IR 05000498/1993036
| ML20058F245 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 11/24/1993 |
| From: | Johnson W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20058F195 | List: |
| References | |
| 50-498-93-36, 50-499-93-36, NUDOCS 9312080043 | |
| Preceding documents: |
|
| Download: ML20058F245 (21) | |
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APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report: 50-498/9 -36 50-499/93-36 Operating License:
NPF-76 NPF-80 Licensee: Houston Lighting & Power Company P.O. Box 1700 Houston, Texas 77251 Facility Name:
South Texas Project Electric Generating Station, Units 1 and 2 Inspection At: Matagorda County, Texas Inspection Conducted:
September 26 through November 6, 1993 Inspectors:
D. P. Loveless, Senior Resident Inspector D. M. Garcia, Resident Inspector J. M. Keeton, Resident Inspector Approved:
/M J//~L4/Y3 W. D.df6hnson, Chief, Project Section A Date Inspection Summary Areas Inspected (Units 1 and 2):
Routine, unannounced inspection of plant status, onsite followup of events, operational safety verification, maintenance and surveillance observations, and review of system certification activities.
Results (Units 1 and 2):
Troubleshooting and repair of the standby diesel generators following
the inadvertent starts of Standby Diesel Generators (SDGs) 12 and 22, indicated a marked improvement in the understanding and diagnosis of control circuit problems (Section 2.1).
The overfilling of the reactor vessel while restoring the reactor
coolant system was caused, in part, by the failure of a reactor plant operator (RPO) and a unit supervisor to fully evaluate and question abnormal indications (Section 2.2).
The identification and resolution of the loss of spent fuel pool (SFP)
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water inventory indicated an increased awareness in this area. The 93120B0043 931202 PDR ADOCK 05000498 G
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situation was handled well and corrective actions to prevent recurrence
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Early in this inspection period, inspectors noted examples of poor
communications and lack of professionalism in the control room.
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Throughout the period an improvement was noted. Operators exhibited a
heightened sense of professionalism, and communications appeared to be j
more formal (Section 3.1).
l Overall, plant housekeeping and material condition improved over the j
period.
RP0s were noted assisting in this effort (Section 3.2).
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Security officers observed during a personnel accountability drill
performed in an excellent manner (Section 3.3)
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Operators failed to control configuration of fuses when two sets of
fuses in the control cabinets of SDGs 12~and 13 were inadvertently reversed (Section 3.4).
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The inspector identified equipment clearance order tags that had not
been initialed as verified. Additionally, the inspector identified tags on a feedwater system clearance which were missing or unreadable because
of exposure to the elements (Section 3.5).
One unresolved item was opened to review the licensee's investigation-
and root cause of a continuing fuse configuration control problem
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(Section 3.7).
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Reinstallation of the upper bearing housing _ cover on High Head Safety
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Injection Pump 2C and a vibration analysis run were observed to be well'-
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performed (Section 4.1).
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Failure to follow established procedures governing freeze stop plugs was
a violation. The attempt at establishment of a freeze seal on Essential.
Cooling Water System A was observed.
Lack of control over contractor activities and procedure weaknesses were noted (Section 4.2).
Good control of testing activities during a 10-hour operability run on
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Train B of the control room heating, ventilation, and air conditioning i
system was observed (Section 5.1).
The conduct of an inservice inspection of Component Cooling Water
Pump IB was good (Section 5.2).
Those portions of the system certification program inspected appeared to
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be thorough and having a positive impact on system readiness and outage i
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scope (Section 6.3).
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-3-Summary of Inspection Findings:
Unresolved Item 498/93036-1 was opened (Section 3.7).
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Violation 498/93036-2 was opened (Section 4.2).
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Persons Contacted and Exit Meeting
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DETAILS i
1 PLANT STATUS j
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1.1 Unit 1 Plant Status At the beginning of this inspection period, the Unit I reactor was shut down and defueled. At the end of the inspection period, Unit I was in Day 275 of l
the forced maintenance outage, and preparations were under way to reload the l
reactor core.
i 1.2 Unit 2 Plant Status
At the beginning of this inspection period, the Unit 2 reactor was shut down
and defueled.
At the end of the inspection period, Unit 2 was defueled and in
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Day 252 of the refueling outaga l
1. '4 Organizational Changes l
During the ingaction period, numerous management changes were made by the licensee as part of their ongoing improvement efforts.
Effective November 1,
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1993, the Unit 1 Operations Manager was replaced. The new Unit 1 Operations
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Manager formerly was an operations specialist.
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i 2 ONSITE FOLLOWUP OF EVENTS (93/02)
2.1 SDGs 12 and 22 Control Circuit Problems On October 8, 1993, while restoring SDG 12 from a maintenance outage, a
simulated engine control run was being performed. Approximately 2 1/2 minutes
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into the cooldown cycle, restart indication was received locally and in the
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control room.
The fiber optic cables in the control circuit had to be removed to cause the ' start relays to open and allow the engine to be shut down. Over
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the next 2 days, suspect fiber optic boards were ' replaced and diesel runs were simul ated. During these runs, the spurious start signals continued to be received.
