IR 05000498/1993024
| ML20057B291 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 09/10/1993 |
| From: | Johnson W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20057B288 | List: |
| References | |
| 50-498-93-24, 50-499-93-24, NUDOCS 9309210150 | |
| Download: ML20057B291 (24) | |
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APPENDIX U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report: 50-498/93-24 1 50-499/93-24 l Licenses: NPF-76 ,
NPF-80 l Licensee: Houston Lighting & Power Company ,
P.O. Box 1700 Houston, Texas 77251 l
Facility Name: South Texas Project Electric Generating Station, Units 1 and 2 Inspection At: Matagorda County, Texas Inspection Conducted: July 4 through August 14, 1993 Inspectors: D. P. Loveless, Senior Resident Inspector l M. A. Satorius, Project Enginee ,
R. J. Evans, Resident Inspector J. M. Keeton, Resident Inspector D. M. Garcia, Resident Inspector :
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Approved: [/// evs 7//C/93 W. D.ffdhnson, Chief, Project Section A Date Inspection Summar_y
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Areas Inspected: Routine, unannounced inspection of plant status, onsite followup of events, operational safety verification, maintenance and .
surveillance observations, review of previously identified violations, unresolved, and open item Results: ,
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e The inspectors noted that the automatic start of Essential Chiller 12C because of oil foaming was caused by a previously identified condition that had been corrected on the Unit 2 chillers (Section 2.4).
- Once identified, the licensee's approaches to resolving the causes of events reviewed were very good (Section 2.5).
- In general, licensed operators conducted plant evolutions in a professional manner and plant mode changes were controlled by approved plant procedures (Section 3.1).
9309210150 930913 [I PDR ADOCK 05000498 p-G PDR W ;
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- Postmaintenance testing of the Unit 1 turMne-driven auxiliary feedwater pump was performed in accordance with tne special test procedur Personnel involved were knowledgeable of the system, anticipated parameter changes, and knew the consequences of their actions (Section 3.2).
- The inspectors expressed concern with the quality of maintenance performed on Standby Diesel Generator 23 during the 5-year inspectio Although the licensee responded to each individual equipment failure, the number of problems identified raised the concerns. Additional inspection of this area will be performed during the next inspection period (Section 3.5).
- The licensee's specific review of the inadequate essential cooling water flows to the standby diesel generators was excellent. However, licensee personnel failed to verify the operability of other systems served by 1 essential cooling water within a reasonable time following the discovery of an inadequate flow balance (Section 3.6).
- Craftsmen stopped work during the repair of an essential cooling water system piping weld to ensure that problems were corrected and that a quality repair could be performed (Section 4.1).
- In general, the surveillance tests observed were performed in a controlled, deliberate manner and were governed by approved procedure Pretest briefings were conducted and test personnel worked effectively together and followed proper procedures (Section 5).
- Test personnel requested and obtained additional guidance prior to ,
continuing the low head safety injection functional test when the procedure was found to be inadequate (Section 5.2).
- The licensee's procedures for protecting plant equipment and radioactive materials from hurricane force winds on site, met and exceeded the current regulatory requirements and licensee commitments (Section 6).
- The reactor plant operator who identified the loss of inventory in the spent fuel pool performed in an excellent manner (Section 7.2).
- Plant operators continued to monitor spent fuel pool level as efforts were initiated to locate the source of the inventory loss. The reactor i plant operators made a reasonable effort to identify and isolate the i source of the spent fuel pool inventory loss (Section 7.3). l
I Summary of Inspection Findings-l
- Unresolved Item 498;499/93011-02 was closed (Section 8.1). ;
- Inspection Followup Item 498;499/92021-02 was closed (Section 8.2). '
- Inspection Followup Item 498;499/93024-01 was opened (Section 2.3).
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l Attachments and/or~ Enclosures:
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- Attachment 1 - Persons Contacted and Exit Meeting i i
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-4-DETAILS 1 PLANT STATUS 1.1 Unit 1 Plant Status At the beginning of this inspection period, the Unit I reactor was in cold shutdown. On August 4, 1993, the unit entered Mode 4 by heating the reactor coolant system to greater then' 200aF. This evolution was performed to facilitate testing of the control rods and the turbine-driven auxiliary feedwater pum On August.12 the unit was taken into Mode 3 and heated to normal operating temperature and pressur On August 13 licensed operators began to cool the reactor coolant system because all four main feedwater isolation bypass valves were declared inoperable. The unit entered Mode 5 on August 1 At the end of the inspection period, Unit 1 was in Day 191 of the forced maintenance outag .2 Unit 2 Plant Status During this inspection period, the Unit 2 reactor remained shutdown and defueled. At the end of the inspection period, Unit 2 was in Day 192 of the refueling outag ONSITE FOLLOWUP 0F EVENTS (93702) Inadvertent Actuation of Component Cooling Water (CCW) Pump 2B (Unit 2)
An inadvertent engineered safety feature actuation of the Train B CCW pump in Unit 2 occurred during the performanle of a maintenance work activity. The cause of the event was determined by the licensee to be equipment failure and inadequate plant impact revie On July 9, 1993, the CCW Pump 28 received an automatic start from_a non-nuclear supply header low pressure signal. The low pressure _ signal occurred when Motor-Operated Valve CC-MOV-0235 was opened to allow maintenance to perform wor The work performed under Service Request CC-178483 was the repair of a flange leak on Valve CC-MOV-0235. This valve was one of two inlet isolation valves in series on the CCW common header. Both valves had been isolated to facilitate draining the common header. Following draining, mechanical maintenance personnel requested that Valve CC-MOV-0235 be opened to allow '
system' pressure on both sides of the valve, while they torqued the bolts to stop the-lea _ _ _ _ _ . _ _ _ _ _
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-5-Operations personnel verified that Valves CC-M0V-0235, CC-MOV-0236, (the in series isolation valves) and CC-0587 (the vent valve) were closed. The unit supervisor assumed that the piping would be full and no flow or pressure transients would occur, and the decision was made not to place the 'B' train CCW/ECW mode selector switch in the "off" positio Upon opening Valve CC-MOV-0235, a low pressure on the CCW common header occurred resulting in CCW Pump 2B starting. After verifyin9 , e operation, the CCW pump was secured and work commenced to torque the flang The '
unplanned actuation of an engineered safety feature actuation c ..ponent was reported to the NRC Operations Center pursuant to 10 CFR Sect',n 50.7 The cause of the unexpected CCW Pump 2B start was the resu': of seat leakage . '
past Valve CC-MOV-0236 and inadequate plant impact assesst.ent by the unit supervisor. With both isolation valves closed and the downstream header drained, leakage from Valve CC-MOV-0236 had partially drained the line between ,
