IR 05000295/1988012
| ML20196J149 | |
| Person / Time | |
|---|---|
| Site: | Zion File:ZionSolutions icon.png |
| Issue date: | 06/22/1988 |
| From: | Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20196J125 | List: |
| References | |
| 50-295-88-12, 50-304-88-13, NUDOCS 8807060332 | |
| Download: ML20196J149 (23) | |
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'. U.S. NUCLEAR REGULATORY COMMISSION
. REGION III Report Nos. 50-295/88012(DRP); 50-304/88013(DRP)
Docket Nos. 50-295; 50-304 License Nos. DPR-39; DPR-48 Licensee: Commonwealth Edison Company P. O. Box 767 Chicago, IL 60690 Facility Name: Zion Nuclear Power Station, Units 1 and 2 Inspection At: Zion, IL Inspection Conducted: April 14 through June 3, 1988 Inspectors: M. M. Holzmer P. L. Eng N
Approved By: J. M. Hinds, Chief d-ZE 68 Reactor Projects Section 1A Date Inspection Summary Inspection from April 14 through June 3, 1988 (Report Nos. 50-295/88012(DRP);
50-304/88013(DRP))
Areas Inspected: Routine, unannounced resident inspection of licensee action on previous inspection findings; summary of operations; Unit 1 startup from refueling; testing of accumulator backup check valves; Unusual Event due to failure to test blackout logic; engineered safety features (ESF) actuation; Unit 1 reactor trip; operational safety verification and ESF system walkdown; surveillance observation; maintenance observation; licensee event reports (LERs); training; and followup of Region III "equest Results: Of the 12 areas inspected, no violations or deviations were identified in seven areas, and six violations were identified in the remaining five areas. Several test procedure deficiencies were identified, as well as failures to follow the procedures, to maintain retrievable test records and to make proper log entries. Some of these deficiencies were repetitive in natur In addition, a response to an NRC notice of violation was found to be inaccurate, Technical Specification required surveillance requirements were not properly incorporated into plant testing procedures, and a change to the plant was not controlled in accordance with design control procedures. None of these violations alone represented a significant increase in risk to members of the ;
general public or to plant workers, but taken together, they indicate a need for l increased attention to detail and management oversigh PDR O
ADOCK 05000295 j PDC
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'. ' DETAILS Persons Contacte +* Plim1, Station Manager
- E.:Fuerst, Superintendent, Production,
- T. Rieck, Superintendent, Services W. Kurth, Assistant Station Superintendent, Operations-
"R. Johnson, Assistant Station Superintendent, Maintenance
- J. Gilmore, Assistant Station Superintendent, Planning
+*R. Budowle, Assistant Station Superintendent, Technical Services
+*N. Valos, Unit 2 Operating Engineer
- M. Carnahan, Unit 1 Operating Engineer
- T. Vandevoort,-Quality Assurance Supervisor
+C. Schultz, Quality Control Supervisor
+*W. Stone, Regulatory Assurance Supervisor
- A. Bless, Regulatory Assurance Engineer
- R.-Mika, Assistant Technical Staff Supervisor
- J. Tiemann, Primary Group Leader, Technical Staff
- P. Beinecke, Thermal Group Leader, Technical Staff-
- M. Petersen, Procedure Coordinator, Regulatory Assurance
+ Printz, Assistant Technical Staff Supervisor
+ Squires, Nuclear Safety, General Office
- Indicates persons present at the exit interview on May 26, 198 + Indicates persons present at the exit interview on June 3, 198 . Licensee Actions on Previous Inspection Findings (92701)
(Closed) Unresolved Item (304/87018-02) July 7, 1987 automatic start of the 2A reactor containment fan cooler (RCFC). This event was an engineered safety feature (ESF) actuation caused by a personnel erro An operator, accompanied by a technical staff engineer, was performing the lineup of TSSP 59-87, "Actuation Test of Unit 2 Second Level Undervoltage MG-6 Relays." The lineup required that 120-volt circuit breakers for safe shutdown circuitry be in the OFF position to prevent actuation of safe shutdown ESF equipment ~. The operator assumed that these breakers were in the ON position and switched the breakers to the opposite position without verifying the correct breaker positio A contributing factor was that the ON and 0FF labels on the circuit breakers were painted over. Since the 2A RCFC was the only safe-shutdown ESF component which was not tagged out of service during the test, it started automatically when the test was performe The operator and the engineer were counselled to ensure proper system alignment without the use of assumptions. Breaker labels have been added to clearly denote the ON and 0FF breaker positions for these and other 120-volt breakers. The labelling was done as part of a major effort to ensure that plant equipment and structures are properly labelle ..