It was suspected that surge suppressor diodes (varistors) were malfunctioning, causing voltage spikes that caused the start signals.
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On October 12, 1993, after further investigation, chart recorders were connected to monitor the start circuit.
An analysis of the recordings
indicated another source was also causing spurious start signals. After further troubleshooting, the technicians discovered that a transistor on a different start circuit board had inadvertently caused the start signal.
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transistor was found to be heat sensitive, causing the spurious start signal.
After condensing all the test data and reviewing the results, licensee, personnel determined that the spurious starts were caused by independent failures of the varistors and transistors in the starting circuit.
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failure constituted an u...
a condition because the diesel generator was still capable of responding to an emergency start and run signal.
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On October 18, 1993, following replacement of the varistors and transistors, the postmaintenance test runs were completed.
The required surveillance testing was completei satisfactorily and SDG 12 was declared operable on
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October 19, 1993.
l On October 19, 1993, whiie performing a surveillance test on SDG 21, SDG 22
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was observed to inadvertently start and come up to operating speed.
Because i
of the similarity to problems experienced on SDG 12, the chart recorder was
moved to Unit 2 and connected to SDG 22 control boards. The control boar's
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were found to be exhibiting the same type failures that had occurred on SDG 12. On October 22, 1993, it was determined that 10 of 13 varistors and 2
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of 4 transistors on the circuit boards had failed.
During the evaluatisc of thesc cortrel circuit problems, the group charged
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with troubleshooting and repair of the SDGs showed marked improvement in their l
understanding and diagnosis of the SDG control circuit problems. Also, licensee personnel took the initiative to procure sufficient transistors and varistors to update the control circuits on the remaining four SDGs.
2.2 Unit _l_ Reactor Coolant System (RCS) Overfill Event On October 22, 1993, the inspector observed operators respond to an overfill of the RCS. The core had been transferred to the SFP and the RCS was drained, including the intermediate leg piping. The night crew was tasked with filling tre RCS from the refueling water storage tank (RWST) and increasing the reactor pressure vessel water level to 37 feet (2 feet below the reactor flange), in preparation for dynamic safety injection system motor operated valve testing and flow testing of the high and low head safety injection pumps.
Calculations were performed by the shift technical advisor and the unit supervisor to determine the total volume of water that was needed to fill ~ the RCS to 37 feet.
The calculations were based on the' RCS volumes listed in Addendum 2 of Procedure OPOP03-ZG-0010, Revision 3, " Refueling Operations."
It was determined that 25,000 gallons of water would be sufficient and prejob briefs were conducted with supporting personnel to commence the fill.
Communications were established between the control room and an RP0 stationed at the magnetic sightglass in the reactor containment building. The magnetic sightglass was the only reliable indication of reactor pressure vessel level available in that condition.
A flow path was established to begin a gravity fill from the RWST. After transferring approximately 1000 gallons, RWST level equalized with the RCS and Charging Pump 1B was started to fill-the 3CS from the RWST at approximately.
200 gallons per minute. The RPO stationed at the magnetic sightglass reported an increase in level. One and one half hours later the operator reported that the RCS level was holding steady at 33 feet 8 inches. The unit supervisor
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-6-i made the erroneous assumption that this was the level at which the steam generator bowls and the intermediate leg piping would be filled. A short time
later, a radiation protection technician reported to the control room that
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water was coming out around the reactor flange onto the reactor cavity floor.
The charging pump was stopped and filling of the RCS was secured.
The actual volume of water transferred was approximately 24,000 gallons. An RP0 was directed to proceed to the flange area and verify that the water was coming from the reactor flange.
In addition, the RPO stationed at the magnetic sightglass mechanically agitated the sightglass and the indicated level immediately began to increase to 39 feet 3 inches, a level that corresponded to the flange. This indicated that the magnetic sightglass had stuck at the 33 feet 8 inches position. Residual Heat Removal Pump 1A was started and the RCS water level was stabilized at 38 feet 3 inches.
The cause of this event was determined by the licensee to include the mechanical failure of the magnetic sightglass and a discrepancy between the-RCS volumes contained in Addendum 2 of Procedure OPOP02-ZG-0010 and the actual volume of water injected into the RCS. The RCS volumes listed in the procedure had been supplied by the architect / engineer. The inspector noted
that several barriers that could have precluded the occurrence of the event
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were missed during this evolution:
(1) the RP0 stationed at the magnetic sightglass did not question why the RCS fill had apparently stopped at 33 feet 8 inches, (2) the unit supervisor assumed that this level was the point at which the steam generator bowls and the intermediate legs fill; a review of the procedure would have indicated differently, and (3) taither operator
understood that the sightglass indication began at 33 fact and that at this level the intermediate piping was already filled.
i Because the core was in the SFP, the safety significance of this event was l
minimal. However, the lack of understanding and review of infrequently performed evolutions by the plant operators was more significant. There were
many contributing causes to this event; however, operat as ' ness and lack of attention to detail during plant evolutions was cor dere-the most significant.
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following the event, an event review team was formed to determine the causes
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of this event and to provide corrective action resolutions to prevent recurrence.
