IR 05000445/1993020
| ML20045A536 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 06/07/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20045A529 | List: |
| References | |
| 50-445-93-20, 50-446-93-20, NUDOCS 9306110041 | |
| Download: ML20045A536 (17) | |
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APPENDIX U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-445/93-20 50-446/93-20 Operating Licenses:
NPF-87 NPF-89 Licensee:
TL Ilectric Skyway Tower 400 North Olive Street Lock Box 81 Dallas, Texas 75201 Facility Name:
Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 Inspection At.
Glen Rose, Texas Inspection Conducted: April 26 through May 13, 1993
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Inspectors:
W. B. Jones, Senior Resident Inspector D. N. Graves, Senior Resident Inspector T. Taylor, Senior Resident Inspector, Region III G. E. Werner, Resident Inspector R. V. Azua, Resident Inspector D. L. Kelley, Reactor Inspector J. Whittemore, Reactor Inspector Approved:
uAL 1 D L. A. Yandell, Chief, Project Section B 0 tte Division of Reactor Projects Inspection Summary Areas Inspected (Units 1 and 2):
Special announced inspection of Unit 2 operational activities, startup test witnessing, identification and resolution of plant deficiencies, and self-assessment activities.
Results (Units 1 and 2):
Plant evolutions were well thought out and measures were implemented to
mitigate potential plant transients (Section 2.1.1).
The shift supervisor (SS) and unit supervisor (US) demonstrated
very good command and control.
Positive control room access was maintained at all times (Sections 2.1.2, 2.1.6 and 3.1)
9306110041 9306.08 PDR ADOCK 05000445 O
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-2-Communications between reactor operators (RO), and also between the R0s
and US, were excellent. Control room logkeeping was good (Section 2.1.2).
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R0 response to annunciators was very good. An instance was noted where
an unexpected fire alarm was initiated because the US was not notified when welding activities were resumed (Section' 2.1.3).
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Excellent. coordination was noted between control room personnel, the
field support supervisor (FSS), and the auxiliary operator (AO) for placing secondary equipment in service. Very good oversight of A0 activities was provided by the FSS (Sections 2.1.4 and 2.1.5).
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Excellent coordination was noted between operations, engineering, and
training personnel in preparing for and executing the remote shutdown test. The loss of offsite power test was similarly well coordinated between operations and engineering personnel (Section 3).
The licensee had identified and taken action to address plant
deficiencies which were identified during the Unit 1 initial startup (ISU) and had applied the lessons learned to Unit 2 (Section 4.1).
The maintenance work activity backlog was well controlled.
The number
of Unit 2 emergent work activities had increased significantly above.the
goal. These were mostly attributable to placing secondary plant equipment in service for the first time (Section 4.2.1).
The licensee had appropriately prioritized work activities to be
performed with the plant in Mode 3.
An extensive work schedule was being developed for the planned Mode 5 surveillance outage I
(Section 4.2.1).
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The corrective maintenance backlog on hold for parts was found to be
small (Section 4.2.2).
The independent safety engineering group (ISEG) had implemented numerous
surveillances of ISU activities and was effective in identifying-issues-pertinent to the Unit 2 startup and power ascension program (Section 5.1.1).
ISEG surveillance findings were appropriately distributed to site
management.
Senior management was provided an overview of these.
findings (Section 5.1.1).
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The ISEG assessment group was effective in reviewing Unit 2 readiness,
its impact on Unit.1, startup' risks, and risks for proceeding above 50 per:ent power (Section 5.1.2).
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The senior management quality assurance meeting provided an effective
forum for reviewing current plant issues and assessing potential plant deficiencies (Section 5.2).
The licensee's 50 percent power assessment was well conducted. _ The
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attributes identified for each organization to consider were appropriately addressed (Section 5.3).
Attachment:
Attachment - Persons Contacted and Exit Meeting
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DETAILS 1 INSPECTION SCOPE AND OBJECTIVES On April 26 through May 13, 1993, the inspectors conducted a 50 percent assessment of licensed activities for CPSES Unit 2.
