IR 05000282/1998007
| ML20248M135 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 06/05/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20248M130 | List: |
| References | |
| 50-282-98-07, 50-282-98-7, 50-306-98-07, 50-306-98-7, NUDOCS 9806150052 | |
| Download: ML20248M135 (31) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION lli Docket Nos:
50-282: 50-306 License Nos:
DPR-42, OPR-60 Report No:
50-282/98007(DRP); 50-306/98007(DRP)
Licensee:
Northern States Power Company Facility:
Prairie Island Nuclear Generating Plant Location:
1717 Wakonade Drive East Welch, MN 55089 Dates:
March 29 through May 11,1998 Inspectors:
S. Ray, Senior Resident inspector P. Krohn, Resident Inspector S. Thomas, Resident inspecter I
Approved by:
J. W. McCormick-Barger, Chief Reactor Projects Branch 7 9806150052 990605 PDR ADOCK 05000202 a
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EXECUTIVE SUMMARY Prairie Island Nuclear Generating Plant, Unit 1 and Unit 2 NRC Inspection Report 50-282/98007(DRP); 50-306/98007(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and picnt support. The report covers a six-week period of resident inspection.
Operations All operations activities observed were conducted well. Operators rapidly identified and
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responded properly to several turbine control valve problems and a problem with volume control tank levelinstrumentation. (Section 01.1)
' Licensee corrective actions for potential flooding of the Unit 2 main steam isolation valve
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rooms, a self-identified condition adverse to quality, were not thorough because engineers failed to prornptly identify or correct an equipment operability concem due to the potential flooding of an adjacent room. This was a violation of Criterion XVI,
" Corrective Action," of Appendix B,10 CFR Part 50. (Section O2.1)
The licensee's Individual Plant Examination did not fully identify the effects of raw water
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(cooling water, circulating water, or fire protection water) line breaks in the screenhouse basement because the examination failed to recognize that flooding of the area could result in inoperability of the motor starter disconnect switches of the fuel oil transfer pump for the diesel-driven cooling water pumps. The safety significance was mitigated by the ability to fill the diesel day tanks from other safety-related, independent fuel oil supplies.
(Section O2.2)
An outplant operator had insufficient knowledge of the location of auxiliary equipment for
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the D5 emergency diesel generator and failed to use self-checking techniques when
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verifying that precautions and limitations for a surveillance test were met. (Section O4.1)
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Maintenance
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All of the ten maintenance and surveillance test activities observed were performed well
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' with only two minor self-checking errors noted. One was identified by a licensee quality l
services inspector and the other by the NRC inspectors. Safe work practices and proper procedure use and adherence were also noted. Communications between the workers in the field and the control room were good. One minor procedure weakness was identified l'
in that a surveillance test procedure did not contain tolerances for test data.
(Section M1,1)
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l Safety-related and nonsafety-related backup air accumulators for air-operated valves in I
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L Unit 1 and Unit 2 were maintained well and met design, functional, and performance requirements. One minor error was noted in the design basis document describing the safety-related backup air accumulators for the containment vacuum breaker valves. Two more minor discrepancies were noted in the configuration documentation contained in a computerized database for the nonsafety-related portions of the backup air accumulator system. (Section M2.1)
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A procedural deficiency and poor communications between electrical maintenance
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l-supervisors and operations personnel contributed to the inadvertent rclling of the D2 emergency diesel generator during electrical post-maintenance testing. Specifically, the test procedure did not provide instructions for ensuring that mechanical portions of the diesel system were property isolated. This was a violation of Criterion V,
" Instructions, Procedures, and Drawings," of Appendix B,10 CFR Part 50. (Section M3.1)
The lack of clear direction to maintenance personnel reinstalling auxiliary feedwater flow
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orifices led to the orifices being installed backwards. The work order step for orifice reassembly did not provide instructions or refer to the drawing containing the proper orientation of the orifice plates. This was a violation of Criterion V, " Instructions, Procedures, and Drawings," of Appendix B,10 CFR Part 50. Maintenance personnel also demonstrated the lack of a questioning attitude conceming proper orifice orientation by either not noticing or fully considering the implications of the word " Inlet" stamped on the L
orifice face and not referring to drawings describing correct system configurations.
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(Section M3.3)
The failure to update auxiliary feedwater refueling surveillance with revised acceptance
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criteria resulted in performance of two surveillance tests with the wrong acceptance
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criteria. This was a violation of Criterion XVI," Corrective Action," of Appendix B, 10 CFR Part 50. It also resulted in a missed opportunity to identify improperly installed flow orifice plates in the system. A weakness in the licensee's administrative control program was also revealed in that there was no guidance for placing procedures in
quarantine until necessary procedure revisions were completed. (Section M3.4)
I Enaineerina Several deficiencies were identified with engineering support for equipment operability
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issues or maintenance and surveillance testing activities. Taken together, the findings raised a concem on the part of the NRC with the quality of engineering support at the facility. (Section E2.1)
Although Temporary Modification 95T047, which added a safety-related backup
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instrument air supply for operation of the cooling water strainer backwash valves, had been in place for over two and one half years, it had not been replaced by a permanent modification nor had periodic test or inspection procedures been developed to verify its proper operation. This was a violation of Criterion XI, " Test Control," of Appendix B, 10 CFR Part 50. (Section E3.1)
Plant Sucoort The two air ejector radiation monitor check sources (containing nine microcuries of
Cesium-137 in each source) were not included in the annual radioactive source inventory lists.- Even though the sources contained exempt quantities of Cesium-137, the radiation protection department had made a common practice of including all sources on the annualinventory lists for control and tracking purposes. (Section R3.1)
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l Report Details
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Summary of Plant Status Both Unit 1 and Unit 2 operated at or near full power for the entire inspection period.
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l. Operations
Conduct of Operations 01.1 General Comments a.
Inspection Scope Unspection Procedures UPs) 71707. 92901)
The inspectors conducted frequent reviews of plant operations. The reviews included observations of control room evolutions, shift tumovers, pre-job briefings, communications, control room access management, logkeeping, control board monitoring, and general control room decorum. Updated Safety Analysis Report (USAR),
Section 13, " Plant Operations," Revision 15, was reviewed as part of the inspection.
b.
Observations and Findinas The inspection period was characterized by routine, full power operation on both units with few operational challenges. Two unusual issues which required some operator action are described below.
On April 12,1998, the Unit 2 reactor operator noted that a small deviation was l
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developing between volume control tank (VCT) Level Channels 112 and 141. The channels each controlled various functions such as automatic VCT makeup, l
letdown diversion to the holdup tank, alarms, and automatic switching of charging pump suction from the VCT to the refueling water storage tank. Operators i
l inspected the detectors and noted a very small leak on one of the sensing lines.
l-Even though the operators believed they knew which detector was deviating from actual level, they tried to control VCT level such that the reading on both detectors
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would stay in the normal operating band. That activity became more and more difficult as the deviation slowly increased. A work request was promptly generated to repair the leaking detector, i
l Instrument and controls (l&C) technicians investigating the problem the next day l
determined that both level detectors had small leaks and both were indicating inaccurately. One was indicating too high and the other too low. The one L
operators had thought was deviating was actually the closest to actual level.
- Therefore the action by the operators to maintain level so that both detectors were indicating within the normal operating range was conservative and prevented the actual level from deviating out of the normal contrc' band.
The more inaccurate detector was replaced on April 15,1998, and the other detector was replaced two weeks later after the necessary parts became available.
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Toward the end of this inspection period, an anomaly, which caused the Unit 1
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turbine control valves to drift, reoccurred a number of times. In each case, operators were quick to identify the problem and take compensatory actions.
The operators and system engineer discovered that the onset of drift problems could be verified by monitoring for a divergence between the Govemor Valve Auto (GVAA21) and Auto Govemor (29 AGZ1) signals. Operators placed real-time plots for the two signals on a computer screen near the turbine control panel to help them predict and identify when the drifting would start. When the signals were noted to be diverging, or control valve drifting was noted, operators would briefly place the turbine controls in manual. The divergence between the signals was then corrected by taking turbine control momentarily to " imp-in" and then back to " imp-out" modes of operation.