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2.3 Unit 1 Loss of SFP Water to RWST On October 25, 1993, the inspector observed evolutions following a loss of SFP j
level.
The SFP level had decreased by 1 1/2 inches, while transferring the
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contents of the recycle holdup tank to the RWST.
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The operators were transferring makeup water to the RWST from the recycle
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holdup tank using Procedure OPOP02-FC-0001, Revision 0, " Spent Fuel Pool Cooling and Cleanup System." Once the transfer was complete, an RP0 commenced the valve restoration lineup in accordance with Addendum 36, which delineated
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how to restore the SFP cooling and cleanup system after a transfer of wat to
the RWST from the recycle holdup tank.
During this evolution, the
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mechanical / electrical auxiliary building operator reported a 1 1/2-inch drop l
in SFP water level since the level indication was last observed 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />
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earlier.
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An RPO was dispatched to verify the valve alignments and reported that the i
valves were in their proper position.
SFP level remained steady at 66 feet,
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and the control room received the SFP level hi/lo alarm as expected. The operators commenced makeup to the SFP with demineralized water to clear the
alarm. An RP0 was stationed at the SFP to report water level every'30 minutes
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to ensure no further decrease. The SFP level hi/lo alarm cleared and the j
operators secured makeup to the SFP.
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The licensee determined that the normal return valve to the SFP cooling
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system, FC-0033, must remain closed prior to opening Purification Header l
Return Valve FC-0016A, in order to prevent back flow from the SFP. However, the procedure did not require a specific valve alignment sequence. The order
in which these valve manipulations are aligned in this flowpath and the restoration of this flowpath may be important, as evidenced by this event.
The addendum did not ensure that Valves FC-0033 and FC-0016A were not open at
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the same time.
As part of the licensee's corrective actions, a station problem report (SPR)
was initiated. A field change to Procedure OPOP02-FC-0001 was approved that added steps to open Valve FC-0033 after performance of Addendum 35 during the alignment and to close this valve prior to performing Addendum 36 for
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restoration. This would ensure that a flowpath does not exist from the SFP
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cooling to the RWST.
Plant operators were asked to review the procedure for other evolutions that require valve manipulations in accordance with an i
addendum with no specific order and ensure that a similar incident does not occur.
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The inspector noted that operators were cognizant of the evolutions that took place and they handled the situation appropriately. The inspector verified the procedure change and found no discrepancies.
2.4 Conclusions i
The licensee's response to events during the period was good.
Significant action was dictated by management and review teams developed comprehensive corrective actions.
In the example of the overfill of the' reactor pressure-vessel, the operators' lack of cognitive understanding of the RCS layout exacerbated the event. During the other two events reviewed, plant personnel identified and corrected the problems in a timely manner.
3 OPERATIONAL SAFETY VERIFICATION (71707)
The objectives of this inspection were to ensure that this facility was being operated safely and in conformance with license and regulatory requirements,
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and to ensure that the licensee's management controls were effectively discharging the licensee's responsibilities for safe operation. The following paragraphs provide details of specific inspector observations during this
inspection period.
3.1 Control Room Observations
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Early in the inspection period, inspectors noted poor communications practices between licensed personnel.
Additionally, a lack of professionalism and
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attentiveness was noted.
RP0s lacked cognizance of plant status in several observed occurrences.
Throughout the period, control room professionalism and RPO ownership showed signs of improvement.
The inspectors noted the heightened sense of professionalism in the control room. Noise level in the Unit I control room, contributed by the supporting organizations awaiting shift turnover, has shown improvement since work start activities were moved to an alternate location. There still appears to be room for' improvement in control of extr&neous activities in the control room by unit supervisors.
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On November 3, 1993, during the night shift, the inspector observed the Unit 2 operating crew training session.
The shift supervisor informed the crew about
the SFP housekeeping and fire protection concerns that were recently initiated by SPRs.
The training session was presented well and the topics were discussed freely among the crew members.
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3.2 Plant Tours Throughout the inspection period, the inspectors observed that the overall material condition and housekeeping in the plant were slightly improved.
Painting and preservation in the Unit 1 turbine building were noted as an
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improvement.
On September 29, 1993, during a night shift plant tour of Unit 1, the inspector observed portions of a preventive maintenance activity.
This activity was authorized by Work Authorization 92039273, to inspect and test a 480-volt breaker.
Electrical raintenance personnel were performing a functional test on the 480-volt electrical auxiliary building Main Air
. Handling Unit llB supply breaker. RP0s were also present to manipulate the i
breaker.
The functional test was performed using Procedure OPMP05-NA-0008,
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Revision 9, " Westinghouse 480 Volt Breaker Test."
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The RP0s had good communications with the operators in the control room, as i
evidenced by the verbal response by the operators. The electrical maintenance personnel performed each step appropriately, and the test was satisfactory.
The inspector noted that the performance between operations and electrical maintenance was well controlled, j
On November 4, 1993, during the night shift, the inspector accompanied the mechanical / electrical auxiliary building RP0 on his routine operator rounds.
The rounds were conducted in accordance with Procedures OPOP01-ZQ-0022, Revision 2, " Plant Operations Shift Routines," and OPSP03-ZQ-0028, Revision 6,
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" Operator Logs." The operator was knowledgeable of the areas and equipment.