The inspectors utilized the guidance provided in NRC Inspection Procedure 93806, " Operational Readiness Assessment Teams (0 RAT) Inspection." The primary objective of this inspection was to evaluate Unit 2 operation up through the 50 percent power ascension plateau.
This was accomplished through direct observation and the evaluation of personnel that control and organizations that support plant operations in order to verify that they were functioning effectively.
The inspection concentrated on Unit 2 control room operations and related activities supporting the facility's safe operation, startup test activities, identification and resolution of plant deficiencies, and implementation-of self-assessment activities. The inspection also included a review of plant deficiencies which were identified as a result of the Unit 1 ISU program and the corrective actions that were taken to address these deficiencies on
Unit 2.
Unit 2 was operating at approximately 48 percent power. On May 4, while decreasing reactor power for the remote shutdown test, a loss of main feedwater occurred and Unit 2 was manually tripped. _ The unit was returned to Mode 2 on May 5 and Mode 1 the following day. At the end of the inspection period, Unit 2 was resuming power operations following the loss-of-offsite power testing. At the beginning of the inspection per od, Unit 1 operated at essentially 100 percent throughout this inspection persed.
2 PLANT OPERATIONS (93806)
The inspectors observed the performance of two operating crews over a 3-day period. The purpose of the observations was to assess plant operations at the 50 percent power ascension testing plateau. This included control room activities, surveillance testing, corrective maintenance troubleshooting, and plant control system calibration. Several surveillance and power ascension test briefings were observed.
2.1 Conduct of Operations 2.1.1 Command and Control
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The inspectors observed activities involving control room personnel during steady state operations and planned transients. The SS, US, and control room operators interfaced effectively with one another.
Routine operator actions were conducted using good self-verification techniques. The US appropriately -
restricted personnel access to the control room and the controls area.
The inspectors noted that test preparation included a review of expected plant
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responses as well as possible unplanned plant transients. An example involved
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L a US's decision to delay the performance of the main generator load swing
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test.
The test allowed performance with one main feedwater pump; however, he decided to wait until the second main feedwater pump was warmed up and in
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standby prior to beginning the test.
2.1.2 Control Room Communications and Logkeeping The inspectors noted that the flow of information within the control room was.
'i effective. Operators kept one another informed of their actions, and USs kept operators informed of upcoming evolutions.
Good communications were noted between maintenance personnel and the USs in keeping them apprised of ongoing maintenance activities.
The inspectors observed that the operating crews effectively utilized alarming timers to ensure that periodic logkeeping functions were not missed. The inspectors also noted that when logkeeping functions required an operator to go behind the control boards or to other areas in the control room to. log data, the other operator was always informed.
If the other operator was
occupied, the logkeeping was delayed until plant evolutions allowed the operator to take the log readings.
During the inspection period, the inspectors observed several surveillance
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tests, one hazard material spill drill, and the paralleling of the main feedwater pumps. The inspectors attended selected test briefings, including the one for paralleling the main feedwater pumps. The briefings were detailed
and clear.
Expected plant responses and possible problem areas were addressed.
I 2.1.3 Operator Response to Control Room Annunciators and Indicators The inspectors noted that when an annunciator sounded the R0 routinely
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announced the alarm. Control room personnel actions taken in response to the alarm were also announced.
On April 28 the hydrogen pressure regulator to the volume control tank was discovered mechanically bound.
The operators took manual control to reduce volume control tank pressure and also notified the chemistry department that
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the reactor coolant system hydrogen concentration would increase due to the increased volume control tank hydrogen pressure. The instrumentation and control (l&C) technicians were immediately notified and the A0 was dispatched to check the volume control tank pressure.
These actions were expedient and appropriately performed.
One area of weakness that was observed concerned continuous. fire alarms in the fuel building.
It appeared that welders in the fuel building had not informed the control room that welding was being continued from the previous day.
Discussion with operating personnel indicated that on occasion, when welding activities restarted after a delay, work crews failed to inform the control room. This apparently occurred because the work crews assumed that, aftar the paper work was signed, there was no need to inform the control room of delays
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-6-or work restart. The operators recalled that welding had been done the previous day. An A0 was sent to the fuel building to verify that this was the case. The welding crew subsequently modified the protective tent they had
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erected and the fire alarms ceased.