the isolation valves. When Valve CC-MOV-0235 was opened, refilling and pressurization of the line caused a momentary low pressure in the upstream piping. While CC-M0V-0235 was open, a steady decrease in CCW surge tank level was observed, which indicated a high leakage rate past Valve CC-MOV-023 Service Request 315121 was initiated to repair valve CC-MOV-023 Similar events have occurred in the past which were caused by inadequate procedural guidance. The licensee has since revised their plant procedures; however, no general guidance exists for evolutions not specifically covered by normal operating procedures. The licensee's proposed corrective actions included: the development of formal guidance for the CCW/ECW mode selector switch; a modification to add a time delay to the low pressure CCW pump automatic start signal; and plant management directed that two trains of the CCW system shall remain in service with the third train off. This should preserve system reliability and prevent inadvertent actuations. This event will be reviewed further prior to the closure of Licensee Event Report 499/93-01 ,
2.2 Essential Chiller 12C Trip and Restart During Surveillance Testing (Unit 1)
On July 4 Essential Chiller 12C was started during performance of Surveillance -
Procedure OPSP03-SP-0010C, " Train C Diesel Sequencer Manual Local Test."
Approximately 1 minute later the chiller tripped on low oil pressure. A reactor plant operator (RPO) was stationed at the cailler to observe the start and operation of the chiller during the surveillance test. While investigating the cause of the trip, the RP0 pressed the STOP/ RESET button to see if the alarm would clear. This action reset the trip allowing the chiller -
to restart on the start signal inserted by the surveillance procedure. The event was initially considered a reportable engineered safety feature actuation by the shift supervisor and was reported to the NRC Operations Center pursuant to 10 CFR Section 50.7 _
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-6-On July 9 Operability Review ST-HS-HS-25403 was issued. This review determined that the trip occurred on low oil pressure that was caused by oil foamin Prior to the surveillance test, the chiller had been idle for 28 days which permitted refrigerant to be absorbed in the oil in the cooler section. When the chiller was started, the colder oil in the cooler was mixed with the hot oil in the compressor oil reservoir causing the refrigerant to boil and the oil to foam. When the foam reached the oil pump suction, the oil pressure fluctuated causing the low pressure trip. As immediate corrective action, the vendor recommended that the chillers be started and operated more -
frequentl Upon further investigation, the licensee discovered that a simple modification could be made to the chillers to prevent the oil foaming. This modification was installed in the Unit 2 chillers in 198 The inspectors concluded that the cause of the event was lack of communication
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between control room operators and the operator in the field. A lack of
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communications between organizations within each unit was also indicated by the failure to install the modification on the Unit 1 chillers when it was done on Unit Had the modification been installed on Unit 1 in 1988, this and several similar actuations of the chillers could have been avoide On July 13 licensing personnel performed Reportability Review ST-HS-HS-2545 A determination was made that the event was not reportable. The-original notification was withdrawn based on the October 13, 1992, change to 10 CFR Section 50.72 which removed the requirement to report invalid actuations of the auxiliary building ventilatio .3 Main Feedwater Isolation B_ypass Valves Closing Spring Design Inadeauate to Meet Required Function On August 13 during plant heatup to normal operating pressure and temperature after entering Mode 3, Steam Generator 10 level was noted to have decraased abnormally. An RP0 was dispatched to investigate and reported that tne Steam Generator ID Main Feedwater Isolation Bypass Valve FV-7145A was approximately ,
10-15 percent open. The underside of the valve operator was vented to atmosphere through the safety-related solenoid valves which should have closed the valve. He also reported hearing flow noise through the valve. The ;
control room instructed the-RPO to take local control of the valve positioner and position it to clos This action applied an air signal to top of the valve operator diaphragm, assisting the spring in closing the valv The valve indicated closed and the flow noise stoppe ;
A followup investigation was implemented and documented in Station Problem Report 932462. The investigation identified that Main Feedwater Check -
Valve FW-0249 leaked by the seat allowing full steam generator pressure to be applied to the downstream side of Valve FV-7145A. This pressure was sufficient to lift the valve disk against closing spring pressur The vendor was contacted and it was-determined that the closing spring strength was ,
sufficient to keep the valve closed against 847 psi. The vendor also stated l 1 .
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that identical springs were used in the other three bypass valves in Unit 1 and all four bypass valves in Unit 2, making them susceptible to the same failure mechanis Technical Specification 3.7.1.7 required that each main feedwater isolation valve be operable. With the bypass valves for all four main feedwater isolation valves inoperable, the operator entered the action statement of Technical Specification 3.0.3. A plant cooldown was commenced and Mode 4 was entered at 10:15 p.m. The cooldown continued and Mode 5 was entered on August 14, at 5 a.m. Technical Specification 3.0.3 was exited at this tim As a result of the premature cooldown, licensee management was preparing a plan of action to address both units at the close of this reporting perio The resolution of this item will be tracked as Inspection Followup Item 498;499/93024-0 .4 Flooding of Standby Diesel Generator (SDG) Room 13 (Unit 1)
On July 14 Essential Cooling Water (ECW) Loop IC was being returned to service following repair of the ECW piping. The system was lined up to fill and vent with the SDG 13 supply and return valves closed because maintenance was still being performed on that portion of the system. The drain valve in the return line was open with a tygon tube attached and extended to the room sum Approximately 2 1/2 hours after starting ECW Pump 10, a technician enter the room and discovered a strong smell of diesel fuel and approximately 1 inch of water on the floo The unit supervisor and an operator investigated and found that water was flowing from the tygon tubing. The drain valve was isolated and the leak stopped. The sump pump was verified to be running and the facility services organization was directed to clean up the wate >
During the followup investigation, licensee personnel determined that the ECW isolation valves, EW0089 and EWOO92, were leaking and allowed the water to be ,
discharged through the drain valve. The leak rate exceeded the capacity of :
the sump pump and the hi-hi level alarm on the sump failed to actuat Initially, operators suspected that the cables in a cable vault beneath the floor had been wetted. The cover plates on the cable vault were removed and the cables were inspected. No evidence of wetting was observed. Service Requests 211184 and 211183 were issued to repair the ECW isolation valves and '
Service Request 211187 was initiated to repair the sump hi-hi level alar .5 Conclusions ,
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Once identified, the licensee's approaches to resolving the causes of events !
