V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3
X1 Exit Me eting S u mm a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3
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Reoort Details
111. Engineering
E1 Conduct of Engineering
E1.1 Plant Desian Chance Modifications Review
a. Insoection Scone (37550)
The purpose of this portion of the inspection was to review and assess engineering
activities, particularly the effectiveness of the engineering staff performing routine
and emergent design activities in support of safe plant operations at the Beaver '
Valley Power Station. The review included plant design changes, temporary
modifications, identified engineering issues, and corrective actions for emergent and
routine plant deficiencies, engineering backlog and prioritization program, review of
previously NRC identified violation pertaining to the design deficiency in the AMSAC
design; 50-334(412)/95005-04. The inspectors reviewed selected design changes
implemented in Beaver Valley Unit 1 and 2, during the last refueling outages to-
assure their conformance with applicable procedures and NRC requirements.
Design inputs,10 CFR 50.59 evaluations, specialty group technical reviews,
calculations, installation and test packages, and selected portions of plant
equipment and installations were evaluated. In addition, the inspectors verified that
the applicable UFSAR changes were appropriately identified in the design change '
packages.
b. Observations and Findinas
Nuclear Engineering' Administrative Procedure (NEAP) NEAP 2.2, entitled, " Design l
Control," Revision 9, established the responsibilities, requirements, and guidelines - {
for implementing and controlling design changes. Nuclear Power Department l
Administrative Manual (NPDAP) procedure, NPDAP 8.18, "10CFR 50.59 !
Evaluations," provided the guidance, responsibilities, requirements for the !
preparation, review, ar>d approval of the safety evaluations of proposed design I
changes, tests or experiments.
The inspectors reviewed the following design change modifications:
Unit 2. DCP-2306. Emeraency Pressurization System Modifi:ation & DCP 2311,
Control Room Emeroency Air Filtration System Modification
The inspectors reviewed portions of emergency pressurizetion system and control 1
room emergency air filtration system design modification, including the safety
evaluation. This design change was prepared to resolvo a single failure concern
that Duquesne Light Company (DLC) identified in December 1997. (Inspection i
Reports 97-09 and 97-11 provide further details.) The changes included: 1) i
replacing the existing motor-operated discharge dampers (one for each of the two I
trains) with gravity-activated back draft dampers; 2) relocating the pressure taps for
sensing differential pressure in the 'A' filter bank; 3) installing a new pressure
differential switch across the 'B' filter bank (and fan); and,4) providing an
automatic start of the back-up 'B' train upon a single failure of the preferred 'A'
train.
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The inspectors determined that the overall quality of the design change package and
safety evaluation was good and the safety evaluation appropriately addressed the
design deficiencies (single failure vulnerabilities).
Unit 1. DCP 2209, Analoa Rod Position Indicator (ARPI) Electronic Uoarade
This design change replaced the existing rack mounted electronic equipment
originally provided by Westinghouse's analog rod position indication system with
ABB Combustion Engineering's rod position indication (CERI) system. The existing
plant system design had not been able to maintain control rod indication within the
original required Technical Specification tolerances of +/- 12 steps of demand under
all required plant conditions.
The inspectors determined that the design changes were designed and satisfactorily
implemented.
Unit 1- DCP 2259, AMSAC Focused Desian Review Chanaes
This design change was initiated in response to an NRC violation cited on
September 11,1996, as documented in the NRC inspection report
50-334/412;96-05,for the failure to consider the effect of static pressure in flow j
transmitters and the effect of hydraulic fluctuations in the feedwater design on this l
system. DLC's design team completed a review of the anticipated transient without l
scram (ATWS) mitigating system actuation circuitry (AMSAC) design deficiency.
The design change was implemented in the last refueling outage for the Unit 1. The i
design change appropriately addressed tne design concern and included additional I
design improvements as recommended in DLC's AMSAC design review group report !
issued on July 31,1997. '
The inspectors review of the above selected design change packages, consisting of
installation plan, related drawings, the test plan, selected procedures, and operator i
training material revealed no concerns. The inspectors found the quality of the I
DCPs and associated documentation acceptable and consistent with established
design change procedures and NRC requirements. The inspectors also found that
the safety evaluations were appropriately prepared and included the design basis
requirements addressed in the UFSAR and determined that the overall quality of the
safety evaluations was good.
c. Conclusions
Overall, the design changer, were appropriate ard well supported with a srsund
technical design basis including thorough, accurate 10 CFR 50.59 evaluations, in
conformance with established design control procedures and design standards.
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E1.2 Temporary Modifications Review
a. Inspection' Scone (37550)
The inspectors examined temporary modifications (T-mods) selected from control
room logs to assure that temporary changes implement in the station were being -
prepared, reviewed and installed in accordance with established requirements,-
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b. Observations and Findinas
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l T-mods in the station were controlled by Administrative Procedure NPDAP 7.4, q
Revision 6," Temporary Modification." This procedure outlined the guidelines for l
administrative requirements, approval, installation, documentation and review of T- 1
mods used in modifying or troubleshooting plant systems.
! The inspectors review of the several T-mods installed in the station in both units
indicated no concerns. The T-mods were installed in accordance established
l administrative procedures, the T-mod packages contained appropriate 10 CFR
! 50.59 applicability reviews, and affected drawings were properly revised to identify
, the changes. The status of all T-mods installed in the station had been reviewed
l and evaluated on a quarterly basis per established procedure requirements.
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The inspectors noted that DLC made significant progress in reducing the installed
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temporary modifications from approximately twenty to five during the last Unit 1 ,
l refueling outage. Similar efforts appeared to be ongoing to reduce the fifteen active
l T-mods installed in Unit 2 during the scheduled Unit 2 refueling outage reflected on
l the January 19,1998, T-mod status report. The inspectors noted that DLC's
j established goal for temporary modifications was to achieve less than fifteen
i installed T-mods on both units.
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c. Conclusions l
Overall, the inspectors concluded that temporary moosfications in the station were
appropriately impemented'and controlled per established procedures. During the
last Unit 1 refueling outage, DLC made significant progress in reducing the installed
E1.3 Engineering Backlog and Prioritization Program
a. Insoection Scope
The inspectors reviewed and assessed the nuclear engineering department's (NED)
outstanding engineering work and the methods used to prioritize and track these
issues. This included the review of recent plant issues status, various station
performance indicator reports, listings of outstanding condition reports (CRs), design
change packages (DCPs), and design change requests (DCRs), and interviews with
several staff members involved in the process to determine the effectiveness of
their overQh'. In this area.
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b. Observations and Findinga
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Desian Chanaes:
L The inspectors noted that the DCP backlog had increased over the past year. Based
on information obtained from the listing of active DCPs dated January 9,1998 and
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the NED monthly performance indicators report dated December 10,1997; 176
DCPs were found to be active, an increase of approximately 22% over the past
year.
The inspectors also noted that DLC was in the process of formalizing a classification
and ranking of all DCPs. DLC expected to issue guidance for the classification for
all DCRs by January 31,1998.
Of the 176 active DCPs 58% were more than 4 years old and 14 dated back to
1980.There were 3 Unit 2 DCPs preliminary designated as a classification 1
(highest priority) and were being aggressively pursued.
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The inspectors reviewed the preliminary classifications of the DCPs and potentia!
DCP listing and noted no concerns. The DCP and DCR prioritizations appeared to
be appropriate.
Procedures;
Review of the backlog of procedure revision requests indicated that the backlog had
increased significantly since February 1997 when there had been 98. The increase
was due to DLC completing a 100% review of all NED procedures. Based on NED
Procedures Status Report, dated January 6,1998, the procedure backlog stood at
300 revision requests affecting 174 NED procedures. Discussions with DLC
personnel and a cursory review of the revision requests and periodic review sheets
indicated that the majority of the revision requests represented administrative
changes resulting from a reorganization within the engineering department and )
- clarification of existing instructions. Based on the DLC revised recovery plan, dated
l November 20,1997, all NED procedures wers scheduled to be updated by
December 1998.