2.1.4 Unit 2 Heater Drain Tank Level Control Good coordination between the US, A0, FSS, and I&C technicians was observed during the attempted restoration of Valve 2LV-2594 (Unit'2 heater drain tank alternate drain valve) to _ a normal operating configuration.
The valve had been pinned to allow handwheel positioning of the air-operated valve.
The inspectors noted discussions between the FSS and the US on valve operation and
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what manipulations would be necessary to shift to automatic control.
The US
accompanied the FSS to the valve to observe and coordinate its restoration.
Several unsuccessful attempts were made to remove the pin.
I&C technicians were contacted and, after they inspected the valve, the I&C technicians determined that the valve required corrective maintenance before it could be placed in automatic operation.
2.1.5 Turbine Overspeed Protection Test
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On May 7 the inspectors observed the performance of Procedure 0PT-217B,-
Revision 0, " Turbine Overspeed Protection System Test," Section 8.4, Testing-the Mechanical Overspeed Devices Manually. The test was conducted at the local control panel by the turbine building A0 with supervision and test coordination provided by the FSS.
i The US conducted a briefing on the surveillance test with the R0, FSS, and A0 present. A review of the procedure, expected system response, and individual responsibilities were discussed to ensure each participant understood the test sequence.
The FSS was given command and control function of the evolution since all actions were accomplished locally.
During the test briefing, the turbine building A0 stated that he had never i
exercised the overspeed devices locally; therefore, the US walked the 'A0
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through the procedure two times prior to performing the surveillance. The US ensured that the-A0 was fully cognizant of the procedural requirements and plant response prior to beginning the test.
The test was completed and all data were within specification. The inspectors did note that additional attention to turbine speed was not provided, even though overspeed protection was inoperable during portions of the surveillance i
test.
Excellent supervision and self-verification were used throughout the test.
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2.1.6 Reactor Startup The inspectors observed control rod shutdown bank referencing conducted in accordance with Procedure IP0-0038, Revision 0, " Power Operations." Good control of the evolution by the US was observed as well as excellent use of
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-7-procedures and repeat backs. Access to the Unit 2 control room area was well controlled and distractions were limited to critical work items.
2.2 Conclusions The SS and US demonstrated very good command and control.
Positive control room access was maintained.
Communication between R0s and between R0s and the US was excellent.
Control room logkeeping was good.
Plant evolutions were well thought out, and measures were implemented to mitigate potential plant transients. The R0s' response to annunciators was very good. An instance was noted where an unexpected-fire alarm was initiated
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because the US was not notified when welding activities were resumed.
Excellent coordination was noted between control room personnel, the FSS, and the A0 for placing secondary equipment in service.
Very good oversight of A0
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activities was provided by the FSS.
3 STARTUP TEST WITNESSING AND OBSERVATION (72302,70316)
3.1 Remote Shutdown Test On May 6 the licensee successfully initiated and completed Procedure 150-225B,
" Remote Shutdown Capability Test at Power." The performance of the test was required to satisfy licensee connitments to Regulatory Guides 1.68 and 1.68.2 as documented in the Final Safety Analysis Report.
Prior to performing the test, the operating crew simulated the test performance on the plant specific simulator. The inspectors witnessed the crew simulate performance of the test twice on the simulator.
The inspectors noted that the operators executed the simulated scenario with the same degree of. professionalism that would be expected when' working with actual plant components. A prejob briefing was helc, procedural usage and adherence were very good, and excellent communications were demonstrated.
The procedure was successfully executed on the simulator, but a procedural problem was identified. Step 9.3.6 of Procedure 150-225B specified the termination criteria for testing. The termination criteria were developed to ensure a safe and orderly return of plant controls to the control room. One of the criteria specified that the test would be terminated if indicated wide-
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range steam generator level was reduced to less than 60 percent.
From operational experience, operations personnel were confident that the reactor trip / turbine trip would result in a steam generator " shrink" with level dropping below 60 percent indicated wide-range level.