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'. (Closed) Unresolved Item (295/85032-03; 304/85033-03) Determination of whether channel functional testing of permissive P-7, P-8, and P-10 was performed monthly as required by Technical Specification (TS) Table 4.1- Table 4.1-1 requires monthly channel functional testing of P-7, P-8, and P-10 without specifying whether a logic channel functional test or an instrument channel functional test is required. The licensee determined by onsite review that a logic channel functional test is required. Logic channel functional testing is performed monthly during PT-5A, "Reactor Protection Logic Reactor at Hot Shutdown" or during PT-58, "Reactor
. Protection Logic Reactor at Normal Operating Conditions," depending on the operational mode of the uni This item is considered close No violations or deviations were identifie . Summary of Operations Unit 1 The unit began the period in the cold shutdown mode for a refueling and maintenance outage which began on February 24, 198 The unit was made critical on May 5, 1988. After low power physics testing the licensee attempted to place the unit online on May 7,1988, but the reactor tripped due to a main generator trip (paragraph 8). The reactor was made critical later that same day, and was tied to the grid on May 9, 198 The unit operated at power levels up to 100% for the remainder of the inspection perio Unit 2 The unit operated at power levels up to 100% for the entire inspection oeriod. On April 22, 1988, an Unusual Event was declared when the licensee initiated a shutdown required by Technical Specifications due to a failure to test a portion of the engineered safety features blackout logic (paragraph 6). The required testing was completed prior to the completion of the shutdown, and the unit was returned to full powe No violations or deviations were identifie l Jnit 1 Startup from Refueling (71711) l l
Unit i began the inspection period on day 50 of a 75-day refueling l
outag The licensee devoted considerably more resources, including contractors, to outage-related activities during this outage than it had during previous outages. Major activities performed during the outage included eddy current testing of all four steam generators, replacement of the main generator rotor, repairs of the reactor vessel head where there had been evidence of leakage, refurbishment and repacking of both pressurizer spray valves, overhaul of the 1A and IB diesel generators, primary and safety-related valve repairs, and large- and small-bore snubber inspection .. - . .-.
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'. The inspectors observed portions of and reviewed the documentation for
.the following startup evolutions:
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MI-2 Reactor Coolant System Fill and Vent-GOP-0, Checklist B Surveillance Status For H/U or S/U GOP-1 Plant Heatup GOP-2 Plant Startup-PT-4A Source Range Functional-Test PT-4B Intermediate Range Functional-Test-Regarding PT-4A and 48, the inspector reviewed these procedures after noting approximately 100-cps noise on source range channel IN-31-following plant startu A review of the procedures performed on May 4, 1988,.
revealed.that these procedures did not specify acceptance criteria _ for -
bistable trip and reset points, or for neutron level when the operation 7 selector switch is selected to various neutron level Bistable trip setpoints and operation selector switch readings are also taken during the performance of instrument maintenance (IM) procedures 1N-31 and 1N-32, "Source Range Nuclear Instrument Electronics," and 1N-35E-and 1N-36E, "Intermediate Range Nuclear Instrument Electronics." These procedures specify an overall loop tolerance of + 10%.
10 CFR 50, Appendix B, Criterion V, as implemented in the licensee's approved Quality Assurance Program; requires that procedures be appropriate to the circumstances and that they contain acceptance criteri Quality Procedure QP 5-51, "Instructions, Procedures and Drawings for Operations - Station Procedures Manual,"Estep A.la, requires
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that procedures shall meet the requirements of ANSI N18.7-1972. ANSI N18.7-1972, "American National Standard for Administrative Controls for Nuclear Power Plants," Section 6.2.5, requires that test procedures contain acceptance criteria that will be used to evaluate the test results. Failure to provide acceptance criteria to evaluate test results in test procedures is considered a violation (295/88012-01a; 304/88013-01a).
Technical Specification Table 3.1-1 requires that the reactor be maintained in the hot shutdown condition if less than one source range high flux reactor trip is operable. Since the redundant source range channel (1N-32) was operable, reactor startup would have been permissible, even if the signal noise had rendered 1N-31 inoperable. The licensee had previously initiated a revision to PT-4A and PT-4B which included acceptance criteria. This revision was issued on May 26, 1988, and the revised procedures incorporate the appropriate accentance criteri Both source range channels would have passed the revised procedures. Consequently, no response to this portion of the violation is require The following problems with the processing of procedure changes were i noted during startup activities:
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A large number of procet Jre Changes were processed just prior to initiation of plant startup activities. Many of these could have been processed well in advance of the time that they were needed for plant operations or testin . -- . . .--
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Some surveillance test procedures take several days to complete, and during the performance of one of these procedures, PT-27,
"Miscellaneous Valve Tests," revisions were issued after many data had already been taken. Since the licensee did not clearly specify whether this procedure should be updated immediately on receipt of the revision, operators became confused as to which revision of the procedure was-appropriate. The problem appears to have been resolved by transferring data from partially completed surveillance test documents onto new procedures; however, this will remain an Unresolved Item pending additional evaluation by the licensee and the NRC to determine if test data were properly taken for the Unit 1 startup (295/88012-02).