The inspectors discussed the control valve drift issue with the system engineer responsible for the turbine control system. The system engineer stated that the anomaly was probably caused by a difference in potentist gradually building up across an amplifier located in the govemor valve controt circuit. The system engineer said that it was difficult to pinpoint the problem due its intermittent nature and that most attempts to troubleshoot the problem resulted in discharging the built-up potential which eliminated the cause of the divergence. He also related that there were ongoing discussions with Westinghouse turbine control specialists in an attempt to determine the cause of the potential buildup and that the electrical grounding of the turbine control cabinets for both units would be improved during future outages.
The issue with unexpected dri8 ting of the turbine control valves, resulting in the r,eed for operator action, was considered an " operator workarourid" and has been tracked by the licensee for a long time. Prior corrective actions seemed to have eliminated the problem until these recent incidents. Although diagnosing the exact cause of the problem has been difficult, adequate engineering attention was being applied to its resolution.
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Conclusions All operations activities observed were conducted well. Operators rapidly identified and responded properiy to several turbine control valve problems and a problem with volume control tank level instrumentation. One instance of inadequate knowledge and self-checking on the part of an outplant operator is discussed in Section 04.1 of this report.
Operational Status of Facilities and Equipment O2.1 ' inadeauste Corrective Actions for intemal Floodina Concem a.
Inspection Scope (IP 93702)
On March 23,1998, the licensee reported in accordance with 10 CFR 50.72 that it had
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identified a condition where a feedwater line break in Unit 1 could disable the ability to close the main steam isolation valves (MSIVs). The Unit 1 MSIVs were declared
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inoperable for a short period of time until interim compensatory actions were taken. On March 24,1998, the licensee reported a similar condition on Unit 2 and declared the Unit 2 MSIVs inoperable untilinterim compensatory actions were taken. The inspectors reviewed the findings and associated corrective actions. As part of the inspection, the following documents were reviewed:
USAR Section 14.4.10, " Loss of Normal Feedwater," Revision 14;
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USAR Section 14.5.5, " Rupture of a Steam Pipe," Revision 14;
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USAR Appendix 1, " Postulated Pipe Failure Analysis Outside of Containment,"
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Revision 14; and Licensee Event Report (LER) 1-98-05, "lnoperability of Actuation Logic for Main
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Steam isolation Valves in Certain Flooding Conditions from a Feedwater Line Break."
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Observations and Findinas The licensee described the findings and immediate corrective actions in LER 1-98-05, dated April 22,1998. The concem described was a high energy line break of a feedwater line which could have resulted in flooding of the Unit i loop A MSIV room and submergence of the MStV solenoid valves and junction boxes. The Unit i loop B MSIV could also have been affected since some of the wiring for its controls were in the same junction boxes. One of the two main feedwater lines was located in a room above the loop A MSIVs for both units and grating on the floor could have allowed flooding of the partially err used MSIV rooms below. The solenoid valves and junction boxes in the MSIV rooms were not designed for submergence and the flooding could disable the ability of the licensee to close the valves. The MSIVs were listed as required equipment for a feedwater line break in Table 1.4-1 of Appendix l of the USAR. Assuming a concurrent failure of the nonsafety-related atmospheric steam dumps, turbine control system, or other risam system components; failure of the MSIVs to close could result in an uncontrolled steaming rate and reactor coolant system cooldown with a resulting positive reactivity addition.
The licensee's immediate corrective actions were to block open doors in the Unit 1 MSIV room and remove a ventilation duct in the Unit 2 MSIV room. Those actions precluded the possibility of water building up to significant levels in the MSIV areas. Additional investigations were being conducted by the licensee and permanent corrective actions were being developed as discussed in the LER.
During the inspectors' review of the event, the inspectors noted that a Train A junction
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box for the Unit 2 MSIVs was located in a room adjacent to the loop A MSIVs. During an
' Operations Committee discussion on April 22,1998, the inspectors leamed that the licensee had assumed that the junction box would not be affected by a feedwater line break.. Licensee engineers had assumed that flooding of the adjacent room was not :
credible because most of the water from the postulated break would enter the MSIV room and openings in the floor of the adjacent room would be sufficient to prevent water buildup. The inspectors pointed out that the adjacent room was open for access from above and the postulated feedwater line break could dump large amounts of water into
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the room if the break flow happened to be directed toward the access. The opanings in the floor were quite small. Licensee engineers then inspected the room and confirmed with preliminary calculations that the adjacent room could flood and submerge the junction box. The licensee blocked open the doors between the room with the junction box and the loop A MSIVs to prevent a potential water buildup during a feedwater lins j
break.
On March 23 and 24,1998, the licensee identified concems with the potential effects of flooding from a feedwater line break on the ability of the MSIVs to close. The licensee took immediate interim corrective actions. However, the licensee failed to promptly
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identify or take corrective actions for the potential effect on an MSIV junction box in the room adjacent to the Unit 2 loop A MSIV until the concem was identified by the inspectors on April 22,1998. This was a violation of 10 CFR Part 50, Appendix B, Criterion XVI, which required that measures be established to assure that conditions adverse to quality i
are promptly identified and corrected (50-306/98007-01(DRP)).
Since the junction box identified by the inspectors affected only Train A of the two I
f redundant control circuits for the Unit 2 MSIVs, concurrent failures of a feedwater line, the train G MSIV cont ols, and at least one additional steam system component such as one i
of the atmosphe'.ic steam dumps would be required before the postulated event would cause an uncontrolled cooldown. Therefore, the potential flooding of the junction box was considered to be a condition adverse to quality of more than minor, but not of major safety significance. The licensee intended to supplement the LER with the information relative to the additional concem raised by the inspectors.
For the licensee's original finding, as discussed in the LER, two opportunities were missed to identify the condition. One was during initial plant licensing and the second was during the analysis for a USAR Appendix I revision completed on August 13,1996.
However, even though USAR Appendix I lists the MSIVs as required equipment for a
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feedwater line break, the analysis did not state exactly why they were needed. Neither the high energy line break analysis nor the analysis for a loss of feedwater event discussed the need for isolation of the main steam lines. In addition, the plant was
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analyzed for certain steam breaks such as a stuck open steam generator relief valve without MSIV isolation.
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The licensee was performing additional research and analysis on the effects of the
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feedwater line break. The results of that analysis were needed to determine the safety
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significance of the issue. The analysis was expected to be completed by about the end of May 1998. This issue is an Unresolved item pending the inspectors' review of the analysis (50-282/98007-02(DRP); 50-306/98007-02(DRP)). In addition, the licensee was working on a major revision to USAR Appendix I and expected to complete that effort by about August 1998. The LER remains open pending completion of the long-term corrective actions (50-282/98005; 50-306/98005).
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Conclusions Licensee corrective actions for a self-identified condition adverse to quality were not thorough because licenste engineers failed to promptly identify or correct an equipment operability concem due to the potential for flooding of an adjacent room when they took corrective actions for potential flooding of the Unit 2 MSIV rooms.
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O2.2 Investigation into the Effects of Screenhouse Floodina on Safety-Related Fuel Oil Transfer Eauipment
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Inspection Scope (IP 71701)
The inspectors evaluated the effects of nonsafety-related pipe ruptures on safety-related systems located in the basement of the plant screenhouse. Normal and flood river level conditions were considered as well as the height of electrical switchgear mounted on the screenhouse basement walls. Included in the inspection was a review of the following documents:
USAR Section 2.4.3.5, " Floods," Revision 13;
USAR Section 6.1.2.8, " Engineering Safety Features Protection from intomal
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Flooding," Revision 14; USAR Appendix F, " Probable Maximum Flood Study," Revision 4;
NRC Generic Letter 88-20, " Individual Plant Examination [lPE) for Severe
Accident Vulnerabilities - 10 CFR 50.54(f)";
Individual Plant Examination (IPE) NSPLMI - 9401, Table 3.3.9, Flood Designator
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SH2, " Effects of Flood Initiators," Revision 0; j
Abnormal Procedure AB-4, " Flood," Revision 12;
Procedure 1C20.6 AOP1, " Loss of Power to MCC [ motor control center) 1 AB1,"
Attachment A, " Actions to Restore 12 Diesel-Driven Cooling Water Pump Day Tank Level," Revision 4; Procedure 1C20.6 AOP2," Loss of Power to MCC 1AB2," Attachment A," Actions
to Restore 22 Diesel-Driven Cooling Water Pump Day Tank Level," Revision 5; Condition Report 19980645, "DDCLP [ Diesel-Driven Cooling Water Pump) FO
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[ Fuel Oil) Transfer Pumps Local Motor Starters Could Be Flooded in Screenhouse Basement at 674' if Pipe Break Exceeds Sump Pump," issued March 31,1998; Northem States Power Company Letter, "Information Related to Plant Drainage
Systems Resolution of NRC Generic issue No. 77," dated January 3,1985; ar.d
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Drawing NF-39232, " Flow Diagram Unit 1 & 2 Fuel & Diesel Oil System,"
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Revision AC.