Since the-test required an at-power reactor trip, operations personnel felt that this particular termination criterion would immediately be satisfied and, thus, the remainder of the test could not be performed.
Prior to proceeding with the test, the test review group met (Meeting 38) to discuss the apparent test procedure anomaly. A Westinghouse representative
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-8-stated that a wide-range minimum steam generator level value of 60 percent was designed to keep the auxiliary feedwater nozzles covered to prevent adverse thermal affects once auxiliary feedwater was initiated.
However, there was no concern with a momentary transient caused by level " shrink" to below 60 percent indicated on the wide-range detectors. The test review group concluded that the actual termination criteria should be based on the prevention of uncovering the top of steam generator tubes and that less than 5 percent level indicated on narrow range instrumentation, which was also designated as a termination criterion, allowed sufficient margin for this to be accomplished. Accordingly, the test procedure was revised to delete the less than 60 percent steam generator wide-range indicated level termination-criterion.
At 12:30 p.m. the licensee convened a final pretest briefing. The test was to be conducted by a US with the assistance of two licensed R0s and two A0s in order to simulate minimum staffing requirements.
The US, who would direct the test, clearly communicated his expectations to the operators and to the Unit 2 on-shift operating crew which would not be participating in the test.
For the test to be successful, it was imperative that the on-shift operating crew not.
communicate with or manipulate plant equipment in such a manner that would invalidate the test.
It was made clear that the operating crew would take actions necessary, regardless of test impact, to protect plant equipment and personnel. The operating crew was instructed to' call out any actions taken in order that performance and test personnel could log the actions to determine their impact on the test. After the briefing by the US, a briefing was conducted by the lead performance and test engineer to define the goals and objectives as well as the test acceptance and termination criteria.
At 2:15 p.m. the test was commenced with the reactor being tripped from 18 percent power.
The reactor trip was initiated outside the control room by opening the reactor trip breakers.
Control was transferred to the hot shutdown panel via the remote transfer panel.
The inspectors observed the test from the control room, remote transfer panel, and hot shutdown panel.
The licensee promptly implemented Sections 9 and 10 of Procedure ABN-905B,
" Loss of Control Room Habitability," which provided the instructions for achieving and maintaining a safe shutdown condition with the main control room controls and instrumentation unavailable.
The US aemonstrated excellent command and control abilities and had the unit stabilized at 2:37 p.m.
Communications between the US, R0s,'and A0s were very good. Good use of repeat back statements was made to ensure that instructions and information were understood.
At 2:40 p.m. performance and test personnel began collecting the required data to ensure that the safe shutdown condition was maintained for a minimum of 30 minutes prior to terminating the test. The acceptance criteria were based on the parameters of pressurizer pressure, pressurizer level, steam generator pressure, and actual steam generator level being within specified bands for at least a 30-minute interval. The inspectors independently observed that the i
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parameters were maintained and verified there was no assistance or direction provided from the control room.
3.2 Turbine Generator Trip with Coincident loss of Offsite Power On May 8 the licensee executed Procedure ISU-222B, " Turbine Generator Trip with Coincident loss of Offsite Power," Revision 1, which was witnessed by NRC inspectors. NRC inspectors had previously evaluated Procedure 150-222B and _
found it to conform to licensee commitments to Regulatory Guide 1.68, " Initial Test Programs for Water-Cooled Nuclear Power Plants," as described in Section 14 of the Final Safety Analysis Report. This evaluation is documented in NRC Inspection Report 50-445/92-21; 50-446/92-21.
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The purpose of this test was to demonstrate that Unit 2 responds properly following a turbine / reactor trip with no offsite power available.
Satisfactory response required the transfer of Unit 2 power to the standby diesel generator power supplies along with operation of the equipment necessary to maintain the reactor in a safe shutdown condition.
Two days prior to the performance of this test, the licensee had shut down the reactor to satisfy the requirement to demonstrate the capability of the plant to be shut down from outside the control room as discussed in paragraph 3.1 of
this report. The licensee had resumed critical operations and raised power to approximately 21 percent indicated reactor power prior to commencing this test.
Reactor power was subsequently lowered to approximately 16 percent reactor power and 130 MWe turbine-generator power to establish initial conditions for the test.