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Other discrepancies identified due to procedure revisions received with the procedure already in progress are discussed in paragraph One viciation and no deviations were identifie One Unresolved Item was identifie . Testing of Accumulator Backup Check Valves (61726)
On April 30, 1988, with Unit 1 in hot shutdown, the licensee performed PT-2L, "Accumulator Backup Check Valve Leak Check," and determined that leakage through check valve 1 SI 8956A exceeded the 5 gpm acceptance criterio The licensee reduced reactor coolant sys',em (RCS) pressure and temperature to approximately 600 psig and 350 F in order to repair the check valve. The inspectors reviewed the tests and associated documentation and log books and identified several deficiencie Background Two redundant accumulator check valves are installed in series in each accumulator injection line. These check valve; provide a pressure isolation function between the RCS piping, which has a design pressure of 2350 psig, and the accumulators and associated piping, which have a design pressure of 700 psig. These accumulator check valves are considered as high pressure / low pressure interface valves or pressure isolation valves (PIVs).
In October 1987, several significant deficiencies associated with the licensee's testing program and procedures used for leak testing PIVs were identified in NRC Inspection Report 295/87032(DRP); 304/87033(DRP).
These deficiencies included failure to follow PIV test procedures, inadequate PIV test procedures, use of uncalibrated test instrumentation, inadequate procedure review and inadequate test control. Enforcement regarding these issues is discussed in NRC letters dated January 4, 1988, and May 26, 198 Technical Specification (TS) 4.8.5.A.3 requires that a test to demonstrate that accumulator check valves are not exhibiting gross leakage be performed at each refueling outage. As a result of the PIV
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'. enforcement issues, the licer.;ee submitted a TS amendment in November, 1987, proposing the addition of section 3/4.3. This new section delineates specific PIV leak testing requirements and defines associated
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limitinriconditions for operatio The licensee stated that acceptable performance of PT-2L fulfills the surveillance requirements of TS 4.8.5.A.3 and proposed TS 4.3. PT-2L , "Accumulator Backup. Check Valve Leak Check," quantifies backleakage past the accumulator backup check valves, which are the check valves _ located farthest from the RCS in the accumulator injection line PT-2L simultaneously tests all four accumulator backup check valves (1 SI 8956 A - D) by using a safety injection (SI) pump to inject reactor water storage tank (RWST) water through a drain line common to all four accumulators into the piping between the two series PIVs on the downstream sides of the 1 SI 8956 A - D valves. Leakage past the backup check valves is exhibited by either a pressure or level increase in the accumulator Event Chronology October 22, 1987 PT-2L, revision 9, was performed for both Units 1 and 2. The results were satisfactor November 18, 1987 A procedure change request was filed for PT-2L which deleted the conversion factor between percent indicated accumulator level and gallon December 18, 1987 PT-2L, revision 10 was issue The conversion factor mentioned above was removed from PT-2 January 4,1988 A Notice of Violation (NOV) regarding PIV leak testing was issued (4 violations).
February 2, 1988 A procedure change request was initiated to restore the deleted conversion factor to PT-2L after discovery by the license February 3, 1988 The licensee responded to the January 4, 1988 NOV and stated that no deficiencies were identified for PT-2 April 29, 1988 The 1A and 10 accumulators were filled to 87% and 91%,
3:35 p.m. respectivel April 29, 1988 PT-2L (revision 10) was logged in the Shift Tngineer's 9:15 p.m. log as "in progress." Shortly after the begi>ning of the test, a high pressure alarm on the 1A accumulator occurred due to leakage through 1 SI-8956A, the backup PIV for the 1A accumulator. The test was stopped before test data could be recorde .
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'. April 30, 1988 1A and 10 accumulator leveis were lowered using System Operating Instruction S0I-4, "Safety Injection and Containment Spray."
- April 30, 1988 PT-2L was performed again in an4 effort to quantify 5:00 a.m. check valve leakage. Test results indicated a 5.8%
per minute leak through valve 1 SI-8956A. The PT-2L acceptance criterion was stated as-5 gallons per minut The Shift Control Room Engineer (SCRE)
contacted the instrument maintenance (IM) department-to obtain a conversion factor and determined that the leak rate was approximately 35 gallons per minut The technical staff was notified about the lack of a conversion factor in PT-2L and about the estimated leak rat April 30, 1988 Following the shift turnover, operators attempted to flush the 1 SI-8956A seating surface using accumulator water. SOI-4, normally used for draining accumulators,-
specifies the use of a valve upstream of 1 SI-8956 A valve located downstream of the affected valve was used instead, in an affort to flush the valve seat; however, operators failed to log draining the accumula-tors or the deviation from S0I- April 30, 1988 Technical staff personnel noted that the procedure change request initiated on February 2, 1988, was not incorporated into the PT-2L procedures used by the operator The procedure rev'ision was expedited. In addition, a temporary procedure change was written to provide for use of a hydro pump instead of the safety injection pump as the pressure source for leak testing i 1 SI-8956 '
April 30, 1988 PT-2L, revision 11, was performed with the hydro 1:30 p.m. pum Data were obtained for the 1A accumulator onl The results indicated an 18.3 gpm leak through 1 SI-8956 April 30, 1988 A Shif t Engineer's log entry records several retries !
2:30 p.m. of PT-2L which were unsuccessful at reducing the leak rate to less than the acceptance criterio April 30, 1988 A Shift Engineer's log entry records another l 3:46 p.m. performance of PT-2L with Appendix A (with the hydro pump).