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Observations and Findinas During a review of potential flooding consequences, the inspectors identified that the fuel oil transfer pumn motor starter disconnect switches for the 12 and 22 DDCLPs could be flooded in the screenhouse basement if a raw water (cooling water, circulating water, or fire protection water) pipe break were to exceed the sump pump capacity. The situation could also exist, even if the associated system pumps were stopped, if the break was
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located below the intake canal water level. The disconnect switches were located at an
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elevation of 672.8 feet above sea level, while the normal water levelin the intake canal
was 674.5 feet.
A licensee letter to the NRC dated Janua.y 3,1985, stated that no safety-related equipment was located in the basement of the screenhouse. Also, IPE Table 3.3.9 stated that a piping break in the lower level of the screenhouse would not affect the safeguards cooling water pumps and that all other remaining safeguards systems would function normally. The inspectors' finding contradicted those statements since flooding exceeding screenhouse sump removal capacity could submerge the DDCLP fuel oil transfer pump motor starter disconnect switches. Submerging the disconnect switches would prevent automatic transfer of fuel oil from the DDCLP fuel oil storage tanks to the DDCLP day tanks. The im> rectors brought this finding to the attention of the licensee.
The licensee issued Condition Report 19980645 and concluded that the DDCLPs were still operaole based on the ability to supply the DDCLP fuel oil day tanks from other
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safety-related, interconnected fuel oil storage tanks using the Unit i emergency diesel generator fuel oil transfer pumps. The inspectors verified that the appropriate procedures for using the alternate pumps were in place. The inspectors discussed the finding with a licensee risk assessment engineer who stated that the IPE would be revised during the next general revision to include the effects of flooding on the switches.
NRC Generic Letter 88-20 requested that the licensee submit an IPE. The licensee provided inaccurate information regarding the potential effects of intemal flooding in the screenhouse basement in its IPE submittal dated March 1,1994. However, the inaccuracy was not materialin that systems and procedures were in place to compensate for the potentialloss of the fuel oil transfer pumps due to flooding.
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Conclusions The licensee's IPE did not fully identify the effects of raw water line br eaks in the screenhouse basement because the examination failed to recognize that flooding of the area could result in inoperability of the motor starter disconnect switches for the DDCLPs.
The safety significance was mitigated bv the ability to fill DDCLP c'ay tanks from other safety-related, independent fuel oil supp.:es.
Operator Knowledge and Performance 04.1 Operator Knowledae Reaardina Emeroency Diesel Generator Auxiliaries
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Inspection Scope (IP 61726)
The inspectors observed an outplant operator during performance of routine emergency diesel generator surveillance tests.
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Observations and Findinas
l On April 13,1998, the inspectors attended the pre-job brief and observed the performance of surveillance tesiting in accordance with SP 2093, "D5 Diesel Generator Slow Start Test," Revision 64, and SP 2334, "D5 Diesel Generator 24-Hour Load Test,"
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Revision 7. Precaution and Limitation Section 3.8 of SP 2093 stated that the diesel generator was limited to 50-percent load with any one of the four duplex fuel oil filter cartridges out-of-service. After the operator had verified that all the precautions and limitations were met, the inspectors asked the operator to identify the fuel oil filters. The operator pointed to the lube oil filters located at the side of the diesel engine. The inspectors noted that these were the wrong filters and pointed out the error to the operator. The operator contacted the system engineer and learned that the duplex fuel oil filters were actually located under an auxiliary operating desk in the same diesel room.
The operator then located and verified the correct lineup of the duplex fuel oil filters.
The operator had been verifying that all precautions and limitations were met as part of the normal routine for preparing for a surveillance test. Although it was a management expectation that the precautions and limitations were met, there was no requirement in SP 2093 to purform that verification, so the failure of the operator to verify the correct lineup of the fuel oil filters was not a procedure violation. However, since the operator had initially verified that the wrong filters were in service, this event indicated a knowledge deficiency on the part of the operator and, of more significance, a failure to use self-checking techniques.
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Conclusions An outplant operator had insufficient knowledge regarding the location of auxiliary equipment for the D5 emergency diesel generator and failed to use self-checking techniques when verifying that precautions and limitations for a surveillance test were met.
II. Maintenance M1 Conduct of Maintenance M1.1 S. surveillance Testina and Maintenance Observations a.
Inspection Scope (IP 61726,62707)
The inspectors witnessed all or major portions of the following maintenance and -
surveillance testing activities. Included in the inspection was a review of the surveillance procedures (SPs) and work orders (WOs) listed below as well as the appropriate USAR sections regarding the activities. The inspectors verified that the surveillance tests
. reviewed met the requirements of the Technical Specifications.
WO 9713239, "PM 3001-2-D2,02 Generator 18 Month Inspection," Revision 13;
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l WO 9713349, " Install Fusing for Indicating Lights on 11 Service Building
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Ventilation System Exhaust Fan Damper,"(Design Change Procedure);
WO 9713351, " Install Fusing for Indicating Lights on 22 Service Building l
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Ventilation System Exhaust Fan Damper,"(Post-installation Test);
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WO 980377, * Replace Volume Control Tank Level Transmitter PT 141";
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SP 1024, " Refueling Water Storage Tank Level Functional Test," Revision 10;
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SP 1088, " Safety injections Pump Test," Revision 40;
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j SP 1093, "D1 Diesel Generator Functional Test," Revision 67;
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SP.1713, " Safety injection Pump Mini Recirc Line Flowmeter Annual Functional
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Test," Revision 5; SP 2093, "D5 Diesel Generator Slow Start Test," Revision 64; and
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SP 2334, "D5 Diesel Generator 24 Hour. Load Test," Revision 7.
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Observations and Findinas Maintenance and surveillance activities observed were all conducted well except for one minor pmblem with operator perfe,rmance during testing in accordance with SP 2093, which was discussed in Section 04.1 of this report. Pre-job briefings were adequate for the work being performed. Communications between the individuals performing the work in the field and the control room were formal and proper. Appropriate safety precautions were followed br all the jobs. Noteworthy comments on specific jobs are discussed below.
For WO 9713349 on the design change to install fusing for indicating lights, a
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licensee quality services inspector noticed that the electrician had inadvertently placed the wrong label on the newly installed fuse block. The eledrician had labels for design changes for four different dampers with him, and accidentally installed the wrong one. The discrepancy was corrected on the spot and the quality services inspector initiated an employee observation report to document
. the error. The electrician failed to perform adequate self-checking to identify his own error. However, the inspectors noted that the electrician had deliberately and carefully checked all of the other steps of the work.
The inspectors noted a minor procedural weakness during SP 1713 on the safety
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injection system. The I&C calibration worksheet attached to SP 1713 contained a note in the comments section to notify the l&C coordinator if tolerances could not be met. However, SP 1713 provided no guidance as to the quantitative value of the tolerances that were acceptable. The inspectors asked the l&C technician what the tolerances were. The technician said that the surveillance procedure contained instructions for checking the digital setpoints originally programmed onto a microprocessor calibration card in the flowmeter instrument. Since the j
programmed setpoints were digital and not expected to change or drift, the l
tolerance between the desired output and the as-found values was zero.
