ML20237A622
| ML20237A622 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/10/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20237A613 | List: |
| References | |
| 50-298-98-04, 50-298-98-4, NUDOCS 9808140215 | |
| Download: ML20237A622 (27) | |
See also: IR 05000298/1998004
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ENCLOSURE 1
- U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
50-298
License No.:
DPR 46
Report No.:
50-298/98-04
Licensee:
Nebraska Public Power District
Facility:
Cooper Nuclear Station
Location:
P.O. Box 98
Brownville, Nebraska
Dates:
May 31 through July 11,1998
Inspectors:
Mary Miller, Senior Resident inspector
Chris Skinner, Resident inspector
Charles Marschall, Senior Project Engineer
Jim Melfi, Project Engineer
Approved By:
Charles Marschall, Acting Chief, Branch C
Division of Reactor Projects
ATTACHMENT:
Supplemental Information
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9808140215 980610
ADOCK 05000298
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EXECUTIVE SUMMARY
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Cooper Nuclear Station
NRC Inspection Report 50-298/98-04
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Ooerations
Plant management continued to demonstrate intrusive involvement in plant activities and
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successfully demanded resolution of safety issues as well as increased site performance
on high profile issues both within and outside of the plant organization (Section 01.1).
Operators demonstrated generally strong standards, responded promptly to challenges,
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and successfully demanded engineering support for these challenges (Section 01.2).
Inspectors identified an operability determination which had not documented the basis for
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its conclusion, although its conclusion was accurate (Section 02.1).
inspectors determined that corrective action for enforcement of past inadequate
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corrective action was not formal and that the licensee performed narrow evaluations of
very recent past corrective actions. These selections of past corrective actions were not
based on programmatic or systematic criteria. In response, the licensee initiated a
sampling process which included a broader scope of past corrective action issues and
involved systematic evaluation of the findings of those assessments (Section 07.1).
Operators routinely initiated a large number of insightful and self-critical problem
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identification reports both within and outside of the operations area, demonstrating a
strong focus on safety (Section O7.2).
Cooper Operations and Maintenance organizations had only recently (January 1998)
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begun to develop a process for systematic self-assessment. The operations and
maintenance departments had not yet demonstrated the ability to improve performance
using results of their self-assessments. The Radiation Protection department had
performed good annual self-assessments for several years (Section 07.3).
inspectors identified that the licensee closed commitment action items without obtaining
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the associated performance improvements. As a result, the commitment tracking system
did not effectively monitor corrective actions for identified deficiencies, and inspectors
could not determine whether the licensee had completed actions to address the
deficiencies identified in NRC Inspection Reports 50-298/97-07 and -97-12
(Section 07.4).
Maintenance
Maintenance during this inspection period was generally good. Supervisors were at the
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work sites, and technicians used appropriate radiological practices. Maintenance
rnanagers imposed a stand down after two instances of improper work practices
(Section M1.1).
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Despite troubleshooting performed at intervals over a month, maintenance failed to
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identify the cause of unexplained reductions in oil level for an essential service water
booster pump. Engineering identified the cause and demonstrated strong ownership and
good safety focus by deciding to immediately replace the pump (Section M1.2).
Some examples of poor rnaterial condition existed, including leakage through the
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residual heat removal heat exchanger outlet valves, resulting in silt buildup in essential
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service water piping and erosion of nonessential service water piping, resulting in
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through-wall leakage (Section M2.1).
Licensed operators assigned to the work control staff demonstrated strong safety focus
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control of plant configuration and communications with both control roorr md
maintenance work crews. Plant configuration was continually monitored by the work
control staff, resulting in improved work flow, scheduling, and safety (Section M4.1).
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Maintenance demonstrated an appropriately low threshold of identification of problems
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regarding equipment failures, lack of procedural acceptance criteria, and other quality
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administrative concerns in problem identification reports. This safety conscience regard
for identification of problems appeared to be an improvement over past performance in
this area (Section M7.1).
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Enaineerina
Significant sitt buildup was observed in residual heat removal service water booster
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pumps' suction and discharge lines. Inspections and evaluations determined that weekly
runs of the pumps would properly clear silt from the lines. This issue will be followed with
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the corrective actions associated with the violation regarding the residual heat removal
heat exchanger tube plugging (Section E2.1).
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The replacement component evaluation and procedures associated with an equivalent
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component replacement of safety-related relays did not insure adequate testing. The
equipment used to test the old design relays caused false failure indications when testing
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the replacement relays (Section E3.1).
Plant Succort
The inspectors identified that procedural guidance for controlling access and egress for
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satellite areas outside the radiological controlled area was weak. The radiological
protection personnel had already recognized this procedural deficiency independently
and had a partially completed revision when the inspector identified the concern
(Section R3.1).
No as-low-as-reasonable-achievable (ALARA) staff were observed to be present, nor
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was a systematic ALARA focus demonstrated for plant activities which were considered
one time. interim, or temporary processes in lower level radiation areas up to about
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35 millirem per hour. The inspector pointed out examples of these types of activities
without ALARA reviews which had been sustained for months or years and still
considered temporary.
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Report Details
Summary of Plant Status
The plant operated at 100 percent power at the beginning of this report period. A scheduled
power reduction to 70 percent power for turbine testing occurred June 12,1998.
1. Operatisns
01
Conduct of Operations
O1.1
Plant Manaaement involvement in Plant Activities
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a.
Insoection Scoce (71707)
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Inspectors observed plant management involvement in plant activities and multiple
formal and informal meetings during the inspection period,
b.
Observations and Findinas
Management raised issues and set expectations for ownership and accountability for
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improved site performance. For example, during plan-of-the-day meetings, plant
management successfully demanded the following: more effective planning for power
reductions, reduced numbers of individuals with overdue training, proactive maintenance
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on intake structure screens (to preclude accumulation of debris during seasonal
flooding), and stronger performance of condition review group members and station
operations review committee members. Also, plant management successfully obtained
timely resolution of several design issues affecting plant procedures, including resolution
of concerns regarding the bases for some operator action points in the emergency
operating procedures, inspectors noted that, for those issues described in this report as
findings and concems, strong management involvement had typically not been
observed.
Plant management tracked completion of corrective actions and commitments within
scheduled due dates. Tracking and articulation of plant management expectations
throug'h this inspection period resulted in a significant reduction of overdue items in every
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site department. For example,6 months ago several departments had 30 or more
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overdue items. During this inspection period, the highest number of overdue items was
nine. Several departments had no overdue items. However, findings indicated that
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some items had been closed out when almost completed on or just before the due dates.
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Issues associated with these standards for closure of open items are discussed in
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Section 07.4 of this report.
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Plant management successfully demanded resolution of Updated Safety Analysis Report
discrepancies and poorly defined bases for operability. Standards for control room
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coordination with dispatchers regarding off-site power conditions and vulnerabilities were
improved regarding potential faults and vulnerabilities on off-site power lines, such as
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degraded electrical poles. Shift crews have successfully intervened with dispatchers
regarding scheduling of off-site power grid maintenance. Plant management
demonstrated intrusive involvement in Check Valves RCIC-42, -40, and -12 issues
described in Section M2.1 of this report, particularly in the scheduling of reactor core
isolation coolant system surveillance prior to resolution of the check valve issue.