April 30, 1988 The 1A accumulator was declared inoperable due to high 4:20 p.m. check valve leakage. The licensee initiated a reactor coolant system temperature and pressure reduction to support valve repair activitie Work request 270264
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'. was'initlated to investigate and repair the source of the PIV_ leakag April 30, 1988 The licensee informed the NRC Senior Resident 6:30 p.m. Inspector that leakage past 1 SI-8956A exceeded the acceptance criterion.
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May 2, 1988 The NRC Resident Inspector reviewed PT-2L documentatio May 3, 1988 PT-2L was performed to support the return to service of 8:30 a.m.1 SI-8956A fcilowing check valve repai May 3, 1988 The Resident Inspector informed the licensee of the deficiencies noted during her PT-2L test documentation revie May 4, 1988 The licensee retested all PIVs'as required by the Confirmatory Order of 1980, including all four accumulator backup check valves. Test results were satisfactor Upon disassembly of 1 SI 8956A, the licensee found that one of the check valve pivot pin bolts had sheared of This resulted in misalignment of the valve disk and caused backleakage into the accumulator. The bolt was replaced. The valve was reassembled and retested. PT-2L results following the repair indicated essentially zero backleakage, and the unit was subsequently made critical on May 5, 198 Findings The version of procedure PT-2L in effect during the period December 18, 1987 through April 30, 1988, was inadequate for use '
in determining the operability of the accumulator backup check valves in that:
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PT-2L specifies measurement of accumulator backup check valve leakage in terms of percent accumulator level increase over time; however, the valve leak rate acceptance criterion is defined in gallons per minute. The revision of PT-2L in effect and performed on April 29 and 30, 1988, did not contain a conversion factor between percent accumulator level and gallons, thereby prohibiting determination of backup check valve operability based on measured leak rates. PT-2L had previously contained the appropriate conversion factor, but it was inadvertently deleted by a procedure change issued on December 18, 198 Therefore, on April 29 and 30, 1988, operators were unable to quantify accumulator backup check valve leak rates until a procedure change request was expedited by members of the technical staff and the conversion factor was restored to PT-2 l
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Appendix A1, added to PT-2L by temporary procedure change T0-88-350 on April 30, 1988, states that steps 2 through 13 may be reperformed if desired; however, there are two sections of the procedure which have more than 13 steps, and which steps 2 through 13 were to be reperformed was not explicitly state There is'no evidence that the test activities stated in steps 2 through 13 of either sectio of the procedure were repeate CFR 50, Appendix B, Criterion V, as implemented by the licensee's Quality Assurance Program, requires in part that surveillances be conducted using procedures which are appropriate to;the circumstances '
and which include appropriate acceptance criteria. Failure by the licensee to provide a conversion factor between percent accumulator level and gallons, in order to determine backup check valve operability, is considered an example of a quality assurance violation (295/88012-Olb; 304/88013-01b). Review of the completed retrievable PT-2L test documents revealed the following instances in which the licensee failed to follow-written procedures:
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Step 3 of PT-2L requires recording of the discharge pressure of the safety injection pump; however, safety injection pump discharge pressures were not recorded for the PT-2L procedures performed at 05:00 and 13:30 on April 30, 198 Step 11 of Appendix Al to PT-2L requires that the operator record the time at which 1 SI-8961, a manual containment isolation valve, is closed; however, the time of closure
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for 1 SI-8961 was not recorded for the PT-2L performed at approximately 13:30 on April 30, 198 Step 14 of Appendix Al to PT-2L requires that the hydro pump
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used as the pressure source for the leak testing of 1 SI-8956A be disconnected; however, the hydro pump was not disconnected as required for the PT-2L performed a; approximately 13:30 on April 30, 1988. No explanation as to why the pump was not disconnected was noted in the test documentatio PT-2L requires determination of the leak rates for all four accumulator backup check valves using the safety injection pump immediately prior to use of the hydro pump to recheck 1 SI-8956A; however, the licensee only obtained data for the 1A accumulator check valve for the PT-2L performed at approximately 13:30 on April 30, 198 Zion TS 6.2.1.G requires that surveillance tests be performed in accordance with properly written and approved procedures. Failure of the licensee to perform PT-2L in accordance with the written procedure as discussed above is considered a violation of Zion Technical Specification 6.2.1.G (295/88012-03; 304/88013-02).