At 9:20 p.m. the shift supervisor and unit supervisor convened a prejob briefing to define responsibilities and communicate expected and potential plant responses to the test. The supervisors clearly communicated roles and responsibilities to those who would be participating in the test. The cognizant performance and test division lead engineer then communicated to
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test participants and evaluators the initial conditions that had been established, the potential for a safety injection actuation signal to occur, and the termination criteria for the test. The Manager, Operations and.the Unit 2 Shift Operations Manager provided management oversight in the control
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room.
As a final prerequisite to the test, the licensee had planned to provide temporary power to the nonsafety Digital Rod Position Indication (DRPI) in order that operators would be assured of reactivity control, since DRPI-is
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lost upon loss of normal station power. The temporary indication system would1 prevent the need to emergency borate the reactor in order to ensure positive reactivity control-and would thus prevent the unnecessary creation of a large volume of radioactive liquid waste when the reactor coolant system would have
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to be diluted. At 10:21 p.m.,
the licensee attempted to switch the DRPI to its temporary power supply and the transfer was unsuccessful.
Normal power
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was immediately restored. However, in lieu of troubleshooting the temporary power supply to the DRPI, the Manager, Operations made the decision to proceed
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The test began at 10:25 p.m. with a manual trip of the turbine generator and the interruption of normal offsite power to the 6.9kV buses by the manual opening of Breakers 2EAl-1 and 2EA2-2.
The NRC inspectors witnessed the plant
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response to the manually initiated transient and noted no significant abnormalities.
A safety injection actuation signal did not occur.
Emergency power, via the emergency diesel generators was promptly supplied to vital
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station buses, which enabled operations to complete the test. The unit was
observed to have been taken to a hot shutdown condition without offsite power available. At 11:03 p. m. the test was successfully completed pending review of results by the performance and test and joint test groups.
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During the transition from the trip cucMition to hot shutdown, operations supervision demonstrated good leadership skills, operators demonstrated sound i
awareness of plant conditions, and the overall execution of the emergency operating procedures was good. No obvious errors in judgement or procedural implementation were noted by the NRC inspectors.
3.3 Conclusions i
Excellent coordination was noted between operations, engineering, and training i
personnel in preparing for and executing the remote shutdown test. The loss of offsite power test was similarly well coordinated between operations and engineering personnel.
4 IDENTIFICATION AND RESOLUTION OF PROBLEMS (93806)
4.1 Resolution of Startup Deficiencies The inspectors reviewed the licensee's lessons learned program to assess whether issues identified during Unit 1 startup were reviewed and resolved relative to Unit 2 operation. The inspectors sampled 10 percent of identified lessons learned. With one exception (manual Crane valves with gear converter operators) the inspectors found that the system engineers were knowledgeable of their system issues and had taken actions to resolve the problems identified through the lessons learned program. The corrective actions for the Crane valves, used in balance-of-plant systems, were subsequently reviewed
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and found to have been implemented.
One deficiency concerning the steam generator blowdown system had a temporary modification in place with a permanent fix being evaluated. The temporary modification was found.t e
appropriately implemented.
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backlogs.
Several outstanding work request and work orders were selected to evaluate its impact on safety-related and essential plant equipment.
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The Unit 1 and common equipment maintenance backlogs had not changed appreciably since the Readiness Assessment Team inspection conducted March 24-29, 1993 (NRC Inspection Report 50-445/93-16; 50-446/93-16).
It was noted that emergent work activities had accounted for a significant amount of the work requests initiated for Unit 2.
The emergent work activities had significantly exceeded the licensee's goals; however, many of the emergent work requests have resulted from balance-of-plant equipment being placed into service for the first time. This has also resulted in a notable increase in the number of work requests and work orders scheduled for plant outages.
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The inspectors reviewed the licensee's work scope scheduled for Mode 3 operation. These work activities included balance-of-plant steam leaks, which could not be isolated with the plant in power operation.
The work items to be completed during the Mode 5 outage planned for after completion of the ISU program were being reviewed and the work orders developed.