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Although the information on acceptable tolerances was within the knowledge of that particular technician, SP 1713 should have clearly stated that the tolerance for values recorded on the l&C calibration worksheet was zero.
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c.
Conclusions All of the ten maintenance and surveillance test activities observed were performed well with only two minor self-checking errors noted. One was identified by a licensee quality services inspector and the other by the NRC inspectors. Safe work practices and proper procedure use and adherence were also noted. Communications between the workers in the field and the control room were good. One minor procedure weakness was identified in that a surveillance test procedure did not contain tolerances for test data.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Examination of Backuo Air Accumulator Functions. Surveillance Testina. Material Condition. and Configuration Control a.
Inspection Scope (IPs 61700. 62707)
The inspectors reviewed design basis information, material condition, configuration control, and surveillance test procedures associated with safety-related and nonsafety-related backup air accumulators in Units 1 and 2. The review included backup air accumulator functional, performance, and design requirements as well as generic letter responses and actions. Particular attention was paid to interfaces between safety-related and nonsafety-related portions of the backup air accumulator e.M air supply lines. Included in the inspcdon was a review of the following documents:
Design Basis Document (DBD), Section 5.6, " Backup Accumulators," Revision 3;
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USAR Section 10.3.10, " Station Air System," Revision 14;
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USAR Section 14.5.4, " Steam Generator Tube Rupture," Revision 14;
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Prairie Island Nuclear Generating Plant Response to Generic Letter 88-14
" Instrument Air Supply Problems Affecting Safety-Related Equipment," dated February 20,1989; Procedure C34 AOP1, " Loss of Instrument Air," Revision 8;
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SP 1298, " Pressurizer PORV [ Power Operated Relief Valve) Air Accumulator
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Check Valve Leak Test," Revision 4; SP 2298, " Pressurizer PORV Air Accumulator Check Valve Leak Test,"
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Revision 3; Test Procedure (TP) 1766, " Instrument Air to Vacuum Breaker Check Valve Test,"
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Revision 3; TP 2766, " Instrument Air to Vacuum Breaker Check Valve Test," Revision a; l
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Preventative Maintenance Procedure (PM) 3505-5, " Instrument Air System Dew
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Point Test," Revision 7;
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Drawing NF-39770, " Instrument Air Supply and Control Piping Reactor
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Building - Unit 1," Revision R; Drawing NF-39771-1," Instrument Air Supply and Control Piping Auxiliary
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Building - Unit 1 & 2," Revision T; Drawing NF-39771-2," Instrument Air Supply and Control Piping Auxiliary
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Building - Unit 1 & 2," Revision P; Drawing NF-39771-3, " Instrument Air Supply and Control Piping Auxiliary
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Building - Unit 1 & 2," Revision M; Drawing NF-39772-1, " Instrument Air Supply and Control Piping Turbine
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Building - Unit 1," Revision W; Drawing NF-39773, " Instrument Air Supply and Control Piping Reactor
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Building - Unit 2," Revision M; Drawing NF-39774-1, " Instrument Air Supply and Control Piping Turbine
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Building - Unit 2 and Screenhouse Units 1 & 2," Revision T; Drawing NL-39776-600, " Instrument Air Accumulator," Revision Q;
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Drawing NH-92966, " Accumulator and Solenoid Mounting Valve Details for
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Turbine Driven Auxiliary Feedwater Pump Steam Supply Valve," Revision D; Drawing NL-39776-811-1, " Supply & Control Air Piping for Accumulators & Control
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Valves," Revision V; Drawing X-HIAW-1106-1, "6"-N-376-SP Swing Check Valve," Revision 1; and
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Drawing X-HIAW-1195-14, " General Arrangement Model 2Fil--18" Butterfly Valve
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with Bettis Operator," Revision A.
b.
Observations and Findinos The inspectors found that 28 backup air accumulators were installed for air-operated valves in Units 1 and 2. Of the 28 backup air accumulators, only four were safety-related:
those for the containment vacuum breakers and pressurizer PORVs. The inspectors reviewed TP 1766 and TP 2766 for the containment vacuum breakers and SP 1298 and SP 2298 for the safety-related pressurizer PORV accumulators and determined that the -
licensee properly tested each accumulator and associated inlet check valve.
The inspectors identified two minor equipment database discrepancies. First, the
inspectors noted that for nine of the nonsafety-related backup air accumulators, the j
licensee's computerized equipme.. database listed the inlet air supply check valve
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manufacturer as " Dragon." Inspection of the as-built configuration of the accumulators i
showed that these check valves were actually "Powell" manufactured valves. Second, J
the computer database cited drawing X-HIAW-1106-1 to describe the inlet air supply j
check valve to six nonsafety-related backup air accumulators on Unit 2.
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Drawing X-HIAW-1106-1, however, referred to a 6-inch nominal diameter swing check valve when the nctual size of the inlet check valves on the accumulators was %-inch nominal diameter. The errors were referred to the system engineer for resolution.
During a review of the D3D information, the inspectors asked the system engineer to identify exactly which backup air accumulators were considered safety-related, since the drawings and information were somewhat confusing. While responding to the inspectors'
question, the system engineer discovered that the design requirement infomiation for the safety-related containment vacuum breaker accumulators discussed in DBD Section 5.6.1.A.3 was incorrect. The DBD referenced drawing NL-39776-600 for the j
containment vacuum breaker safety-related accumulators. The actual safety-related air
accumulators supplying the containment vacuum breakers were described in Drawing X-HIAW-1195-14. Drawing NL-39776-600 described nonsafety-related accumulators also installed in the system. The inspectors discussed the findings with the DBD' administrator who stated that a change notice would be issued to correct Section 5.6 in the next DBD revision.
,
The inspectors examined the licensee response and subsequent actions related to l
Generic Letter 88-14 and found that licensee commitments and actions had been
!
properly implemented in surveillance test and plant procedures. The inspectors specifically verified that the actions to sample air system quality semi-annually and add procedural guidance conceming the failure modes of valves equipped with backup cir accumulators had been completed.
Material condition of the backup air accumulators and associated eir supply lines was
.
good. All equipment was properly maintained with no signs of degradation. The l
inspectors found that all of the backup air accumulators met the design, functional, and performance requirements discussed in the USAR and other design basis documentation.
,
c.
Conclusions i
Safety-related and nonsafety-related backup air accumulators for air-operated valves in Unit 1 and Unit 2 were maintair ed well: nd met design, functional, and performance requirements. One rninor error was rioted in the DBD describing the safety-related backup air accumulators for the containment vacuum breaker valves. Two more minor discrepancies were noted in the configuration documentation contained in a computerized database for the nonsafety-related portions of the backup air accumulator system.
M3-Maintenance Procedures and Documentation M3.1 Procedure Deficiencies Resultina in the inadvertent Rollina of the D2 Emeroency Diesel Generator (EDG)
a.
Inspection Scope (IPs 61700. 62707)
The inspectors examined the circumstances of the inadvertent rolling of the D2 EDG during performance of 18-month preventive maintenance. Work orders, isolation and restoration records, surveillance procedure revision records, and maintenance schedules associated with the D2 preventive maintenance were reviewed. The inspectors interviewed maintenance and electrical engineering supervisors to understand the
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communications, root causes, and corrective actions associated with the maintenance activity, included in the inspection was a review of the following documents:
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l l
WO 9713241, "PE 3001-4-D2, D2 Generator 18-Month inspection - Electrical,"
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l Revision 1;
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l WO 9713239, "PM 3001-2-D2, D2 Generator 18-Month Inspection," Revision 13;
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i SP 1306, "D2 Diesel Generator Functional Test," Revision 2;
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SP 1306, "D2 Diesel Generator Functional Test," Revision 3; and
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Procedure Submittal Form, Tracking 1.D. # PCR19962335, SP 1306, "D2 Diesel
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Generator Functional Test," dated August 19,1997.
t b.
Observations and Findinas
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j On April 30,1998, during performance of work under WO 9713239, testing in accordance
'
with SP 1306, Revision 3, was performed. When the D2 diesel generator control switch was p' aced in the neutral position per SP 1306, Step 7.8, the diesel air start solenoid valve opened and the EDG engine rolled. The engine did not start because the fuel oil q
l supply to the EDG was isolated.