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, Review of the test documentation and operator's log book entries associated with the performance of PT-2L on April 29 and 30, 1988 revealed that the licensee's test documentation controls were inadequate in that:
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Test records of two PT-2L procedures logged as being performed on April 29, 1988, and at 15:46 on April 30, 1988, in the shift engineer's log book could not be found. Discussions with members of the operating staff revealed that since the PT-2L performed on April 29, 1988, was not completed, no useful data had been obtained. The task of completing PT-2L was given to oncoming shift personnel. When the crew that had performed the -
initial PT-2L on April 29, 1988, returned a day later, members of the operating crew noted that two additional PT-2L procedures had been performed. It was thought that the initial PT-2L, performed on April 29, 1988, was no longer necessary, and the t
test documentation was therefore discarded. The licensee stated that it suspects that the PT-2L logged in the shift engineer's log book as being performed at approximately 15:46 on April 30, 1988, was also discarded for unknown reason ZAP 10-52-2, "Operating Log Books," requires that abnormal surveillance or test data, off-normal items concerning the systems being tested, test results and actions taken to correct abnormal test conditions, are logged in the shift engineer's log book. The ZAP also requires that' unusual system alignments, abnormal surveillance data, indications of equipment malfunctions and the actions taken to alleviate equipment malfunctions are logged'in the unit operator's log boo There were no log entries noting (1) the inability to complete PT-2L on April 29, 1988, due to the accumulator high pressure alarm and on April 30, 1988, due to the lack of a conversion factor between percent accumulator level and gallons was not contained in PT-2L, (2) draining the accumulators on April 30, 1988, in the attempt to flush the 1 SI-8956A valve seat, and (3) deviation from the normal procedure for draining accumulators as specified in 501- CFR 50, Appendix B, Criterion XVII, as implemented by the licensec's Quality Assurance Program, requires in part that test records be maintained and retrievable. Zion Administrative Procedure 10-52-2, "Operating Log Books," requires in part that certain situations and plant conditions associated with surveillance testing be recorded in either the shift engineer's and/or unit operator's log book. Failures to maintain retrievability of two PT-2L tests and to log activities taken to evaluate and rectify the difficulties associated with performance of PT-2L during the period of April 29 and 30, 1988, as discussed above, are considered a violation (295/88012-04; 304/88013-03).
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' The' licensee's February 3,1988 response to the findings identified I in inspection report 295/87032(DRP); 304/87033(DRP) included reviews I of procedures which leak tested PIVs. Of the five test procedures reviewed, only PT-2L was identified as having no deficiencies. The PT-2L revision in effect at the time of the response did not contain the conversion factor necessary to quantify the backup check valve leak rates and thereby demonstrate component operabilit The inspectors reviewed previous revisions of PT-2L and noted'that on December 18, 1987, the licensee issued revision 10 to PT-2L, which effectively removed the conversion factor between percent accumulator level and gallons per minute from the procedure. On February 2, 1988, the licensee initiated a procedure change to restore the conversion factor to PT-2L; however, this procedure change was not incorporated until April 30, 1988, after two attempts to leak test the accumulator backup check valve CFR 50.9, requires in part, that information provided to the Commission as required be complete and accurat Failure of the licensee to accurately characterize the adequacy of surveillance test procedure PT-2L in its response to findings identified in inspection report 295/87032(DRP); 304/87033(DRP) is considered to be a violation (295/88012-05; 304/88013-04).
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l Root Cause The majority of the procedure deficiencies identified above were due to !
inadequate procedures, inadequate review of procedure revisions, and .
untimely execution of procedure changes. Review of past revisions to l
PT-2L revealed that prior to December 18, 1987, PT-2L, revision 9, was '
adequate to demonstrate accumulator backup check valve operability. Two separate procedure changes, which essentially consisted of procedural enhancements, were initiated against revision 9 of PT-2L on October 20
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and October 22, 1987. A subsequent procedure change was requested on November 18, 1987, which cancelled both of the changes requested in October and combined the two changes into one procedure change reques The November 18th procedure change request inadvertently deleted the j conversion factor originally contained in PT-2L. Deletion of the l conversion factor was not noticed during any of the reviews of the November 1987 procecure request, and revision 10 of PT-2L without the conversion factor was issued on December 18, 198 ,
A subsequent licensee review of PT-2L conducted in early February 1988 identified the fact that the conversion factor was missing and a fourth procedure Aange request was initiated on February 2,1988, to replace the conversion factor. This February 2, 1988 procedure change request was not issued until after revision 10 of PT-2L, without the conversion factor, had been performed twice by operations personne .
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A fifth procedure change request was initiated by the licensee on April 30, 1988 to allow.the use of a hydro pump as the pressure source
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, for check valve leak testing. Instructions related to testing with the nydro pump were inserted halfway through PT-2L and did not clearly define the sequence in which steps were to be performe The procedure i therefore required the operators to quantify the leakage for all four accumulator backup check valves using the safety injection pump as the pressure .ource immediately prior to use of the hydro pump; however, Appendix Al states that the appendix be performed for the 1A accumulator check valve only. The confusion resulted in the failure to obtain leak rates for three out of four accumulator backup check' valves as noted abov Corrective Actions On May 3, 1988, following the repair of 1 SI-8956A, the licensee initiated a temporary procedure change to PT-2L which addressed the deficiencies identified by the inspector PT-2L was subsequently ,
performed at approximately 08:30 CDT on May 3, 1988, to quantify the post maintenance leak rate for 1 SI-8956A only. The test documentation
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On May 4, 1988, at approximately 15:57 CDT, the licensee performed PT-2L in its entirety to determine the leak rates for all four of the accumulator back up check valves. The deficiencies previously identified had been corrected, and the valve leak rates met the procedure acceptance criteri On June 6, 1988, a discussion of the potential violations pertaining to PT-2L was held at a department head meetin Departments heads were directed to review these and other findings with their respective
, departments. Management and supervisory personnel were also directed to conduct more thorough reviews and to reject deficient work. Other corrective actions being developed involve the quality control group and additional trainin Four violations and no deviations were identifie . April 22, 1988 Unit 2 Unusual Event Due To Failures To Test Blackout Logic (93702)
On April 22, 1988, while investigating wiring discrepancies associated with the Unit 1 two-out-of-three service bus undervoltage (blackout)
logic, the licensee discovered that a portion of the blackout logic on both Unit 1 and Unit 2 had not been tested since pre-operational testing.
