IR 05000373/1999007
| ML20206G674 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 05/03/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20206G665 | List: |
| References | |
| 50-373-99-07, 50-373-99-7, 50-374-99-07, 50-374-99-7, NUDOCS 9905100112 | |
| Download: ML20206G674 (26) | |
Text
_ - - _ - _ _ _ _ _ _ _ _
_ _ _ _ _
- _ - _ _ _ _
- _ _ _ _
.
.
U.S. NUCLEAR REGULATORY COMMISSION REGION lil Docket Nos:
50-373, 50-374 License Nos:
50-373/99007(DRP); 50-374/99007(DRP)
Licensee:
Commonwealth Edison Company Facility:
LaSalle County Station, Units 1 and 2 Location:
2601 N. 21st Road Marseilles,IL 61341 Dates:
March 29 through April 2,1999 Inspectors:
J. Lara, Team Leader L. Cheung, Reactor inspector, Region i M. Kurth, Resident inspector, Duane Arnold J. Starefos, Resident inspector, Browns Ferry, Region 11 R. Vogt-Lowell, Operations inspector, NRR R. Winter, Reactor inspector, Region lil Approved by:
Melvyn N. Leach, Chief Reactor Projects Branch 2 Division of Reactor Projects 9905100112 990503 PDR ADOCK 05000373 b
- _ _ _ _ _ _ _ _ _ _ - _.
..
.
EXECUTIVE SUMMARY
!
LaSalle County Station, Units 1 and 2 NRC Inspection Report 50-373/99007(DRP); 50-374/99007(DRP)
-The Restart Operations. Assessment Team inspection evaluated the readiness of plant j
hardware, plant staff, and management programs to support a safe restart and continued operation of LaSalle Unit 2 while maintaining safe operation of Unit 1. During this inspection g
period, which included a period where 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of continuous control room observations were conducted, the team evaluated activities in the operations, maintenance, and engineering l
performance areas.
Plant Operations J
The Unit 1 and Unit 2 Nuclear Station Operator and Shift Manager logs were in
-
' compliance with administrative' procedure requirements. Operational problems were being documented in accordance with the licensee's administrative procedures for initiating Problem Identification Forms. Three-way communications were consistently
]
and effectively used by Operations personnel for all observed orders and directions that
{
involved operation of plant equipment or exchange of critical information related to the
'
plant or plant equipment. (Section O1.2)
Observed briefings conducted by Shift Managers and Unit Supervisors were effective in l
-
conveying plant status, shift priorities, planned evolutions, problems with plant equipment, and evolutions in progress. The Heightened Level of Awareness briefings were also determined to be effective in ensuring individuals involved in the pertinent evolutions were fully briefed. Personnel in the control room were alert and performed their assigned duties in a professional manner throughout the period of observation.
(Sec. ion O1.2)
j The team observed the control room shift personnel attentive to assigned duties.
-
Operators frequently monitored control room instrumentation and annunciator status to
,
detect abnormalities and identify trends in important parameters. Operators responded
- to annunciators and alarms in accordance with applicable standards and procedures.
(Section 01.3)
j
,
With one exception, the operating shift staffing met the requirements provided in
-
Technical Specifications and site administrative procedures. 'One Non-Cited Violation was identified where shift manning requirements were not met during control rod friction testing due to the supervising Senior Reactor Operator having other concurrent duties.
Nonetheless, the friction testing was observed to be performed without error and with the appropriate safety focus by licensed individuals performing the test. (Section 01.4)
The communication of plant status, planned evolutions, priorities, and expectations
-
during shift tumover and shift briefings was good. The team observed effective shift turnovers and appropriate implementation of administrative requirements for the performance of shift tumovers. (Section 01.4)
L-
b
.
1*
I Administrative procedures for the control of overtime use were being appropriately
-
l implemented. (Section O1.4)
Various plant walk-downs of the reactor water cleanup and standby liquid control I
l
-
!
systems indicated generally good material condition of plant equipment and components.
Equipment was labeled appropriately and in accordance with system drawings.
However, team walk-down inspections identified examples where the licensee's area walk-downs were not thorough in identifying miscellaneous housekeeping items.
(Section O2.1)
A discrepancy was identified involving the licensee's Updated Final Safety Analysis
-
Report not being updated to reflect the physical removal of a valve as part of a design
modification. This was identified as a minor violation. (Section O2.1)
i Control room observations identified good Unit Supervisor review of work items prior to
-
implementation. The team observed appropriate implementation of administrative procedures used to track inoperable and degraded Technical Specifications related equipment. Adequate controls were in place to ensure that a review of the Degraded Equipment Log was completed before changing from Mode 5 to Mode 4. (Section O2.2)
The licensee had appropriately reviewed the circumstances involving the reactor water
--
cleanup system out of service configuration, which resulted in a drain down event.
Licensee corrective actions were prompt. Control room operators isolated the drain down in a timely manner. (Section O2.3)
The licensee properly used procedures in the control room and in the plant. In general,
-
procedures prWded sufficient detail and guidance to plant personnel. The timeliness of procedure change distribution could result in the control room having a different revision j
of a procedure than the remote shutdown panels. (, Etion O3.1)
The licensee conducted operator training at an acceptable level to provide operators with
-
the skill and knowledge necessary to operate systems modified during the Unit 2 outage.
Some operators lacked knowledge of the difference between the annunciator response procedure setpoints and the actual alarming setpoints. (Section O5.1)
The Nuclear Oversight assessment activities were wide-ranging and effectively
-
challenged the site organizations' overall performance and readiness for plant restart.
Based on a review of completed integrated Operations Performance Review summaries, the team concluded that the Integrated Operations Performance Review process was effective in evaluating the operators' performance against station standards.
(Section O7.1)
Maintenance i
The surveillance test activities observed were' generally adequate and properly
-
' implemented. Communications between the control room and personnelin the field involved in the activities were generally good. Control room personnel were kept informed of the testing status, out of service equipment, and expected alarms.
(Section M1.1)
j
j e
.
.
'
i Enaineerina The temporary modification packages were generally of good quality and appropriately
.
installed. The licensee had adequate procedures to provide administrative controls of the process and safety evaluation preparation for new temporary modifications.
However, one temporary modification had changed the plant configuration no7 conservatively; also, this was not consistent with the aesign basis specified in the Updated Final Safety Analysis Report, and no written safety evaluation was provided by
,
the licensee to determine that the change did not involve a Unreviewed Safety Question.
'
This was a Non-Cited Violation. (Section E1.1)
The operability evaluations reviewed were of good quality and the conclusiens were
.
supported by adequate technical justification. (Section E1.2)
i The team concluded that engineering self-assessments were of good quality and well
-
structured. The self-assessment perforrned by the corporate staff was comprehensive.
The assessment method was logical, and the presentation of the assessment resu'ts was effective. This assessment had resulted in many good finoings and recommendations for the site engineering to improve its performance. (Section E7.1)
__
.
.