reviewed were very good. The events were fully understood and corrective I actions appeared to be sufficient to prevent recurrence. However, the automatic start of Essential Chiller 12C because of oil foaming was caused by a previously identified condition. Had the modification installed on the
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Unit 2 chillers in 1988 been installed in Unit 1 at the same time, this and several similar actuations of the chillers could have been avoide 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, 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 perio .1 Control Room Observations I Throughout this inspection period, the inspectors performed routine control room observations. In general, operator performance was considered goo Required control room staffing was maintained, and operator behavior was commensurate with plant activities in progress. Operators properly responded to alarms and were aware of the status of plant equipmen On August--10 the licensed operators attempted to transfer temperature control to the Steam Generator IC power-operated relief valve for entry into Mode During the transfer, the valve experienced erratic behavior. When the operators attempted to return temperature control to the residual heat removal system, Valve MOV-31B, the Train B residual heat removal outlet valve would not open and the motor failed during the attemp Licensee personnel were unable to find any problems with the steam generator power-operated relief valve. All attempts to recreate the erratic behavior failed. After testing under various conditions, the valve was declared operabl The motor of Valve MOV-031B was replaced and the valve was tested. After completing testing the pressure and temperature conditions were recreated to see if a correlation could be drawn. With the conditions reproduced, the valve again failed to operate (a dead man switch was installed to protect the "
motor). The licensee concluded that Valve M0V-031B failed because of temperature binding. At the end of this inspection period, licensee engineers were studying other methods of transitioning to Mode 3 without exercising Valve MOV-031 :
The inspectors observed the preparations and activities performed during the plant mode changes discussed in Section 1.1 of this inspection repor Operators were following Plant Operating Procedure OPOP03-ZG-0001, " Plant ,
Heat-up." Necessary plant equipment was operable and the appropriate limiting conditions for operation were met. Operators conducted themselves in a professional manner and management oversight was provide The inspectors verified the control board alignment of the emergency core cooling system prior to each mode change. The water supply and heat sink were I
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available, and Technical Specification requirements were met. Heatup and cooldown were performed in a controlled and deliberate manner. Heatup rates were maintained below Technical Specification limit .2 Turbine-Driven Auxiliary Feedwater Pump Post Maintenance Testing 4
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The inspectors witnessed portions of the turbine driven auxiliary feedwater pump test conducted using Plant Engineering Procedure OPEP07-AF-0013, Revision 0, " Auxiliary Feedwater Pump 14(24) Special Post Maintenance Test." The purpose of the test was to verify that the turbine-driven auxiliary feedwater pump would consistently perform its design function. In addition to testing,-
this procedure called for the collection of baseline data for: drainage flow rates from normal drain tailpieces; pipe wall temperatures for cold, normal running and standby conditions; and the acoustical monitor leakage flow rate past Valve MOV-51 !
A pretest briefing was held at approximately 8 a.m. on August 13 in the Unit 1 ,
control room. The first phase of the test was discussed which consisted of >
performing test Sections 8.4, 8.5, 8.6, and 8.7 followed by a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />'cooldown (Section 8.8). These test sections include a manual rollup, vibration check, electrical trips, and data taking on the turbine and pump. This procedure also required the performance of other test procedures to obtain specific dat Primary among these tests were:
- OPEP07-AF-0001, " Auxiliary Feedwater Turbine Overspeed Trip Test"
- 1(2) PSP 03-AF-0007, " Auxiliary Feedwater Pump 14(24) Inservice Test"
- OPSP03-SP-0019D, " Turbine Driven Auxiliary Feedwater Actuation and Response Time Test" At 9:53 a.m. following the briefing, the licensee manually rolled the turbine driven auxiliary feedwater pump. The turbine speed was brought to 2000 rpm and held while data was collected. The turbine speed was increased to normal operating speed in 500 rpm increments. The licensee recorded data at each increment. The turbine speed was held at normal operating speed for a minimum of 30 minutes to allow the final data to be taken. At the end of the data taking period the turbine was electrically trippe The manual rollup and trip was followed by a cooldown period of approximately 30 minutes. The turbine was then started from the control room, data was taken, and then the turbine was tripped electrically. This was repeated three times. The test was suspended following the last 30 minute run and prior to ,
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u going to Section 8.8 of the procedure because of the failure of the main feedwater isolation bypass valve The operators adhered to the procedures for those sections of the test that were completed. Communications between the operators in the auxiliary feedwater pump room and the control room were very good. All operators
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involved in the test were knowledgeable of the system, anticipated parameter changes, and knew the consequences of their actions.