Vg.ndor Technical Information:
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Over the past year DLC has made steady progress in reducing the backlog of vendor
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technicalinformation (VTl) and improved the timeliness of the initial screening of j
vendor technical information. Review of the VTl data through the month of '
November 1997 indicated 295 items needed a technical evaluation down from 372
in December of 1996. Of the 295 VTl items needing a technical evaluation only 7
were priority 1 (VTl reviews with potential for impact on safety related equipment). j
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_Qondition Reoorts:
Over the last five months an increasing trend existed in the number of outstanding
and overdue condition reports (CRs) and corrective action request forms (CARFs)
assigned to NED, including 15 CR investigations and 25 CARFs identified as
overdue in the December 29,1997, weekly status report. The number of overdue
SPED evaluations of CRs and CARFs was also found to be increasing over time.
SPED management had implemented a commitment tracking system in
September 1997 per SPEAP 1.10 in order to eff.iciently manage the SPED backlog.
The inspectors noted that the overdue CRs and CARFs were generally classified as
a lower safety priority and were not an immediate safety concern.
Workload Manaaement System:
During 1997 DLC's efforts to correct significant emergent design issues (e.g. small l
bore piping supports, charging pump gas binding, control room ventilation, and
electrical isolation in process control system racks of Westinghouse Spec 7100 &
7300) and a 100% review of their engineering procedures last year had resulted in
a significant increase in the routine engineering backlog. DLC management stated
that they have initiated a process to hire approximately 35 contract engineers to
assist in reducing the outstanding backlog of engineering work.
c. Conclusions
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The inspectors concluded that NED had not been keeping up with the engineering
workload in many areas, notably design change packages, design change requests,
procedure changes, condition reports, and corrective action requests. Nonetheless,
engineering efforts had resolved some significant issues, had reduced the backlog of
vendor technical information, and was generally appropriately prioritized. Further,
hiring efforts were underway to add engineering resources.
E2 Engineering Support of Facilities and Equipment
E2.1 Plant Problem Identification and Resolution Review
a. Insoection Scoce (37550)
The inspectors reviewed several selected plant Condition Reports (CRs) generated
by NED and system performance engineering department (SPED) staff over the past
year and some recently identified emergent issues to assure DLC was appropriately
identifying and correcting design and equipment related deficiencies. T he scope
included the applicable review of the root cause analyses, operability
determinations, technical evaluations, and corrective actions. The inspectors ,
interviewed personnel, reviewed station records, and controlled drawings, and l
observed work activities to assess resolution of emergent design deficiencies.
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b. Observations and Findinas ' )
The reviewed CRs included CR 97117, June 27,1997, Unit 1 seismic qualification
of main feedwater flow transmitters, CR 972304, December 16,-1997, Unit 2
control room emergency pressure fan lacks single active failure proof design, and
CR 972346, December 19,1997, lack of electricalisolation in Unit 2 diesel room
temperature circuit. From these the inspectors determined that over the past year
the engineering staff had identified significant old design issues at the Beaver Valley
Power Station. This was an indication of the engineering staffs strong technical
knowledge and the aggressive review of the design basis of the station and that this
was noteworthy.
Inadeauate Electrical Seoaration for Safety Related Comoonents ;
(CRs 971714,972346,972395,980011, and 980058)
During the extent of condition review on September 24,1997, NED engineers
identified (CR 971714) Unit 2 safety related (Class 1E) components of 7300 !
l process control systems that were not properly separated from non-safety related- 1
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(non-Class 1E) circuits. This condition rendered the subject loops of the 7300 l
process control system and associated equipment inoperable.
DLC's review noted that this existing isolation configuratic.n was not as described in
the Unit 2 FSAR requirements. This deficiency was originally believed to be an
isolated case which was caused by implementation of a design change to the main
steam line and pressure flow instrumentation loops installed in 1993 per DCP-1596.
DLC decided to modify the above circuit and review other loops.
The inspector noted that the Unit 2 UFSAR, Section 7.1.2.2.1 states that the class
1E protection systems: nuclear instrumentation system (NIS), solid state protection
j system (SSPS), and 7300 process control system (PCS) are not degraded by non-
Class 1E circuits sharing the same enclosure, and are in conformance to the
requirements of IEEE Standard 279-1971 and Regulatory Guide 1.75. lEEE Std
384-1977, Standard Criteria for independence of Class 1E Equipment and Circuits,
specifies that electrical isolation be used in instrumentation and control (l&C)
circuits to maintain the independence of redundant circuits and equipment such that
protective functions required during and following any design basis accident are
maintained. The electricalisolation shall be achieved througn use of Class 1E
isolation devices applied to interconnections of Class 1E and non-Class 1E circuits.
While reviewing a recent electrical separation issue event at another facility and
continuing extent of condition reviews for Unit 2 emergency diesel generator (EDG)
room ventilation system temperature control circuits, (CR 972346), engineers
determined that additional electrical separation deficiencies existed in the Unit 2
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secondary process rack design. Over 85 instruments or controllers were affected,
including both EDGs, the reactor coolant system boration flowpaths, station battery
room ventilation, emergency switchgear room ventilation, and recirculation pump
flow.
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The inspectors met with engineers and reviewed controlled circuit drawings to l
assess implementation of recuired separation criteria for the secondary process {
racks. The secondary process racks contained both Class 1E circuit cards and non- I
Class 1E clicuit cards. Original plant procurement specifications properly specified j
the electrical separation requirements. However, the specification was not correctly l
implemented by the original architect engineer. While the original plant design {
properly separated the Class 1E and non-Class 1E signals with qualified isolation j
devices, it failed to properly consider isolation of the non-Claas 1E signals from the !
two Class 1E power supplies contained within each of the four secondary process ;
racks. l
The inspectors determined that engineers were knowledgeable concerning design l
requirements and were conducting an acceptable detailed, systematic design
validation review of the Unit 2 secondary process racks. All cards are connected to ;
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the rack's two Class 1E power supplies. Consequently, a fault in a non-Class 1E
circuit could damage or trip both Class 1E rack power supplies, and deenergize the l
Class 1E circuits within the rack. Loss of an entire secondary process rack could
result in a reactor trip, but would only deenergize one channel of protective circuits.
Engineers noted that a single event could cause a fault on non-Class 1E circuit cards
in more than one secondary process rack at once This could result in losing more
than one protection channel and be a condition outside of design.
Engineers identified several specific examples of separation criteria deficiencies
which could result in secondary process rack power supply failure as discussed
below.
- Case 1: Certain 7300 series circuit cards have a capacitor connected
between the plus and minus DC inputs in the power supply section of the
card. The capacitor plus lead is connected to the input side of the card fuse.
Therefore, the card fuse will not open (perform its protective action) if the
capacitor short circuits.
- Case 2: Non-Class 1E field cables from more than one secondary process
rack could be routed in a common raceway. Without proper Class 1E/non-
Class 1E electrical separation, a common physical fault (i.e. fire, seismic
fault) could deenergize more than one secondary process rack at a time.
Based on the circuit analysis, the inspectors questioned whether the design
deficiencies were applicable to Unit 1. The engineers agreed that they did not have
sufficient basis to eliminate applicability to Unit 1, which was preparing for restart
following a refueling outage. Management promptly established a hold on Unit 1
startup and elected to proceed from mode 3 (hot shutdown) to mode 5 (cold
l shutdown) until issue applicability was resolved. The inspectors determined that
this action was appropriate and demonrtrated a conservative safety perspective by
DLC.
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I NED established a logical evaluation and correction plan for both units to verify and I
i . restore required electrical separation. This included expanding scope where
l appropriate to review circuit design within the primary protection racks as well.
Investigation and corrective actions included visualinspections of each secondary
process rack, material history reviews, replacement of several non-Class 1E cards
l with Class 1E cr.;ds, Material Equipment List corrections, installation of two
l - temporary modifications to eliminate a separation issue associated with the primary
component cooling water surge tank level controls, qualification of certain isolation -
,j devices, and over twenty wiring modifications within the secondary process racks
performed using the design change process. The Unit 1' secondary process racks
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were confirmed to meet applicable separation criteria.