.
Report Details Summary of Plant Status During this inspection period, the licensee maintained Unit 1 at 100 percent power and Unit 2 was completing outage activities and final surveillance tests which were required to be completed prior to restart.
1. Or rations
Conduct of Operations O1.1 General Comments The team conducted observations of routine control room activities during a continuous
.
72-hour period using Inspection Proce9ure 93802, " Operational Safety Team
{
Inspection," as guidance. In genen
'es conduct of operations was professional and i
focused on operational safety. Spatic observations and findings are discussed in the following sections.
)
O1.2 Conduct of Routine Operations
{
a.
Inspection Scope (71707)
{
l During the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of continuous observation, the team reviewed ongoing plant operations, log-keeping practices, communications, command and control, and overall control room decorum. The following procedures were considered in the review process:
CWPI-NSP-OP-1-1, " Operations Department Standards," Revision 1
-
CWPI-NSP-OP-1-9, " Heightened Level of Awareness Briefings," Revision 0
-
CWPI-NSP-OP-1-10, " Watch Standing Practices," Revision 0
-
CWPI-NSP-OP-1-11, * Verification Practices"
-
CWPI-NSP-OP-1-13. " Roles and Responsibilities of On-Shift Personnel,"
Revision 1 LAP-200-3, " Conduct of Operations - Shift Operations," Revision 38
-
LAP-200-5, " Conduct of Operations - Shift Records," Revision 11
-
NSP-AP-4004, " Corrective Action Program Procedure," Revision 0
b.
Observations and Findinos Loo Keepino Practice _s The team reviewed all control room Nuclear Station Operator (NSO) logs generated during the 72-hour continuous control room observation period, as well as a selection of NSO logs generated prior to the inspection week. In general, the types of information procedurally required to be recorded in the NSO logs were being recorded. Although use of handwritten logs was inferred, (i.e., "... log entries shall be made using black ink..."), the team noted that in actual practice control room shift personnel utilized desktop personal computers and word processing software to accomplish the log keeping task. The Unit 1 and Unit 2 Shift Manager paper log books were reviewed to
.
.
I i
verify compliance with Procedure LAP-200-5. With one minor discrepancy noted (a printed log sheet in the book was missing the Shift Manager's signature), the logs were determined to be in compliance with administrative procedure requirements.
The team performed an assessment to determine whether operational problems were being documented in accordance with the licensee's administrative procedures. This assessment was performed through the review of operator logs and selection of numerous log entries which appeared to meet the Problem identification Form (PlF)
criteria. Based on the team's questioning of the log entries, the licensee initiated three new PlFs (L1999-01755, L1999-01757 and L1999-01758) to document conditions or events for which PlFs had not been written. Based on the large sample review, the team concluded that plant and equipment abnormal conditions were being appropriately reviewed and PIFs initiated as required.
Communica'.ig_na n
During the control room observations, the team monitored communications between shift crew persor nel within the control room and between the control room and plant personnel to confirm adherence with administrative procedures. During significant evolutions s uch as the reactor cavity drain down and vessel head tensioning, the team noted that s hift crew management reemphasized communications expectations. Routine control roor1 communications were effective, instructions were acknowledged, and receipt of ir structions were verified. The NSO alarm responses and the ensuing communica tions with the Unit Supervisor were consistent and in accordance with administrat,ve procedures. Control room environment was observed to be adequate for clear communications.
The team also observed " Heightened Level of Awareness" (HLA) briefings. The licensee conducted HLA briefings to ensure that responsibilities for direction, control, oversight, and the conduct of infrequently performed evolutions, tests, or other risk significant activities were established. For example, prior to commencing drain down of the Unit 2 reactor cavity after reloading of the reactor core was complete, the Unit 2 Unit Supervisor
,
performed a thorough HLA briefing on the pending evolution. The Unit Supervisor
stressed the importance of communication for the evolution to be successful and
'
ensured that the responsibilities, and authorities of all personnel involved in the evolution were clearly stated and understood. The thoroughness of operations briefings was also observed duri eg a pre-job briefing relating to suppression pool diving activities.
The licensee's management representative for the activity provided an adequate briefing to the control room personnel on the operational restrictions on usage of the suppression pool while divers were in the pool. Communications, lessons learned, and the hazards and contingency planning associated with " confined space entries" were included in the briefing.
Command and Control The team observed numerous interactions and interfaces between shift management and other personnel during the control room observation period. The team observed that the Unit Supervisor was the single point of accountability for the assigned unit, displayed command authority over the operators and plant operations within, provided
...........
,
,
.
direct oversight of the NSOs assigned to the unit, and routinely reviewed the Technical Specifications (TS) regarding existing and potential conditions associated with planned evolutions. The Unit Supervisor was also observed to adequately monitor and control access to activities in the control room; authorize test, surveillance, and maintenance activities; and conducted acceptable HLA briefings for infrequently performed evolutions and risk significant activities.
The above observations were made during the team's witnessing of routine activities and activities associated with the following major evolutions for Unit 2: 1) completion of reactor core reloading; 2) installation of the Unit 2 fuel pool to reactor cavity gate; 3) reinstallation of the steam separator and steam dryer into the reactor vessel; 4) reactor cavity drain down; and 5) reactor vessel head installation and tensioning. Tne reactor cavity drain down evolution provided several examples of good implementation of various facets of command and control responsibilities on the part of the Unit 2 Unit Supervisor. This activity was successfully accomplished without any unexpected results or interruptions.
During the overall period of control room observation, the NSOs on-shift were alert and attentive to control board indications and alarms. Indications were monitored frequently and deficiencies in main control board indications were documented and received prompt attention and resolution. While performing reactivity manipulations, operators were dedicated to that task with no concurrent activities that could cause distraction.
On-shift NSOs were observed to routinely utilize "self-checiting" principles, as well as
" peer checking" for tasks which, if performed incorrectly, could result in personnel injury, plant transient, or equipment damage. Utilization of " concurrent dual verification," as described in Procedure CWPI-NSP-OP-1-11, was also noted during various control switch and breaker manipulations.
Control Room Decorum During the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of continuous control room observation, the team was able to msess the formality of control room operations under a variety of conditions ranging from periods of very low activity to periods intensely focused on specific evolutions. Both Unit Supervisors exhibited direct responsibility for minimizing control room distractions and were cognizant of activities that could distract the attention of their NSOs from their assigned duties. Unit Assist NSOs were observed to routinely perform tasks and surveillances, thus allowing the Unit NSO to monitor the unit without distraction. No activities were observed that could adversely affect the ability of individuals or equipment to perform their intended safety function.
The team observed the Unit Supervisor exhibit good control of access to the control room as evidenced by requiring individuals to obtain permission to enter and by excluding non-essential personnel during critical evolutions such as prior to
- commencement of the reactor cavity drain down evolution.
c.
Conclusions The Unit 1 and Unit 2 NSO and Shift Manager logs were in compliance with administrative procedure requirements. Operational problems were being documented
..