Management intervention resulted in more effective resolution of valve operability,
reducing the time an essential system was inoperable.
c.
Conclusiomi
Plant management continued to demonstrate a strong safety focus and intrusive
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involvement in plant activities. Plant management successfully demanded resolution of
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high profile issues as well as increased site performance on issues both within and
outside of the plant organization.
01.2 Control Room Staff Activities and Resoonse to Plant issues and Events
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Insoection Scoce (71707)
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inspectors observed multiple control room activities, including routine maintenance and
surveillance control, problem identification and resolution, and implementation of
abnormal and emergency procedures.
b.
Observations and Findinas
Control room crews demonstrated generally strong, proactive response to plant
conditions and activities. The control room supervisor or shift supervisor maintained
awareness and positive control of activities performed. Crew standards were generally
strong, with exceptions noted elsewhere in this report. The shift technical engineer
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typically provided strong intrusive evaluation of problems. The crew appropriately
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entered emergency procedures upon recognition of entry conditions. On July 6, before a
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weather front traveled across the area, the centrol room staff had discussed expected
conditions with the National Weather Service. When the reactor building vacuum
momentarily indicated a positive pressure of 0.03 inches of water, the operators
immediately entered Emergency Operating Procedure S.A," Containment Control"
Similarly, operators entered tornado alert procedures upon the declaration of tomado
watch conditions by the National Weather Service. Loss of offsite power procedures
were briefed to the crew under these conditions.
On June 14,1998, a station operator identified a leak in service water system discharge
from the nonessential turbine equipmerit cooling heat exchanger. Plant staff found a
through-wall leak and wall thickness degraded to as low as 0.16 inch for approximately a
6-inch diameter elliptical area inside an elbow. There was no isolation valve between the
leak and the river. A pipe patch was applied to stop leakage.
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Operators, with assistance from engineering, developed contingencies for loss of pipe
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integrity. The contingencies addressed flooding of the turbine building basement and
expected equipment losses under those conditions, such as feed pumps, condensate
booster pumps, some fire protection equipment, and other nonessential gear. Each crew
reviewed, updated, and added further detail to the contingency plans during their watch.
Inspectors observed as many as three engineers continuously assisting operators in the
control room in development of the contingency plans, such as identification of affected
circuitry, affected procedure steps, and equipment requirements under a flooding
condition.
The inspector and licensee were unable to locate a flood analysis that described the
expected effects of a turbine building flood. Engineers planned to determine if an
analysis was required to demonstrate that a turbine building flooding event was
appropriately analyzed. The inspectors walked down the accessible barriers between
the reactor building and the turbine building and did not identify apparent leakage paths
or po'ential circuit interaction. Since secondary containment forms the barrier for vital
equipment in the reactor building, and no leakage paths were apparent, the lack of an
analysis for turbine building flooding will be followed by an inspector followup item (50-
298/98004-01).
c.
Conclusions
Operators demonstrated generally strong standards, responded promptly to challenges,
and successfully demanded engineering support for these challenges.
O2
Operational Status of Facilities and Equipment
O2.1
Lack of Documentation for Operability Determination
a.
Insoection Scoce f71707)
The inspectors reviewed and followed the resolution of a problem identification report
that documented that test equipment failures nonconservatively affected relay settings.
Discussions were held with operations, maintenance, and engineering personnel.
b.
Observations and Findinos
inspectors identified an issue associated with replacement relays during routine review of
plant problem reports. Problem identification Report 2-28983 described several relays
that had failed testing. The problem identification report identified that the relays were
installed in multiple emergency core cooling systems. The operability determination
concluded that the relays were operable but did not describe the basis for the operability
conclusions.
Further inquiry found that existing relays had been replaced by a different model. The
new model had been evaluated as appropriate for service in a replacement component
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evaluation performed by engineering. The replacement component evaluation had
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evaluated the characteristics associated with the safety function of the relay, but had not
evaluated the test equipment used to test the relays. Electricians generated the problem
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identification report, when several replacement relays failed testing. The control room
had concluded that the relays remained operable based on knowledge of the acceptable
replacement component eva!uation; however, the inspectors noted that operators did not
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include or reference the component evaluation as the basis for operability. The lack of
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documentation of a basis for the operability conclusion was a weakness, although the
conclusion that the relayc were operable appeared valid. The cause of the test failures
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will be discussed in Section E3.1 of this report.
c.
Conclusions
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Inspectors ideritified an operability determination that had not documented the basis for
its conclusion, although its conclusion was accurate.
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Quality Assu.ance in Operations
07.1
Site-Wide Corrective Action Prooram Activities
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a.
Lrisoection Scoce (71707)
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Inspectors observed corrective action program activities, including review of closed
problem identification reports and performance assessment group activities to appraise
the adequacy of corrective actions.
b.
Conclusions
inspectors determined that corrective action for enforcement on past inadequate
corrective action was not formal and that the licensee performed narrow evaluations of
very recent past corrective actions. These selections of past corrective actions were not
based on programmatic or systematic criteria. In response, the licensee initiated a
sampling process which included a broader scope of past corrective action issues and
involved systematic evaluation of the findings of those assessrnents.
07.2 Ooerations Problem identification and Corrective Action
a.
Insoection Scoce (71707)
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Inspectors reviewed problem identification reports init ated by the operations staff as well
as corrective actions for problems in the operations area.
b.
Observations and Findincs
During routine review of problem identification reports, inspectors noted that operations
problem identification reports continued to be insightful and self-critical. For example,
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operators questioned the length of time required for maintenance to provide an
evaluation of the operationalimpact of repeated service water booster pump oillevel
problems. This example demonstrated a questioning attitude and operator insistence on
engineering support. Control room operators and station operators also documented
more thm a dozen additional degraded conditions in problem identification reports during
a 3-day period.
Operators also demonstrated aggressive corrective action in initiating stop-work for
inadequate industrial safety work practices. Operator response to a nonessential service
water piping leak is an example. The response to the througn-wall leak is described in
more detail in Section 01.2 of this report.
c.
Conclusions
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Operators routinely initiated a large number of insightful and self-critical problem
identification reports both within and outside of the operations area, demonstrating a
strong focus on safety.
07.3 Self-Assessment
a.
Insoection Scoce (40500)
Inspectors evaluated the effectiveness of the licensee's self-assessment capability in the
operations, maintenance, and radiation protection areas by reviewing self-assessment
reports, audits (including audits of both onsite and offsite safety committee activities),
and evaluations. Engineering self-assessment was not within the scope of the
inspection.
b.