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l' The inspectors observed that procurement support and coordination between
engineering and maintenance personnel during these activities was excellent, in
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addition, DLC's communication with the industry and NRC personnel was excellent i
concerning this potentially generic issue. DLC was communicating with the
architect engineer concerning a potential 10 CFR Part 21 applicability review at the
close of the inspection period.
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10 CFR 50 Appendix B, Criterion lil, requires that measures be established to assure
that applicable regulatory requirements and design bases are correctly translMed
into specifications, drawings, procedures, and instructions. These measures shall
l include provisions to assure that appropriate quality standards are specified and
l included in design documents and that deviations from such standards are
l controlled. The UFSAR commits Unit 2 to the design standards of IEEE 384-1977.
l' The inspectors concluded that the failure to establish required electrical separation
l between Class 1E and non-Class 1E components within the Unit 2 secondary
process racks as described in IEEE Std 384-1977 was s violation of 10 CFR 50
Appendix B, Criterion 111, Design Control. DLC identified this issue through a
voluntary initiativeicorrective actions were prompt and comprehensive, the
violation was not likely to be identified by routine efforts such as a normal
surveillance or quality assurance activities, and the vicMtion is not reasonably linked
[ to current performance. As a result, this violation of NRC requirements will not be
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i cited in accordance with Section Vll.B.3 of the N_RC Enforcement Poliev.
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c. fgqnclusions
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i- DLC engineers determined that the Unit 2 secondary process racks failed to meet
L Class 1 E/non-Class 1E electrical separation requirements resulting in several safety
related components including the EDGs and boration flowpaths being inoperable.
This original design deficiency was identified through review of extent of condition
reviews and industry operating experience. Engineering evaluation and corrective
actions were comprehensive. NRC enforcement discretion was exercised and no
violation issued, in recognition of self identification and correction through voluntary
initiatives of an old design issue.
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E2.2' , Longstanding RHR Valve Degradation
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L a. Insoection Scooe (37550)
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t The inspectors reviewed details surrounding a residual heat removal system valve
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b. Observations and Findinas
The inspectors reviewed CR 972281, dated December 12,1997,~ which described
difficulties in operating the Unit 1 RHR system in accordance with normal system
l- configuration. The CR referenced an existing seat feakage problem with RHR valve
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MOV-RH-758, which was the primary reason for the operating difficulties. MOV .
RH-758 is a 12 inch tutterfly valve'that is located in the piping that is cornmon to
both RHR trains, and is dow;nstream of the two RHR heat exchangers. - This valve is
used to centrol flow through the RHR system, i.e., a throttle valve, not an isolation
valve. The HHR system is a safety-related system designed to remove heat from
, the core and reduce the temperature of reactor coolant system (RCS) from 350*F to
l 140*F during the second phase of reactor cooldown.
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The two .7HR heat exchangers are cooled by the component cooling (CCR) system.
As per design and operating procedures, CCR flow through the RHR heat
exchangers is controlled via two 18 inch manually operated CCR valves (one per
heat exchanger), located inside containment and downstream of the outlet of each
heat exchanger. CR 972281 noted that these CCR valves are difficult to access,
and that known RHR system leakage through MOV-RH-758 necessitates additional
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CCR flow adjustment. In particular, the CR requested that a set of downstream
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CCR valves, which are located outside containment, be used as throttle valves
during the upcoming reactor startup. This was requested because the operators
expected to adjust (reduce) CCR flow through'the RHR heat exchangers to prevent
excessive cooldown rates due to the combination of low decay heat and excessive
leakage past MOV RH-758. The inspectors reviewed Engineering Memorandum
(EM) 115624, dated December 15,1997, which was initiated to address a final
throttling position for the inside containment CCR valves upon reactor startup. That
!- EM teferred to prior throttling of the outside containment CCR valves by operators, g-
which was degrading their rubber seats (See Section E4.2 of this report for
additional discussion related to procedures for operating the CCR system).
The inspectors found CR 972281 stated that additional review was needed prior to
entry into Mode 4. The inspectors requested and reviewed DLC's list to identify
and track mode holds, however, this item was not listed. The specific item was
addressed prior to exceeding Mode 4; however, the absence of this item on the list
was indicative of an administrative error in identifying, tracking and implementing all
identified mode holds.
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DLC informed the inspectors that the leakage past MOV-RH-758 was formally
documented using a maintenance work request (No. 38916)in January 1995.
However, according to operations and system engineering personnel, the leakage
had existed for several years before 1995. In response to the January 1995 work
request, DLC performed an operational leak rate measure aent through the RHR
system with MOV-RH-758 and a related RHR heat exchanger common bypass valve
(MOV RH-605) closed. The February 1995 measurement determined that the
combined leakage past these two valves was 2200 gpm. More recent calculations
completed by system engineering indicated that the leakage past MOV-RH-758 was
between 1000 gpm and 1500 gpm, with the remaining 700 gpm to 1200 gpm
leaking past MOV-RH-605. i
, The inspectors concluded that the internal bypass leakage identified by DLC was 1
excessive. However, DLC had not determined the cause of the excessive bypass I
leakage, nor had DLC performed an evaluation to assess the potential failure modes
and consequences of a failure of either valve. DLC stated that because they did not
know the nature of the malfunction of MOV-RH-758, and the fact that no other
intrusive maintenance was scheduled for the RHR system during the recent 1R12
refueling outage, they had decided that only the actuator for that valve would be
inspected. DLC further stated that if the actuator work failed to correct the i
problem, then the RHR system would be drained and the valve internals would be !
examined during the next (1R13) refueling outage. The actuator work performed
during 1R12 did not correct the excessive bypass leakage problem. No additional
operability or evaluative efforts were taken or planned at that time.
In response to the operability concerns described above, DLC performed non-
destructive examination (ultrasonic measurement) of MOV-RH-758, as well as two
of the CCR valves. The data indicated sufficient wall thickness for the valve body,
and confirmed the structuralintegrity of the RHR system. However, DLC had not
yet performed internal inspections of the two leaking RHR system valves. DLC had
provided engineering judgement as a basis for deteimining that the RHR system was
Beaver Valley procedure 1/20M-48.3.M," Operator Work-Arounds," defines an
operator work-around as any equipment deficiency or plant condition which during
normal plant operating conditions increases operator burden (or during
abnormal / emergency conditions will complicate operator response by requiring non-
routine cornpensatory operator actions). The purpose of the procedure is to define
responsibilities for identification, assessment and review of operator work-arounds.
The inspectors determined that the excessive bypass leakage through MOV-RH-
758, coupled with the compensatory actions to control heatup and cooldown rates
by throttling CCR system valves represented an operator work-around. However, ,
DLC had not properly identified this long-standing RHR system deficiency as an )
'
operator work-around in the Unit 1 control room log.
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L The inspectors concluded that DLC's actions in response to the known leakage past
[ MOV-RH-758, as well as the associated heat exchanger bypass valve, were
l . inadequate. Specifically, after significant leakage was identified in February 1995,
DLC had not determined the cause for the excessive leakage or corrected it. Also,
DLC had not evaluated postulated' valve failure. On February 4,1998, the
inspectors contacted DLC management personnel via telephone to question the
l current operability status of the RHR system considering the excessive leakage and
- lack'of knowledge of the cause, potential failure modes, and consequences of- l
l associated postulated failures. DLC informed the inspectors that they would further
evaluate this condition and complete an operability determination or Basis for
i- Continued Operation (BCO) for the RHR system. Overall, the inspectors assessed )
[
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that DLC was slow in performing an operability determination or BCO. At the end . i
of the inspection, the RHR system engineer was completing a formal basis for
continued operation (BCO) determination to support DLC's initial engineering
judgement decision.