..
..
.....
....
_
.
.
.
.
.
,
)
in accordance with the licensee's administrative procedures for initiating PlFs.
Three-way communications were consistently and effectively used by Operations personnel for all observed orders and directions that involved operation of plant equipment or exchange of critical information related to the plant or plant equipment.
Observed briefings conducted by Shift Managers and Unit Supervisors were effective in conveying plant status, shift priorities, planned evolutions, problems with plant equipment, and evolutions in progress. The HLA briefings were also determined to be effective in ensuring individuals involved in the pertinent evolutions were fully briefed.
Personnel in the control room were alert and performed their assigned duties in a professional manner throughout the period of observation.
O1.3 Operator Attentiveness to Duty and Panel Monitorino a.-
Inspection Scooe (71707L The team reviewed procedural guidance and requirements to assess operator awareness of control board indications, awareness of equipment status and response to annunciators, during the period of control room observation. The following procedures were reviewed:
,
LAP-200-3, " Conduct of Operations - Shift Operations," Revision 38
=
CWPI-NSP-OP-1-1, " Operations Department Standards," Revision 1
.
b.
Observations and Findinos Control Board Awareness LaSalle administrative procedures require that operators maintain a state of control board awareness. These expectations were developed to ensure that the control room operators were alert for changing critical parameters, alarms, and trends, such that resolution of an abnormal trend could be addressed before plant safety was challenged.
As an example of awareness of a degrading trend, PlF L1999-01668, documented a condition where NSO recognition of an increasing level in the reactor building equipment drain tank allowed actions to be taken to isolate the reactor water cleanup (RWCU)
system. In addition to the normal control board monitoring during steady state plant
,
operations, procedural expectations were that the Unit NSO perform a complete j
overview of the control boards on approximately 15 minute intervals, with a complete j
physical walk-down of the unit every 60 minutes to log critical parameters. During the
'
period of control room observation, the team confirmed general compliance with the procedurai expectations.
i Eaoioment Status Awareness The team noted that equipment deficiencies were properly controlled and degraded equipment was adequately documented and tracked for repair. System lineups and configurations resulting into entry of TS Action Statements were properly identified and controlled. This was evident when the 'B' Residual Heat Removal (RHR) loop was
. placed in suppression pool cooling, during which time Secondary Containment would be inoperable.
p
,
,
..-
Overall awareness of equipment status was evident during turnovers from one crew to the next. Awareness was also displayed in the conduct of thorough and effective pre-job briefs, and in the response to expected and unexpected annunciators. However, during the inspection period, two events occurred involving inadequate equipment control on Unit 2. These events were documented by the licensee in PlF L1999-01666 and PlF L1999-01668. The first event involved the overflow of 250-500 gallons of water to the local area from the 2TE02 sump while breaking condenser vacuum under procedure LOP-CD-12. The second event involved licensee personnel valving in the "A" RWCU heat exchanger, unaware that several vents and drains were still open. This action resulted in a level increase in the reactor building equipment drain tank which prompted the control room operator to manually isolate the RWCU system. The second event regarding the RWCU system is further discussed in Section O2.3 of this report.
Annunciator Response LaSalle procedures required the on-duty NSO to be knowledgeable of the reason for annunciators in the alarmed condition. During the team's observations in the control room, numerous annunciators were in the alarmed condition as a result of ongoing maintenance, testing, or equipment being out of service. When questioned by the team, the on-duty NSOs were knowledgeable of the reason for each annunciator.
During the period of observation, on-duty NSOs and Unit Supervisors effectively communicated expected and unexpected alarms received in the control room. This type of interaction was consistent throughout the period of observation. During planned maintenance or surveillance activities, the NSOs were meticulous in pre-identifying all annunciators that were expected to come in as a result of the activity, and as an operator aid, would identify these annunciators by placing an adhesive flag on the annunciator L window itself. These flags were consistently removed at the conclusion of the maintenance or testing activity.
c.
Conclusions The team observed the control room shift personnel attentive to assigned duties.
Operators frequently monitored control room instrumentation and annunciator status to detect abnormalities and identify trends in important parameters. Operators responded to annunciators and alarms in accordance with applicable standards and procedures.
01.4 Shift Mannina. Shift Tumovers. and Administrative Control of Overtime a.
Insoection Scooe (71707)
The team performed assessments in the areas of control room shift manning, shift tumovers, and administrative control of overtime. The following documents were reviewed:
LAP 200-2, " Conduct of Operations, Operations Shift Complement and
-
Functions," Revision 4 1.AP-200-3, " Conduct of Operations - Shift Operations," Revision 38,
-
I
-
l
.
$
.
LAP-100-17, " Overtime Control for Personnel Performing Work at LaSalle
!
-
Station," Revision 12 CWPI-NSP-OP-1-8, " Shift Turnover and Relief," Revision 0
-
CWPI-NSP-OP-1-13 " Roles and Responsibilities of On-Shift Personnel,"
Revision 1 b.
Observations and Findinos Shift Mannino Adequacy of crew staffing was assessed by the team on numerous occasions during the 72-hour continuous observation of control room activities. The major responsibilities and roles of on-shift positions in the Operations Department were defineated in procedure CWPI-NSP-OP-1-13. The team noted that additional licensed personnel were added as necessary to the shifts during critical evolutions such as the Unit 2 reactor cavity drain down. During the team's observations, one instance was noted during which the TS staffing requirements were not met. Technical Specifications Section 6.1 required a minimum of one Senior Reactor Operator (SRO) for shift staffing of both units, with one unit in operation and the other in shutdown. Nonetheless, the licensee maintained two SROs in the control room during the inspection observation period, one was assigned as the Unit 1 Unit Supervisor and the second was assigned as the Unit 2 Unit Supervisor.
The team noted that during performance of Procedure LTP-1600-30, " Single Rod Subcritical Check," the Unit 2 SRO directly supervised this core alteration activity.
- Distractions were minimized and attention was focused on the task with no safety concems identified. However, on March 31,1999, during the Unit 2 performance of Procedure LTP-700-2, " Control Rod Friction and Settling Testing," the team observed j
that the SRO observing and supervising the test was also performing the concurrent responsibility of Unit 2 Unit Supervisor. This was contrary to TS Figure 6.1-3, Minimum
)
Shift Crew Composition (notation (b)), which required that during core alterations on either unit, a licensed SRO, who has no other concurrent responsibilities, must be present to observe and directly supervise the operation. As defined in TS Section 1, core alterations included the movement of reactivity controls within the pressure vessel
.
with the vessel head removed and fuelin the vessel. The team observed that the Unit 2 SRO involved with core alterations (movement of control rods) had other concurrent duties which included acknowledging alarms not related to the core alteration activity and
.
performed other duties normally assigned to the Unit 2 Supervisor at the control room I
work station without suspension of testing. This Severity Level IV violation is being treated as a Non-Citod Violation (NCV), consistent with Appendix C of the NRC Enforcement Policy (NCV 50-374/99007-01, Control Room Shift Manning Requirements Not Met). This violation was in the licensee's corrective action program as PlF L1999-01721.