Observations and Findinas
The licensee's self-assessment program was in the early stages of development and
implementation. Departments had begun a monthly self-assessment program in January
1998. Only the radiation protection department had been performing annual self-
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assessments. Administrative Procedure 0-CNS-25, "Self-assessment," Revision 0,
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established the requirement for departments to assess their performance.
The operations department began to produce monthly reports in January. The monthly
reports contain good broad based performance information, including problem
identification reports, observations from outside organizations, and quality assurance
audit findings. Inspectors noted that, although the reports included observations by shift
mentors, the reports relied heavily on observations frun other organizations, such as
NRC inspection reports. These contributions do not constitute self-assessment, and the
operations staff has performed little assessment based on direct observation. rhe
reports do, however, include some analysis of problem identification repcrte. Tr'e reports
for January, February, and March 1998 presented a collection of information similar to
performance indicators, but did not furnish an evaluation of the data. Operations staff
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also produced a quarterly report on June 18,1998, for the first quarter of calendar year
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1998. The report compiled the results of the monthly reports for January through March
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1998 and documents performance strengths and five areas for improvement.
Additionally, a section of the report documented planned actions to address the areas for
improvement. Although the report identified actions to address many of the areas
needing improvement, in some cases areas for improvement remained unaddressed.
For example, the report documented planned action to address low numbers of
management observations, but oid not address operations emergency preparedness
training deficiencies. The assessment report aim documents plant status and
configuration control as the " biggest problem area for Operations." The report included
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actions to improve performance, but did not describe the problem. As a result, the
reader cannot determine whether the operations staff has addressed the problem
appropriately. The report also provided very little tre 'd information, possibly due to the
very small number of monthly reports. Since the due dates for the planned actions for
improvement were after the end of the inspection period, the inspectors could not assess
the overall effectiveness of the operations self-assessment.
The maintenance department had not yet begun to produce monthly reports.
Department personnel had, however, performed an assessment of their performance
based on information existing iri NRC inspection reports, quality assurance audits and
assessments, performance assessment by independent reviewers, and observations of
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managers and supervisors based on historical observations. Based on this information,
the maintenance staff developed the Maintenance improvement Plan, which identified
valid areas for improvement. The maintenance staff intended to use the plan to perform
focused performance assessments in the identified areas that require improved
performance. The inspectors found that the initial performance assessment had
identified valid areas requiring performance improvement and considered this approach
sound. The inspectors could not assess the effectiveness of raaintenance self-
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assessment, since no basis existed for determining whether implementation of the
program will result in performance improveinents.
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jnspectors found that the radiation protection department had an existing program of
annual self-assessment that had been ongoing since 1995. As documented in NRC
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inspection Report 50-298/98-18 the existing process was a good example of a critical
review that demonstrated good management oversight. The assessment made good
use of industry peers to identify problems and potential areas of improvement. As
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required by Administrative Procedure 0-CNS-25, the radiation protection staff has also
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initiated development of a monthly self-assessment report. At the time of the inspection,
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however, no reports had been completed.
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Inspectors also noted that the Safety Review and Audit Board (SRAB) has performed a
meaningful self-assessment and made changes to improve SRAB effectiveness. In
addition, inspectors considered the practice of individual SRAB member involvement in
quality assurance and engineering activities a positive indication of their involvement in
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improving plant performance. Inspectors found that quality assurance audits were
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appropriately scoped and that the reports contained meaningful findings. Inspectors
noted some repetitive quality assurance findings, an indication that some portions of the
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line organization did not implement corrective actions based on the findings.
c.
Conclusions
Cooper operations and maintenance organizations had only recently (January 1998)
begun to develop a process for systematic self-assessment. The operations and
maintenance Apartments had not yet demonstrated the ability to improve performance
using results of their self-assessments. The radiation protection department had
performed good annual self-assessments for several years.
07.4 Licensee Resoonse to inadeouate Corrective Action
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Insoection Scoce (40500)
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inspectors reviewed licensee action to address the inadequate corrective actions
identified in NRC Inspection Reports 50-298/97-07 and 97-12 (EA 97-424).
b.
Observations and Findinos
inspectors noted that plant staff had performed substantial effort to address the identified
concerns, however, the inspectors could not determine that plant staff had completed
sufficient action to permit closing this item. In addition, the inspectors identified some
problems with the monitoring of corrective actions.
The licensee tracks action items, including commitments to the NRC in the nuclear
power group action item tracking system (NAITS). In reviewing the NAITS and the
associated documentation, the inspectors found that the licensee had closed some
NAITS items by reference to the corrective action program and the strategy for achieving
engineering excellence, without a corresponding cross-reference to the closed NAITS
item. Items, in some cases representing licensee commitments to the NRC in response
to the violation (EA 97-424), were not tracked further despite lack of completion of the
committed actions. For example, the licensee committed to implement Nuclear Safety
Advisory Group (NSAG) to provide additional oversight of engineering activities. The
licensee closed the NAITS item tracking this commitment, based on development of
administrative requirements for the NSAG, yet the three-member NSAG was not fully
staffed. The licensee also closed the NAITS item associated with engineering support
personnel training, although four people had not completed the training. In addition,
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plant staff closed a NAITS item to improve work standards associated with preventive
maintenance activity based on a project underway to upgrade the program despite not
completing the upgrades for all systems.
Inspectors also fcund NAITS items closed with no indication that performance had
changed. For example, one item required development of initial testing parameters and
determination of as-found leakage rates at the end of each operating cycle for torus to
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drywell vacuum breakers. The closure package contained no evidence of initial testing
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parameters or data or procedures associated with as-found leak rates. Another item
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required that operations management reinforce high standards for operator performance,
including procedure use and adherence. The closure package contained no evidence of
improved procedure use and adherence or other indications of improved performance.
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An additional NAITS item required that supervisors re-emphasize standards for conduct
and adequacy of prejob briefs. Inspectors noted that, although plant staff had revised
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Operations Instruction 8, dealing with prejob briefs, no evidence existed to support a
conclusion that prejob briefs improved.
The inspectors also reviewed licensee action in response to the residual heat removal
heat exchanger fouling documented in the previously mentioned NRC inspection reports.
In Nebraska Public Power District letter from G. R. Horn, Senior Vice President, Energy
Supply, to the Director, Office of Enforcement, NRC, dated December 31,1997, the
licensee committed to develop a formal Generic Letter 89-13 (Service Water System
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Problems Affecting Safety-related Equipment) program document with defined
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ownership, roles and responsibilities, and program criteria. Engineering Procedure 3.34,
Heat Exchanger Program, Revision 0, Section 1, states that the procedure defines the
ownership, roles, organization responsibilities, and program criteria for implementing the
Cooper Nuclear Station heat exchanger program. Section 4.4, implementing Action 111,
states, " Ensure by establish:.ng a routine inspection and maintenance program for open-
cycle service water system piping and components that corrosion, erosion, protective
coating failure, silting, and biofouling cannot degrade the performance of the safety-
related systems supplied by service water." Surveillance Procedure 6.SW.102, Service
Water System Post-LOCA Flow Verification, Revision 4, stated that it "can be used to
monitor silt accumulations to detect degraded system performance." The licensee could
not furnish evidence, however, that plant staff had used the procedure for that purpose.