I-
l. The inspectors determined that DLC failed to implement measures to assure' that' I
this condition adverse to quality was promptly identified and corrected, as required
by 10 CFR 50, Appendix B, Criterion XVI (Corrective Action), and was considered a ;
,. violation of NRC requirements. (VIO 50-334/98080-02) ,
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c. Conclusions !
l.
l DLC's overall response to this known long-standing RHR valve deficiency was
l untimely and inadequate. Station personnel were aware of significant internal
l bypass leakage through an RHR valve, the primary controller for reactor coolant
i system temperature while in the shutdown condition. However, the deficiency was
i documented in January 1995, and since then, the root cause of the degraded valve
had not been identified or corrected. Also, the bases for operability or basis for
continued operation (BCO) had not been completed. In addition, the valve was not
j characterized as an operator work-around in the Unit 1 control room log.
l
l E3 Engineering Procedures and Documentation
E3.1 10 CFR 50.59 Safety Evaluation Proaram
l
L
a. Inspection Scope (37001)
l
The inspectors reviewed selected procedures and interviewed DLC representatives
to verify that: (1) proper procedural guidance had been established for
l
i implementing the requirements of 10 CFR 50.59 for proposed changes, tests and
experiments (CTEs) including safety evaluations (SEs); and (2) procedural guidance
had been established for updating the Final Safety Analysis Report (FSAR), as
required by 10 CFR 50.71 (e).
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b. Observations and Findinas
The inspectors reviewed eighteen site and department procedures, listed in
Attachment A, that provided guidance and responsibilities related to 10 CFR 50.59
and 10 CFR 50.71(e) requirements. From the procedures, the inspectors found that
all plant change processes are linked to the two administrative procedures, NPDAP I
8.10 and NPDAP 8.18, which define the 10 CFR 50.59 program at the BVPS.
The inspectors found that the procedures provided proper guidance for determining
when SEs are required to be completed in accordance with 10 CFR 50.59 and
describes the process for preparing and approving safety evaluations. The
procedures adequately delineated responsibilities for the various individuals who i
prepare, process, and approve SEs. The SE development, evaluation, and approval
process was clearly defined.
l J
c. Conclusions
i
l; in general, the procedures supporting the 10 CFR 50.59 process were found to be l
l acceptable. The procedures provided comprehensive guidance and detailed ;
responsibilities for implementing the requirements of 50.59 and updating the Final l
Safety Analysis Report.
E3.2 imolementation of 10 CFR 50.59 Proaram
a. Inspection Scone (37001)
l
l
The inspectors examined the quality of safety evaluations (SEs) prepared by DLC in -l
accordance with 10 CFR 50.59 to determine if the SEs for plant design changes and ,
procedure changes addressed all safety issues pertinent to the associated change, ;
l test, or experiment. The inspectors selected and reviewed a representative sample )
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of 15 safety evaluations (SEs) listed on Attachment A. In addition, the inspectors
selected and reviewed 12 safety evaluations, which DLC had reported to the NRC in I
its most recent annual reports of facility changes, tests, and experiments listed on
Attachment A. The Unit 1 annual report was dated January 20,1997, and covered
the period January 23,1995 through January 22,1996. The Unit 2 annual report
was dated August 6,1997, and covered the period of November 1,1995 through ,' A
October 31,1996. As part of these reviews, the inspectors verified that the
changes described in the SEs had been appropriately documented in Unit 1 UFSAR
Revision 15 and Unit 2 UFSAR Revision 9.
Safety Evaluations for Facility Modifications
The inspectors determined that the SEs were prepared and reviewed by individuals
who had received annual training regarding the preparation and review of 10 CFR
50.59 SEs. All the individuals who prepared and reviewed the SEs were listed on
DLCs roster of those approved for preparing and reviewing 10 CFR 50.59 safety
evaluations.
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b. - Observationt and Findinas
Safetv Evaluations for Procedure Chances
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The inspectors reviewed the 50.59 evaluations for several procedure changes and
tests, and determined whether the evaluations were in accordance with DLC
procedures and reached the appropriate conclusions.
The safety evaluations were generally acceptable, met 10 CFR 50.59 requirements
and had been appropriately included in UFSAR revisions. Nonetheless, the
inspectors noted one case where a written safety evaluation was inadequate, in
that, it did not provide the proper basis for determining that the change did not
involve an unreviewed safety question and was considered a violation of 10 CFR
50.59 requirements. Also, the inspectors identified two safety evaluations that
were found to be weak, in that, they were narrowly focused and of limited scope.
Examples of deficient and weak safety evaluations are described below:
- Safety evaluation for DCP 2133 evaluated the acceptability of a modification
to supply propane gas to an existing furnace in the auxiliary intake structure
building and to add a concrete pad next to this building to support three
l 1000-gallon propane storage tanks. However, the SE failed to evaluate any
l potential hazards or impact on equipment important to safety associated with
the storage of large quantities of liquid propane next to the auxiliary intake
'
structure.
The inspectors toured the auxiliary intake structure area and found that the
l concrete pad and the three 1000-gallon propane storage tanks had not been
i installed, but rather, a SOOO-gallon capacity tanker truck trailer was parked
( next to the auxiliary intake structure and was being used to store and supply
! the propane. DLC stated that although the tanker capacity was 5000
gallons, the propane supplier limited the quantity of propane in the tanker to
80% of tank volume (4000 gallons) to provide for expansion. The inspectors
l verified that the Unit 1 UFSAR had been revised (Revision 15) to reflect the
storage of 4000 gallons of propane at this location. The inspectors inquired
to determine if a supplemental SE had been prepared for this change in
propane storage method or quantity. DLC was unable to locate a revised SE.
The inspectors concluded that the SE was inadequate, in that, it failed to
evaluate the potential hazards of storing large quantities of liquid propane
(neither the proposed three 1000-gallon tanks, nor the 4000-gallons stored in
the tanker truck trailer), nor did the SE evaluate the change in propane
storage methods. Failure to perform an adequate safety analysis to ensure
that the modification did not involve an unreviewed safety question was
considered to be a violation of 10 CFR 50.59 requirer ents. (VIO 50-
334(412)/98080-03)
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Subsequently, engineering revised the safety evaluation and presented the
evaluation at the Onsite Safety Committee meeting on February 11,1998.
j DLC concluded that the storage of propane next to the auxiliary intake
- structure did not pose a significant safety hazard or represent an unreviewed
! safety question. The inspectors attended the O.C. meeting and reviewed the
l
revised safety evaluation and found the safety evaluation acceptable. ;
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i e . Safety evaluation for TER 10897 evaluated the acceptability of installing wire
j mesh cage assemblies at the doors of the Safeguards Building, Auxiliary
Building, Diesel Generator Building, and at other plant locations deemed j
necessary to increase the time required to pass through a particular location. l
, Each cage assembly has a gate. These cage barriers are Category lli, non-
'
safety-related and are typically in addition to an existing door. The cage gate 3
, has a manuallatch and may be opened or closed from either side of the gate. i
l
j- ' The SE stated that the credible mode of failure would be a cage panel
i becoming dislodged or its anchorage failing. According to the SE, cages
near safety-related equipment were seismically analyzed to ensure their
l integrity. The SE noted that some cages were not seismically' analyzed. The
- inspectors' concern with these cages was that they could become loose or
distorted, thereby resulting in the gates or latches becoming jammed. The
l SE failed to consider the time delays that could be caused by delays in
l- passage through the gates if non-seismic gates or latches became jammed
due to distortion. The increased time for operators to pass through these
i gates may cause some interference in response to events or equipment
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problems. The inspectors determined the failure to consider such potential 4
l time delays to be a narrowly focused safety evaluation. l
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e Safety evaluation for TER 9421 stated that TER 9421 added a non-Q (non- ;
, safety-related)/O (safety-related) Safety Class Break between QA Category ll !