c At the time of the discovery, Unit 1 was in cold shutdown and Unit 2 was operating at full power. Unit 2 was placed on a fou -hour limiting condition for operation (LCO), after which the blackout logic was tested, i
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. During the test, the licensee identified additional wiring discrepancies '
in the Unit 2 circuitry, which delayed successful completion of the
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testing long enough to require the initiation of a reactor shutdow Upon initiation of the Unit 2 shutdown, the licensee declared and unusual event (UE) in accordance with their Generating Stations Emergency Plan ,
(GSEP). Testing was subsequently completed satisfactorily prior to the expiration of the four hour LCO, and the rampdown and the UE were terminate Resolution of the wiring discrepancies identified by the licensee will be reviewed and documented in NRC inspection report 295/88003(DRS). A ,
- - discussion of the enforcement of the missed TS surveillances is contained in paragraph 12 of this repor '
No violations or deviations were identifie , April 27, 1988 Unit 1 Engineered Safety Features (ESF) Actuation -
, Inadvertent Stroking of 1 MOV-CS 0006 and 1 MOV-CS 0010 (93701)
On April 27, 1988, after performing a section of TSS 15.6.43-1,"Endurance Testing of Diesel Generator During Refueling Unit-1," the 1C containment spray (CS) pump discharge valve, 1 MOV-CS 0006, and the 1C CS pump eductor suction valve, 1 MOV-CS 0010, reopened unexpectedly due to an ESF signal. Operators had attempted to restore the valves to their normal lineup by closing the valves, but they immediately reopened after the-valve control switches were release Investigation revealed that a typographical error had resulted in a series of events which caused the 1C CS pump switch to be in the pull-to-lock (PTL) position when it should have been in the normal position. A section of TSS 15.6.43-1 designed to actuate ESF components was successfully performed, but the IC CS pump switch in PTL prevented .
the reset of the ESF actuation relays for the two MOVs. When operators '
attempted to reclose 1 MOV-CS 0006 and 0010, the valves immediately reopened from the ESF signal. Resolution of the typographical error was complicated by the complexity of TSS 15.6.4 Immediate corrective action was to reset the actuating relays manually, ,
to return the 1C CS pump switch to normal, and to close the valve The ;
ESF circuitry operated as designed. The licensee will review and revise !
TSS 15.6.43-1 to correct the typographical error and to employ a more l logical test sequence. NRC review of the revised TSS 15.0.43 will be considered an Open Item (295/88012-06; 304/88013-05).
No violations or deviations were identifie One Open Item was
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'. 8. May 7. 1988 Unit 1 Reactor Trip Due to Failure of Generator Excitation Breaker (93702)
On May 7, 1988, at about 5:05 p.m., while Unit 1 was in the hot standby mode, Unit 1 tripped from about 4% reactor power due to low-low level (10%) in the 8 steam generator (SG). 'The trip occurred when the generator excitation breaker tripped open due to overexcitation while operators were applying excitation voltage to the main generator. The generator excitation breaker trip was followed by automatic trips of the main generator, the turbine, and the running feedwater (FW) pump. The loss of the FW pump eventually led to the low-low SG-level reactor tri Just prior to the turbine trip, the reactor power was about 6%, and steam was being dumped to the condenser. When the FW pump was lost, operators immediately started two electric auxiliary feedwater (AFW) pumps to maintain SG 1evels and began to slowly reduce reector power to lower steam demand. Before the lowering SG 1evel trend:could be reversed SG level in the B SG reached 10% and the reactor tripped. Except for the trip of the generator excitation breaker, all automatic and manual systems worked as designe Emergency operating procedures E-0,"Reactor Trip or Safety Injection," and ES 0.1, "Reactor Trip Response," were followe After conducting a post-trip review, the licensee took the reactor
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critical on May 7,1988, at 10:54 p.m. while attempting to determine the cause of the excitation breaker trip. The licensee determined that the breaker trip was caused by corrosion on the connecting lugs of a current ,
limiting resistor bank, which caused an apparently false overexcitation I tri The corrosion appeared to be caused either by condensation or by J a leak in the isolation phase bus duct coolers. After repairing the corrosion damage, the unit was returned to service, and tied to the grid on May 9, 1988. Additional NRC review of this event and the licensee's corrective actions will be performed following receipt of the licensee's 30-day licensee event report (LER).