Although the licensee did not comply with the TS requirement, friction testing was observed to be performed without error and with the appropriate safety focus by licensed NSOs performing the test. When the team questioned the licensee's method for implementation of the TS requirement, the licensee immediately documented a clarification of responsibilities during non-fuel core alterations in an Operations Daily Order dated March 31,1999.
,
.
.
r Shift Turnovers The team observed various shift turnovers which consisted of log reviews, panel walk-downs, and a shift brief. Panel walk-downs were conducted jointly by off-going and on-coming shift personnel. During the walk-downs, the status of plant equipment and
'
planned evolutions were discussed. Plant status and planned evolutions were also provided in shift tumover data sheets. Immediately following shift tumover, a shift brief was conducted with operating shift personnel. This brief covered current plant status, planned evolutions, pertinent daily orders, unusual conditions, and general shift routine.
,
Each shift member presented a portion of the overall brief, as appropriate in addition, the shift manager provided expectations and priorities for the shift. The communication of plant status, planned evolutions, priorities, and expectations during shift turnover and shift briefings was good. The team observed effective shift turnovers and appropriate implementation of administrative requirements for the performance of shift turnovers.
Administrative Control of Overtime Hours The team reviewed the licensee's administrative process used to control operator overtime, as prescribed in administrative procedure LAP-100-17. The team reviewed the overtime records for one SRO who on one day was observed to be onsite for greater than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. The team's reviews indicated that since January 1999, the licensed
.]
individual had averaged 62 hours7.175926e-4 days <br />0.0172 hours <br />1.025132e-4 weeks <br />2.3591e-5 months <br /> per week over the time span examined. The team performed a semple review of Overtime Deviation Authorization Forms (LAP-100-17,
Attachment A), and verified that the required reviews and approvals had been obtained j
when the overtime criteria was exceeded.
c.
Conclusions i
With one exception, the operating shift staffing met the requirements provided in TS and site administrative procedures. One Non-Cited Violation was identifieKi where shift manning requirements were not met during control rod friction testing due to the
)
supervising SRO having other concurrent duties. Nonetheless, the friction testing was
'
observed to be performed without error and with the appropriate safety focus by licensed individuals performing the test.
j The communication of plant status, planned evolutions, priorities, and expectations during shift tumover and shift briefings was good. The team observed effective shift tumovers and appropriate implementation of administrative requirements for the performance of shift tumovers.
Administrative procedures for the control of overtime use were being appropriately implemented.
,.
.
.
.... ---
- _ - _ - _-_- _ - _-__ _ _ _ ____ __-__ - -_ _ _ _________
4 *
.
,)
Operational Status of Facilities and Equipment
. 02.1' Enaineered Safety Feature System Walk-down a.
Inspection Scope (71707)
The team performed walk-downs of various plant equipment and components to verify acceptable configuration and material condition. The team reviewed Procedure LOP-RH-01, * Filling and Venting the Residual Heat Removal System," Revision 30 and the Updated Final Safety Analysis Report (UFSAR).
b.
Observations and Findings The team performed walk-downs of the accessible portions of the reactor water cleanup and standby liquid control systems and generally noted good material condition of plant equipment and components. Inspection attributes included equipment configuration, componer:t labeling, and overall material condition. Equipment was labeled appropriately and in accordance with system drawings. The team noted that several valves in the reactor water cleanup system had action request tags to identify outstanding deficiencies or concems. These tags did not identify operability issues.
However, the team also observed various tags, streamers, drawings, and other miscellaneous items hanging on equipment. These items remained installed even after the licensee had completed area walk-down inspections. Although these items did not affect system or component operability, the team discussed with licensee representatives the need for increased attention to detail during these walk-downs. The licensee acknowledged the team's observations and indicated that additional management area walk-downs were scheduled prior to restart to verify acceptable plant conditions.
The team performed field walk-downs to verify correct equipment configurations. This inspection effort focused on 480-volt circuit breaker configurations. Several circuit breaker configurations in Division I and II 480-volt motor control centers were selected for review. Circuit breakers were identified to be controlled in accordance with electrical checklists and as specified in out-of-service tags. Two of the circuit breakers reviewed were associated with valves used for the steam condensing mode of residual heat removal (RHR) operation. The implementation of administrative controls to ensure that the valves were open during power operations was provided in LOP-RH-01. The team compared the UFSAR and LOP-RH-01 and identified that valve 2E51-F091, RCIC Steam to RHR Warmup Valve, was listed in the UFSAR as required to be closed but was not listed in the procedure. In response to the team's questions, the licensee identified that a 1995 plant modification removed the valve from the plant and the need for a UFSAR change was identified in Exempt Change Request E01-2-9500158. However, a i
UFSAR change was not processed. The licensee initiated PlF L1999-01742 to
!
document this issue and provide corrective actions. The failure to revise UFSAR I
Section 5.4.7.2.2.3 to reflect the removal of an RHR valve resulting from a design
modification was considered to constitute a violation of minor significance and is not subject to formal enforcement action in accordance with the NRC enforcement policy.
!
'
_ _ _ _ _ _ _ _ _ _ _ _ _ _
.
,
c.
Conclusions Various plant walk-downs by the team of the reactor water cleanup and standby liquid control systems indicated generally good material condition of plant equipment and components. Equipment was labeled appropriately and in accordance with system drawings. However, team walk-down inspections identified examples where the licensee's area walk-downs were not thorough in identifying miscellaneous housekeeping items. A discrepancy was also identified involving the licensee's UFSAR not being updated to reflect the physical removal of a valve as part of a design modification. This was identified as a minor violation.
O2.2 Eauioment Status a.
Inspection Scope (93802)
The team observed activities in the control room to ensure acceptable sensitivity to the status of equipment and reviewed implementation of selected portions of the licensee's process for tracking degraded equipment required by the licensee's TS. The following documents were reviewed:
LAP-200-3, " Conduct of Operations - Shift Operations," Revision 38
LOP-AA-03, " Reactor Mode Changes," Revision 9
-
"Offsite Dose Calculation Manual"
+
b.
Observations and Findinas The team noted good Unit Supervisor review of work packages that came to the control room before allowing work to proceed. Examples of the active use of TS during the review of work packages was also observed. Control room operators were sensitive to the effect of clearance positions on the current alignment of plant systems and additional reviews or changes were requested.
Procedure LAP-200-3 provided direction for tracking inoperable and degraded TS related equipment. This procedure was also used to track the operability of equipment in Chapter 12 of the Offsite Dose Calculation Manual and Administrative Technical Requirements equipment and instruments via the use of " red tags". The " red tags" were used as aids to operations personnel in identifying inoperable equipment required by TS or the Offsite Dose Calculation Manual. A Degraded Equipment Log was also maintained to track the status of an item which was likely to be inoperable for a period of time longer than the current shift. Additionally, all inoperable safety-related equipment
. was to be red-tagged if a Degraded Equipment Log entry was made. The team observed appropriate implementation of the L.AP-200-3 requirements and use of the Degraded Equipment Log when the "A" RHR Service Water Process Radiation Monitor flow was identified as inoperable.