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Good radiological controls practices were used, when required to enter contaminated areas.
Stray material (e.g., pipe fittings, extension ladder,
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and hose clamps) were placed in their proper location by the operator.
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The inspector noted a leak on the Train C chemical addition tank drain Valve 2-CH-0602 that was overlooked by the RPO. When prompted by the
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inspector, the RP0 found a similar leak on Train B.
This discrepancy was forwarded to chemistry operations. Overall, the inspector observed good performance by the RPO.
3.3 Security Observations
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Throughout this inspection period, the inspectors made daily observations of
security force activities.
Searches of packages and personnel'were professionally conducted.
Badge issuance was performed in a manner to prevent errors.
On November 2, 1993, the inspectors observed security officers in the east gatehouse respond to a site personnel accountability drill. The response was excellent.
Processing of the large volume of badges was performed in a manner that supported the full accountability.
Supervisors were observing and able to respond as problems arose.
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3.4 SDG 12 Incorrect Control Power Fuses (Unit 1)
On October 12, 1993, during restoration of SDG 12 following a maintenance
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outage, an independent verifier discovered that incorrect fuses were installed in the control power circuit. Two fuse blocks, one with 30-ampere fuses for the closing circuit and one with 15-ampere fuses for the trip circuit were switched when the fuse blocks were reinstalled. The fuse blocks were danger tagged with the correct identification corresponding to fuse size and-position. Reversal of the fuses was apparently a personnel error.
The error was corrected on SDG 12 by installing the ~ fuses in the correct position. The licensee checked the other five SDGs to verify that the fuses were in the correct position. They discovered fuses were also incorrectly installed on SDG 13 and immediately corrected the error.
These fuses had been
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replaced and reverified to be correct, indicating redundant personnel error.,
s All other SDGs had the fuses installed correctly.
l Procedure OPGP03-AE-0001, " Circuit Breaker Operation," required that the
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operators pull the tripping and closing fuses when racking out a breaker.
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This guidance has routinely been used to tag out breakers. On these breakers,
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the 30 ampere fuses supply power to the closing and tripping circuits with the
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trip coils being fused separately within the circuits protected by the
15 ampere fuses.
Therefore, removal of the 15 ampere fuses in addition to the
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30 ampere fuses was not necessary.
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The procedural guidance has been changed to specifically identify this type of breaker.
In the future, it will only require removal of the 30 ampere fuses i
to remove the breaker from service, thereby preventing recurrence of this event.
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3.5 Review of Eauipment Clearance Order (ECO) Discrepancies
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On October 14, 1993, during a walkdown of the chemical and volume control l
system valve room, the inspector discovered clearance tags on Valves CV-0206 and CV-0219 that were not initialled as having been independently verified.
The inspector determined that these valves had been closed, tagged, and verified closed while establishing ECO 2-93-5317. On October 6, licensee
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personnel released ECO 2-93-5317 and added Valves CV-0206 and CV-0219 to EC0 2-93-7110. The inspector reviewed the release of EC0 2-93-5317 and determined that the verification of the release for these two valves had also not been signed. These problems were reported to the shift supervisor who dispatched an operator to perform the verifications.
Although the failure to perform the verifications indicated a personnel error
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had occurred, there was no safety significance because the valves had been
aligned to the correct position and verified to be in that position.
On October 18, 1993, the inspector reviewed the main feedwater system ECO on l
the turbine dect. Several tags on the feedwater storage tanks, deaerator, and
steam generater feedwater pumps were unreadable and some tags were missing (only the string and eyelet were left hanging on the valves). Also, several tags on the steam generator feedwater pumps were blank, except for an initial in the verification block. These problems were discussed with the shift
supervisor who dispatched personnel to correct them.
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SPN 932996 was issued to investigate the ECO discrepancies involving the blank tags.
During the investigation, operators identified that the probable cause of the blank tags was that the tags were written with water-soluble ink, whereas the verifier used the correct type of pen. Operations personnel
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proposed a change to the tagging procedure that would require the proper pens
to be used to write on the tags.
i On October 19, 1993, the inspector performed a complete walkdown verification j
of ECO 1-93-3616, which removed the Unit I standby transformer from service to
perform routine maintenance. Clearance of the Unit I transformer required breakers in Units 1 and 2 and the switchyard to be racked out and tagged. All
breakers were in the proper position and tagged accordingly. The EC0 was i
completed in accordance with procedural requirements.
In NRC Inspection Report 50-498/93-30; 50-499/93-30, a noncited violation documented failure of the licensee to properly implement Procedure OPGP03-Z0-'
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0039, Revision 4, " Operations Configuration Management." At that time, the J
licensee initiated extensive actions to correct the problems with the EC0 program and its implementation.
These corrective actions included a revision
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to Procedure OPGP03-ZO-0039, a maintenance stand down to brief personnel on t
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the safety significance of obtaining an appropriate EC0, improvements in the
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ability of management to track the status of the EC0 program, and appropriate
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training to heighten awareness and improve self-checking of clearance activities. The corrective actions were not fully implemented at the time that the ECOs discussed above were authorized. No additional enforcement action is deemed necessary at this time. The inspectors will closely monitor i
the licensee's corrective actions in the ECO area.