, 3.3 Plant Tours On a routine basis throughout this inspection period, the inspectors toured *
accessible portions of the plant. Portions of the containment isolation valve alignment was verified. Additionally, in Unit 1 the inspectors locally verified the auxiliary feedwater flow alignment, a well as the flow path of ECW through the SDG Local area radiation monitors were in an operable statu .4 Security Observations Throughout this inspection period, the licensee's day-to-day implementation of the physical security plan was adequate. X-ray machines, metal detectors, and explosive detectors were operational. Personnel and packages entering the protected area were properly searched. No openings in the fence fabric were noted during plant tour .5 SDG 23 Postmaintenance Testino Resolutions At the end of the last inspection period, SDG 23 had experienced a reverse power trip and a loss of control air trip. The details of this event were !
documented in NRC Inspection Report 498;499/93-2 Since that time, the !
licensee has learned new information about the cause of the trip l On June 30 while performing the postmaintenance test on SDG 23 following the :
5-year maintenance outage, the diesel experienced a reverse power trip j 7 . seconds after the output breaker was closed. Initially the licensee attributed the trip to operator action, assuming that the operator had lowered t the reactive load without raising generator output, resulting in the tri .
After further review it was determined that the reverse power relay installed ;
in the generator control cabinet was different from the original design. The relay had been replaced during the outag i The original design relay was no longer available and a document change notice ,
was used to purchase the replacement relays. The vendor recommended a different relay from the same manufacturer, but the new relay _ was not the same ;
design, and it had to be modified prior to installation. The original relay :
had two point contacts, whereas the new relay had a single point contact. The l authorized use of the document change notice was limited to only allow l procurement of parts and to ensure that parts are readily available for plant i operations. Because the part required a modification, a hold tag should have i been initiated to identify the need for a plant change form. The modification ;
would then have been approved by design engineering prior to installatio The replacement relay did not have the hold tag; however, the document change notice did contain wiring diagrams that showed the difference in the contact Therefore, the replacement relay was installed without proper design ;
authorization. The inspectors verified that the remaining relays in the !
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warehouse had hold tags in plac The inspectors will continue to review this j issue during the next inspection perio .
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On July 1 while performing a short postmaintenance test, SOG 23 experienced a loss of control air trip about 7 minutes into the run. Service Request 213308 l was initiated to investigate and repair the problem. Following 2 weeks of troubleshooting, a cold solder joint was found on one terminal pin on the ,
speed control circuitry unit (known as the speed air-pack). This caused the !
pin to intermittently lose continuity, resulting in actuation of the starting l air solenoid. The licensee repaired the pin and simulated a diesel run to verify that the circuitry was operating properl i On July 26 while performing the postmaintenance run, SDG 23 experienced another reverse power trip. The system engineer was present and suspected the relay was installed backwards. The licensee pulied the relay and compared the internal wiring with the original reverse power relay that had been sent to the training department. Review of the internal wiring found differences in polarity of the voltage coils. Investigations revealed that the new relays ,
were standardized relays with the phase rotation A to B to C. The phase ;
rotation for the SDGs, however, was C to B to A. The original relays ,
installed-in the SDGs had been modified by the vendor for the non-standard ;
phasing, but the documentation did not address the phase relationship. The licensee did not capture the different phase relationship because the letter r
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by the vendor for the new relays did not indicate the difference. The relay terminal leads were reversed and it was reinstalled. The licensee proposed to -
modify all the spare reverse power relays, or to order the correct phase rotatio ;
On July 30 an analyzed diesel run was completed. At the start of the analyzed ;
run, the diesel received a loss of DC control power alarm. The licensee-checked all local indications and everything appeared satisfactory and the alarm subsequently cleared. A service request was developed to investigate .
and repair as necessary, but the decision was made to continue the run. On !
August 2 an electrical card was found with broken connections. The card was replaced and a station problem report was written to determine the root cause ,
of the degraded car .
Six engine-driven fuel injector pumps needed to be adjusted for proper timin '
One of the injector pumps was replaced because the pump could no longer be shimmed and remain within specification. An ultrasonic test revealed eight ;
questionable fuel nozzles. They were removed and tested. One of the fuel .
nozzles was not operating correctly and it was replaced. The seven other fuel ;
nozzles were reinstalle An increase in pressure was also noted across one of the duplex lube oil '
strainers. When the lube oil strainer was shifted, the change in pressure decreased to normal. A service request was initiated to investigate and !
repair. A slight film of what appeared to be lint was seen in the straine !
The fibrous material was ' collected and analyze The fiber came from the ,
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I absorbent cotton pads used to wipe the oil from the newly installed filter l There were no problems noted once the fibrous material was remove On August 10 a lube oil leak on the turbocharger filter housing was found near the flange. A service request was initiated to investigate and repair. The cover was removed and the o-ring was inspecte Although the o-ring appeared to be in good condition, it was replaced. The leak, however, was still present. The cover was removed again. This time the o-ring was found to be cut in two place The new o-ring had bren slightly misaligned during installatio This caused the o-ring to crack when the cover was tightene The 0-ring was again replaced and the leak cease On August 11 another engine analysis run was commenced. With the inspection plate lifted on Cylinder 6L, a puff of black smoke emitted from the fuel nozzle. Two hold-down nuts were found to be loose on the fuel nozzle, allowing exhaust gases to escape. The analysis run was stopped and a station problem report was written to investigate the cause of the loose nuts. These nuts were last torqued to 50 ft-lbs, which had been witnessed by a quality control inspecto The fuel nozzle was disassembled and inspected. There were no discrepancies. It was suspected that either the injector hold-down bracket or the copper gasket that seals the combustion chamber was slightly -