! Pipeline 2"-OS-29-152 and QA Category 1 Chemical Addition Tank QS-TK-2 l
on BVPS Unit 1 Flow Diagram 8700-RM-513-1 and UFSAR Figure 6.4-1 A. )
l To justify the addition of this saft,ty class break, which was not previously l
l shown on these drawings, the SE referred to ANSI /ANS-51.1-1983 Page E-3 i
Case 6(d) and stated that the Pipeline 2"-OS-29-152 meets the condition of
a less stringent class equipment connected to a more stringent class l
equipment OS-TK-2. However, the inspectors noted that ANSI /ANS-51.1- I
1983 has not been endorsed by the NRC and therefore, reference to it was l
L an inadequate justification for this change.
!
The SE stated that this change was only to provide a location of the non-
safety / safety class break on the flow diagram and UFSAR figure and that the
change would not affect the QA Category of any component. The SE also
stated that the change only provided an indication and that there would be
no physical change or QA Category change on any component of the plant.
However, upon review of isometric drawing Cl-3028, " Quench Spray
Discharge Piping Wet Yard Piping," dated January 7,1974, the inspector
determined that the subject piping, back to and including the first isolation
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valve, were classified Q3 (safety-related) and that this classification had nnt
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been changed. Subsequent investigations disclosed that the DLC's Master !
! Equipment List (MEL) had identified this isolation valve as non-safety-related I
l since origination of the MEL in 1988 and that the subject section of pipe had-
l Its classification changed from safety-related to non-safety-related on
l February 1,1988. The inspectors determined the safety evaluation to be
t
narrowly focused and of limited scope.
c. Conclusign
The 10 CFR 50.59 safety evaluations were prepared and reviewed by qualified
personnel using adequate guidance to prompt the preparer to consider the )
appropriate criteria for evaluating changes. In general, safety evaluations for )
facility modifications were of good quality and performed in accordance with the j
requirements of 10 CFR 50.59 and with applicable plant procedures. However, .]
some safety evaluations exhibited some weakness in that they were narrowly i
focused and of limited scope. Also, a violation was identified in the 50.59 safety
evaluation area for an inadequate 50.59 safety evaluation associated with the
storage of propane next to the auxiliary intake structure. The SEs reported in
DLC's annual reports of facility changes, tests, and experiments were appropriately
reflected in the annual UFSAR revisions.
E3.3 10 CFR 50.59 Aoolicability Determinations
i
The inspectors reviewed selected CTEs for which DLC determined that 50.59
safety evaluations were not required to verify that the applica'oility determinations
for these CTEs were made conforming to the 50.59 procedures and controls. The -
inspectors reviewed seventy five CTEs that were described in OSC meeting
minutes, as partially listed in Attachment A. Appropriate 50.59 applicability
determinations were made for CTEs that did not require safety evaluations.
E4 Systera Engineer Knowledge and Performance )
E4.1 Technical Knowledae ;
a. Inspection Scope (37550)
The inspectors interviewed several system engineers to assess their knowledge
and use of certain processes (e.g. design change process, condition report
process). In addition, the inspectors questioned system engineers regarding overall
performance, including known problems, for their respective systems.
- b. Observations and Findinas
Overall, the inspectors found that system engineers were knowledgeable of the I
administrative controls for the design change process. They were also
knowledgeable of the condition report process, which is the system implemented
to identify, track, investigate, correct, and trend deficiencies. The inspectors
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! observed that the system engineers generally displayed a sense of system
ownership and responsibility with regard to addressing component or system
problems. One notable exception, however, was apparent for an issue where
degraded performance of the residual heat removal system had existed and was
not properly addressed for several years (See Section E2.2 of this report). The
l Inspectors reviewed selected condition reports and concluded that the associated
( issues were generally evaluated and corrected appropriately.
'
Based upon the interviews with system engineers and a review of open condition
reports, the inspectors found that the majority of known system or component
problems had been formally identified via condition reports or the maintenance
work request process. Some problems were also the subject of design change
requests (the initiato. of a design change). Any individual can initiate a condition
l- report or a maintenance work request to identify any type of observed or
l suspected problem.
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However, the inspectors found that some system engineers noted a reluctance to
l initiato condition reports, which typically require a response within 30 days, for
l apparent minor issues because the issues would likely become assigned to them.
- The engineers expressed concern with this because such assignments increase
l their immediate workload. Some system engineers referred to this as a
" boomerang" effect, which the inspectors judged translated to a disincentive to
j identify problems. The inspectors found this especially to be the case for concerns
that the system engineers felt to be of low safety significance. The system
engineers felt that there were no instances in which safety significant issues were
not identified via the condition report process.
l
The system engineers typically stated they spend a large percentage of their time
responding to condition reports (between 30% and 50%). The engineers stated
i that this already large condition report workload contributed to their boomerang
!' concern for initiating low significance condition reports. They stated that they )
l could otherwise spend their time more productively by providing more direct i
involvement with their systems. Many of the system engineers have multiple l
(three or four) systems assigned to them. Based on a review of existing condition ,
,
reports and by interviewing the system engineers, the inspectors did not find ,
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examples where system engineers failed to initiate condition reports for safety I
significant deficiencies due to concerns for increasing their immediate workload.
However, the inspectors concluded that system engineers are reluctant to engage
the condition report process represented a weakness. This weakness was
presented to DLC management, who acknowledged that this performance did not
meet their expectations for implementation of the condition reporting process. DLC
management planned to conduct a detailed review of this weakness. '
'
The inspectors identified a similar concern in the area of design change requests.
System engineers stated that they were aware of minor system or component
deficiencies that may require a design change to correct. However, they believe
that some of them would not be approved via the design change review panel
process, and therefore may not initiate a design change request.
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l
One example of the abeve related to certain manually-operated-valves in the Unit 1
fuel pool cooling system. The system engineer noted that in the past, operations
or maintenance personnel had to slightly loosen the valve's body-to-bonnet nuts in
order to operate the vsive handwheel because it was very difficult to operate. The
valves in questior, were six inch ball valves PC-19, PC-21, PC-40, PC-41, and PC-
112. Tao dspectors presented this information to operations management, who
informed me inspectors that although the alleged practice could not be confirmed,
a representative from mechanical maintenance informed him that those valves have
been retorqued on several occasions to assist valve manipulation because of
difficulties in moving the handwheels. The operations representative
acknowledged that his brief review did not consider possible work by the Fix-it-
Now team, which requires less documentation of work activities. He further
acknowledged that DLC needed to look further into this issue, which would include
a deteimination whether the above practice, or the recognized difficulty in
operating the above valves, would constitute an operator work-around (as per
procedure 1/20M-48.3.M) that would require additional attention for corrective
actions.
c. Conclusions
Overall, the system engi x nm ' nowledgeable of the administrative controls
for the design change ar, ;t #%r port processes. The system engineers
generally displayed a --r - ove .. ownership and responsibility with regard to
addressing system p2 '
- J problems. However,in some instances where
the system engineers have u" clied a problem believed to be of minor
significance, they were reluctant to engage the condition report process, because
the condition report resolution would be assigned to them, increasing their
immediate workload. This was considered to be a weakness. Also, in one
instance, a design change request was not submitted because the system engineer
felt the request would not be approved due to its low significance. This resulted in
personnel taking inappropriate actions to compensate for the deficiency (fuel pool
cooling system valves).
E4.2 lmotorsei Imolementation qf I'rocedure Chance Process
a. Insoeq1igL9cooe (37550)
The inspectors reviewed a temporary operating procedure and associated change
related to the Unit 1 residual heat remo al (RHR) and component cooling (CCR)
systems. The inspectors reviewed related documentation and interviewed station
personnel.
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b. Observations and Findinas
I' During a review of issues related to valve leakage of certain RHR system valves
(See Section E2.2), the inspectors reviewed Temporary Operating Procedure 1 TOP-
97-28, Determining the Final Throttled Positions of [1CCR-249 and 250]. The
inspectors determined that a temporary change to this TOP was implem6nted
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incorrectly as a non-intent change and without the necessary 10 CFR 50.59 safety
evaluation.