It was concluded that the licensee had established appropriate guidelines for reviewing and scheduling work activities which should be completed during the upcoming Mode 3 and Mode 5 outages.
The inspectors also reviewed the maintenance work history and outstanding work request for the chemical and volume control, residual heat removal, diesel generator, and main feedwater systems. The review showed, for the systems reviewed, that significant equipment problems encountered on Unit I during startup and operation were addressed and had not resulted in a repeat of.
similar significant problems on Unit 2.
4.2.2 Parts Availability The inspectors reviewed the work requests which had been placed on hold awaiting parts.
It was found that, as of May 4, there were 35 Unit 2 work orders on hold awaiting parts.
This compared very closely with 30 for Unit I and 35 for common equipment. None of the work orders had an appreciable operability affect on safety-related or essential plant equipment.
4.3 Conclusion The licensee had identified and taken action to address deficiencies which occurred during the Unit 1 ISU and applied the lessons learr-d to Unit 2.
The work activity backlog was well controlled.
The number of Unit 2 emergent work activities had increased significantly above the goal; however, these
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-12-were attributable to placing secondary plant equipment in service for the first time.
The licensee had appropriately prioritized work activities to be performed with the plant in Mode 3.
An extensive work schedule was being developed for the planned Mode 5 outage.
The work backlog on hold for parts was found to be small.
5 LICENSEE SELF-ASSESSMENT (93806)
5.1 Adequacy of Nuclear Oversight Activities
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The inspectors evaluated the ISEG activities, which involved the surveillance and assessment of Unit 2 startup activities.
The ISEG responsibilities included maintaining surveillance of unit activities to provide independent verification that those activities were being performed correctly.
The Final Safety Analysis Report and licensee organization charts indicated that the
Manager, ISEG reported to the Director of Nuclear Overview.
This reporting chain was administrative in nature as ISEG findings and concerns could be i
reported directly to corporate management. The licensee identified that the function of this group was to make detailed recommendations for revised procedures, equipment modifications, maintenance activities, operations activities, or other means of improving unit safety, to the Group Vice President, Nuclear Engineering _and Operations.
The inspectors observed that ISEG's two principle responsibilities were assessment and surveillance.
Each section consisted of four engineers and a manager.
For the startup of Unit 2, the surveillance section responsibility had been expanded to provide around-the-clock surveillance of startup testing activities.
The licensee had engaged eight contract inspectors to provide
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this surveillance of startup testing. One of the surveillance engineers had
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been designated as lead for this effort and was responsible for coordinating the efforts and reporting the findings of the contract inspection group.
The ISEG assessment section had performed various assessments that served to assure that the startup and related testing was being performed safely.
5.1.1 ISEG Surveillance The inspectors reviewed the genesis, review methodology, and findings of the ISEG surveillance section for activities pertaining to Unit 2 startup and testing.
Upon formation of the contract group, all of the inspectors were administered a training program for ISU testing that had been developed and
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implemented by the licensee's performance and test group.
When the training was completed, the prospective' inspectors had been issued qualification cards which they subsequently completed to attain qualification for the position.
The contract inspector ISEG surveillance section associated with Unit 2 startup utilized a desk top instruction, separate from the previously established ISEG surveillance procedures, as guidance for performing i
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surveillance of various ISU. tests. These surveillance instructions had been developed prior to the beginning of startup testing to cover all ISU_ testing.
Additional provisions had been made to notify surveillance personnel prior to the performance of specific steps in a test they had chosen to observe.
ISU tests had been marked to alert test personnel to notify surveillance personnel that these " steps of interest" were being performed.
Each instruction provided the following information to the individual conducting the surveillance:
Purpose of the test
Surveillance objectives
Notification points
Philosophy of notification point assignment
Test attributes and instructions for notification steps
Surveillance inspectors used field notes to report surveillance findings.
Each finding was documented on a field note form, which was an attribute of the normal ISEG surveillance procedure.
This form provided a method for entering findings into an electronic data base and tracking its resolution.
The surveillance findings were reported to the lead surveillance _ engineer.
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turn, the lead engineer issued a weekly startup test summary report, which was distributed to site management.