cocked when the nuts were torqued. When the diesel was run a combination of vibration and temperature caused the assembly to reseat and relaxed the torque on the nuts. The fuel nozzle was reassembled and the two pullout studs were replaced. On August 12 the analysis run was resumed. Three injector pumps needed to be adjusted and one of the three was replace ,
At the end of this inspection period, the licensee planned to continue the analysis runs until the engine was properly adjusted and in a reliable condition. Although the unit is currently defueled and the SDGs are not required to be operable, the inspectors expressed concern with the quality of
. maintenance on SDG 23. As corrective action, plant management decided to
- reorganize plant engineering to develop a diesel generator group which would ,
a include all the plant expertise in this area. The inspectors will continue to
- observe and evaluate the licensee's postmaintenance testing of SDG 23 until it l
has been declared operabl .6 Discovery of Inadequate ECW Flow to the SDG Heat Exchangers On July 15 plant operators were performing a complete position verification of i all locked-in-place throttle valves. For the ECW system an RPO used the valve lineups found in Plant Operating Procedure OPOP02-EW-0001, Revision 1, ,
" Essential Cooling Water Operation." The RP0, after consultation with the unit supervisor, verified the valve position by momentarily closing the valve and then repositioning the valve in accordance with the valve lineup, recording the "as found" and "as left" positions. Four ECW throttle valves
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(2-EW-0199, 2-EW-0201, 2-EW-0202 and 2-EW-0204) were found out of positio ,
The valves, which provided cooling water to three SDG heat exchangers, were -
aligned to the required positions in accordance with the Procedure OPOP02-EW- >
0001 system lineu ,
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On July 16 during an independent verification of the locked throttle valves, it was discovered that the total flowrate through SDG 23 heat exchangers was l not within the band required by Procedure OPOP02-EW-0001 (1500 to 1550 gpm). l Flow through SDG 22 was found to be below the minimum 1550 gpm and this SDG ,
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was declared inoperable. SDG 23 was already inoperable as described in Section 3.5 of this repor The valves were repositioned to meet the total flow requirements using the local total flow indication and the qualified display processing system. These new positions were contrary to the Procedure OPOP02-EW-0001 required positions and were entered in the locked valve deviation log. SDG 22 was returned to an operable status. Station Problem Report 932231 was written to identify the discrepanc Later that same day, the ECW flow rate through each individual heat exchanger on SDG 21 and 22 were recorded with a portable ultrasonic flow meter because there was no other means of indication. The jacket water heat exchanger on SDG 21 had less than design flow (594 gpm vs. 628 gpm) and the diesel was declared inoperable at approximately 6:30 Throttle Valve 2-EW-0199 was adjusted to bring the flow to 652 gpm and the diesel was returned to operable status at 10 p.m. The turbocharger heat exchanger on SDG 22 also had less than design cooling water flow (532 gpm vs. 560 gpm) and the diesel was declared inoperable at 10:55 p.m. Throttle Valve 2-EW-201 was adjusted and the diesel was returned to service at 1:30 p.m. on July 1 The throttle valves were not left in the positions specified in the approved procedure, but were documented in the locked valve deviation lo A station problem report was written to determine the operability of the SDGs prior to the flow adjustments. Based on engineering analysis, it was determined that SDG 21 was operable because the 532 gpm would have provided
sufficient cooling and that operations took a conservative approach by declaring the diesel inoperabl On July 19 the inspectors questioned whether the ECW flow rates through other operable heat exchangers in both units were adequate. The licensee had not verified the flows at that time. The inspectors performed walkdown 4 inspections of the local flow rate instruments available and verified that flow rates were sufficient to support operable safety-related equipmen Although no additional discrepancies were identified, failure of the licensee to determine the extent and scope of the flow rate problem was considered a weaknes The licensee was still investigating when these valves were adjusted to the
as found" position. The licensee determined that operators were not all using the same method for determining valve positions. There was no guidance provided on how to verify the position of a locked-in-place throttle valv The valve positions listed in the valve lineups were designed for prestartup ,
conditions and the required position could change as the system ages based on fouling of the heat exchangers. The inspectors noted that operations personnel were not fully aware of the impact of the manipulations of the throttle valves on the system. Therefore, the RPO did not verify delivered
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A flow balance was performed for both total flow and individual flows through the lubricating oil, jacket water, and turbocharger heat exchangers, using a portable ultrasonic flow meter for all of Unit I and Unit 2 SDGs. The total flow was within the band required by Procedure OPOP02-EW-0001 and the .!
individual flows met the design flow rat The licensee proposed the following corrective actions: 1) develop a field change to Procedure OPOP02-EW-0001 to revise the valve lineups, 2) revise the procedures to ensure that individual SDG heat exchangers are receiving the .
correct flow, 3) install specific position indication for throttle valve ;
positioning, and 4) install local flow indications for the ECW flow through ,
the individual heat exchangers for both Units 1 and 2 SDG .7 Conclusions Throughout this inspection period, control room operators performed in a controlled and deliberate manner. Unit 1 mode changes were controlled by plant procedures -and in compliance with Technical Specifications. Testing of the turbine-driven auxiliary feedwater pump met the testing criteria and was performed by qualified personne The performance of the licensee was considered poor in performing the 5-year maintenance outage on the SDG 23. Although the licensee responded to the ,
individual equipment failures, the number of problems identified during .
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postmaintenance testing raised concern about the quality of the maintenance activities. At the end of this inspection period,-the licensee intended to perform comprehensive testing of the SDG before returning it to an operable statu .
The licensee's specific review of the inadequate ECW flows to the SDGs was i excellent. However, licensee personnel failed to verify the operability of other systems served by ECW within a reasonable time following the discovery of an inadequate flow balanc ,
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 inspectors verified that the activities were conducted in accordance with approved work instructions and procedures, the test equipment was within the current calibration cycles, and i housekeeping was being conducted in an acceptable manner. Activities i witnessed included work in progress, postmaintenance test runs, and field !
walkdown of the completed activities. Additionally, the work packages were j reviewed and individuals involved with the work were interviewed. All j observations made were referred to the licensee for appropriate actio !