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As of the end of the inspection, the licensee had riot furnished evidence that a program
existed to inspect for silting in service water system components. Ine NAITS item
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remained open, however, it contained a January 27,1998, entry that stated,
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" Engineering Procedure 3.34, ' Heat Exchanger Program,' has been approved and meets
the intent of the commitment." The inspectors concluded that the licensee had not yet
completed the action necessary to effectively monitor degradation of service water
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system components, despite the entry in the NAITS.
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c.
Conclusiqos
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Inspectors identified that the licensee chmd commitment action items without obtaining
the associated performance improvemeou. As a result, the commitment tracking system
did not effectively monitor corrective actions for identified deficiencies, and inspectors
could not determine whether the licensee had completed actions to address the
deficiencies identified in NRC Inspection Reports 50-298/97-07 and -97-12.
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08
Miscellaneous Operations issues
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08.1
(Closed) Violation 50-298/97011-01: Technical Specification violation for sample line
isolation. The licensee was in two limiting condition for operations that had the same
action for reactor sample valves. One of the limiting conditions of operation allowed the
isolation valves to be opened under administrative controls, and the other one did not.
The valves were opened under administrative control. The inspector identified that the
other limiting condition of operation was violated.
The licensee's reply to the Notice of Violation, dated April 8,1998, corrective action
taken was narrowly focused on the specific problem and the licensee did not indicate any
corrective steps to avoid further violations. The inspectors reviewed Condition Report
97-1541 to identify additional corrective actions. The condition report documented
several actions which would prevent the problem from recurring. For example, both the
scheduling and work control process were modified to contain a review of inoperable
Technical Specification equipment with respect to the weekly and daily schedule. The
inspectors considered the corrective actions acceptable.
08.2 (Ocen) Violation 50-298/97012-01 (EA 97-424): Inadequate corrective actions. The
NRC took escalated enforcement for several examples of inadequate corrective actions
in multiple areas. Review of the licensee's process to correct this condition found, for
assessment of the extent of condition, the actions were narrow and, in samples of past
concerns, small. Results were not evaluated in a systematic fashion. In response to the
concerns raised by the inspector, the licensee broadened this assessment. This issue is
described in Sections 07.1 and 07.4 of tnis report.
08.3 (Closed) Licensee Event Reoort 50-298/97-017: Inadequate original design did not meet
primary containment isolation requirements. On July 24,1996, the licensee discovered
that the motors and operators for the residual heat removal system heat exchanger vent
valves (RHR-MOV-M0166A, -B and RHR-MOV-M0167A, -B) did not meet the applicable
primary containment isolation requirements. The licensee determined that the inboard
isolation valves were powered from the same electric source and there was not an
automatic closure signal to the valves from the primary containment isolation function.
The valves were designed to vent noncondensable gases from the residual heat
exchanger during the steam condensing mode of operation.
The licensee identified that the apparent cause was an inadequate original design which
failed to consider the primary containment isolation requirements and electrical
separation requirements associated with these valves. As corrective actions the steam
condensing mode of operation was deleted from all procedures and the valves were
closed and de-energized.
The failure to meet primary containment isolation requirements for the residual heat
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removal system heat exchanger vent valves is a violation of 10 CFR Part 50,
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Appendix B,
Criterion III.
This nonrep3titiva, licanssa
idsntificd and corrected violation is bsing trsated as c
-noncited violation, consistant with Saction VII.B.1 of ths
NRC Enforcement Policy (50-298/98004-02).
?
(
II. Maintenance
'
M1
Conduct of Maintenance
M1.1 General Comments
a. Insnection Scone (62707 and 61726)
The following maintenance activities were observed:
Maintenance Work Request 97-1385
Replacement of Service
Water Booster Pump A
L
Maintenance Work Request 98-1665
Inspection of Service
l-
Water Booster Pump C for
Silting
l
Maintenance Work Request 98-1697
Inspection of Service
Water Booster Pump B for
Silting
Maintenance Work Request 98-1698
Inspection of Service
Water Booster Pump D for
Silting
' Maintenance Work Request 98-1919
Troubleshooting Service
Water Booster Pump A
low
outboard 011 bearing
Level
'
Maintenance Work Request 98-1967
Troubleshooting and
Correction of Service
Water Booster Pump A
]
Surveillance Procedure 6.PC.302
Suppression Chamber Water
Level Calibration Test
and Functional Test
Instrument and Controls Procedure 14.4.4
Instrument
Sensing Line
Backflush/Backf
ill
Maintenance Procedure 7.2.14
Service Water Booster
Pump Overhaul and
l
Replacement
L
b.
Observations and Findinas
Maintenance personnel conducted good prejob briefings and
implemented management expectations for performing
maintenance.
Inspectors observed engineering presence
during many of the activities and saw strong maintenance
adherence to procedure and good practices for control of
y
work packages.
Maintenance personnel stopped work
'
immediately
_ _
_ _ _ _ _ - _ _ _ _ _ _ _
- - . _ _ _ - _ _ _ _ _
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. _ _ _ _ _ _ .
__
_ _ _ _ _
_ _ _ _ _ _ .
.
.
-11-
immediately and informed supervision when they encountered unexpected conditicns.
Maintenance supervisors and managers were often at job sites, and workers observed
appropriate radiological practices.
On June 10, the maintenance department conducted a stand down to address
performance concerns identified by maintenance managers. The concerns involved two
improper work practices; in one case workers did not have the maintenance instruction in
active use during the work. In the other, a mechanic changed a valve position within a
clearance boundary without informing operators or work control. Neither activity resulted
in a direct effect on plant safety. Maintenance craft were reminded of management
expectations in these areas.
c.
Conclusions
Maintenance during this inspection period was generally good. Supervisors were at the
work sites, and technicians used appropriate radiological practices. Maintenance
managers imposed a stand down after two instances of improper work practices.
M 1.2 Troubleshooting and Correction of Service Water Booster Pumo A Oil Level Droo
a.
J.cspection Scone (62707)
Inspectors observed licensee's activities associated with troubleshooting and
replacement of Service Water Booster Pump A after repeated oillevel decreases,
b.
Observations and Findinos
)
On June 1,1998, the licensee replaced Service Water Booster Pump A as part of
scheduled maintenance. Seven days later operations initiated a problem identification
report documenting that the thrust bearing oil level had dropped to the low level at a rapid
rate. Maintenance staff made several unsuccessful attempts to correct the problem. On
June 30, the licensee disassembled the pump and found that the shaft was undersized
as a result of an overhaul about a year earlier at a qualified pump overhaul facility.
Engineering determined that further troubleshooting and testing might not resolve the
degraded condition, and plant staff replaced the pump.