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The inspectors noted that SP 1306, Revision 2, had contained a prerequisite that the l
D2 EDG be tagged out-of-service. However, Revision 3 to SP 1306 changed the l
prerequisite (Step 6.1) to require that the D2 EDG be logged out-of-service instead of tagged out-of-service. On April 30,1998, mechanical maintenance on D2 EDG was still in progress while electrical maintenance had been completed. Electrical post-maintenance testing in accordance with SP 1306 was scheduled. Realizing a potential conflict between mechanical and electrical activities and tagouts, the electrical maintenance supervisor stated during the daily work planning meeting on April 30,1998, that only the hold cards on the EDG output breaker and ground truck should be cleared prior to performing the testing. The remaining hold cards on the D2 diesel generator air starting isolation valve,2DG-35, and other components were to remain in place until other mechanical maintenance had been completed.
The electrical maintenance supervisor communicated these tagout instructions to the
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Unit 1 day-shift shift supervisor and night-shift electricallead-in-charge. Despite those instructions, the Unit i night-shift shift supervisor and electrical lead-in-charge cleared all of the hold cards associated with the D2 EDG electrical maintenance. This cleared the hold card on valve 2DG-35 providing a source of starting air to the diesel engine. When SP 1306, Step 7.8, was reached and the control switch was placed in the neutral position, a stari signal was received, energizing the air start solenoid valve, sending starting air to the engine, and causing the EDG to roll.
A system engineer locally observing the testing noticed the condition and manually
- isolated starting air to stop the diesel rolling. Knowing that the D2 EDG had been rolled
'without prelubrication, the EDG vendor representative later removed inspection covers and observed normal prelubrication oil flow before the engine was run again. The licensee concluded that no damage to EDG bearings or components had occurred.
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- Testing was aborted and engineers revised the surveillance procedure to include the correct isolations. Maintenance supervisors reviewed the revised surveillance procedure and verified that the necessary isolations were in place to prevent the D2 EDG from
. rolling again. The revised SP 1306 was then used to perform the testir.g without discrepancy. The licensee assigned its Error Reduction Task Force to conduct an investigation of the event and recommend corrective action. That investigation was not complete at the conclusion of this inspection period but some corrective actions had i
already been taken. Electrical engineering personnel were reviewing three other i
l 18-month EDG surveillance procedures (SP 1150, SP 2150, and SP 2306) to clearly l
identify mechanical and electrical interfaces and to ensure that adequate isolations existed prior to starting work.
Criterion V of Appendix B of 10 CFR Part 50 requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances. Surveillance Procedure 1306, Revision 3, was not appropriate to the circumstances because prerequisites and initial conditions Step 6.1 did not contain adequate isolation instructions to prevent an inadvertent start attempt of the diesel engine during surveillance testing. This was a violation (50-282/98007-03(ORP)).
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Although the violation was considered of minor safety significance for the health and safety of the public, the inadvertent rolling of the EDG could have resulted in personnel injury to maintenance workers. In addition, one of the root causes of the violation was that the licensee's review of logic circuits was inadequate to understand the effects of the surveillance activity. Since several other errors associated with inadequate logic reviews have been documented in recent inspection reports, the licensee-identified violation is considered repetitive and therefore enforcement discretion was not considered appropriate.
c.
Conclusions A procedural deficieay and poor communications between electrical maintenance supervisors and operations personnel contributed to the inadvertent rolling of the D2 EDG during electrical pcst maintenance testing. Specifically, SP 1306 did not provide instructions for ensuring that mechanical portions of the EDG system were properly isolated.
M3.2 Potential Failure to Verifv Bvoassino of Trios on Emeroency Diesel Generators a.
Inspection Scope (92902)
During the licensee's detailed review of SP 1306 as a result of the event discussed in Section M3.1 of this report, engineers discovered that they may have neglected to test one specific EDG trip feature required by Technical Specifications (TS2). The inspectors reviewed the details of the finding and the licensee's subsequent actions. The following documents were reviewed:
SP 1093, *D1 Diesel Generator Functional Test," Revision 67;
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SP 1306, "D2 Diesel Generator Functional Test," Revision 3;
.
.
e Drawing NE-40006, Sheet 73, " Schematic Diagram," Revision YB; a
Drawing NE-40009, Sheet 82, "D2 Emergency Diesel Generator Schematic
+
Diagram," Revision CW;
l USAR Section 8.4, * Plant Standby Diesel Generator Systems," Revision 14; and
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USAR Section 8.8, " inspection and Testing," Revision 11.
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b.
Observations and Findinas l
Technical Specification (TS) 4.6.A.3.e required that at least every 18-months, for Unit 1, the licensee simulate a safety injection signal and verify automatic bypass of the diesel generator trips, except those for engine overspeed, ground fault, and generator
differential current. The performance of testing in accordance with SP 1093 and -
SP 1306, for the D1 and D2 EDGs respectively, met the TS requirement for testing the automatic blocking of the low lube oil pressure, high Jacket coolant temperature, and high crankcase pressure trips. However, on April 30,1998, the licensee discovered that the automatic bypassing of the reverse current trip was not being tested.
At the time of discovery, the D2 EDG was inoperable for normal preventive maintenance and SP 1306 was revised to include testing of the automatic bypass feature of the
. reverse current trip before the EDG was retumed to an operable status. The bypassing
,
feature worked as designed during the test. The licensee made an initial operability L
assessment that the D1 EDG was operable because engineers thought that the verification had been accomplished by some other surveillance test. The superintendent of electrical systems engineering, who made the operability decision, stated that it was based on the fact that diesel tripping logic had been examined in detail at least three
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times in the recent past. One time was during completion of an Operational Event Assessment from an event at another plant, one time was in preparation for and during the NRC's Electrical Distribution System Functional Inspection, and one time was during
the licensee's reviews required by NRC Generic Letter 96-01, " Testing of Safety-Related Logic Circuits."
No existing surveillance test which performed the required circuit verification was found in the next few days, so SP 1093 was revised and testing was performed on May 7,1998.
The bypassing feature worked as designed. At that tima, licensee engineers still believed that the trip bypass feature had been properly tested in the past, but performed the new test anyway as a conservative action. The D5 and D6 EDGs on Unit 2 were of a different design and had been properiy tested.
Technical Specifications require that the bypassing of that trip be verified at least each 18-months. The licensee had not found proof that the verification had ever been accomplished before April 30 and May 7,1998. The licensee questioned if the TSs and regulatory guidance specifically requires verification of the bypassing of the reverse current trip. The inspector will further review this issue and discuss the technical requirements with the Division of Reactor Safety technical staff. The issue is considered an Unresolved item until the inspectors have completed this review and determined if a l
violation of TSs had occurred (50-282/98007-04(DRP)).
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O c.
Conclusions The verification required by TSs at least each 18-months that the reverse current trip of the EDGs was automatically bypassed during a safety injection may not have been accomplished for the D1 and D2 EDGs until April 30, and May 7,1998. If this is a valid concern, the licensee missed at least three opportunities in the last few years to identify the discrepancy.
M3.3 Procedure Deficiencies Resultino in the Backwards Installation of Auxiliary Feedwater (AFW) Pumo Orifices a.
Inspection Scope (IP 37551)
The inspectors examined the circumstances surrounding the backwards installation of Unit 2 AFW flow orifices. Work orders, surveillance procedures, condition reports, and engineering drawings associated with the Unit 2 AFW to steam generator flow orifice installations were reviewed. Maintenance personnelinvolved with the removal and installation of the orifices were interviewed to understand the materials and information available to woricers at the job aite. Included in the inspection was a review of the following documents:
WO 9800533, " Inspect FE [ Flow Element)-27146, AFW to 21 SG [ Steam
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Generator) Flow Orifice";
WO 9800534, " Inspect FE-27148, AFW to 22 SG Flow Orifice";
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USAR Section 11.9.2.2, " Auxiliary Feedwater System," Revision 14;
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SP 2101, "21 Motor-Driven Auxiliary Feedwater Pump Once Every Refueling
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Shutdown," Revision 26; SP 2103, "22 Turbine-Driven Auxiliar' Nedwater Pump Once Every Refueling
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Shutdown," Revision 29; Condition Report 19980890, " Unit 2 Degraded AFW Flow Indication as a Result of
+
Orifices Being Installed Backwards," identified April 27,1998; Condition Repori 19980891, "22 AFW Pump Declared inoperable Due to
Surveillance Results That Would Not Have Met Operability Limits," identified April 27,1998; and Drawing X-HIAW-452-2, * Daniel industries Inc. Orifice Flange Plate Drawing,"
.