The team noted that a large number of red deficiency tags still existed on the Unit 2 control room panels. The team reviewed outstanding control room red tags versus the Degraded Equipment Log to determine adequacy ofimplementation of the process for controlling deficiencies on safety-related equipment. Discussions with operations
.
.
.
>
personnel indicated a general knowledge of the reasons for several of the tags. The team noted that Attachment B of Procedure LOP-AA-03, required a review of the Degraded Equipment Log by operations personnel before changing from Mode 5 to Mode 4.
c.
Conclusions
Control room observations identified good Unit Supervisor review of work items prior to implementation. The team observed appropriate implementation of administrative procedures used to track inoperable and degraded TS related equipment. Adequate controls were in place to ensure that a review of the Degraded Equipment Log was completed before changing from Mode 5 to Mode 4.
!
O2.3 Imoroper Restoration of Reactor Water Cleanuo (RWCU) System a.
Inspection Scope (71707)
The team reviewed the licensee's accelerated investigation report which documented the circumstances involving the draining of water from the RWCU system due to improper system alignment. The following documents were reviewed:
LAP-900-48, " Writing and Hanging An Out of Service," Revision 7
LOP-RT-01, " Reactor Water Cleanup System Filling and Venting," Revision 23
-
LOP-RT-12. " Reactor Water Cleanup System Draining," Revision 15
-
" Accelerated Investigation Report, Unit 2 Reactor Water Cleanup Drain to
-
Reactor Building Equipment Drain Tank During Out of Service Manipulation,"
(PlF L1999-01668)
b.
Observations and Findinos On March 30,1999, operations personnel c! eared out of service (OOS) 990003789 on the Unit 2 RWCU regenerative heat exchangers. When auxiliary operators opened RWCU valve 2G33-F0478, a flow path was established through the RWCU suction piping, through the heat exchangers, out the vents and drains associated with the lower regenerative heat exchanger, and into the reactor building equipment drain tank.
Operators in the control room received a RWCU high flow alarm and noted that a RWCU j
High Flow automatic isolation did not occur since it was in bypass. Subsequently, one of j
the NSOs observed that the reactor building equipment drain tank level was increasing I
and therefore the SRO requested that RWCU isolation valves be closed. This j
terminated the drain down event. This event resulted in approximately 400 gallons of I
water being drained from the reactor skimmer surge tank. However, no change was l
observed in the water level over the fuel in the pool or reactor vessel and cavity. The licencee performed an accelerated review of the event and identified a root cause and contributing causes. These included:
I Vents and drains were manipulated during the course of hanging the OOS tags.
-
However, these valves were not included in the OOS, as required by LAP-900-48. The realignment of the vents and drains had been expected to be closed during the fill and vent Procedure LOP-RT-01.
14
O
,
,
s The work control supervisor changed the restoration plan identified in the OOS
.
without addressing the configuration of the plant as established in the RWCU operations procedures. Due to other ongoing maintenance activities on the RWCU system, the supervisor elected to clear the OOS, but not fill and vent the system at that time.
Additional emergent work items were initiated on the RWCU system after the
-
maintenance and modification window had been closed.
The licensee implemented prompt corrective actions in response of this event which included:
All available SROs were called in to review the event with Operations
management.
A plant management duty team conducted an investigation of the event.
- The team reviewed the licensee's investigation report and interviewed the work control supervisor involved with the clearing of the OOS. The team also reviewed applicable
{
system and administrative procedures, and RWCU system drawings. The team g
I concluded that the licensee had appropriately reviewed the circumstances involving this event and implemented prompt corrective actions. The team also concluded that control room operators had isolated the drain down in a timely manner. No deficiencies were identified during this review, c.
Conclusions i
The licensee had appropriately reviewed the circumstances involving the RWCU OOS configuration, which resulted in a drain down event. Licensee corrective actions were prompt. Control room operators isolated the drain down in a timely manner.
Operations Procedures and Documentation O3.1 Procedures and Procedural Usaae
- a.
Insoection Scooe (71707)
The team assessed procedure adequacy and usage through observation of activities in the contro! room and in the plant. The review included the following procedures:
LAP-100-40, " Procedure Use and Adherence Expectations," Revision 17
=
. LAP-200-3, " Conduct of Operations," Revision 38
-
LTP-700-2, " Control Rod Drive Friction and Settling Testing," Revision 7 i
-
'
LOP-RH-07, " Shutdown Cooling System Startup, Operation, and Transfer,"
=
Revision 42 LOP-RH-16, " Raising and Lowering of Suppression Pool Level," Revision 16
-
LGA-RH-01, "Altemate Vessel Injection Using Shutdown Cooling Return,"
-
Revision 7 -
--
LGA-RH-02, "Altemate Vessel injection Using Head Spray Line," Revision 7
,
.:
LGA-SC-02, "Altemate Vessel Injection Using Standby Liquid Control System,"
(deleted)
LGA-SC-102, " Unit 1 Alternate Vessel Injection Using Standby Liquid Control
System," Revision 0 LGA-SC-202,' Unit 2 Attemate Vessel injection Using Standby Liquid Control
System," Revision 0 LAP-820-2, " Procedure Preparation, Revision, and Review," Revision 44
LAP-820-3, " Station Procedure Distribution," Revision 30
b.
Observations and Findinas The team observed strict use of procedures by NSOs in the control room. The team also observed the proper use of procedures in the plant. In general, the procedures provided sufficient detail and guidance to plant personnel. However, the team noted minor discrepancies during review of Procedures LGA-RH-01, LGA-RH-02, LGA-SC-02, LOP-RH-07, and LOP-RH-16.
On April 1,1999, the team audited the locked cabinets at the Unit 1 and 2 Remote Shutdown Panels to determine whether the abnormal operating procedures were the current revision. The team determined that the locked cabinets did not have the latest revision to LGA-RH-01 and LGA-RH-02, approved on March 16 and 15,1999, respectively. The team considered the safety significance minimal due to the minor scope of the revision which was generally administrative. Additionally, two unit-specific procedures had superceded Procedure LGA-SC-02 due to a plant modification replacing three 50 percent RWCU pumps with two 100 percent pumps. The new procedures had been approved on March 13,1999, but were not in the locked cabinets at the remote J
shuidown panels at the time of the team's inspection.