Engineering actively supported the troubleshooting on June 28-30, and took an active
role in determining whether to replace the pump. Maintenance sent the pump to the
vendor for a complete evaluation and initiated a quality assurance assessment of the
vendor's pump rebuilding program. Engineering determined that the oillevel reduction
resulted from an improperly high oil operating band. This was not identified during
I
receipt inspection. Engineering determined that the high oillevel resulted in formation of
an oil mist that flowed out of the bearing housing and deposited on the pump housing
i
and local area. This occurred until the level was reduced to the lower third of the bearing
race, where misting was significantly reduced and the oillevel stabilized. The pump
l
t
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_ _ _ , _ _ _ _ _ - _ _ _ _ _ _
_ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _
.
.
-12-
)
l
shaft was also undersized, but engineering determined it had no effect on safety. The
.
undersized pump shaft and the improperly marked oil operating band were the basis for
I
engineering requiring pump replacement.
During these activities, maintenance identified that some technicians had demonstrated
poor workmanship, and critical parameters may not have been checked properly during
receipt and acceptance testing. These technicians were also involved in the stand down
described in the previous section of this report. As an interim corrective measure, these
maintenance technicians were subsequently decertified for supervisory and quality
control activities and sent to retraining after counseling with management.
When maintenance managers recognized that the incorrect overhaul of the pump had
not been properly diagnosed, they initiated a problem identification report. Inspectors will
track the possibly generic issue of installation of an undersized shaft during overhaul,
and the resolution of performance by the maintenance staff using inspector followup item
(50-298/98004-03),
c.
Conclusions
Despite troubleshooting performed at intervals over a month, maintenance failed to
identify the cause of unexplained reductions in oil level for an essential service water
booster pump. Engineering identified the cause and demonstrated strong ownership and
]
good safety focus by deciding to immediately replace the pump.
j
M2
Maintenance and Material Condition of Facilities and Equipment
4
M2.1 Examoles of Plant Material Condition
a.
Scone (62703.71707.61726)
Inspectors observed several indications of plant material condition, summarized in this
section.
b.
Observations and Findinos
Inspectors observed the following indications of material condition of the plant.
I
Significant silt accumulation was found in the suction and discharge lines of service
water booster pumps and in the residual heat removal heat exchanger head
(Section E2.1).
Residual Heat Removal System Heat Exchanger Outlet Valves SW-MO-89A and -B leak
past the seats, allowing significant transport of silt into the essential service water
system.
'
.
I
lL_.-------
,
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_ _ _ __
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
!
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,
,
-13-
Service Water Booster Pump A was found to have been improperly rebuilt by a Part 21
vendor (Section M1.3).
Through-wall leakage occurred on an eloow in the nonessential service water portion of
the turbine equipment cooling system. This was determined to have been caused by
f
erosion of piping by service water sitt (Section E2.2).
l
c.
Conclusion
Some examples of poor material condition existed, including leakage through the
l
residual heat removal heat exchanger outlet valves, resulting in silt buildup in essential
service water piping and erosion of nonessential service water piping, resulting in
]
M4
Maintenance Staff Knowledge and Performance
,
M4.1 Ooerator Involvement in the Work Control Process
a.
Insoection Scoce (71707)
Inspectors observed operator and work control staff implementation, completion, and
processing of several work orders.
b.
Observations and Findinas
in general, operators in control of work demonstrated very effective interaction with
maintenance and operating crews to insure proper control of plant conditions, resulting in
a significant improvement in safety and coordination of work flow. Communications were
detailed, accurate, timely, and properly conveyed the priorities associated with each
scheduled activity. Licensed operators performed many of the tasks associated with
planning and implementation of the work control process. Clearances were determined
and discussed with technicians and control room crew members, work packages and
postmaintenance testing were reviewed, work schedules were coordinated with the
control room, limited condition for operation entry conditions associated with work
packages were properly recognized and recommended, and clearances and plant
configuration were controlled and maintained with close, effective coordination with the
I
control room. Problem identification reports were reviewed by licensed operators in the
work control center, resulting in several examples of safety focused evaluation of
concerns.
c.
Conclusions
Licensed operators assigned to the work control staff demonstrated strong safety focus,
good control of plant configuration, and effective communications with corurol room and
i
l
maintenance crews. The work control staff continually monitored plant configuration,
resulting in improved safety, work flow, and scheduling.
_ _ _ _ _ _ _ _ _ _ _ _
_ _ - - - _ _ - _ _ _ _ _ _ _ _ _ _ _
_ _ _ - _ _ _ _ _ _ _ _ _ _ _ _
_
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._
.
.
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M7
Quality Assurance in Maintenance Activities
M7.1 Problem identification in Maintenance
a.
Insoection Scoce (62707)
Inspectors reviewed problem identification reports initiated during the inspection period
and observed maintenance performance in the area of problem recognition and
documentation.
b.
Observations and Findinas
During this inspection period, over 30 problem identification reports initiated by
maintenance personnel demonstrated an appropriately low threshold for equipment
problem and problems in the area of administrative and programmatic issues. One
example was failures of relays in test devices discussed in Section E3.1. Other reports
clearly described equipment that had not responded as expected, procedures or work
instructions that did not adequately address the job requirements, or administrative
requirements had not been met. Interviews with maintenance technicians indicated a
higher standard for proper maintenance and an improved understanding of the process
and purpose of problem identification reports.
c.
Conclusions
Maintenance demonstrated an appropriately low threshold of identification of problems
regarding equipment failures, lack of procedural acceptance criteria, and other quality
administrative concerns in problem identification reports. Inspectors considered this
safety conscience regard for identification of problems an improvement over past
performance.
M8
Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Licensee Event Reoort 50-298/98-007: Missed surveillance testing of main
turbine stop valve closure. Technical Specification Table 4.1.1 requires that the main
turbine stop valve closure scram function be tested once per month. During shutdowns,
the surveillance cannot be performed. With the valves inoperable, Technical
Specification Table 3.1.1, Note 1.b, requires that operators reduce power below
30 percent. Testing of the main turbine stop valve prior to exceeding 30 percent power
was not performed during startups from the December 1995 refueling outage and the
May 1997 refueling outage.
This item was identified during completion of corrective actions for Licensee Event
Report 50-298/98-004 and Violation 50-298/98002-03. The licensee's corrective action
will be reviewed during the closure of Violation 50-298/98002-03.
_ _ _ _ _ _
_ _ _ _ _
_ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _
____
.
.
-15
The failure to test the main turbine stop valves prior to exceeding 30 percent power is a
violation of Technical Specification 4.1.1. This nonrepetitive, licensee identified and
corrected violation is being treated as a noncited violation, consistent with Section Vll.B.1
of the NRC Enforcement Policy (50-298/98004 04).
M8.2 (Closed) Licensee Event Reoort 50-298/97-016: Diesel generator test did not meet
minimum Technical Specification time requirements. Technical Specification
Surveillance Requirement 4.5.F.1 required the redundant operable diesel generator be
. demonstrated operable by a run time greater than or equal to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following the
declaration that the other diesel generator was inoperable. On December 10,1996, the
operable diesel generator was run fcr only 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />,9 minutes.