Daniel Industries Drawing SO-23107-2.
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b.
Observations and Findinaf l
l On April 26,1998, an engineering superintendent performing a close-out review of a i
SP 2103 procedure change request that included changing acceptance criteria, noted
'
that this change should have been completed prior to a March 5,1998, performance of the same surveillance test. The superintendent's finding prompted an analysis of the
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l March 5 data which suggested that the revised acceptance criteria would not have been met. Subsequently, the licensee determined that the AFW to steam generator orifice plates for 21 and 22 steam generators (FE-27146 and FE-27148), which had been removed for inspection during a Unit 2 forced outage in February-March 1998, had been j
installed backwards.
l The orifice plate manufacturer was contacted and indicated that a reversed flow orifice would result in a flow indication approximately 20-percent lower than actual. Testing in accordance with SP 2103 and SP 2101 had been performed on March 4 and 5,1998, to meet American Society of Mechanical Engineers (ASME),Section XI, check valve testing requirements imposed during extended shutdowns. Licensee engineers determined that the Unit 2 AFW pumps were operable based on the following:
the flow error caused by the orifice platos being installed backwards was
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conservative, in that actual flow was greater than indicated flow;
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the previous performance of testing in accordance with SP 2101 and 2103, with
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the orifice platn in the proper orientation, had been satisfactory when compared to the revised im acceptance criteria; no maintenance had been performed on the Unit 2 AFW pumps; and
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the monthly AFW pump surveillance did not suggest any pump degradation.
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The inspectors reviewed WOs 9800533 and 9800534 which contained instructions for removal, inspection, and reinstallation of the AFW to steam generator flow orifices. The work orders had been written by the Unit 2 AFW system engineer and the work had been accomplished on February 9 and 10,1998. Work Order Step 7.8 provided instructions to reinstall the orifice plates in the AFW piping following inspection but did not provide any guidance as to the orientation of the plates. While a drawing showing the proper orifice orientation was attached to the WOs, Step 7.8 did not specifically refer the workers to that information.
On April 29,1998, the inspectors interviewed the maintenance workers who reinstalled the orifice plates in accordance with Step 7.8. None of the workers could recallif they had referred to the drawing showing the correct orifice orientation or if the drawing had even been attached to the WOs used at the job site on February 9 and 10,1998. One of the workers mentioned that, since this work took place in the radiologically clean portion of the auxiliary building, it was likely that the record copy of the WO was present at the job site. Although the inspectors could not independently verify the statement, the same worker said that it was likely that the record copy would have had the drawing showing the correct orifice orientation attached. During the investigation, the inspectors noted that the orifice plates had the word " Inlet" stamped on the side of the orifice through which flow should have entered. The maintenance workers did not notice or fully consider the implications of that stamp.
Criterion V, of Appendix B, of 10 CFR Part 50, requiros, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances. Step 7.8 of WOs 9800533 and 9800534 was not appropriate to the circumstances because it did not contain adequate instructions to l
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O ensure the proper orientation of flow element orifice plates when reinstalled in the AFW system. As a result, maintenance workers reinstalled the orifice plates backwards, resulting in low AFW system flow indications during surveillance testing. This was a violation (50-306/98007-05(DRP)).
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Installing the orifice plates backwards affected AFW flow measurements but did not affect actual flow to the steam generators. Since the flow indications were lower than actual flow, the error was in the conservative direction for most accident conditions since emergency operating procedures (EOPs) call for maximum AFW flow until steam
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generator levels are in the indicating band and then call for controlling AFW flow by observing steam generator levels rather than AFW flow. However, if AFW flow indicated less that 200 gallons per minute when it was actually greater than 200 gallons per minute, an unnecessary entry into Functional Response Procedure 1(2)FR-H.1, " Response to Loss of Secondary Heat Sink," could have resulted during certain scenarios. Thus the error was considered to be of more than minor safety significance.
The licensee has referred this event to the Error Reduction Task Force for determination of root cause and recommendations to prevent reoccurrence. As an interim corrective action, SP 2101 and SP 2103 were quarantined until the procedure change process was completed. Due to previously identified WO problems, the licensee had instituted a user
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review of all safety-related WOs before they were used. However, the AFW orifice WOs had been written before that policy was established. New WOs 9804014 and 9804016
'i have been written to direct the reorientation of the orifice plates during the next scheduled refueling outage in November 1998. Because a number of examples of inadequate WOs have been identified in recent NRC inspections, this event was considered repetitive and enforcement discretion was therefore not appropriate.
c.
Conclusions Lack of clear direction to maintenance personnel reinstalling AFW flow orifices in
,
accordance with WOs 9800533 and 9800534 led to the orifices being installed backwards. The work order step for orifice reassembly did not provide instructions or refer to the drawing containing the proper orientation of the orifice plates in the AFW !ine.
Maintenance personnel also demonstrated the lack of a questioning attitude conceming proper orifice orientation by either not noticing or fully considering the implications of the word " Inlet" stamped on the orifice face and not referring to drawings describing correct system configurations.
M3.4 Failure to Promptly Correct inadeouate Acceptance Criteria in AFW Surveillance Test Procedures a.
Inspection Scope (IP 37551)
During the course of its investigation of the evant discussed in Section M3.3 of this report, the licensee discovered that it had failed to promptly complete some corrective actions for a previously identified violation. The inspectors reviewed the circumstances of the finding. The inspectors reviewed the following documents as part of the inspection:
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SP 2101, "21 Motor-Driven Auxiliary Feedwater Pump Once every Refueling
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Shutdown," Revision 26;
20
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SP 2103,"22 Turbine-Driven Auxiliary Feedwater Pump Once every Refueling
)
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Shutdown," Revision 29; and Condition Report (CR) 19980891, "22 AFW Pump Declared Inoperable Due to
.
Surveillance Results That Would Not Have Met Operability Limits," identified April 27,1998.
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l b.
Observations and Findinos in May 1997, the NRC identified that AFW surveillance procedures, as written, did not verify that the AFW pumps could meet their design flow requirements because they did not adequately consider the effects of instrument tolerances. The finding was documented in Safety System Operational Performance Inspection Report 50-282/97008(DRS); 50-306/97008(DRS), Section E1.1, and the associated enforcement action documentation (EA 97-290). Based on engineering calculation ENG-ME-321, the licensee subsequently determined new acceptance criteria and initiated action item CR 19970254 to change the acceptance criteria for each of the eight affected
.
l surveillance procedures. Procedure change requests (PCRs) were issued for all eight of the procedures and temporary memoranda were issued for six of the eight procedures pending completion of the procedure change process. Because the next Unit 2 refueling i
outage was not scheduled until November 1998, it was not expected that the Unit 2 AFW refueling surveillance procedures (SP 2101 and SP 2103) would be needed prior to the completion of the procedure change process. As a result, temporary memoranda were not issued for SP 2101 or SP 2103. However, SP 2101 and SP 2103 were not quarantined to prevent their use until the procedure revisions were completed.
During the course of the Unit 2 outage for the removal of the part length control rod drive mechanisms, the licensee determined that, upon retuming to power, SP 2101 and SP 2103 would be required to meet ASME Section XI check valve testing requirements imposed during extended cold shutdown periods. Testing in accordance with SP 2103 was performed on March 4, and SP 2101 on March 5,1998, prior to the PCR for these surveillance bemg completed. Failure to revise the procedures before they were used was of more than minor safety significance because, had they been revised, it is likely that the improperly installed orifice plates discussed in Section M3.3 of this report would ho ' been discovered because the surveillance would have failed to meet the revised at
'ance criteria. As part of the corrective actions for this issue, the licensee was devo.oping administrative guidance for establishing quarantine provisions for procedures that should not be used until a revision is completed.