,
The existing TOP addressed manual valves 1CCR-249 and 1CCR-250 (RHR heat
'
exchangers 1 A and 1B CCR outlet isolation valves, respectively), and provided a
method to adjust the throttled position of these valves infrequently (e.g., once per
outage) for CCR system flow balancing regarding the heat exchangers. Later, in
! response to Condition Report 972281 (RHR system operational difficulties due to
excessive leakage past an RHR throttle valve), the TOP had been supplemented to
include a procedure to also control reactor coolant system (RCS) heatup and
i
cooldown rates by introducing throttling of CCR flow rates to the heat exchangers
via the downstream isolation valves,1CCR-251 and 1CCR-252, located outside
containment.
The inspectors reviewed the change to 1 TOP-97-28 (Operating Manual Change
Notice, OMCN 1-97-884), dated December 17,1997. DLC had processed OMCN i
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1-97-884 as e non-intent procedure change, including Attachment 5, Non-intent
Verification Form, to procedure NPDAP 2.3, Procedure Review and Approval, to
document their basis for determining the change was non-intent. The TOP and the
associated change had been implemented on December 18,1997, without review
by the Onsite Safety Committee (OSC) based on this non-intent determination.
OSC review occurred five days later on December 23, which was acceptable
timing for a non-intent change.
The inspectors determined that the OMCN should have been an intent change,
because it changed the operating configuration for 1CCR-251 and 1CCR-252 such
that these valves could be throttled frequently (e.g., daily) to adjust RCS l
temperature. As such, the OSC should have reviewed the change prior to its
implementation.
In addition, when the OSC reviewed the change, the OSC review was faulty in that i
it did not determine that a 10 CFR 50.59 safety evaluation had not been i
performed. Nuclear Power Division Administrative Manual 8.10, Onsite Safety ;
Committee, requires that all material presented for OSC review shall be
accompanied by a completed Change Presentation Form and a completed safety
evaluation (if applicable). The OSC Change Presentation Form that accompanied i
OMCN 197-884 conciuded that a 10 CFR 50.59 safety evaluation was not
required.
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However, the inspectors determined that a 10 CFR 50.59 safety evaluation was
l
required because the change to 1 TOP-97-28 changed the method by which the
cooldown and heatup rate of the reactor coolant would be regulated. Section 9.3 I
of the Beaver Valley Unit 1 UFSAR states that "the cooldown rate of the reactor
coolant is controlled by regulating the reactor coolant flow through the tube side of
the RHR heat exchangers." Therefore, in addition to regulating reactor coolant
system (RCS) temperature by adjusting the RHR flow rate through the tube side of
the RHR heat exchangers, the procedure change would permit the operators to
regulate RCS temperature by adjusting the CCR cooling flow through the shell side
of the RHR heat exchangers. )
The inspectors concluded that the implementation of the proceduro change as a
non-intent change and the failure to perform a 10 CFR 50.59 safety evaluation
i represent a violation of 10 CFR 50.59. (VIO 50-334/98080-04)
DLC was informed of this deficiency, and in response, completed a revised OSC
Change Presentation Form for OMCN 1-97-884 on Februaiy 9,1998, which
l. concluded that a 10 CFR 50.59 safety evaluation was required. Engineering
l subsequently completed the required safety evaluation on February 9,1998, which
concluded that the procedure change did not represent an unreviewed safety
question. The inspectors found the revised safety evaluation to be acceptable.
l The inspectors identified an additional deficiency in that the two review signatures
l for OMCN 1-97-884 were signed by the same individual, although a separate
qualified reviewer was the OMCN initiator. The inspactors expressed concern
whether appropriate independence was provided to OMCN reviews. In response to
this concern, DLC initiated Condition Report 980240 on February 5,1998. DLC
l promptly completed a self-assessment of a random sample of 751 OMCNs (both
l Units) in an attempt to identify the extent of condition. Three similar concerns
l were identified, which indicated that the deficiency was not programmatic,
! however, additional corrective actions were warranted. The inspectors found
DLC's response to this concern to be prompt and appropriate.
The inspectors determined that 1 TOP-97-28 and the associated OMCN constituted
a work-around that was not identified, documented, or tracked by DLC. In
response, the inspectors reviewed all open TOPS associated with Unit 1 and Unit 2
to determine whether this was a programmatic problem. There were 10 open Unit
1 TOPS and six open Unit 2 TOPS. In addition, the inspectors reviewed a
surveillance procedure (1/2 OST-48.11)that performs a quarterly review of TOPS
and determined that DLC was appropriately conducting the required reviews. The
inspectors concluded that this issue was not indicative of a broad programmatic
j concern.
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c. Conclusions
DLC inappropriately processed a change to a temporary operating procedure by
mis-characterizing the change as a non-intent change and failing to perform a
required 10 CFR 50.59 safety evaluation. Upon identification of this deficiency,
DLC completed an acceptable 10 CFR 50.59 safety evaluation. Also, DLC '
responded promptly and appropriately to an additional NRC concern related to
conducting proper independent reviews of procedure changes.
E5 Engineering Staff Training and Qualifications
E5.1 10 CFR 50.59 Safetv Evaluations Proaram Trainina and Qualifications
a. Insoection Scone (37001)
The inspectors reviewed training material to determine the quality of training and #
evaluate the qualification status of DLC's 50.59 evaluators and reviewers.
b. Observations and Findinas
The inspectors reviewed initial and requalification training materials for 10 CFR'
50.59 evaluators and reviewers. The lesson plans and classroom handouts were
of the appropriate scope and depth. Initial training required individuals to perform a
. 10 CFR 50.59 evaluations as part of their qualification. In addition to classroom
training for requalification, evaluators had to complete an actual 10 CFR 50.59
review during the past year to remain qualified. The inspectors compared the list
of qualified evaluators to training rosters, and no discrepancies were observed.' In
addition, the inspectors noted that DLC had good participation in industry-wide
workshops on this topic.
DLC had good control over the 10 CFR 50.59 training program and content. The
inspectors also reviewed audits of the 10 CFR 50.59 training and concluded that
the audits provided a source of feedback for evaluating and modifying the training
process.
The inspectors also reviewed training regarding safety concepts. Topics included
examples of industry events demonstrating the necessity of broad based reviews
when assessing plant issues, as well as providing an overview of the licensing
process and associated documents which are also involved in the 10 CFR 50.59
evaluation process. The inspectors assessed this training as good.
Nuclear safety concepts training was provided to the NED and SPED staffs in the
, summer of 1997. The training appeared to have enabled a higher quality of safety
evaluations, as the inspectors did not identify any discrepancies with safety
evaluations performed after mid-1997.
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c. Conclusions
I
DLC has a satisfactory program for training employees on the requirements of
j 10 CFR 50.59 and preparing safety evaluations. The contents of the training were
l appropriate and supported the 10 CFR 50.59 evaluation process. The nuclear
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safety concepts training appeared to have enabled a higher quality of safety
evaluations.
E7 Quality Assurance in Engineering Activities
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l E7.1 Quality Assurance (QA) Audit of 10 CFR 50.59 Prooram
!
l a. Inspection Scone (37001)
l
l The inspectors reviewed a quality assurance (QA) audit report of the 10 CFR 50.59
program and corrective actions taken in response to identified deficiencies.
b. Observations and Findinas
l
l A DLC audit in August 1997 determined that implementation of the 10 CFR 50.59
l program was not fully effective. The audit found that non-intent procedure
l changes had not received 10 CFR 50.59 screening. _ in addition, the vast majority
! of OSC Presentation Forms had a bases section that was just a restatement of the
proposed change with little justification provided.
,
Condition Report No. 971546 was generated as a result of this audit and identified
the following deficiencies: non-intent changes to procedures bypass the 10 CFR
,
50.59 screening solely because they are not required to be presented to the OSC;
!
NPDAP 8.10 does not indicate specific requirements for the preparer or reviewer of i
OSC Change Presentation Forms (CPF); and, only a minirnal amount or no )
corresponding bases written supporting the "no" response to the screening i
questions. l
1
Corrective actions were being taken for these identified audit findings by revising l
NPDAP 8.10 to require a CPF for non-intent changes and to require the CPF to be
'
prepared or reviewed by a qualified person. Nonetheless, as documented in
Section E4.2, the inspectors identified problems on a non-intent change in
December 1997, indicating that problems remained uncorrected.