The inspectors reviewed a sample of surveillance field notes and weekly summary reports. The field note sheets indicated personnel observed, personnel contacted, applicable Technical Specifications, and governing documents or procedures.
The field. notes also provided details of the observations and
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indicated if additional documents such as corrective action or evaluations had been initiated by surveillance personnel.
Field notes did not indicate if other plant personnel had initiated other documents. The weekly summary reports contained a synopsis of each test observed, which included the test purpose, observations, and conclusions about performance adequacy. The weekly report also included a conclusion section, which identified problems and inconsistencies and went on to offer recommendations for resolution. When specific recommendations were adopted, they were usually issued in a monthly ISEG activities report. Theses recommendations were tracked to final resolution.
5.1.2 ISEG Assessment The ISEG assessment section had conducted assessments related to Unit 2 startup and testing activities.
These efforts included the following assessments that had been completed since the beginning of 1993:
Unit 2 readiness
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Unit 2 startup impact on Unit 1
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Unit 2 startup risk
Unit 2 risk to exceed 50 percent power
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-14-The inspectors reviewed these assessment reports to evaluate their effectiveness. The assessments had been performed by teams of_ISEG and-other a
personnel from the nuclear overview department. These documents revealed that each assessment was performed for the specific purpose verifying that functions, programs, and organizations would support sate startup and testing of the second CPSES unit.
Specific methodology and criteria were applied to reach the conclusions made.
For example, to evaluate the effect of the startup of Unit 2 on Unit 1, the assessment focused on common systems, unit cross-ties, interfaces, and isolation points. These areas were assessed for problems by applying schedules, procedures, and license requirements to these known configurations.
Assessment reports contained positive and negative conclusions and, when justified, recommendations. As with the surveillance section, assessment recommendations were entered into the ISEG tracking system until resolution
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was affected. The inspectors found the recommendations that had been issued in the above reports to be appropriate.
5.1.3 Disposition of ISEG Findings ISEG findings were officially reported in the ISEG monthly activity summary report.
The inspectors reviewed the contents of the reports for February and March 1993. These reports placed ISEG surveillance and assessment findings into functional areas that paralleled the Systematic Assessment of License Performance evaluation process.
Based on the assessment of the performance
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within the functional areas, ISEG would issue recommendations to improve performance within the functional area. Attachment B of the monthly report contained the status of all open ISEG recommendations. The February report contained eight open recommendations. The March report contained four
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recommendations, with four additional recommendations being carried over from the previous month. There were no new recommendations in the March report.
None of the open recommendations had exceeded the. action item response due date.
Routinely, the ISEG organization did not initiate the corrective action
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document (Operations Notification Evaluation [0NE] form). According to licensee personnel, it was more effective and less adversarial for a responsible organization to initiate corrective action against the program or area of responsibility.
Thus, in routine situations, ISEG informally recommended the initiation of the corrective action document. There had been very few occurrences where a disagreement between ISEG and the affected l
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organization had resulted in ISEG initiating the corrective action document.
As a result of this practice, ISEG did not identify or track corrective actions.
Therefore, it was difficult and time consuming for an auditor or inspector to locate and assess the majority of corrective actions that had been initiated as a result of ISEG findings.
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The inspectors were able to determine that a total of 10 ONE forms had been initiated from 108 surveillance field notes related to ISU testing.
Eight of these ONE forms had been dispositioned and closed. The inspectors. reviewed ~
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-15-the licensee's disposition of the findings and verified that, in each case, the corrective action had been appropriate and any possible generic issues had been considered.
The inspectors further reviewed the ongoing efforts to disposition the two remaining open ONE forms and considered them appropriate.
The inspectors believed that problems identified during the surveillance of ISU testing had been properly assessed and that adequate corrective action had been or was being implemented.
The inspectors reviewed how recommendations from ISEG or any other oversight group were handled administrative 1y. There were no ISEG or facility documents that described the status or implementation of oversight recommendations.
ISEG routinely issued and tracked recommendations, but a formal instruction for handling disagreements did not exist. The inspectors observed that recommendation response due dates had been extended on numerous occasions; however, no rationalization for the extension was documented.