Failure to promptly correct the inappropriate acceptance criteria in AFW surveillance
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SP 2101 and SP 2103, or to take actions to assure that the procedures would not be
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used until corrected, was a violation of 10 CFR Part 50, Appendix B, Criterion XVI,
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" Corrective Action"(50-306/98007-06(DRP)).
l c.
Conclusions l
Failure to update AFW refueling surveillance with revised acceptance criteria resulted in l
prformance of two surveillance tests with the wrong acceptance criteria. It also resulted i
in a missed opportunity to identify improperly installed flow orifice plates in the AFW I
system. A weakness in the licensee's administrative control program was also revealed j
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in that there was no guidance for placing procedures in quarantine until necessary procedure revisions were completed.
Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Enoineerina Support of Operations. Maintenance. and Surveillance Testina Activities l
Several of the issues discussed in previous sections of this report involved equipment l
operability issues or maintenance and surveillance testing activities. However, most of the issues also involved engineering support of those activities and several deficiencies in that support were identified. Some of the issues were identified by the plant staff, but others were identified by the NRC. During this inspection period, violations of regulatory requirements were identified conceming two instances of failure to promptly correct conditions adverse to quality, two instances of procedures that did not contain enough information to ensure successful performance of maintenance and testing activities, and i
one instance of failure to develop testing for a safety-related system that was installed i
over 2 % years ago. In addition, weaknesses were identified in the plant's individual l
Plant Examination submittal, the plant's computerized equipment database, and a safety l
evaluation for a temporary modification. Two other licensee-identified issues were considered unresolved items which meant that violations of regulatory requirements may have occurred but more information was needed for a final determination. Taken together, the findings raise a concem on the part of the NRC regarding the quality of l
engineering support at the facility.
E2.2 Review of Updated Safety Analysis Report (USAR) Commitments ops 37551. 92903)
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While performing the inspections discussed in this report, the inspectors reviewed the app!icable portions of the USAR that related to the areas inspected and used the USAR as an engineering /lachnical support basis document. The inspectors compared plant
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practices, procedures, and/or parameters to the USAR descriptions as discussed in each section. The inspectors verified that the USAR wording was consistent with the observed l
plant practices, procedures, and parameters. No discrepancies were identified.
E3 Engineering Procedures and Documentation E3.1 Inadeauste Temporary Modification on Air Suppiv to Coolina Water Strainers a.
Inspection Scope UP 92903)
l The inspectors reviewed the adequacy of a temport.ry modification performed in 1995 to i
add a safety-related backup instrument air supply for operation of the cooling water i
strainer backwash valves. As part of this inspection, the inspectors reviewed the I
following documents:
Temporary Modification 95T047, " Backup Compressed Air Supply for Cooling
Water Strainer Backwash Valve Actuator," Revision 0;
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WO 9606278, " Install Backup Compressed Air System for Cooling Water Strainer
Backwash Control Valves";
NRC Information Notice No. 88-24, " Failures of Air-Operated Valves Affecting
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Safety-Related Systems";
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Automatic Switch Company (ASCO) Catalog No. 31, "ASCO Red-Hat Solenoid Valves," Bulletin 8317; Neles-Jamesbury Valves Catalog, Bulletin 251;
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i Procedure H10.1, "ASME Section XI Inservice Testing implementation Program,"
.
Revision 8; and Design Change 97ZH02, " Backup Cc;.ipressed Air Supply for the Control Room
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Chillers," Revision 1.
b.
Observations and Findinos The safety-related cooling water system was designed with four strainers that.
automatically backwashed by flushing water back irito the intake bay on high strainer differential pressure. The strainer backwash control valves were designed to fail to the open position on loss of instrument air to insure that the strainers could still be flushed during a loss of the nonsafety-related instrument air system. During a self-assessment of the cooling water system in 1995, licensee engineers discovered that, if all four of the backwash valves were to fail open, enough flow might be diverted from the cooling water header that the design heat removal capability might not be met. To address that concem, the engineers developed a temporary modification to install a safety-related backup supply of compressed air so that in case of loss of instrument air, the control valves would not fail open. The backup air would also allow the backwash valves to be used to clean the strainers as needed during a loss of instrument air event. Installation of the backup system was completed in September 1995. Prooperational testing of the system was completed on October 3,1995.
Tne inspectors had three concems with the temporary modification:
The installation was intended to be temporary. The safety evaluation for the
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temporary modification stated, "In the long term, a modification will be initiated."
After about 2 % years, the temporary installation was still in place and action to design a permanent replacement was proceeding slowly.
The compressed air bottle installed was normally charged to sbout 2200 pounds
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per square inch-gauge. The safety evaluation for the installation addressed the possibility of the regulator on the compressed air bottle failing and subjecting the system to the full bottle pressure. In that case, the installation tubing would probably fail, resulting in the same mode of failure as the originalloss of instrument air pressure that the installation was intended to prevent. The licensee concluded that no new type of malfunction of equipment important to safety was introduced.
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However, the regulator was exactly the same (Smith Model H1408-346) as in another recently installed backup air system for the control room chillers. The l
safety evaluation for that design change stated that the regulator was a two-stage l
model. In case of failure of the first stage, an intemal relief valve prevented damage to the second stage. in case of failure of the second stage, discharge pressure of the regulator would be about 250-pounds per square inch-gauge.
I That pressure would probably not damage the installation tubing but, according to the appropriate vendor catalogs, would overpressurize the solenoid and control valves in the backwash system. Such a condition could potentially prevent the backwash valves from opening when required as discussed in NRC Information Notice No. 88-24. The inspectors determined that the safety evaluation for the temporary modification did not address that type of failure, nor verify that the modification dio not introduce a different type of malfunction of equipment important to safety than those previously evaluated in the USAR.
At the end of the inspection period, the system engineer informed the inspectors that he was in the process of revising the safety evaluation to include failure of the regulator second stage. This issue will be considered an Unresolved item (50-282/98007-07(DRP); 50-306/98007-07(DRP)) pending revision of the safety evaluation to determined whether a 10 CFR 50.59 viclation may have occurred due to failure to evaluate the regulator second stage failure.
The inspectors identified that no testing or preventive maintenance procedures l
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were developed to test or inspect the installation despite the fact that the system
,
had been in place for over 2 % years. Proper operation of most of the system was
'
verified once on installation, but the operation of the check valves intended to isolate the safety-related backup air supply from the nonsafety-related instrument air system in case of its failure were not tested on it'stallation or since. For the
similar design change that installed a backup air supply to the control room chillers, the licensee developed preventative maintenance procedures that checked all components annually. Failure to establish tests to demonstrate that the components and system installed under Temporary Modification 95T047 would pe; form satisfactorily in service was a violation of 10 CFR Part 50, Appendix B, Criteria XI, " Test Control" (50-282/98007-08(DRP);
50-306/98007-08(DRP)).
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Conclusions c.
The safety evaluation for Temporary Modification 95T047, which added a safety-related backun instrument air supply for operation of the cooling water strainer backwash valves, was not adequate in that it did not address the effects of a failure of the second stage of
,
l the compressed air bottle regulator. In addition, although the temporary modification had been in place for over two and one half years, it had not been replaced by a permanent modification nor had periodic test or inspection procedures been developed to verify its proper operation.
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f E8 Miscellaneous Engineering lasues (IPs 97700, 92903)
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E8.1 (Open) LER 50-282/98006: 50-306/98006 (1-98-06): Control Room Vent Outside Air Equipment Qualification.
l This LER discussed a condition, identified by the licensee, in which one of the outside air l
isolation dampers for the control room ventilation system was found not to be qualified for l
the environment which might exist during a design basis accident. At the time of discovery, the issue was not an operability concem since the control room outside air l
dampers were all isolated for other reasons. However, the condition had existed since initial plant construction.