I
c. Conclusions
..
A QA audit had been effective in identifying some deficiencies and DLC initiated ,
l appropriate corrective actions to prevent recurrence of the identified deficiencies, j
i However, the inspectors identified problems demonstrated that some problems i
remained uncorrected.
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E7.2 Onsite Safety Committee l
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l a. Insoection Scope (37001)
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! The inspectors attended the Onsite Safety Committee Meeting (BV-OSC-3-98) held
l on January 21,1998 and reviewed selected documents used at the meeting to
verify that the OSC adequately performed the review and approval requirements of
procedure NPDAP 8.10.
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b. Observations and Finchngs
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l The OCS members demonstrated expertise in their respective areas and asked
l probing questions. The presenters demonstrated a thorough understanding of
I
items discussed. The OSC Chairman demonstrated excellent oversight of the OSC
members and presenters. Of the 46 items presented,39 items were approved,
four items approved with appropriate OSC comments, two items were tabled, and I
one item was disapproved. I
The inspectors reviewed the OSC CPFs and supporting documentation for three i
CTEs requiring 10 CFR 50.59 evaluations and six CTEs for which 10 CFR 50.59
evaluations were not required, as listed in Attachment A.
c. Conclusions
i
The OSC meeting was conducted in conformance with NPDAP 8.10. The CPFs
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were prepared in conformance with NPDAP 8.10 and contained adequate
descriptions for the bases for 10 CFR 50.59 applicability determinations.
E7.3 Offsite Review Committee
l
l a. insoection Scoce (3700,1)
The inspectors attended portions of the Offsite Review Committee (ORC) Meeting
291 held on January 7,1998, reviewed the ORC minutes of Meeting 291 and
reviewed the report for Safety Evaluation Subcommittee (SES) Meeting 98-1 held
on January 5,1998, to verify that the ORC and SES adequately performed the l
l review requirements of procedures QSP 20.1 and QSP 20.6.
b. Observations and Findinas
SES Report 98-1 documented the review of safety evaluations, Onsite Safety
Committee (OSC) meeting minutes and other OSC correspondence associated with ,
OCS meetings BV-OSC-19-97 through 43-97. No unreviewed safety questions l
were identified. The report described the SES discussion of items which required
management attention and items which should continue to receive management
attention.
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c. Conclusions
DLC management responded appropriately to issues identified in SES Report 98-1.
The Offsite Safety Review process provided good oversight of the modification
process and appeared to be effective.
E8 Miscellaneous Engineering issues
E8.1 (Closed) Violation 50-334f412)/95-05-04, pertaining to inadequate existing design
with AMSAC.
As documented in the NRC inspection report 50-334/412;96-05,the NRC
identified a design deficiency in the Anticipated Transient Without Scram (ATWS)
Mitigating System Actuation Circuitry (AMSAC). The concern was that DLC failed
to consider the effect of static pressure in flow transmitters and the effect of
hydraulic fluctuations in the feedwater system when the system was designed.
During this inspection, the inspectors noted that DLC's design team had completed
a review of AMSAC. As a result of this assessment, DLC initiated DCP 2259 to
upgrade the Unit 1 design of AMSAC system. The inspectors noted that DLC had
included several design improvements in the existing design of AMSAC system as
documented in their design review group report issued on July 31,1997. Design I
changes for Unit 1 were implemented during the last refueling outage. Unit 2
AMSAC improvements are planned to be installed per DCP 2260, which was
ongoing and scheduled for the upcoming Unit 2 refueling outage in
September 1998.
Based on review of the Unit 1 documentation, verification of Unit 1 installation, j
and satisfactory results and verification that the Unit 2 DCP was in progress and !
was being properly tracked for implementation in the upcoming refueling outage,
the inspectors concluded this item is closed.
V. Manaaement Meetinas
!
X1 Exit Meeting Summary
Mr. Kaufman presented the preliminary inspection results to Mr. Cross and other members ;
of Duquesne Ligat Company management on January 23,1998. Mr. Kaufman discussed
additional findings with Messrs. Sushil Jain and Dick Brandt at the site at the conclusion of
the inspection on February 12,1998. Duquesne Light Company acknowledged the
findings presented.
l No materials examined during the inspection were considered proprietary. No proprietary
information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
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'J. Cross, President, Generation Group
- S. Jain, Senior Vice President, Nuclear Services
, 'R. Brandt, Vice President, Nuclear Operations / Plant Manager
l *R. LeGrand, Vice President, Nuclear Operations Support
i *M. Pergar, Acting Manager, Quality Services Unit ,
'
'J. Macdonald, Manager, System & Performance Engineering J
'J. Arias, Director, Safety & Licensing
, *W. Kline, Manager, Nuclear Engineering Department
- R. Hruby, Director, Design Basis Engineering
'R. Brosi, Manager, Management Services i
- S. Nass,10 CFR 50.59 Program Manager
NRC
- Paul Kaufman, Team Leader
- Don Brinkman, Sr. Project Manager, Beaver Valley, NRR
' Steve Pindale, Resident inspector, Oyster Creek
- David Silk, Senior Emergency Preparedness Specialist
- Rick Welch, Reactor Engineer l
- Don Haverkamp, Project Engineer
- Ram Bathia, Reactor Engineer
- D. Kern, SRI
- G. Dentel, RI
Indicates presence at preliminary findings exit meeting on 01/23/98. Note: The list
of persons contacted does not include every individual contacted during this
inspection.
INSPECTION PROCEDURES USED
IP 37550: Engineering
IP 37001: 10 CFR 50.59 Safety Evaluation Program 1
IP 92903: Follow-up - Engineering !
ITEMS OPENED AND CLOSED ,
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Opened
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l 50-412/98080-01 eel Failure to establish separation between Class 1E and
non-Class 1E components (Section E2.1) ,
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l 50-334/98080-02 VIO Failure to implement adequate and timely corrective
actions associated degraded RHR valve (Section E2.2)
'50-334(412)/98080-03 VIO Failure to perform an adequate safety analysis related to -
l
the storage of large quantities of propane next to the
! auxiliary intake structure (Section E3.3)
50-334/98080-04 VIO Failure to perform a safety evaluation for temporary
operating procedure 1 TOP-97-28 (Section E4.2)
Closed
50-334(412)/95005-04 NOV inadequate existing design with AMSAC (Section E8.1)
LIST OF ACRONYMS USED
50.59 10 CFR Section 50.59
CTEs Changes, Tests and Experiments
FSAR Final Safety Analysis Report
NPDAP Nuclear Power Division Administrative Procedure
NEAP Nuclear Engineering Administrative Procedure
UFSAR Updated Final Safety Analysis Report
l MPUAM Maintenance Programs Unit Administrative Manual
OEDM Operations Experience Department Manual
OSP Ouality Services Procedure
BVPS Beaver Valley Power Station
USQ Unreviewed Safety Question
NPD Nuclear Power Division
OSC Onsite Safety Committee
TS Technical Specification
l
CPF Change Presentation Form
SER Safety Evaluation Report
ORC Offsite Review Committee
SES Safety Evaluation Subcommittee
NSG Nuclear Services Group
NEl Nuclear Energy Institute
QSU Quality Services Unit
SER Safety Evaluation Report
ORC Offsite Review Committee
SES Safety Evaluation Subcommittee
NGS Nuclear Services Group
NEl Nuclear Energy Institute l
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QSU Quality Services Unit ;
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l CTEs NOT REQUIRING EO.59 EVALUATIONS
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e - QEC Meetina (BV-OSC-45-961 held on November 8.1996
Procedure Enhancements
! - IMSP-44.10-1, SLCRS Vent Particulate and Gas Flow Test F-VS112
- 96-PG2-067, Field Revision to 2 CMP-10RHS-P21 A-B1E
- IMSP-31.06-lF-CW101-1,Outfall Structure Discharge Flow Calibration
l - 10M .44C-4.H, Control Rod Drive Mechanism Shroud Cooling System
Administrative Oversite/ Assessment
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- 2MSP-9.05 2DAS-F1100, Reactor Containment Sump Discharge Flow
i Calibration
- 1/2OST-33.12, Fire Protection System Loop Flow Test
- 1/20M-58E.4.AT, Transferring ERFS 480v Bus Power Source to Alternate
Supply
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e OSC Meetina (BV-OSC-5-971 held on Februarv 5.1997
l Plent improvements
!