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On June 30 Service Request EW-1-179340 was issued to repair a leak in the -
ECW Pump IC discharge header. The leak was in Field Weld EW-1302FWOO32 which had previously been repaired. The weld had cracked in the weld repair are Industry experience showed that repaired aluminum bronze welds had a high probability of developing new defects. Therefore, the old weld and the heat affected zones on either side were cut out and a 4-inch pipe section was t fabricated and welded into the pip On July 6 the inspectors observed preparation for cutting out the cracked weld. The workers were using a properly signed work package and procedure. A prejob briefing had been conducted, and workers identified fo. the job were qualified to perform the work. When the lower cut was made, the upper section of pipe (a 9P degree elbow) shifted 1/4-inch to the west and 3/8-inch to the south. Wor ( was stopped because the workers thought the elbow was cold sprun It was later determined that the piping elbow was cold rolled, bent into position, and seam welded and did not produce a truly concentric pip The additional pipe section had to be custom fabr:cated so that the pieces could be aligned as closely as possibl On July 8 the inspectors observed the fitup surface preparation for the wel The piping was aligned with special fitup clar.ms. The ends of the pipe and the replacement pipe section were mitered and surfaces prepared for weldin s The weld gap appeared to be excessive. inerefore, a longer pipe section was
, fabricated to provide a closer fit. The new pipe section was aligned, surface prepped, and welded into place. Quality control performed nondestructive examination on the fitup and weld on July 11, and the weld was accepted. On July 14 the system was returned to operations for postmaintenance testin .2 Conclusions The maintenance observed during the repair of an ECW system piping weld was performed by qualified personnel following an approved work packag Craftsmen stopped work, as appropriate, to ensure that problems were corrected and that a quality repair could be performe BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)
The inspectors observed the surveillance testing nf safety-related systems and components addressed below to verify that the activities were being performed in accordance with the licensec's approved programs and Technical Specification , 5.1 Standbv Diesel No. 21 Operability Test On July 27 the inspectors observed licensee personnel performing portions of Surveillance Procedure OPSP03-DG-0001, " Standby Diesel #21 Operability Test."
The unit supervisor briefed the control room personnel and ensured that good, ,
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clear communications would be utilized. Operations and engineering personnel were involved in the performance of the tes i The inspectors reviewed the surveillance procedure and verified proper licensee approval. The insrecters verified that the test instrumentation was currently calibrated. Personnel conducted the test in a conscientious, step-by-step manner. The inspectors reviewed the test data and found no discrepancie ,
5.2 Low Head Safety Injection (LHSI) Pump Functional Test On July 29 the inspectors observed the performance of Procedure IPSP03-SI-0003, " Low Head Safety Injection Pump IC Inservice Test," ,
Revision 3. The purpose of this test was to verify that LHSI Pump 10 was .l operable by observing that the pump was performing within the acceptable range !
of test quantities as specified by the ASME Boiler and Pressure Vessel Code, ;
Section X t The inspectors verified that a test coordinator had been designated and that i all the prerequisites had been met. Control room operators coiamunicaten well :
with the RPO who was stationed at the pump in order to observe proper equipment operation and to collect data during the test. All recorded Jata j was determined to be within the acceptance criteri ,
The inspectors noted that the RP0 was originally unable to measure the .[
unfiltered displacement vibration amplitude at the Section XI test point as directed by Step 5.12 of the surveillance procedure. The RP0 requested '
assistance from.the control room operators, who dispatched an operator who was familiar with the operation of the vibration analyzer and the proper location '
of the test point Further questioning of the test coordinator and the system engineer determined that the test points were generic for all pumps and ,
motors; however, a generic diagram indicated the test points was not included r
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in the surveillance package. The inspectors considered that the addition of a generic test point diagram to packages would be an enhancement to surveillance test performance. No other problems were note .3 C_onclusions
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In general, the surveillance testing observed was performed in a controlled, deliberate manner and was governed by approved procedures. Pretest briefings were conducted and test personnel worked effectively together and followed proper procedures. Test personnel requested and obtained additional guidance
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prior to continuing the LHSI pump functional test when the procedure was found ,
to provide incomplete guidanc HURRICANE AND SEVERE WEATHER PREPAREDNESS i
The inspectors reviewed the actions-that the licensee had taken to prepare the statica for potential hurricanes and severe weather that could be anticipated
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i during the ensuing hurricane season. A number of potential generic issues were evaluated and the licensee's actions were reviewe The licensee has an administrative procedure that gives general guidelines to station personnel on action to take in the event of severe weather. General Procedure OPGP03-ZV-0001, Revision 0, " Severe Weather Plan," was rewritten-from a previous Interdepartmental Procedure (IP-1.51, Revision 0) and contained guidance for all severe weather including: hurricanes, tornados, flooding, and cold weather. The procedure describes four progressively severe weather classification for hurricanes:
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SEVERE WEATHER CONDITION FOUR:
Issued during hurricane season - June I through November 3 * SEVERE WEATHER CONDITION T"'EE:
Issued when a hurricane or tropical storm was located in the Gulf of Mexico or a tropical storm watch was posted for the Texas coast between '
Corpus Christi and Galveston Islan i
- SEVERE WEATHER CONDITION TWO:
Issued when a hurricane watch or tropical storm warning was posted for U.: Texas coast between Corpus Christi and Galveston Islan * SEVERE WEATHER CONDITION ONE:
Issued when a hurricane was predicted to impact the South Texas Project "
within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as evidenced by a hurricane warning between Corpus Christi and Galveston Islan The procedure provided guidance on responsibilities of various department managers and directed the operations, maintenance, and technical services r (radiation waste, chemical operations, health physics) department managers to establish individual departmental procedures for these specific department ,
The procedure contained an extensive checklist that directed station l management to take increased compensatory actions as the storm progressed >
through the four categories described abov .1 Adequacy of Timina Plant Shutdown in Anticipation of a Hurricane The inspectors reviewed the Technical Specifications and other licensing commitments to determine requirements regarding licensee re?ponse to hurricanes and identify licensee operating procedural reqc.rements for l hurricane l l
The inspectors determined that the Technical Specification contained no requirements with respect to timing of a plant shutdown based on hurricanes or