The licensee event report stated that the cause of the Technical Specification violation
was due to a past interpretation regarding the applicability of the surveillance procedures
(6.1DG.102 and 6.2DG.102, " Diesel Generator Demonstration of Operability Test"). As
corrective actions the procedures were placed on administrative hold until revised to
specifically state the purpose of the procedures. The inspectors considered the
ambiguous understanding of the purpose of the procedure to have been a contributing
factor, but concluded that the root cause was poor operator standards for clear
understanding and precise implementation of the Technical Specification requirements.
The licensee did not address inadequate operator understanding and implementation of
Technical Specifications in the licensee event report. Since the root cause of this
problem is similar to that of Violation 50-298/98002-03, documenting that Technical
Specification amendments were not rigorously implemented, the corrective actions will
be reviewed during the closure of that violation.
The failure to run the operable diesel generator for greater than or equal to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is a
violation of Technical Specification 4.5.F.1 which required that the operable diesel
l
generator be demonstrated operable by running it for greater than or equal to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
This nonrepetitive, licensee identified and corrected violation is being treated as a
noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-
298/98004-05).
111. Enaineerina
E2
Engineering Support of Facilities and Equipment
E2.1
Identification of Sil' Builduo in Residual Heat Removal Service Water Booster Pumos
a.
Insoection Scoce (93702. 37551)
Inspectors responded to the finding of significant silt buildup in service water booster
pump piping. Inspectors observed the conditions which the licensee encountered,
observed boroscope inspections, reviewed evaluations and sitt inspection findings, and
held discussions with maintenance technicians, engineers, and managers.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . -
_
i
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.
-16-
b.
Observations and Findings
l
On May 26,1998, during maintenance on Service Water Booster Pump A, technicians
'
reported that the suction and discharge lines had accumulated significant sitt. The inlet
was found 75 percent clogged and the outlet about 50 percent clogged. A problem
identification report was initiated, as well as significant engineering involvement and a
problem resolution matrix. Plant staff examined the other three pumps and both of the
residual heat removal heat exchangers by boroscope inspection. They found Service
Water Booster Pump B suction line about 50 percent full of sitt and found approximately
one inch of sitt in the outlet. The remaining pumps (C and D), and the two heat
exchangers contained minimal silt (approximately one inch). Service Water Booster
Pumps A and C had last been run in March, while B and D had been run more recently
to provide torus cooling.
I
,
An evaluation determined that running the Service Water Booster Pump B with silt in the
inlet would cause no adverse effects. Operators ran the pump without incident. A
boroscope examination conducted immediately afterward found that the silt in the inlet
had been removed, and no sitt was present in the outlet or in the heat exchanger.
Technicians completed replacement of Service Water Booster Pump A, returned the
pump to service, and performed a boroscope inspection. No silt was observed in the
inlet, outlet, or heat exchanger. After approximately 3 weeks of boroscope inspections
and pump runs, an engineering evaluation concluded that weekly pump runs would keep
silt properly controlled.
Silt ao umulation in service water systems will be addressed with the corrective actions
for Violution 50-298/97012-01, fouling of the residual heat removal heat exchanger,
c.
Conclusions
Significant silt buildup was observed in residual heat removal service water booster
pumps' suction and discharge lines. Inspections and evaluations determined that weekly
runs of the pumps would properly clear silt from the lines. This issue will be followed with
the corrective actions associated with the violation regarding the residual heat removal
heat exchanger tube plugging.
E2.2
Engineering Supoort of Through-Wall Leak in Nonessential Service Water System
a.
Scooe (37551. 93702)
Inspectors reviewed the engineering response to operations identification of through-wall
leakage on the nonessential service water piping. Inspectors participated in conference
calls, reviewed analyses, inspected the system, and held discussions with engineers and
managers.
\\
.
-_
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
._.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
-
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!
17
I
b.
Conclusions
As described in Section 01.2 of this report, engineering response to a through-wallleak
in the nonessential service water system was prompt, but was not comprehensive
regarding analysis of piping integrity or flooding analysis.
E3
Engineering Procedures and Documentation
E3.1
Lack of Evaluation of Test Eauioment in Replacement Comoonent Process
a.
Icipection Scoce (37551)
Inspectors reviewed a problem identification report which indicated a vulnerability in the
replacement component evaluation process.
b.
Observations and Findinos
Problem Identification Report 2-28983 described indications of multiple failures of
equivalent replacement relays during pre-installation testing. As described in
Section O2.1, the relays were equivalent replacement relays that engineering had
accepted in a replacement component eva:uation. This evaluation had not considered
whether the existing test equipment would provide valid testing of the replacement
components. Further, Procedure 3.25, " Replacement Component Evaluation, and
Procedure 3.4, " Configuration Change Control", Revision 22, did not require evaluation of
test equipment to assure that testing of replacement equipment would result in valid
conclusions. The licensee initiated Problem identification Report 2-26318 in response to
the inspector's concerns regarding lack of procedure adequacy. The licensee had not
concluded the scope of the concern and to date considers that, since the testing failed in
a conservative manner, no corrective actions were necessary. The licensee's conclusion
and final corrective actions will be followed by an inspector followup item (50-298/98004-
06)
c.
Conclusions
The replacement component evaluation and procedures associated with an equivalent
component replacement of safety-related relays did not insure adequate testing. The
equipment used to test the old design relays caused false failure indications when testing
the replacement relays.
,
Miscellaneous Engineering issues (92903)
E8
l
'
E8.1
(Ocen) Insoector Followuo item 50-298/98002-07: Potential effect of high torus level
allowed by emergency operating procedures. On March 30,1998, the inspectors
questioned procedural controls for the torus level with respect to the design requirements
for cntical torus components. Engineering had identified that the torus strainer
penetration calculations were nonconservative, and that penetrations were still operable,
.
L _ -- _ _
_
__
_ _ - _ _ _ _ _ _ _
________-__- __ ______ _ _ _ _ _ - - _
.
.
-18-
hydrodynamic loads associated with a loss-of-coolant accident blowdown from the
downcomers. The hydrodynamic loading is bounded by analysis only when torus levelis
2 inches or less. The inspector noted that emergency operating procedures allowed a
torus level to increase to a level of 37 inches before an emergency depressurization was
required. This indicated that the plant could remain at full pressure and therefore be
vulnerable to a loss-of-coolant accident in conditions where the torus level and
associated hydrodynamic forces could cause the strainer penetrations to be in an
unanalyzed condition. Licensee evaluation for the following few weeks was inconclusive,
and licensee management involvement was requested based on potential safety
significance.
During a briefing on June 16 after significant management involvement, licensing,
engineering, and operations staff presented a thorough and integrated evaluation of this
issue. Engineers concluded that the vendor's emergency procedure guidelines (EPGs)
l
and the severe accident management guidelines (SAGS) had not considered
hydrodynamic loading effects on torus strainers in determining an acceptable torus level
for implementation of the guidelines during accidents.