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3.6 Testing of Tornado Dampers (Unit 1)
On October 21, 1993, an attempt was made to test the tornado dampers on L
Unit 1.
Specifically, Fuel Handling Building Supply Damper DA-052 and Plant Exhaust Stack Damper DA-ll3 operability tests were attempted. These tests resulted in the heating, ventilation, and air condition system associated with
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the dampers being declared inoperable.
On October 25, 1993, following a review of the dampers and operability
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requirements, the systems were declared operable. A detailed inspection of
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the tornado damper issue was performed and documented in NRC Inspection
Report 50-498/93-42; 50-499/93-42.
3.7 Fuse Configuration Control On 0:tober :18,1993, the inspector reviewed SPR 933063, which documented that
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5-ampere fuses had been installed in the nuclear instrumentation cabinets in place of the 1-and 2-ampere fuses required by design.
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The inspector requested the licensee's corrective action group to provide a
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listing of all SPRs issued in the last 9 months that involved misapplied fuses. Following the request, licensee personnel issued SPR 933086 to document that, since the completion of configuration control program walkdowns i
in May 1993, four issues involving improper sizing of fuses had been identified, t
During the electrical distribution system functional inspection, conducted in May and June 1991, and documented in NRC Inspection Report 50-498/91-05;
50-499/91-05, the inspectors identified deficiencies in the licensee's fuse
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control program. Additionally, fuses installed in the plant were identified
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as having the wrong amperage rating.
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In February and March 1993, the inspector reviewed the licensee's actions
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associated with fuse control.
The licensee had developed Revision 4 to Plant i
General Procedure OPGP03-ZM-0021, " Control of Configuration Changes," that require completion of data sheets for any fuses installed or replaced in the
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plant. The Plant Engineering Department was then responsible for evaluating
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the proper usage of the fuse. The licensee's actions for control of installation and replacement of fuses were found to be acceptable.
l However, on February 13, 1993, during surveillance testing of the solid state
protection syetem, power was lost to an actuation cabinet. A licensee
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r investigation determined that an undersized fuse had blown.
During the subsequent investigation, licensee personnel identified six additional cases t
of undersized fuses installed in the reactor protection system.
As a result, on February 17, 1993, an SPR was initiated to determine the
extent and cause of fuse control problems.
In May 1993, licensee personnel
performed fuse walkdowns and determined that safety-related distribution
panels had properly sized fuses.
Since the completion of these walkdowns, the
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four issues discussed above were identified. The licensee has initiated an event investigation team to further evaluate the extent of the fusing problem.
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Additional information was necessary to determine whether the four issues l
affect the operability f safety-related systems' and to determine the cause
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and scope of these additional problems. This item was considered unresolved until the extent of the licensee's investigation and corrective action can be reviewed (498;499/93036-01).
l 3.8 Identification of Poor Quality Workmanship on Valve Operators
On October 20, 1993, design engineering personnel identified poor quality
workmanship in motor controlled valve operators. These actuators had been
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adjusted and tested by a contractor during the present outage. During rework i
of terminations on a Unit 2 motor operator in August 1993, wiring discrepancies were discovered. Wire insulation was cut-to bare conductors on
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two wires, both limit switch finger bases were loose, lock washers and flat i
washers were missing on ten of the termination points on the limit switch terminations, and the terminal points were loose on the torque switches.
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Craftsmen discovering these discrepancies initiated an SPR and obtained a work
instruction revision to allow repair.
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During the licensee's SPR investigation, it was noted that several work
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packages had been performed which could have caused the discrepant conditions.
Additionally, the activities revealed that a number of opportunities had been
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available to identify the conditions, had the conditions existed before these activities. The licensee determined that.the cause of.the deficiencies was a i
lack of attention to detail during the actuator rework. Additionally, i
contractor craftsmen failed to identify these conditions during the-
inspections documented in accordance with Plant Maintenance Procedure OPMP05-
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ZE-0309, Revision 7, "MOV Diagnostic Testing." This procedure required I
inspection for damaged wire insulation and wire interference when closing the i
compartment cover.
i As a result of these findings, design engineering personnel inspected an
'i additional six motor operators, which had been refurbished in Unit 1.
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these inspections, licensee personnel found deficiencies in all six operators.
j Deficiencies included insulation cut to bare conductor, loose wires, improper i
terminations, limit switch finger bases loose, and missing lock and flat l
washers on terminal points.
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As a corrective action, licensee management decided to inspect all safety-i related motor operators. The initial scope focused on 96 valves which were
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required to support core reload.
Core reload was delayed to allow time to l
evaluate the operability of these actuators.
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Licensee personnel developed Engineering Instruction El-4.07, "Limitorque
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Actuator Limit Switch (LS) Compartment Inspection." This procedure i
specifically identified inspection criteria and required a signature by a valve operator. technician, an engineer, and a quality control inspector.