I The team reviewed the process for distribution of new and revised procedures. The administrative procedures specified normal distribution every Friday and allowed for an accelerated distribution if a reviewer determined that the procedure change was important to plant operation. The procedures found to be out of revision and superceded had not been identified for accelerated distribution. Therefore, in accordance with the licensee's administrative procedures, the procedures were initially distributed to the Work Control Center to allow for subsequent dhtribution at the shutdown panels within a week
,
'
after receipt. This had not yet occurred at the time of the team's review. Although this procedure distribution practice met the licensee's administrative requirements, the team j
questioned the timeliness, particularly since the practice could allow as much as a week-t
'
delay between the updating of control room procedures and the updating of the same procedure located in a locked cabinet at the remote shutdown panels.
The team also identified a discrepancy between the required position of the governing thermal overload bypass switch for motor operated valves. Precaution C.5 in LOP-RH-07 stated that during routine operation of various motor operated valves, including 1(2)E12-04A/B, the goveming thermal overload bypass switch located in the control room should be in " TEST" position during valve motion. After completion of valve motion, the thermal overload switch should be returned to and left in the ' NORMAL" l
position for emergency valve operation. However, for the same valve,1(2)E12-04A/B, precaution C.2 in Procedure LOP-RH-16, stated that the goveming thermal overload j
1
!
l
m
-
q
\\
.
b bypass switch should be in " BYPASS" position during valve motion. The team verified that procedure LOP-RH-16 was incorrect since the required position was " TEST" as denoted on the control room board nomenclature and in Procedure LOP-RH-07. The
" BYPASS" position was not provided at the switch but control room operators had been trained or understood that the " BYPASS" position was the same as " TEST". This issue was discussed with the licensee representatives who subsequently initiated a procedure change request for Procedure LOP-RH-16 to change " BYPASS" to " TEST". The licensee initiated PIF L1999-01740 to document this procedure discrepancy. The inaccurate instruction in Procedure LOP-RH-16 was considered to constitute a violation of minor significance and is not subject to formal enforcement action in accordance with the NRC enforcement policy.
c.
Conclusions The licensee properly used procedures in the control room and in the plant. In general, procedures provided sufficient detail and guidance to plant personnel. The timeliness of procedure change distribution could result in the control room having a different revision of a procedure than the remote shutdown panels.
Operator Training and Qualification j
05.1 Modification Trainina a.
Inspection Scope (71707)
The team assessed operator knowledge of system modifications performed during the extended outage by conducting interviews with operations personnel. Included in the assessment was a review of the modification, training lesson plan, and data showing when operations personnel had been trained. The design change packages (DCPs)
selected for review included:
DCP 9600466, " Revise 2E12-F0048 Valve to Address " Hot Shorts" Issue"
-
DCP 9700543, " Replace Unit 2 B Residual Heat Removal (RHR) Suction
-
Strainer" DCP 9700621, "2E21-N001/N009 Setpoint Change: Division 1 Low Pressure
Core Spray Discharge Pressure Switch" DCP 9900015, " Reactor Building Fuel Pool Exhaust Radiation Monitor Calibration
Setpoint Change" b.
Observations and Findinas The team interviewed several NSOs and SROs and determined that the operators had knowledge of the modification and understood, in general, how it affected their area of responsibility. The lesson plans used for the modification training were adequate and training records accurately documented personnel instruction on the modifications selected.
Two of the DCPs selected by the team (9700543 and 9900015) involved control room annunciator setpoint changes. The team noted that setpoints listed in the annunciator
.
.
.,
response procedures differed " rom the DCP setpoints. Operations personnel explained that, in general, the annunciator response procedure setpoints were based on Technical Specifications, UFSAR, or vendor recommended setpoints. Additionally, training personnel stated that operators were instructed that actual alarm setpoints were conservative, nominal values which differed slightly from annunciator response procedure setpoint values to compensate for electronic drifting and calculation errors.
Additionally, the operators were expected to be knowledgeable on the use of the electronic data base (Electronic Work Control System) to determine actual alarm setpoints. However, the team interviewed four NSOs and noted that all four believed that annunciators were set to alarm at the annunciator response procedure setpoints.
Although the safety significance was minimal, the team was concerned that operators were unaware of the difference between annunciator response procedure setpoints and actual setpoints. Additionally, operators interviewed were not familiar with the Electronic Work Control System and the ability to retrieve actual alarm setpoints. The licensee acknowledged the need to remind operators of the difference between annunciator response procedure setpoints, actual calibrated setpoints, and use of Electronic Work Control System.
c.
Conclusions The licensee conducted operator training at an acceptable level to provide operators with the skill and knowledge necessary to operate systems modified during the Unit 2 outage.
Some operators lacked knowledge of the difference between the annunciator response procedure setpoints and the actual alarming setpoints.
07_
Quality Assurance in Operations O7.1 - Self-Assessment a.
Insoection Scope (93802)
The team evaluated the assessment process within the operations department and assessments performed by the Nuclear Oversight department. The following documents were reviewed:
"LaSalle Station Restart Plan," Revision 4
-
"LaSalle Nuclear Oversight Monthly issues Report," February 1999
+
" Unit 2 Integrated Operations Performance Review (IOPR) Test 1," February
-
1999
" Unit 2 IOPR Test 2," March 1999
.
" Operating Department Additional [ Restart issue Review Committee] RIRC Topic
.
Review"
"LaSalle Station Assessment Plan, Nuclear Oversight Assessment
+
NOA-01-99-003"
"LaSalle Station Assessment Plan, Nuclear Oversight Assessment
-
NOA-01-99-022"
'
l i
e '
l b.
Observations and Findinas The licensee's restart plan described the process for establishing the plant restart readiness and review and verification efforts provided by various groups. The restart readiness reviews included those performed by the Restart Issue Review Committee.
'
The Restart issue Review Committee had primary responsibility for determining what activities were required to be completed by restart and verification of satisfactory implementation. The Nuclear Oversight group provided independent assessment of l
plant readiness. The team reviewed the scope and content of the Nuclear Oversight i
assessments and results. The team noted that the scope of reviews were wide-ranging in numerous areas including radiation protection, industrial safety, training accreditation, maintenance work practices, operations procedure adequacy, configuration control, and material condition. The assessments were probing and challenged the line
{
organizations' overall performance and readiness for plant restart. The IOPRs consisted of observations of specific plant evolutions to assess the readiness of the operations department to safely restart and operate the plant. Based on the review of lOPR results,
]
the team concluded that the IOPR was effective at evaluating operations performance as compared to station standards. Areas observed by the IOPR included control room
)
communications, procedure usage, briefings, and interfaces with other plant
!
departments.
c.
Conclusions The Nuclear Oversight assessment activities were wide-ranging and effectively j
challenged the site organizations' overall performance and readiness for plant restart.
Based on a review of completed IOPRs summaries, the team concluded that the IOPR process was effective in evaluating the operators' performance against station standards.
II. Maintenance and Surveillance
]
M1 Conduct of Maintenance and Surveillance
]
M1.1 General Comments on Observed Surveillance Testina Activities a.
Inspection Scope (61726)
The team observed a portion of surveillance testing activities taking place during the inspection week. Most of the observations centered around activities in the main control room.
b.