'
The licensee modeled a reactor coolant system breech with higher torus level r id found
that, under typicalloss-of-coolant accident simulator scenarios, no core damage was
predicted. However, with torus level elevated and modeling of a breech of primary
containment as a result of torus hydrodynamic loading on suction strainer penetrations,
the resulting torus failure would cause a higher core damage probability than a loss-of-
coolant accident event without containment damage. This aspect of probabilistic risk had
not been modeled in EPGs or licensee-specific individual plant evaluation.
The licensee reviewed the SAGS to determine if torus level had been properly
considered in their development. The licensee found that torus hydrodynamic loading as
a result of torus level had not been modeled and that, under severe accidents resulting in
reactor coolant system breech, a containment failure subsequent to reactor coolant
system breech should be considered if torus level resulted in exceeding hydrodynamic
loading limits on primary containment suction strainer penetrations. The licensee noted
that further conservatism may be available in calculations for hydrodynamic loads.
I
However, the licensee also considered this aspect of severe accidents to require review
from a generic standpoint by the Boiling Water Reactor Owner's Group (BWROG) in
development of severe accident guidelines and presented these issues to the BWROG
SAG working group on June 24.
l
The BWROG SAG working group concluded that torus level guidelines had not been
evaluated with respect to hydrodynamic loading of torus internals, such as strainers, for
l
any BWR containment design. The issue was assigned a BWROG EPG issue number
l
(EPG 9817) and had been assigned to various licensees for technical evaluation and
recommendations.
The licensee noted that current emergency operating procedures require torus level to
be promptly reduced if it should rise above 2 inches. This would be an immediate action
i
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i
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_ _ _ _ _ _ - - _ _ _ _ _ _ _
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19
be promptly reduced if it should rise above 2 inches. This would be an immediate action
unless a group isolation had isolated the pathway from the torus to radwaste. In that
case, a plant trip would have been anticipated, and emergency operating procedurec do
not allow reset of that isolation without first fully understanding the causes of plant
conditions. This pathway would remain isolated and the torus level would not be
reduced until further diagnosis had occurred. To address this concern, operations
determined that a prompt plant cooldown and depressurization would be required to
reduce the potential for hydrodynamic loading. This expectation was promptly provided
t
to crews and evaluated in simulator scenarios. This item will remain open to follow up
l
resolution of generic concerns.
c.
Conclusions
After significant inspector and plant management involvement, engineering performed
l
thorough and complete technical evaluation of a complex issue, and effectively
integrated operations and licensing staff in the evaluation and interim resolution.
l
Engineering assessed the potential effects of hydrodynamic loading on torus strainers,
[
caused by high torus levels allowed by emergency operating procedure and severe
'
accident guidelines. The licensee concluded that the guidelines had not considered
these effects, implemented interim compensatory actions, and presented the issue to the
IV. Plant Suonort
!
'
R3
Radiological Protection and Chemistry Procedures and Documentation
R3.1
Weak Guidance for Access to and Exit from Radiologically Controlled Satellite Areas
a.
Inspections Scoce (71750)
The inspectors observed posting and control of radiological controlled areas and
technician implementation of controls, reviewed Procedure 9.RADOP.3, " Area Posting
,
'
and Access Control," Revision 0, and held discussions with radiological protection
i
personnel and management.
b
Observations and Findinos
During the review of Procedure 9.RADOP.3, the inspectors identified that access and
I
exit requirements for radiologically controlled satellite areas were not well defined in the
procedure. Satellite areas were defined to be areas within the restricted area that require
,
posting by 10 CFR Part 20. The procedure clearly described the requirements for
I
access and exit for the radiological controlled area. Step 4.4 stated that access and exit
requirements for satellite areas will not be as extensive as those established for the
radiological controlled area. The procedure did not clearly state what the requirements
'
were for a satellite area nor did the procedure state how the requirements for the two
areas were different.
.
._____________. _ _ _
. _ -
'
.
o
-20-
Based on discussion with radiation protection, the inspectors discovered that the
guidance for access and exit from satellite areas had already been recognized
radiation protection staff and a procedure revision was partially developed. Until the;
procedure change is implemented, the radiation protection staff will control the acce
and exit of the satellite areas.
c.
Conclusion
The inspectors identified that procedural guidance for controlling access and exit f
satellite areas outside the radiological controlled area was weak. The radiologica
and had a partially completed revision when the inspec
!
R4
Radiological Protection Staff Knowledge and Perfor;aance
R4.1 At>>AA Procram Deficiencies
h
Inspections Scone (71750)
a.
Inspectors reviewed the ALARA program efforts for one time, interim, or temp
changes to plant activities in radiation areas. Inspectors held discussions with
maintenance, engineering, planning, and radiological protection staff.
b.
Observations and Findinos
inspectors noted that the ALARA staff had not been involved in a review to determ
the radiation exposure could be reduced for the inspections of the residual heat re
heat exchanger silt buildup discussed in Section E2.1 of this report. The radiatio
in the heat exchanger rooms vary from 5 to 20 millirem per hour, with 35 millire
hour on contact. Since the inspections were initiated to respond to recent events n
determination had been made rqardino how many more inspections were expect
,
The licensee performed more inspections v,'he heat exchangers over the fo
weeks, and the interviews with plant staff identified that no ALARA reviews we e
performed to reduce exposure.
The inspector had observed that ALARA personnel were usually involvec in re
activities in radiation areas and in one-time tasks in the higher radiation areas. Site
personnelgenerally used basic radiation protection and ALARA practices. However n
involvement of ALARA personnel or systematic ALARA focus was observed in s
,
as they prepared for interim, potentially repetitive, or emergent tasks in low radiation
areas of up to about 35 millirem per hour.
An additional example is the chemistry control measures for addition of oxygen
feedwater. The long-term plan of piping gas from outside the turbine building ha
been accomplished, so chemistry performs the interim measure of regularly b
feedwater chemistry control gas bottles into a radiologically controlled area of the
.
_ _ _ - _ _ _ _
_
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_ _ _ _
. -__
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l
e
-20-
l
!
Based on discussion with radiation protection, the inspectors discovered that the lack of
guidance for access and exit from satellite areas had already been recognized by the
radiation protection staff and a procedure revision was partially developed. Until the
procedure change is implemented, the radiation protection staff will control the access
and exit of the satellite areas.
j
c.
Conclusion
The inspectors identified that procedural guidance for controlling access and exit for
satellite areas outside the radiological controlled area ; as weak. The radiological
protection personnel had already recognized this procedural deficiency independently
'
and had a partially completed revision when the inspector identified the concern.
R4
Radiological Protection Staff Knowledge and Performance
R4.1
ALARA Proaram Deficiencies
a.
Lrlspfctions Scoce (71750)
Inspectors reviewed the ALARA program efforts for one time, interim, cr temporary
changes to plant activities in radiation areas. Inspectors held discussions with
maintenance, engineering, planning, and radiological protection staff.
b.