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inspector reviewed this procedure and it appeared to cover the scope of l
identified problems.
i By the end of this inspection period, the licensee had completed approximately l
95 percent of the inspections required for reload activities to commence.
i Although most valves exhibited some discrepancies, none of the identified conditions would have rendered the valve inoperable.
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The inspector noted that the slow identification of this problem indicated
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i another example of poor oversight of station contractors. However, management-
attention and the scope and timeliness of corrective actions, once identified, i
was considered excellent.
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3.9 Conclusions Overall, plant operations, including control room professionalism, RPO ownership of equipment and spaces, and plant material condition, improved slightly throughout this inspection period.
Some poor housekeeping items were roted.
Lack of control of fuses and discrepancies in ECOs continued to be
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identified. The evaluation and corrective action for minor deficiencies found
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in motor controlled valve operators was excellent and indicated a willingness of management to permanently correct plant problems.
4 MONTHLY MAINTENANCE OBSERVATIONS (62703)
The station maintenance activities addressed below were observed and documentation reviewed to ascertain that the activities were conducted in accordance with the licensee's approved maintenance programs, the Technical Specifications, and NRC Regulations. The inspector verified that the activities were conducted in accordance with approved work instructions and procedures, the test equipment was within the current calibration cycles, and housekeeping was being conducted in an acceptable manner. Activities witnessed included work in progress, postmaintenance testing, and field walkdown of the completed activities. Additionally, the work packages were reviewed and individuals involved with the work were interviewed.
All ebservations made were referred to.the licensee for appropriate action.
4.1 Unit 2 High Head Safety Injection (HHSI) pump 2C Vibration Analysis Run On September 29, 1993, the inspector observed electrical maintenance personnel reinstall the upper bearing housing cover to the HHSI Pump 2C, in preparation
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motor upper and lower bearings and to perform motor rotor test stand balancing. The electrical maintenance personnel were observed to be following
the work instructions as authorized by Work Authorization 93014891.
The inspector noted that the quality notification point following the step to torque the housing cover bolts had been waived and had a waiver number.
This was brought to the attention of quality control (QC). The QC inspector stated that, at that time, a QC. inspector had not been available and the notification point was waived and given a waiver number for their records.
The inspector reviewed the Quality Control Procedure QCP 2.0, Revision 8, " Inspection Activities," and verified the waiver justification. A quality notification point is a preselected step in a procedure or work process that identifies a discretionary inspection point which may be waived based on the availability
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of QC personnel.
On September 30, 1993, the inspector observed the vibration analysis run. The vibration data was collected in accordance with Procedure OPEP06-ZG-0032, Revision 3, " Vibration Monitoring Data Collection." The inspector verified
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the calibration date of the instruments and found them to be within calibration. The personnel obtaining the vibration data were knowledgeable and had good communications with the RPO and the electrical maintenance
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personnel present for the notor start. Vibration checks were performed for approximately I hour, and then the HHSI pump was secured.
The inspector noted good radiological controls by the personnel inside and outside the contamination zone.
The instruments used for the vibration analysis were properly handled. The inspector noted no discrepancies.
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I 4.2 Attempted freeze Seal on Essential Cooling Water (ECW) A Chiller Supply and Return Headers (Unit 1)
The licensee attempted to use a freeze seal on Train A of the ECW system to facilitate performing Modification 93-049 to the system. The modification was initiated to install bypass valves for the 150- and 300-ton essential chillers l
to provide cold weather control of the cooling water flow to the chillers.
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This modification had been previously proposed and was identified as being
.i necessary to eliminate an additional operator workload during cold weather and i
to improve reliability of the essential chillers. The modification package was not issued in time to be installed on Train A during its scheduled outage but was installed on Trains B and C.
To preclude placing Train A in another outage to install the modification, licensee management decided to use freeze plugs on the ECW system to allow the Train A SDG to remain functional during the modification.
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Additionally, the licensee procured contractor support to provide the
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expertise to perform the job because the licensee did not have personnel qualified to perform the freeze seal. The licensee's procedure for freeze
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seals, Plant Maintenance Procedure OPMP04-ZG-Oll3, " Liquid Nitrogen (LN2)
Freeze Seal," was for piping smaller than 4 inches in diameter.
The subject
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piping was 10 inches in diameter.
The contractor personnel were given a short
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Three of the people provided by the contractor were rejected based on lack of experience. The contractor provided their procedure to be used in conjunction with Procedure OPMPO4-ZG-0113. The contractor procedure, MNP-1004, " Freeze Stop Procedure," was reviewed and approved for use by licensee personnel on May 28, 1993. The procedure was
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incorporated into Work Package EW-308833 and was intended to be used to
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establish and maintain the freeze plugs. All preparatory work and most documentation were performed using Procedure OPMP04-ZG-0113, addenda, and data sheets.
Freeze seal temperatures were recorded on contractor provided data sheets, " Freeze Stop Record," which were used to record times and temperatures for six thermocouples, three for each freeze jacket.