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any anticipated severe weather. Review of other licensee commitments revealed no other regulatory commitments with respect to the timing of plant shutdown based on anticipated severe weather except the Station Blackout Rule. The Station Blackout response commitments required that both units be placed in Mode 3 a' minimum of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> prior to 120 mph winds being present on sit The operations department severe weather procedures were more restrictive in that they required that if a hurricane warning was in effect for the Texas coastal area between Port Lavaca and Galveston and the National Weather Service predicted the hurricane landfall at a probability greater than 50 percent with maximum sustained winds greater than 120 mph, both units would commence a shutdown 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> prior to the hurricane's projected arrival. In addition, the operations procedure directed that a plant cooldown would be initiated within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of the hurricane's projected arrival and that 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> prior to arrival exterior doors and hatches would be secure .2 Adequacy of Compensatory Measures for Equipment or Facilities not Designed for a Hurricane The inspectors reviewed the vulnerability of licensee's radioactive materials and waste storage areas to hurricane force wind ,
By procedure the licensee collected both disposable low-level radioactive wastes and low-level contaminated equipment'in various standard sized cargo containers. At Severe Weather Condition 2, the Technical Services Severe Weather Plan directed technical service personnel to either tie down or move these containers inside hurricane proof fuel buildings, based on the containers' content The licensee shipped disposable low-level wastes offsite to a contractor that incinerated and compacted the material and loaded the material into a 4 foot by 4 foot by 6 foot dry active waste containe In the past, prior to the closure of the Barnwell site, this material was then shipped to a low-level storage facility for disposal. At the time of this inspection, the licensee received this compacted low-level material back on site. They had a low-level onsite storage facility that was located west of the protected area approximately 1000 yards. When the waste containers were returned from the compactor, they were placed into the storage facility and strapped to the floor. Although, the storage facility, which was a steel frame warehouse structure with 20 gauge steel roof and walls was only designed for 90 mile-per-hour winds, the failure mechanism for the building was the removal of the roof and walls with the structural supports remaining intact to protect the content The dry active waste containers were constructed of 3/4-inch external plywood, with 2-inch by 6-inch internal bracin In addition, the storage containers contents were sealed in a water and air-tight membran The station's high-level radioactive waste was stored in the fuel handling building or in an outside fenced area also located west of the protected are I
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Material located in the outside area was stored in 9-foot diameter cylindrical l casks. These casks each weighed approximately 15,000 pound i In addition, the Technical Services Severe Weather Plan specified actions to be taken during increased levels of severe weather. -These. actions included reducing radioactive waste to a minimum, and moving containers into protected -
areas or strapping them dow .3 Adeauacy of Examination of the Impact of Nonsafety Eauipment on Important Eauipment Durina External Events The inspectors reviewed with licensing potential vulnerabilities based on lessons learned at Turkey Poin :
The South Texas Project fire main supply tanks are low cylindrical tanks located in the protected crea. These tanks, and other nonsafety-related -
tanks, were not considered susceptible to damage from wind. The review of the operations and maintenance departments' severe weather programs revealed that as the storm severity category increased, maintenance personnel were directed to lock down all traveling cranes, in addition to other actions to reduce the potential for missile hazard All safety-related components and all equipment necessary for the safe shutdown of the facility were located in the power block which was designed for 125 mph hurricane wind .4 Conclusions The licensee's procedures for protecting plant equipment and radioactive materials from hurricane force winds on site, met and exceeded the current regulatory requirements and licensee commitment ;
7 SPENT FUEL POOL (SFP) INVENTORY LOSS (71707)
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On July 21 Unit I was in Mode The SFP cooling pump and Heat Exchanger 1A'
were in service, cooling the SFP with heat removal supplied by the component .
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CCW system. At 9:40 p.m. on July 21 a RP0 discovered that the in service SFP Pump 1A Drain Valve FC-0150 was partially open. This condition resulted in an inventory loss in the SFP which was later determined to have been ongoing for approximately 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> , Background The normal fuel handling building logs required readings to be taken every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. However, a temporary fuel handling building logsheet required readings to be recorded every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, which necessitated a third fuel handling building entry by one RP0 during each 24-hour perio The SFP was configured such that 1 inch of-level contained approximately 700 gallons of borated water. Normal SFP level was maintained at 66 feet
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-20-6 inches, with high and low level alarms set at 67 and 66 feet. These level alarms were the only annunciation available to the control room concerning SFP level status. Operators informed the inspectors that previous experience indicated that makeup to the.SFP to replace evaporative losses needed to be performed roughly every 10 days. However, this frequency was subject .to the SFP temperature and the ambient temperature in the fuel handling buildin .2 SFP Inventor _y loss Identification On July 20 the control room received a SFP low level alarm. The control room operators directed the mechanical / electrical auxiliary building RP0 to locally verify the level and the SFP level was restored to 66 feet 6 inches at 4 on July 2 At 3 a.m. on July 21 while conducting routine rounds, the mechanical / electrical auxiliary building RP0 recorded the local SFP level at 66-fect, 4%-inches, a decrease of 1% inches over the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, which would correspond to an inventory loss of approximately 1000 gallons of SFP water. This RP0 was the same watchstander who had been involved in the SFP makeup evolution during the previous midshift. The RP0 considered the loss of 1000 gallons of inventory to be excessive for a 24-hour period and informed the control room operators of his findings. Identifying the loss was considered excellent performance by the RP Control room operators subsequently initiated actions to identify the source of the SFP inventory loss. These actions primarily consisted of directing the mechanical / electrical auxiliary building RP0 to conduct a thorough walkdown of the SFP piping and components in order to determine the inventory loss pat The RP0 was not able to identify the cause of the inventory loss during his shift and turned over the information to his dayshift relief at 7 a.m. on July 2 Watchstanders continued to search for the inventory loss without succes Finally, at 9:40 p.m. on July 21 an RPO discovered that SFP Pump 1A Drain Valve FC-0150 was partially open, which allowed SFP Pump 1A discharge to be directed to a drain that emptied into the fuel handling building sump where it was pumped to the mechanical auxiliary building water processing syste The RP0 shut Valve FC-0150 which stopped the SFP inventory los .3 Plant Operator Performance The inspectors conducted a partial walkdown of the SFP piping and components in order to determine if the amount of time required by the plant watchstanders to identify the cause of the SFP inventory loss was excessiv Both of the Unit 1 SFP pump rooms were posted as contaminated areas, which required operators to don anticontamination clothing prior to entr Valve FC-0150 was a %-inch angled globe valve with a "T" shaped handle that was positioned such that if plant personnel were not careful with the placement of their feet during inspection and log taking in the area of the