Observations and Findinas
Irispectors noted that the ALARA staff had not been involved in a review to determine if
the radiation exposure could be reduced for the inspections of the residual heat removal
heat exchanger silt buildup discussed in Section E2.1 cf this report. The radiation levels
in the heat exchanger rooms vary from 5 to 20 millirem per hour, with 35 millirem per
hour on contact. Since the inspections were initiated to respond to recent events, no
determination had been made regarding how many more inspections were expected.
The licensee performed more inspections of the heat exchangers over the following
weeks, and the interviews with plant staff identified that no ALARA reviews were
performed to reduce exposure.
1
The inspector had observed that ALARA personnel were usually iavolved in repetitive
activities in radiation areas and in one-time tasks in the higher radiation areas. Site
personnel generally used basic radiation protection and ALARA practices. However, no
involvement of ALARA personnel or systematic ALARA focus was observed in site staff
as they prepared for interim, potentially repetitive, or emergent tasks in low radiation
areas of up to about 35 millirem per hour.
An additional example is the chemistry control measures for addition of oxygen to
feedwater. The long-term plan of piping gas from outside the turbine building has not
been accomplished, so chemistry performs the interim measure of regularly bringing
feedwater chemistry control gas bottles into a radiologically controlled area of the turbine
l
0
_..__________.__._.___-_-_w
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.
e
-21-
building. The radiation area is low. This practice had not been evaluated by ALARA to
determine if radiation exposure could be reduced or a higher priority could be placed on
the final modification for chemistry control to reduce the number of bottle replacements
required.
c.
Conclusions
No ALARA staff were obsewed to be present, nor was a systematic ALARA focus
demonstrated for plant activities which were considered one time, interim, or temporary
processes in lower level radiation areas up to about 35 millirem per hour. The inspector
pointed out examples of these types of repetitive activities without ALARA reviews that
had been sustained for months or years and were still considered temporary.
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at
the Corrective Action Program exit meeting on June 4,1998, and at the routine exit
j
meeting on July 7,1998. The licensee acknowledged the findings presented.
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The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. Proprietary information had been provided, and the
inspectors agreed that it was to be controlled consistent with existing memoranda of
understanding and NRC policy. The information will be retumed to the licensee.
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_ . - _ - _ _ - - _ _ _ _ - _ _ _ _ _ _ - _ _ _ -
_ - _ _ _ _ - _
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a
PARTIAL LIST OF PERSONS CONTACTED
i
Licensee
" Mark Bohling, Senior Auditor, Quality Assurance
- Mike Boyce, Plant Engineering Manager
- Joe Burton, Performance Analysis Manager
- Paul Caudill, Senior Engineering Manager
- Tim Chard, Assistant Radiological Manager
- Linda Dewhirst, Licensing Engineering
- Roman Estrada, Corrective Action Program Supervisor
- Charles Fidler, Assistant Maintenance Manager
- Chuck Gaines, Maintenance Manager
- Ted Gifford, Design Engineering Manager
- Paul Gritton, Employee Communications
- Andy Jacobs, NSAG
- David Madson, Licensing Engineer
- Mike Peckham, Plant Manager
- Jennifer Peters, Licensing Secretary
- Andy Sessoms, Senior Quality Assurance Manager
- Alan Shiever, Operations Manager
- Sara Stiers, Administrative Services Manager
- Jim Sumpter, Lice.1 sing
- Bruce Toline Quality Assurance Audit Supervisor
NEG
- Charles Marschall, Project Engineer
- Attended Corrective Action Program exit meeting on June 4,1998
- Attended routine exit meeting on July 7,1998
INSPECTION PROCEDURES USFO
IP 37551: Onsite Engineering
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation
IP 71707. Plant Operations
IP 71750: Plant Support Activities
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IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving and Preventing Problems
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9
-2-
ITEMS OPENED, OPENED AND CLOSED, CLOSED, AND DISCUSSED
Opened
50-298/98004-01
IFl
No analysis for turbine building flooding (Sections 01.2 and E
50-298/98004-03
IFl
.
Problems associated with service water booster pump vendor an
maintenance (Section M1.2).
50-298/98004-06
IFl
Replacement component evaluations failed to address test
equipment (Section E3.1).
Opened and Closed
50-298/98004-02
Inadequate original design did not meet primary containment -
isolation requirements (Section 08.3).
h
50-298/98004-04
}
Failure to test the main turbine stop valves prior to exceeding
30 percent power (Section M8.1),
50-298/98004-05
Diesel generator test did not meet minimum Technical
Specification time requirements (Section M8.2).
C1019.d
50-298/97011-01
Technical Specification violation for sample line isolation
(Section 08.1).
50-298/97-017
LER
inadequate original design did not meet primary containment
isolation requirements (Section 08.3).
50-298/98-007
LER
Missed surveillance testing of main turbine stop valve closure
(Section M8.1).
50-298/97-016
LER
Diesel generator test did not meet minimum Technical
Specification time requirements (Section M8.2).
Qiscussed
50-298/98002-03
Inadequate corrective actions in identifying the extent of condition
(Sections M8.1, and M8.2).
50-298/97012-01
Inadequate corrective action (Sections 07.1,08.2, and E2.1).
50-298/98002-u,
IFl
Potential effect of high torus level allowed by emergency oper
procedures (Section E8.1).
.
_
_ - __ _ _________-___ _ __ _ _ _ _ _ _
-_
~
i
-2-
ITEMS OPENED, OPENED AND CLOSED, CLOSED. AND DISCUSSED
Ooened
50-298/98004-01
IFl
No analysis for turbine building flooding (Sections 01.2 and E2.3).
50-298/98004-03
IFl
Problems associated with service water booster pump vendor and
maintenance (Section M1.2).
50-298/98004-06
IFl
Replacement component evaluations failed to address test
equipment (Section E3.1).
Ooened and Closed
50-298/98004-02
NCV Inadequate original design did not meet primary containment '
isolation requirements (Section 08.3).
50-298/98004-04
NCV Failure to test the main turbine stop valves prior to exceeding
30 percent power (Section M8.1).
50-298/98004-05
NCV Diesel generator test did not meet minimum Technical
Specification time requirements (Section M8.2).
Closed
50-298/97011-01
Technical Specification violation for sample line isolation
(Section 08.1).
50-298/97-017
LER
Inadequate original design did not meet primary containment
isolation requirements (Section 08.3).
50-298/98-007
LER
Missed surveillance testing of main turbine stop valve closure
(Section M8.1).
I
50-298/97-016
LER
Diesel generator test did not meet minimum Technical
Specification time requirements (Section M8.2).
Discussed
50-298/98002-03
Inadequate corrective actions in identifying the extent of condition
(Sections M8.1, and M8.2).
50-298/97012-01
Inadequate corrective action (Sections 07.1,08.2, and E2.1).
50-298/98002-07
IFl
Potential effect of high torus level allowed by emergency operating
procedures (Section E8.1).
.