No violations or deviations were identifie . Operational Safety Verification and Engineered Safety Features System Walkdown (71707, 71709, 71710, & 71881)
The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators from April 14 through June 3, 1988. During these discussions and observations, the j inspectors ascertained that the operators were alert, cognizant of plant conditions, and aware of changes in those conditions, and that they took prompt action when appropriate. The inspectors verified the operability of selected emergency systems, reviewed selected tagout records and verified proper return to service of affected components. Tours of the auxiliary and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenanc _
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'. The inspectors by observation and direct interview verified that selected physical security activities were being implemented in accordance with the station security pla The inspectors observed plant housekeeping / cleanliness and radiological conditions and verified implementation of radiation protection control From April 14 through June 3, 1988, the inspectors walked down the accessible portions of the safety injection system to verify operabilit These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under Technical Specifications, 10 CFR, and administrative procedure No violations or deviations were identifie . Monthly Surveillance Observation (61726, 37700)
The inspector observed Technical Specifications required surveillance testing on portions of the emergency core cooling system and verified whether testing was performed in accordance with adequate procedures, whether test instrumentation was calibrated, whether limiting conditions for operation were met, whether removal and restoration of the affected components were accomplished, whether test results conformed with both 1 Technical Specifications and procedure requirements and were reviewed l by personnel other than the individual directing the test, and whether any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne The inspector witnessed portions of the following test activities:
TSS-15.6.114 Unit 1 SI (Safety injection) and RHR (Residual Heat Removal) Check Valve Leak Check
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The inspectors also reviewed test documentation for the following test activities:
PT-2L Accumulator Backup Check Valve Leak Check PT-6 Containment Spray System Tests and Checks PT-210 Aircraft Fire Detection System Test PT-30 Station Battery / Security Battery Record - Monthly Quarterly Equalizing Charge PT-2G Accident Monitoring Instrumentation Channel Check Test TSSP 35-88 Procedure for Back-Feeding Unit 1 Non-ESF Buses from 1 Unit 1 ESF Buses I
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Findings:
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Comments regarding PT-2L are noted in paragraph 5 of this repor Regarding PT-210, permanent change number 0-88-226 added the following note to the portion which tests diesel generator (OG)
room ventilation intake isolation dampers:
"Verify at least ene hour before testing that heat trace for D/G intake damper's air lines and actua. tors is plugged in."
The reason for this change was to maintain the heat trace plugged
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in for "smooth damper operation." The heat t' ace was added to the instrument air lines and damper actuator to prevent moisture
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l accumulation in the lines from freezing during cold weather, thus preventing damper operatio DG room ventilation intake dampers are required by Technical Specification (TS) 4.17.1.b to close within 2 seconds of a simulated fire condition to prevent damage to safety-related equipment in the DG room caused by an external fire due to the crash of an aircraft at the plan PT-210 is a semi-annual test, and if the heat trace l
were plugged in just prior to the test during cold weather periods, l a damper which may have been inoperable due to frozen condensate in l the air operator lines would pass PT-210, and the as-found
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condition of the system would not have been tested and recorde CFR 50, Appendix B, Criterion V, as implemented by Commonwealth Edison Company's NRC-approved Quality Assurance Topical Report, CE-1-A, requires in part that activities affecting quality be prescribed by procedures of a type appropriate to the circumstance QP 5-51, "Instructions, Procedures and Drawings for Operations -
Station Procedures Manual," step A.la, requires that procedures shall meet the requirements of ANSI N18.7-1972. ANSI N18.7-1972,
"American National Standard for Administrative Controls for Nuclear Power Plants," Section 6.2.5, requires that test procedures shall require recording of the as-found condition. Failure of PT-210 to determine and record the as-found condition is considered a violation (295/88012-01c; 304/88013-Olc).
PT-210 has not been used since change number 0-88-226 was implemented, and a revision to PT-210 to correct the note was submitted on May 25, 1988.
l The heat trace was installed on all five DG room damper air lines l
from mid-1984 to mid-1985. The installation which modified the l plant was performed withcut using the modification controls of QP 3-51, "Design Control for Operations - Plant Modifications."
QP 3-51 addresses both permanent and temporary plant modification CFR 50, Appendix B, Criterion III, as implemented by the
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'. licensee's approved Quality Assurance Topical Report, in QP 3-51, requires that design changes be treated with the same design control measures as the original design, including appropriate approval QP 3-51, Attachment A, "Definition of a Modification and Phases of Testing," states that plant modifications are controlled using QP 3-51. Failure to control plant modifications as required by QP 3-51 is considered a violation (295/88012-07; 304/88013-06).
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Regarding TSSP 35-88, this procedure, dated April 4, 1988, was inadequate in that it required operation of components which did not exist (grounding disconnects to transformer 142), and it violated established procedures pertaining to load dispatcher control of switchyard breakers. These discrepancies were identified during performance of the procedure by operations personnel on April 5, 1988, and the procedure was halted. After the procedure was revised to correct these discrepancies, it was successfully performed on April 8, 198 These procedural inadequacies are considered a Licensee Identified Violation, for which no citation will be given (295/88012-08).