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pump, the valve handle could be kicked and inadvertently mispositione Downstream of the valve, the %-inch piping continued parallel to the floor and then turned downward at a 90-degree angle to approximately 1 inch above '
the floor drain. The floor drain had a funnel configured to prevent splashing during operation. This funnel also precluded direct observation of the discharge of the drain piping which make it difficult for watchstanders to 1 detect the leakage through that drain pat ;
Although the inventory loss continued for approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />, operators i were aware of the problem, monitored the SFP level to ensure that adequate inventory was maintained, and conducted walkdowns of the system to locate the source of the loss. Based on the system configuration, the inspectors I determined that the RP0s made a reasonable effort to identify the source of the SFP inventory los <
7.4 Licensee Corrective Action
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As a result of the SFP inventory loss problem, the licensee took several immediate and longer termed corrective actions. Immediate corrective actions taken includd: removing the "T" handled operators from all similar drain "
valves for the SFP pumps in both Units 1 and 2; briefing plant operators on the potential for inadvertent valve manipulation when .in confined areas; and continuing to monitor SFP level closely to ensure that the inventory loss had been isolate Longer termed corrective action included the generation of a station problem report to determine the root cause of this event. In addition, the licensee appointed an event review team to more closely examine the human performance aspects of this issu ,
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7.5 Conclusions The RPO who identified the loss of inventory in the SFP performed in an excellent manner. Plant operators continued to monitor SFP level as efforts '
were initiated to locate the source of the inventory los The RP0s made a reasonable effort to identify and isolate the source of the SFP inventory loss. Licensee actions appeared to be adequate to prevent a recurrence of this even ,
8 FOLLOWUP OF CORRECTIVE ACTIONS FOR VIOLATIONS, UNRESOLVED ITEMS, AND INSPECTION FOL4.0WUP ITEMS (92701 and 92702) (Closed) Unresolved item 498:499/93011-02: Incorrect Breaker Setpoints In NRC Inspection Report 498;499/93-11 it was identified that several Technical Specification limiting conditions for operation may have been ,
exceeded because of incorrect breaker setpoints. The potentially inoperable j electrical breakers resulted from the erroneous use of the incorrect setpoint values by maintenance planners. The instructions for setting circuit breaker i i
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-22-magnetic adjustable elements did not provide sufficient clarity to ensure consistent application. The trip setpoints were incorrectly set on 12 breakers. As documented in NRC Inspection Report 498;499/93-21, the issue was reviewed but remained unresolved because an engineering evaluation was being performed by the licensee to determine if the adjustments made to these circuit breakers were acceptable and the associated components served by the breakers were operable. Sx:ifically, the licensee was conducting an evaluation to determine if .ne magnetic trip settings for the affected circuit breakers were conservative and that these breakers in their as-found condition would have performed their intended functio An analysis of the molded case circuit breakers was performed to determine if the loads were actually inoperable. The licensee submitted their findings to the NRC in Revision 1 to Licensee Event Report 498/93-012. The results of the breaker testing indicated the breakers were operable based on analysis of the as-found breaker settings. The breakers were found to be operable because there was sufficient margin between the breaker settings and the locked rotor currents of the associated loads, or, in one case, the breaker was larger in amperage rating than originally considered. Based on these engineering analysis results, the licensee concluded that the loads supplied by the breakers had also remained operable. Therefore, no enforcement action was warranted, and this unresolved item is closed.
, (Closed) Inspection Followup Item 498:499/92021-02: Adequacy of Alarm Response Procedures During a previous inspection, inspectors noted that the alarm response procedure for the " Isolation Valve Cubicle Temperature High" alarm appeared inadequate to correct an area high temperature. This lack of procedural guidance was considered to be a weakness. An inspection followup item was used to track further reviews of other alarm response procedures in order to assess their adequacy and to assess the effectiveness of the procedure upgrade progra During this inspection period,12 alarm response procedures were reviewed for technical accuracy. Overall, the proceaures were adequate in their level of detail and accuracy. Problems were identified on some of the procedures. The
" Essential Cooling Water Pump 1B (2B) Bay Level Low" annunciator referred the operator to an " Essential Cooling Water Pond Level Low" annunciator, which was previously deleted by Engineering Change Notice Package 91-J-0021. The
" Emergency Response Facility System Alarm" procedure stated that the alarm was disabled by Temporary Modification T1-AN-89-031 in Unit 1 This temporary modification was restored in December 1992. These two examples indicate that the licensee still has problems with revising procedures in a timely manner following plant change As documented in NRC Inspection Report 498;499/92-15, inspectors reviewed and evaluated selected procedures to verify that the procedures were in .
conformance with appropriate requirements and were technically adequate. A procedure enhancement program commenced in May 1989 to upgrade station
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procedures, including alarm response procedures. This program was completed on the alarm response procedures in 1992. Overall, the procedures that were !
reviewed appeared to be technically adequate for their application, t
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ATTACHMENT 1 1 PERSONS CONTACTED ,
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Licensee Personnel H. Bergendahl, Manager, Technical Services M. Berrens, Shift Supervisor, Plant Operations J. Blevins, Supervisor, Procedure Control J. Calloway, Consultant, Participant Services M. Chakravorty, Executive Director, Nuclear Safety Review Board R. Cook, Senior Staff Consultant, Industry Relations W. Cottle, Group Vice President Nuclear S. Head, Manager, Licensing M. Johnson, Nuclear Licensing Technician T. Jordan, General Manager, Nuclear Engineering D. Keating, Director, Independent Safety Engineering Group W. Kinsey, Vice President, Plant Support D. Leazar, Plant Engineering Manager F. Mangan, General Manager, Plant Services L. Martin, General Manager, Nuclear Assurance L. Myers, Assistant Vice President, Operations G. Parkey, Plant Manager P. Parrish, Senior Specialist, Licensing R. Rehkugler, Director, Quality Assurance T. Underwood, Maintenance Manager C. Walker, Manager, Public Information The above listed personnel attended the exit meeting. In addition to these personnel, the inspectors-contacted other personnel during this inspection perio EXIT MEETING An exit meeting was conducted on August 24, 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 inspector ,