Observations and Findinas The team observed all or portions of the following surveillance / test activities:
LOS-DG-M2, "2A Diesel Generator Operability Test"
.
LFS-100-4, Attachment A," Core Alterations Shiftly Surveillance"
.
LES-EH-204, " Combined Intermediate Valve Limit Switch Test and Inspection"
.
LIS-RT-210, * Reactor Water Cleanup High Differential Flow isolation Calibration"
.
'19
I
.
i
{
.-
LTP-700-2, " Control Rod Drive Friction and Settle Testing"
.
The team observed good procedure use on the part of control room operators and other involved personnel. Communications during these surveillance testing activities were generally good. Control room personnel were kept informed of the testing status, out of service equipment, and expected alarms. A minor problem was identified by the licensee with respect to the revision being used of procedure LOS-DG-M2. Revision 41 of this procedure required the NSO to log the start time of the diesel, yet there was no control room indication to indicate the time of the diesel generator local start. This discrepancy was documented in PIF L1999-01720 for subsequent followup.
l c.
Conclusions
)
The surveillance test activities observed were generally adequate and properly implemented. Communications between the control room and personnelin the field involved in the activities was generally good. Control room personnel were kept informed of the testing status, out of service equipment, and expected alarms.
l Ill. Enoineerina E1 Conduct of Engineering E1.1 Temoorary Modification Review
. a.
Insoection Scope (37551_)
The team performed reviews of temporary modifications (Tmod), and associated engineering documentation, and conducted walk-downs to verify proper installation. The team selected four Tmod packages for review from the seven Tmods which were expected to remain installed beyond the Unit 2 restart. The fol lowing Tmods were reviewed:
2-0074-96, " Supply altemate sump pump for Fire Sump 2DT04PA"
2-0100-96, " Bypass static transfer switch in Panel 2FP05E" l
2-0019-97, " Install temp power for the hot shop bead blaster "
2-0026-97, "2B DG day tank tygon tubing level indicator"
=
b.
Observations and Findinas The team's review of the Unit 2 Tmod list indicated that there were approximately
,
30 Tmods at the time of the inspection. Licensee representatives stated that all but
!
seven Tmods would be removed before Unit 2 restart.
I I
The team reviewed Tmod packages 2-0074-96,2-0019-97, and 2-0026-97 and determined that the packages were generally of good quality and verified that the Tmods were appropriately installed. With respect to Tmod package 2-0100-96, the team concluded that it was properly installed; however, the Tmod was non-conservative compared with the original plant design.
l
.
O Tmod 2-0100-96 This Tmod was installed on December 30,1996, and had been extended several times, with the last extension made on March 15,1999. This Tmod was scheduled to be removed after Unit 2 restart.
Panel 2FP05E consisted of a 2 kVA inverter (125 Vdc to 120 Vac) and a static transfer switch (AC34-1). This panel, which was part of the fire protection power supply system, provided 120 Vac power supp;y to eight ultra-violet fire detectors in the refueling area, and four sirens and numerous indicating lights in various areas. The static transfer switch was designed to automatically transfer the power supply from the 120 Vac source to the 125 Vdc source (safety-related battery) upon failure of the ac source. On December 16,1996, the static transfer switch failed. While waiting for the replacement part from the vendor, the licensee issued Tmod 2-100-96 on December 27,1996, to install a bypass to the static transfer switch, and to disconnect the 125 Vdc source from the inverter and install an alternate ac power source. The licensee later found the replacement pa.4 was no longer available because the inverter was an obsolete model.
The team noted that a 10 CFR 50.59 safety evaluation was not included in the Tmod package to provide the basis that no unreviewed safety questions were involved. The team was concemed that the Tmod had changed the design configuration of the fire protection power supply and that the condition had existed for over two years. The team also noted that the design basis for the fire protection power supply was described in the LaSalle UFSAR Section 9.5.1.3, ' Safety Evaluation', which stated,
"As required by the (National Fire Protection Association] NFPA, loss of power to the fire protection system is prevented by using the unit's 125 Vdc power supply for a power source."
The team concluded that the installation of the Tmod disabled the 125 Vdc power source, which resulted in the system being inconsistent with the design basis as specified in the UFSAR. The team determined that the design basis noncompliance constituted a violation of 10 CFR 50.59(b)(1), which required the maintaining of records includhg written safety evaluation providing the bases for the determination that the l
Tmod change does not involve a Unresolved Safety Question. The violation of
'
10 CFR50.59 is considered a violation of NRC requirements. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV), consistent with Appendix C of the Enforcement Policy (NCV 50-374/99007-02, Failure to Perform Safety Evaluation).
This violation was in the licensee's corrective action program as PlF L1099-01719.
The team discussed this issue with licensee management. Licensee representatives stated that PlF L1999-01719 had been issued to review all existing Tmods for similar problems and to correct them, as required. Additionally, the team was informed that the licensee's Tmod process had improved significantly during recent years, and new procedures existed to provide administrative controls of the Tmod process and the safety evaluation process. The team reviewed Procedure NSWP-A-21, " Temporary Modification", Revision 0, and noted that Section 6.2.3.h3 adequately prescribed the 10 CFR 50.59 requirements for Tmods and referenced hocedure NSWP-A-04, " Safety Evaluation Process", Revision 11, for the safety. *4on process. The team I
- - _ _ _ _ - _ _ _ _ _ _
-
_-_
_ _ - _ _ _ _ _ _ _ _ _ -.
.
-
.,
determined that Procedure NSWP-A-04, provided sufficient guidance for safety evaluat.bn preparation.
While reviewing Procedure NSWP-A-21, the team noticed that Section 6.7 discussed Tmod extensions. This section required a justification be provided for Tmod extension and Exhibit J, "Tmod Extension Installation Justification", be filed with the Tmod package.
The team requested a copy of the Exhibit J for the Tmod 2-100-96 extension which had been approved on March 15,1999. The licensee stated that the new procedures did not apply to existing Tmods. However, PlF L1999-01374, had been written after the extension of Tmod 2-100-96 was made. The PIF required that Exhibit J be prepared and filed for extensions made after the issuance of the PlF. Previously, a Tmod could be extended numerous times without justification for an extension. The team concluded that the requirement to provide an Appendix J for Tmod extenaians was an improvement from previous practices.
On April 3,1999, the licensee completed a safety evaluation and operability determination for Tmod 2-100-96. The licensee's evaluations concluded that no Unresolved Safety Question resulted from the Tmod and a TS revision was not required.
The NRC reviewed the licensee's determination and no concems were identified. The licensee informed the team that attempts would be made to replace the inverter and the static transfer switch with a newer model prior to Unit 2 restart.
c.
Conclusions The Tmod packages were generally of good quality and appropriately installed. The licensee had adequate procedures to provide administrative controls of the process and safety evaluation preparation for new Tmods. However, one Tmod had changed the plant configuration non-conservatively; also, this was not consistent with the design basis l
specified in the UFSAR, and no written safety evaluation was provided by the licensee to determine that the change did not involve a Unresolved Safety Question. This was a Non-Cited Violation.