On October 12, 1993, the system was turned over to the contractor to establish the freeze plugs. At 11:30 p.m., data recording was commenced at 5-minute intervals. At 5:05 a.m. on October 13, 1993, the contractor personnel declared that freeze plugs had been established, Progress Record Sequence 85 of WP 308833-EP01 was signed as complete, and the system was returned to
licensee personnel for work. As part of the licensee's work package, the system was tested to verify that the freeze plugs were adequate by starting ECW Pump 1A. At this time, the temperatures recorded for the freeze jacket on
the inlet header were 25.4aF, -311.00F, and -24.9oF.
The temperatures for the freeze jacket on the outlet header were 72.8*F, -312.0 F, and 0.l*F.
Testing indicated that the freeze plug was not intact on the outlet header. Contrary to the requirement of Procedure MNP-1004, Step 4.10.9, a freeze plug was not established prior to informing the licensee that the freeze plug was in place and releasing the system for work to begin.
This was a violation of the procedure (498/93036-02).
On October 13, 1993, the inspector observed the attempt to establish the
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freeze seal. Other observations during the attempt were as follows:
lt was not evident that the contractors were following their procedure.
- When asked to see the procedure, one worker said he had not seen it and speculated that it was with his supervisor. When his supervisor was questioned, he replied that it might be in the work package, but he did
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not know the location of the package.
Several of the workers involved in direct handling of the nitrogen
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bottles were not wearing the proper clothing for personal safety.
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The inspector did not see an oxygen analyzer in the work areas.
It was not evident that a licensee employee had control of contractor
actions, including direct communication with the control room.
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At 9:30 a.m. on October 13, 1993, licensee management cancelled attempts to establish a freeze plug, and removal of freeze seal equipment was commenced, i
SPR 932970 was issued to evaluate these events.
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The following discrepancies existed:
The level of contractor training and expertise was not readily apparent.
- The procedure supplied by the contractors was not adequate because it
did not state the specific freeze plug teoperature criteria.
The licensee's review of the contractor's procedure was not adequate.
- The contingency plan provided was nnt adequately detailed.
- Based on the rate of actual nitrogen usage, if a seal had been
established, it is not clear that an adequate supply of nitrogen was on i
hand to support the expected 7-day duration of the outage.
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The licensee was requested to discuss the lack of control over contractor
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4.3 Conclusions
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The performance of electrical maintenance personnel during the testing of the Unit 2 HHSI pump was good. However, the licensee's lack of control over
contract personnel contributed to the failure to establish a proper freeze i
I seal. One violation was identified for failure of the licensee and its contractor to follow established procedure.
5 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)
l The inspectors observed the surveillance testing of safety-related systems and components addressed below to verify that the activities were being performed
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in accordance with the licensee's approved programs and the Technical l
Specifications.
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5.1 Unit 2 Control Room Envelope B Heating Ventilation and Air
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Conditioning (HVAC) Surveillance
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On September 30, 1993, the inspector observed portions of the Train B control
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room envelope HVAC surveillance test being performed. The test consisted of a 10-hour operability run on Train B HVAC.
The reactor operator received
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written authorization to perform the test by the control room supervisor. The l
procedure governing the surveillance test was Procedure OPSP03-HE-0001,
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Revision 0, " Control Room Emergency Ventilation System." The operator reviewed the procedure prior to commencing the test.
The operator was attentive and had good communications with the RPO stationed at Essential Chiller 21B. The operator stopped and verified the control board
configuration before manipulating the switches.
The inspector returned to the l
cuntrol room 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after the test had begun. The operator was verifying the
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operation of the heaters, as directed by the procedure.
The test results were
satisfactory, and the inspector noted no deficiencies.
5.2 Component Cooling Water Pump 1B Inservice Test-(Unit 1)
On October 13, 1993, the inspector observed a performance of Plant Maintenance Procedure IPSP03-CC-0002, Revision 4, " Component Cooling Water Pump 1B l
Inservice Test." Conduct of the pretest briefing was good. All personnel l
involved in the test were familiar with the test and appeared to have good i
system knowledge.
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The test was conducted in accordance with the procedure.
The test results
satisfied the acceptance criteria established and were reviewed and accepted l
by the shift supervisor.
5.3 Conclusions Overall, during the inspection period, surveillance testing observed was well controlled and conducted by knowledgeable individuals.
Testing results
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indicated operability of the tested equipment.
6 SYSTEM CERTIFICATION REVIEW (71710)
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6.1 Background During the Diagnostic Evaluation Team inspection documented in an NRC Evaluation Report dated June 10, 1993, the team identified that operetors were
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significantly affected by degraded plant equipment, including equipment workarounds and the administrative burden associated with the high rate of removal and return of equipment to service. Additionally, weaknesses in maintenance and engineering had created large backlogs of work in each
organization. The backlogs caused concern for the overall readiness and operability of safety-related systems to support plant operations.
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As a result of these findings, the licensee developed the system certification
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program to demonstrate the operational readiness of the plant by comparing the material readiness of the plant systems or components to objectives and t
measurable criteria.
This process was committed to in the licensee's Operational Readiness Plan.
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f 6.2 System Readiness Review j
The inspector reviewed Station Procedure OTGP03-ZA-0005, Revision 0, " System
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Readiness." Under this procedure, system engineers reviewed open items on
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their assigned systems. All work previously scheduled within the outage scope
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were expected to be completed prior to restart. Therefore, the reviews were
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performed on an exception basis.