- IMSP-43.08,19,22,25,29 and 34, Field Revisions, Radiation Process
l Monitor Calibration
! - lMSP-21.23, Field Revision 97-11-507P-1MS485, Loop 2 Steamline
l Pressure Protection Channel lli Calibration
- OMCN 2-97-046 to 20M 10.4, Residual Heat Removal System Shutdown
Administrative Oversite/ Assessment
- SCP PCL-005, U2 Ull PLC Flowrate Alarm Changes
- . - 2MSP 6.20 (6.21 and 6.22), Field Revision, Delta T-Tavg Temperature
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Loop 2RCS-T412 (422 and 432) Test
- 2MSP-6.38 (6.39 and 6.40), Field Revision, Reactor Coolant Temperature
Loop 2RCS-T412 (422 and 432) Delta T-Tavg
- NPDAP 5.7, Basis for Continued Operation Deturminations
e OSC Meetina (BV-OSC-19-97) held on May 14.1997
. Procedure Enhancements
- 1 CMP-75, Ingersoll Pump 1M FR 97-PG1-037
- 1/2 CMP-75, Relief Valve 1M FR 97-PG3-036 Testing Spring Operated
Safety Relief Valves (Liquid and Pneumatic)
- 20M-25.4.C, Steam Generator Blowdown System Shutdown
- CM1-7.9, Chilled Water System
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CHANGE PRESENTATION FORMS REVIEWED FOR OSC MEETING (BV-OSC-3-98)
,
CTEs Reauirino 50.59 Evaluations
!
- TER 11554, Change 62-SSRAB and 62-SSRBBto Normally Deenergized
Operation
- UFSAR Change Pages 8.3-8A, Delete incorrect Statement in the UFSAR for
4kv Transfer Switches .
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- TER 11612, QA Category Upgrade of Process Rack Circuit Cards
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CTEs Not ReauiringJ0.59 Evaluations
l - 2MSP-13.09-I Field Revision, 2RSS-L151 A, Containment Sump Wide Range I
! Level Calibration
j - 2 CMP-6-RCS-LT459(460,461) Field Revisions, Filling and Venting
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Pressurizer Level and Pressure Sensing Legs
- 1 MSP-60.03.M, Spent Fuel Pool Crane (CR-27) Hoist Test )
- 1 CMP-60-CR-27 Operation-1M, Operation of Unit 1 Spent Fuel Pool Bridge
l Crane, CR-27
i - 2LCP-15-L100A (FR 98-21-004), Component Cooling Water Surge Tank
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(2CCP'TK21 A) Level Loop 2CCP-L100A Calibration
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- 2MSP-43.07-1 (FR 98-21-003),2GWS-DAU104, Waste Gas Storage Tanks
Radiation Monitor Calibration
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10 CFR 50.59 SAFETY EVALUATIONS REVIEWED
TER 10897 Unit 1 Installation of d.e mesh cage assemblies at 1
various plant locations
Temp Mod l Temp Mod Leak Repair Ball Valve tri-80 l 1
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UFSAR l Steam Demp Control System UFSAR Discrepancies1 l l
2 TOP-97-04 Open.tir.g the (2CWS-P21D) Motor Uncoupled for 2
Clearance l Operational Clearance #661414 Justifications
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Clearance Safety Evaluation for Isolation of GSS Charcoal 2
Filter Deluge System (Clearance 153289 and
153290)
DCP 900 Personnel and Emergency Air Lock Typo "B" Leak 2
Test Panels
LRM Table 5.1-1 l Containment Isolation Valve Arrangements 1
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TER 11339 Intake Structure 14.. Compressor (1 A-C-3) Air 1
Compressor Block Replacement
TER 10943, Rev.1 Emergency Diesel Generator Undervoltage Start 1
Relay Setting Change
UFSAR Change Table 9.2-2 Change to Lower Minimum Flow to the 2
Charging ' Pump Oil Cooler
Temp Mod Removal of FIRE DOOR (CV-67-1) during MODES 5 2
and 6 l
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TER 11464 Evaluation of 17x17 Enhanrad Performance 1
RCCAs
MPUAM 4.10 EM 115283 Heavy Load Path for Bergen Patterson 1
Snubbers Handling of NUREG 0612 Heavy Loads
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10 CFR 50.59 SAFETY EVALUATIONS REVIEWED I
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c. 4 . . .. . . ., . , ... . .: - . . . -;;.- . :., + . .
DCP 2078, fiev.1 River Water System Flushing Modification 1
DCP 2100 Reversal of DCP 1756 1 j
DCP 2133 Heating improvements for the Alternate intake 1
Structure
TER 9259 UFSAR Drawing Changes for the Supplementary 1
Leak Collection and Release System
~
TER 9421 Revised UFSAR Figure Specifying Quality 1 i
'
Classification of Quench Spray Chemical Addition
Tank and Fill Line
DCP 2177 Service Water System Pump Seal and Filter Water 2
Pipe Material Upgrade
kER 9352 Addition of Local Bimetallic indicators to UFSAR 2 l
Figure
TER 10457 Drawing Discrepancies Associated with Valves in 2
First Point Heater Level Control Piping
TER 10675 Replace Vent Valve in the Quench Spray - 2
Chemical Addition System
UFSAR Table 6.2-60 Fire Protection Water System Containment 2
1
UFSAR Section Add Reactor Level Instrumentation System to 2 l
l 6.2.4.2 Containment Penetration Table and UFSAR
20M 18.3 Solid Waste Disposal System Valve List 2
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SITE AND DEPARTMENT 50.59 PROCEDURES REVIEWED
Nuclear Power Division Administrative Procedure (NPDAP) 2.3, Procedure Review
and Approval, Revision 8 (7/31/97)
NPDAP 7.2, Design Change Control, Revision 6 (5/22/97)
NPDAP 7.3, Annual Final Safety Analysis Report Update, Revision 3 (1/8/97)
NPDAP 7.4, Temporary Modifications, Revision 6 (7/9/97)
l NPDAP 7.8, Station Modification Control, Revision 3 (5/15/97)
NPDAP 7.13, Technical Evaluation Report, Revision 1 (12/8/97)
NPDAP 8.10, Onsite Safety Committee, Revision 2 (9/1/94)
NPDAP 8.13, Nuclear Safety Review Board, Revision O (2/28/97)
NPDAP 8.18,10 CFR 50.59 Evaluations, Revision 4 (7/21/97)
NPDAP 10.1, Definitions, Revision 11 (7/22/97)
Nuclear Engineering Administrative Procedure (NEAP) 2.2, Design Control, Revision
9 (5/13/97)
NEAP 2.12, UFSAR Reviews, Revision 4 (10/27/97)
NEAP 2.13, Technical Evaluation Reports (5/13/97)
Maintenance Programs Unit Administrative Manual (MPUAM) Section 7.3, Control
and issuance of Maintenance Procedures, Revision 3 (8/28/97)
Operations Experience Department Manual (OEDM-4.1), Operations Procedures
Section General Guidelines, Revision 5 (4/15/97)
Operating Manual (OM) Procedure 1/20M-48.2.B, Control of Operating Procedures,
Issue 4, Revision 12 (12/9/97)
Quality Services Procedure (OSP) 20.1, Offsite Review Committee Charter, Revision
O (10/1/97)
QSP 20.6, Safety Evaluation Subcommittee Charter, Revision O (10/1/97)
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