E1.2 Ooerability Evaluation (OE) Review
,
a.
Insoection Scooe (37551)
The team reviewed a selected sample of completed operability evaluations. The
,
following operability evaluations were reviewed:
l OE98021, "DG Air Start Valves Do Not Meet Design Requirements'
-
' OE98034, " Nuclear Over-site identified Potential Qualification issue for RCIC 250
+
VDC Motor Control Center "74" Relays'
I b.
Observations and Findinos For systems affected by these operability determinations, the team verified that the technical basis for system or component operability was supported by engineering evaluations, calculations and/or corrective measures. With respect to OE98021, the
. team noted that although the installed valves were currently operable, the licensee I
. _ - _
. - - _..
.
._ _ __ _
.
'
.,c-planned additional corrective actions to replace the diesei generator air start valves with a valve having better performance characteristics. With respect to OE98034, laboratory test data supported the component qualification. No deficiencies were identified during these reviews.
c.
Conclusions The operability evaluations reviewed were of good quality and the conclusions were supported by adequate technical justification.
E7 Quality Assurance in Engineering Activities E7.1 Enaineerina Self-Assessments a.
Inspection Scope (37551)
The team reviewed two engineering self-assessments of Unit 2 restart readiness to determine their adequacy. In particular, the team reviewed the licensee's identified action plan as it pertained to the engineering area.
b.
Observations and Findinos The licensee performed several self-assessments in the engineering area pertaining to Unit 2 restart readiness. The team reviewed the following two self-assessments:
" Engineering Self-Assessment of LaSalle Unit 2 Readiness for Restart,"
-
March 22,1999
" System Engineering Assessment of Unit 2 Readiness for Fuel Load," March 23,
1999 The first self-assessment was completed by the licensee's corporate staff. The assessment was conducted in accordance with an assessment plan, entitled "A Comprehensive Assessment of LaSalle Unit 2 Restart Readiness, Engineering," dated February 1,1999. This assessment plan was later revised on March 5,1999. The
,
assessment covered five engineering areas: engineering program, system engineering, design engineering, engineering administration, and engineering quality. Each area was again divided into many subareas (such as motor-operated valves, environmental qualification, and fire protection / Appendix R), and each subarea was assessed in several categories (such as staffing, corrective actions, ar d operability determination). The assessed result of each category was classified as: 1) a restart issue was identified; 2) a weakness was identified; 3) no issue was identified; and 4) not applicable for this category. A matrix was created using these assessment results. By reviewing this
'
matrix, licensee management was able to understand the assessment results quickly and to make prompt decision for proper actions. The team found this assessment to be comprehensive, the assessment method to be logical, and the presentation of the assessment results to be effective. The team's review of the assessment report revealed that the assessment had resulted in many good findings and recommendations.
For example, in the " relay" and fire protection / Appendix R subareas, the assessors
)
(
I
.
.
.
- - _ _ -
I
'
p identified strengths, deficiencies requiring corrective actions (not restart issues),
weaknesses, and recommendations, as appropriate.
The second self-assessment was completed by the site system engineering in response to a February 9,1999, memorandum entitled " Departmental Unit 2 Restart Readiness Assessment Guideline", from the chairman of the Restart issues Review Committee.
This assessment covered three major areas in system engineering: performance indicators, corrective action program, and lessons leamed focused self-assessment.
The team's review of the assessment report iridicated that this was an internal status report rather than an assessment report. The report was found to be of good quality and included sufficient data for plant management to understand the status of each area.
The assessment did not identify restart issues, but did identify weaknesses that needed to be addressed. The assessment also identified 18 engineering surveillances that were required for fuel loading. The final conclusion of the assessment indicated that system engineering was ready to support the fuel load of Unit 2.
c.
Conclusions The team concluded that engineering self-assessments were of good quality and weil j
structured. The self-assessment performed by the corporate staff was comprehensive.
The assessment method was logical, and the presentation of the assessment results
'
was effective. This assessment had resulted in many good findings and recommendations for site engineering to improve its performance.
V. Manaaement Meetinas X1 Exit Meeting Summary The team presented the results of these inspections to licensee management listed below at an exit meeting on April 2,1999. The licensee acknowledged the findings presented. The team i
asked the licensee if any materials examined during the inspection should be considered j
proprietary. The licensee identified none.
l l
l
.
.
~
.
'4.*
PARTIAL LIST OF PERSONS CONTACTED Commonwealth Edison S. Barrett, Maintenance Manager J. Benjamin, Site Vice President -
'
C. Berry, Chief of Staff.
,
E. Carroll, inspection Coordinator D. Farr, Operations Manager F. Gogliotti, Design Engineering Manager C. JeanBlanc, Staff Support - Operations
'
G. Kaegi, Site Training Manager --
M. Lohmann, Engineering Administration Manager J. Meister, Engineering Manager T. O'Connor, Plant Manager
. J. Place, Radiation Protection Manager W. Riffer, Q & SA Manager F. Spangenberg, Regulatory Assurance Manager R. Stachniak, Nuclear Oversight Assessment Manager INSPECTION PROCEDURES USED
,
iP 37551:
Onsite Engineering IP 61726:
Surveillance Observation IP 71707:
Plant Operations IP 93802:
' Operational Safety Team inspection ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-374/99007-01 NCV Control room shift manning requirements not met
' 50-374/99007-02 NCV Failure to perform safety evaluation Closed 50-374/99007-01 NCV Control room shift manning requirements not met 50-374/99007-02 NCV Failure to perform safety evaluation Discussed None
,
.
i g
LIST OF ACRONYMS USED
'CFR Code of Federal Regulations CWPl Common Work Practice Instruction DCP Design Change Package DG Diesel Generator DRP Division of Reactor Projects HLA Heightened Level of Awareness IOPR Integrated Operations Performance Review IP Inspection Procedure kVA Kilo Volt Ampere LAP LaSalle Administrative Procedure LES LaSalle Electrical Maintenance Surveillance j
LFS LaSalle Fuel Handling Surveillance LGA LaSalle General Plant Abnormal Procedure LGP LaSalle General Procedure
-
LIS LaSalle Instrument Surveillance LMP LaSalle Maintenance Procedure LOP LaSalle Operating Procedure LOS LaSalle Operating Surveillance LTP LaSalle Technical Staff Procedure NCV Non Cited Violation NSO Nuclear Station Operator NSP Nuclear Station Procedure NSWP Nuclear Station Work Procedure
'
OE Operability Evaluation OOS Out of Service -
PIF Problem identification Form RCIC Reactor Core Isolation Cooling RHR-Residual Heat Removal RWCU Reactor Water Cleanup SRO Senior Reactor Operator
-
Tmod Temporary Modification TS Technical Specifications UFSAR Updated Final Safety Analysis Report Vac Volts Alternating Current Vdc Volts Direct Current 26