The reviews included work management system items, engineering / hardware
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issues SPRs, and any known issues not yet captured by those systems.
The
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engineer determined whether these items should be worked prior to plant l
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The reviews evaluated Technical Specification applicability, effect on safety function, and impact on nuclear safety or reliability. Those items l
considered significant were required to be added to the outage scope.
r The inspector received several system readiness review packages and determined that the system engineers had added items to the outage scope as appropriate, i
Those packages reviewed included fire protection, SDGs, auxiliary feedwater, and residual heat removal systems. The inspector determined that the reviews were thorough and that open items not added to the outage scope were clearly
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documented on deferral justification forms.
Throughout the licensee's process, the inspectors attended readiness review committee meetings. The committee for each system was composed of representatives-from maintenance, plant engineering, and operations.
The
- committee reviewed the system engineers' deferral forms and challenged his decisions to ensure that the evaluation criteria had been met. The inspector determined that the committee had a positive impact on the readiness review process and that the outage scope increased based on committee decisions.
Additionally, the committee reviewed with the system engineer, the normal testing of the system, including surveillance, preventive maintenance, and postmaintenance.
The system engineer had previously reviewed system testing and determined that testing was adequate. On a limited basis, the engineer recommended additional testing be performed based on a large outage scope or previously identified deficiencies.
The inspector questioned the ability of the committee to fully evaluate the
adequacy of testing.
In some cases, the system readiness redew package only l
included the exceptions, those items that were'not to be included in the
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outage scope.
Therefore, a review of this package alone was considered insufficient to review the need for additional testing based on work performed during the outage.
The licensee representatives responded to the questions by stating that the committee members, by means of their position, were familiar with the outage scope for each system. Operators were in a good position to understand the
impact of the outage on a given system.
The maintenance representative was selected based on his familiarity with the system and its components, and the plant engineering representative was usually the system engineer's supervisor, and, as such, had already more thoroughly reviewed system readiness.
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The inspector did determine that the committee had added additional testing requirements on a limited number of systems. Therefore, the inspector
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concluded that the system readiness committee was having an impact on the i
decisions that system testing was adequate for plant restart.
Procedure OTGP03-ZA-0005 also required the system engineer to present'the
system readiness review package to the Plant Manager for approval. The
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inspector noted that this process also had an impact on the system readiness
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6.3 Conclusions The scope and detail of the system readiness reviews appeared to be adequate j
to meet the licensee's commitments in the Operational Readiness Plan. The review by the system engineer was thorough and included.a comprehensive set of j
open items on the system being reviewed. Although the management review
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process contained some minor discrepancies, the approval process had a
'j positive impact on system readiness.
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ATTACHMENT
PERSONS CONTACTED j
1.1 Licensee Personnel
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l M. Berg, Engineer Support Manager, Design Engineering Department
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H. Bergendahl, Manager, Technical Services i
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D. Bize. Licensing Engineer J. Blevins, Supervisor, Procedure Control i
H. Butterworth, Unit 1 Operations Manager D. Clifford, Project Manager, Diesel J. Conly, Licensing Engineer
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M. Coppinger, Assistant Manager, Maintenance Support W. Dowdy, Unit 2 Operations Manager D. Fisher, Supervisor, Plant Engineering Department C. Gonzalez, Consultant Engineer, Plant Engineering Department i
A. Harrison, Supervising Engineer, Nuclear Licensing S. Head, Senior Consulting Engineer J. Johnson, Supervisor, Quality Assurance W. Jump, Assistant to Group Vice President Nuclear l
M. Kanavos, Division Manager, Mechanical Nuclear
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D. Keating, Director, Independent Safety Engineering Group D. Leazar, Plant Engineering Manager
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L. Martin, General Manager, Nuclear Assurance L. Myers, Plant Manager, Unit 1 G. Parkey, Plant Manager, Unit 2 i
P. Parrish, Senior Specialist, Licensing S. Parthasarathy, Supervisor, Engineer i
S. Rosen, Vice President, Industry Relations
R. Ruthrauff, Material Engineer G. Sandlin, Supervisor, Maintenance
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J. Sheppard, General Manager, Nuclear Licensing l'
H. Smith, Senior Consultant R. Tennant, Director, Nuclear Purchasing and Material Management
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S. Thomas, Assistant to Vice President, Nuclear Engineering
W. Waddell, Manager, Operations Support
L. Walker, Licensing Engineer T. Walker, Consulting Engineer Specialist l
H. Wright, Supervisor, Mechanical Maintenance Diesel
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The above listed personnel attended the exit meeting, in addition to the personnel listed above, the inspectors contacted other personnel during this
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inspection period.
2 EXIT MEETING
An exit meeting was conducted on November 8, 1993. During this meeting, the
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inspectors reviewed the scope and findings of the report. The licensee did
not identify as proprietary any information provided to, or reviewed by, the
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inspectors.
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During the meeting, the Plant Manager concurred that plant personnel had failed to adequately control contractor personnel during the installation of the freeze plug. Additionally, he agreed that a trend of fuse control issues was evident and that evaluation and corrective action would be taken, as appropriate.
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