As discussed in the LER, the damper was backed by redundant downstream isolation dampers, but the configuration would not have met single failure criteria assuming the I
subject damper failed due to a harsh environment. Since all control room outside air dampers were isolated at the time of discovery, no additional immediate corrective actions were necessary. The licensee's long-term corrective actions, as described in the LER, should be adequate to resolve the condition. No other recent cases of inadequate environmental qualification of equipment have been identified and the finding appeared to be an isolated case. All other control room ventilation equipment, including the other outside air isolation dampers, were located in areas that would be mild environments during design basis accidents.
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Failure of the licensee to assure that suitable materials, parts, and equipment were selected for damper CD-34177 so that it could perform its safety-related function of i
isolating outside air to the control room during all design basis accidents was a violation l
of 10 CFR Par 150, Appendix B, Criterion lil, " Design Control." This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-282/98007-08(DRP);
50-306/98007-08(DRP)). The LER will remain open pending the completion of the
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corrective actions discussed therein.
IV. Plant Support R3 Radiological Protection and Chemistry Procedurus and Documentation
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R3.1 Condenser Air Elector Gas Monitor Review l
a.
Inspection Scope (IP 71750)
The inspectors examined the material condition and the design, performance, and surveillance requirements associated with the Unit 1 and 2 condenser air ejector gas l
monitors. Interactions with connected auxiliary building ventilation systems were reviewed as well as radioactive source term bases. Included in the inspection was a review of the following documents:
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Final Safety Analysis Report (FSAR), Section 11.2.3, " Condenser Air Ejector Gas
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Monitor," Amendment 12;
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USAR Section 7.5.2, " Process Radiation Monitoring System," Revision 14;
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USAR Section 14.5.4, " Steam Generator Tube Rupture," Revision 14;
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USAR Appendix D, " Radioactive Source Bases," Revision 14;
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Offsite Dose Calculation Manual, Section 5.0, " Gaseous Effluent Calculations,"
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Revision 14; Radiation Protection implementing Procedure (RPIP) 1732, " Radioactive Source
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Tracking, inventory and Leakage Testing," Revision 0; SP 1028, " Radiation Monitoring Monthly Source Test," Revision 32;
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Radiation Protection Procedure (RP) 122, " Semi-Annual Leakage Test Source
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Leak Test";
Prairie Islano Nuclear Generating Plant Annual Inventory Source Location List;
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and Prairia Island Nuclear Generating Plant AnnualInventory Source List Annual
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Decay.
b.
Observations and Findinas The inspectors examined the material condition and routing of ducting connecting the Unit 1 and 2 condenser air ejector discharges to the auxiliary building ventilation systems. Sufficient holdup volume between the air ejector discharges and the auxiliary building ventilation systems was available for the decay of short-lived isotopes that would be discharged from the condensers during a steam generator tube rupture accident. The material condition of the air ejector gas monitors and connected ducting was good.
Radioactive source term quantities, activities, and assumptions were consistent between offsite dose calculation manual and USAR references.
The inspectors researched the condenser air ejector radiation monitor check source inventory requirements and found that, when performing testing in accordance with SP 1028, Steps 7.8 and 7.9, the technicians used the installed check sources to obtain a meter response on the air ejector gas monitors (1R-15 and 2R-15) Radiation Protection Imp;ementing Procedure 1732, Step 11.0, stated that since SP 1028 used the sources to obtain 1R-15 and 2R-15 monitor responses, the sources were effectively inventoried in place and no further verification was required.
The air ejector radiation monitor check sources (Serial Number 02-013 for Unit 1 and Serial Number 02-016 for Unit 2) both contained 9 microcuries of Cesium-137. Since the activities were less than 10 microcuries, the check sources were exempt according to 10 CFR 30.71, Schedule B. Thus, there was no requireinent mandating inventory or
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I leakage testing of the air ejector radiation monitor check sources. The inspectors noted i
L that the check sources were not included in the annual source inventory location or decay lists mairtained by the radiation protection department. However, the lists contained several other exempt sources that were less than the limits of 10 CFR 30.71, Schedule B.
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The inspectors asked a radiation protection department system engineer why the air ejector radiation monitor check sources had not been included in the inventory lists of sources maintain 9d by the licensee. The system engineer responded that this was an oversight and that it was intended that the check sources should have been included in the inventory lists. The system engineer subsequently updated the annual inventory lists to include the sources.
c.
Conclusions The air ejector radiation monitor check sources were not included in the annual radioactive source inventory lists. Even though the sources contained exempt quantities of Cesium-137, the radiation protection depsrtment had made a common practice of including all sources on the annual inventory lists for control and tracking purposes.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 11,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED Licensee J. Sorensen, Plant Manager K, Albrecht, General Superintendent Engineering, Electrical / Instrumentation & Controls T. Amundson, General Superintendent Engineenng, Mechanical J. Goldsmith, General Superintendent Engineering, Generation Services J. Hill, Manager Quality Services G. Lenertz, General Superintendent Plant Maintenance R. Lindsey, General Superintendent Safety Assessment D. Schuelke, General Superintendent Radiation Protection and Chemistry T. Silverberg, General Superintendent Plant Operations M.' Sleigh, Superintendent Security I
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INSPECTION PROCEDURES USED
' IP 37551:
Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750 Plant Support Activities IP 92700:
Onsite Follow-up of Written Reports of Non-routine Events at Power Reactor Facilities IP 92901:
Follow up - Operations IP 92902:
Follow up - Maintenance IP 92903:
Follow up - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50-306/98007-01(DRP)
VIO Failure to Promptly identify or Correct a Flooding Concem for a Unit 2 MSIV Junction Box 50-282/98007-02(DRP)
URI Potential Inoperability of MSIVs due to a Feedwater Line 50-306/98007-02(DRP)
Break 50 282/98005 (1 98-05)
LER inoperability of Actuation Logic for Main Steam isolation 50-306/98005 Valves in Certain Flooding Conditions from a Feedwater Line Break 50-282/98007-03(DRP)
VIO Inadequate Procedure for Electrical Testing of the D2 EDG 50-282/98007-04(DRP)
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Possible Failure to Perform TS Required Surveillance Testing of the Unit 1 EDGs l
I 50-306/98007-05(DRP)
VIO Inadequate Procedure for Installing AFW Flow Element l
Orifices
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50-306/98007-06(DRP)
VIO Failure to Promptly Correct incorrect Acceptance Criteria in AFW Surveillance Test Procedures 50-282/98007-07(DRP URI Possible failure to perform an evaluation in accordance with 50-306/98007-07(DRP)
10 CFR 50.59 50-282/98007-08(DRP)
VIO Failure to Develop Testing Procedures for a Safety-Related 50-306/98007-08(DRP)
Temporary Modification to the Cooling Water System 50-282/98006 (1-98-06)
LER Control Room Vent Outside Air Equipment Qualification 50-306/98006 50-282/98007-09(DRP)
NCV Control Room Vent Outside Air Equipment Qualification 50-306/98007-09(DRP)
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Closed None.
Discussed
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LIST OF ACRONYMS USED AFW Auxiliary Feedwater ASCO Automatic Switch Company ASME American Society of Mechanical Engineers CFR Code of Federal Regulations CR Condition Report DBD Design Basis Document DDCLP.
Diesel-Driven Cooling Water Pump DRP Division of Reactor Projects DRS Division of Reactor Safety EA Enforcement Action EDG
- Emergency Diesel Generator FE Flow Element FO Fuel Oil FSAR Final Safety Analysis Report I&C Instrument and Control IP inspection Procedure
'IPE Individual Plant Examination LER Licensee Event Report
'MCA Maximum Credible Accident MSIV Main Steam isolation Valve NCV Non-Cited Violation NRC Nuclear Regulatory Commission PCR Procedure Change Request
.PDR Public Document Room PM Preventive Maintenance
.PORV Power Operated Relief Valve
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RP Radiation Protection Procedure RPIP Radiation Protection implementing Procedure SI Safety injection SP Surveillance Procedure TP Test Procedure
.TS Technical Specification URI Unresolved item USAR Updated Safety Analysis Report VCT Volume Control Tank VIO Violation WO Work Order
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