The inspectors were told that issues of disagreement would be worked out between the affected organization management and ISEG.
It was noted that these recommendations were typically fully implemented.
5.2 Senior Manager Quality Assurance Meetina The inspectors attended the senior management quality assurance meeting held on April 27.
It was noted that the meeting provided an effective forum for discussing current plant issues and nuclear oversight activities.
Three areas of particular significance reviewed were:
the use of " experts" from other utilities to. enhance the quality assurance program; review of the ISEG monthly -
report for March 1993; and an initial assessment of plant systems which could result in system modifications. A request to have operations, engineering, and maintenance provide a review of the most'significant system modifications at the following meeting was made. The meeting minutes were subsequently developed and distributed to each individual in attendance.
5.3 Licensee 50 Percent Power Self-Assessment The inspectors reviewed the licensee's 50 percent power readiness self -
assessment in preparation for power escalation to 100 percent power.
The purpose of this assessment was to assure that Unit 2 was ready for full power operation and that power ascension and dual unit operation would be conducted safely.
The self-assessment was performed by each line function department such as operations, maintenance and engineering, work control, and quality control.
Each organization appropriately addressed each of the attributes established for the assessment.
Overall, the inspectors concluded that the licensee had performed a comprehensive self-assessment.
It was found to include reviews of ONE forms, technical evaluations, and work requests. The plant performance overview report results were effectively incorporated into the self-assessment. The-
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-16-l results of the self-assessment were subsequently reviewed and accepted by the station operations review committee.
5.4 Conclusions l
The ISEG surveillance group had conducted numerous surveillance activities of ISU activities.
The ISEG surveillance group was effective in identifying issues related to the startup and testing of Unit 2.
There was indication that, when the need for corrective action was identified, implementation was timely and correct.
ISEG surveillance findings were appropriately distributed
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to site management. Senior management was provided an overview of these findings.
The ISEG assessment group was effective in reviewing Unit 2 readiness, its impact on Unit 1, startup risks, and risks for proceeding above 50 percent power.
The implementation of ISEG recommendations often exceeded the established completion time, but were usually fully implemented.
The senior management quality assurance meeting provided an effective forum for reviewing current plant issues and assessing potential plant deficiencies.
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The licensee's 50 percent power assessment was well conducted. The attributes-identified for each organization to consider were appropriately addressed.
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ATTACHMENT 1 1 PERSONS CONTACTED 1.1 TV ELECTRIC D. B. Allen, Initial Startup Manager 0. Bhatty, Site Licensing B. Bird, Manager, Integrated Planning and Scheduling M. R. Blevins, Director of Nuclear Overview W. J. Cahill, Group Vice President, Nuclear Engineering and Operations D. L. Davis, Manager, Plant Analysis J. W. Donahue, Manager, Operations S. L. Ellis, Work Control Manager J. J. Kelley, Vice President, Nuclear Operations D. C. Kross, Shift Operations Manager J. J. LaMarca, Manager, Engineering Outage B. T. Lancaster, Manager, Plant Support D. M. McAfee, Manager, Quality Assurance D. R. Moore, Manager, Maintenance J. W. Muffett, Manager of Technical Support & Design Engineering M. W. Sunseri, Manager, Maintenance Engineering R. D. Walker, Manager of Regulatory Affairs for Nuclear Engineering Organization C. Wells, Operations 1.2 NRC Personnel T. A. Bergman, Project Director, Office of Nuclear Reactor Regulation S. C. Black, Project Manager, Office of Nuclear Reactor Regulation T. P. Gwynn, Deputy Director, Division of Reactor Projects (DRP), Region IV R. M. Latta, Resident Inspector, Section B, DRP, Region IV L. A. Yandell, Chief, Section B, DRP, Region IV-The personnel listed above attended the exit meeting.
In addition to the personnel listed above, the inspectors contacted other personnel during this inspection period.
2 EXIT MEETING An exit meeting was conducted on May 13, 1993. During this meeting, the inspectors reviewed the scope and findings of the report. The licensee did not identify as proprietary any information provided to, or reviewed by, the inspectors.