Two violations and no deviations were identifie One licensee identified violation was identifie . Monthly Maintenance Observation (62703)
Station maintenance activities on the safety-related systems and components listed below were observed or reviewed to ascertain whether they were conducted in accordance with approved procedures, regulatory guides, industry codes or standards, and in conformance with Technical Specification The following items were considered during this review: the limiting '
conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were i.nplemente Work requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performanc The following maintenance activities were observed or reviewed:
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HFA relay replacement
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FT-36.2, Overpressure Protection Setpoint and Functional Operation Verification, Cold Shutdown Only
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Following completion of maintenance on overpressure protection setpoints, the inspector verified that the system had been returned to service properl Resident Inspector Concerns:
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Plant out-of-service (005) procedures permit work without an 00S document if the work requires that the equipment be operating, energized, or pressurized in order to troubleshoot or to make adjustments or repairs spccified in the work request. 00S
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procedures additionally state that when doubt exists as to whether-an 00S is required, the Operating Department and the working group involved shall mutually agree on the conditions under which work will be performed, in order to satisfy safety and procedural requirements prior to the start of wor In some cases 00S controls were not used in circumstances under which.the work did not require equipment to be operating, energized, or pressurite For example, a service water hose leak on the 2A diesel generator was repaired with operators-stationed to assur that the work was isolated and that the isolation points were not disturbed while the repairs were in progress. Flex hose replacement does not normally require the system to be pressurized, and in this case, it required only two points of isolatio This work was done without an 00S to avoid the inconvenience of preparing out-of-service documents and to save time while the DG was unavailable for servic Construction Department personnel performed work on the main generator exciter while the generator and exciter were rotating on the jacking gear (about 1 to 3 rpm). During a break, operators stopped the jacking gear to permit replacement of a bearing lift pump filter. Construction department personnel returned from their break and resumed work on the exciter, after which the operator restarted the jacking gear without notifying the individuals engaged in the work. One construction worker was nearly injured when the exciter began rotating. Neither the work on the exciter nor the filter replacement were performed using OOS control The resident inspector informed plant management that these 005 concerns may indicate a weakness in plant work controls. The licensee agreed to examine the matte No violations or deviations were identifie . Licensee Event Reports Followup (92700)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, that immediate corrective
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. action was accomplished, and that corrective action to prevent recurrence had been accomplished in accordance with Technical Specifications. The LERs listed below are considered closed:
UNIT 1 LER N DESCRIPTION 87012 Failure to Perform Logic Surveillance for High Steam Flow Safety Injection Block Permissive (P-12)
88009 Failure to Test Safeguards Undervoltage Logic Due to Inadequate Review of Tect Procedures 88010 Inadvertent Actuation of Safeguards Equipment During Diesel Generator Test UNIT 2 LER N DESCRIPTION 88002 Unit 2 Steam Generator Safety Valves Inoperable
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Regarding LER 295/87012, a licensee quality assurance audit identified the failure to perform quarterly surveillance testing of the high steam flow safety injection block permissive (P-12). The licensee determined that the required testing was only performed during plant startups when the units were not drawing steam. The procedure which tests P-12 results in closure of the main steam isolation valves (MSIVs), and contains a caution not to perform this portion of the test when the MSIVs are open. Because of the caution, it was assumed that P-12 was not testable when drawing steam and that the intent of the Technical Specifications (TS) was me Technical Specification 4.4.2 states that instrument channel functional check frequency requirements for safeguards instrumentation and centrol channels are as specified in Table 4.4- Table 4.4-1 requires channel functional testing of permissive P-12 on a quarterly frequency. Failure to perform quarterly channel functional testing of permissive P-12 from initial operation to June 3, 1987, for Unit 1, and from initial operation to the startup from the summer 1987 refueling outage for Unit 2 is considered a violation of Technical Specification 4.4.2 (295/88012-09; 304/88013-07).
The licensee developed a special test to verify operability of P-12 without closing MSIVs, which was successfully performed. The test will be permanently added to PT-10A, "Safeguards Logic Test at Hot
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. Shutdown or Power Operation." In addition, the licensee intends to propose a revision to the TS definitions to reduce confusion caused by Amendments 96/8 .
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Regarding LER 295/88009, the blackout logic is initiated by an
- undervoltage condition en two of the three service buses which supply the three essential service buses. Initiation of the i blackout logic automatically starts safe shutdown components. The
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4 initiating undervoltage relays on the service buses are calibrated and functionally checked each refueling outage by the Operational Analysis Department. These undervoltage relays energize slave relays, contacts of which are arrayed in a two out of three logic
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matrix. Automatic starting of safe shutdown loads is tested each refueling outage in Technical Staff Surveillance (TSS) 15.f 35,
"Manual Actuation of the Safety Injection and Safe Shutdown Systems and Diesel Generator Loading Test." Only parts of the blackout logic portion of the circuit were unteste Technical Specification 4.4.2 states that engineered safeguards system testing be performed in accordance with Table 4.4-1, which
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function) be verified to occur from station blackout logic once per !
refueling shutdown. Failure to completely perform blackout logic testing each refueling outage from 1974 to 1987 is considered a violation (295/88012-10;304/88013-08).
After testing the Unit 1 and Unit 2 blackout logic circuits, a review of TS 4.4 was conducted to ensure that all surveillance
requirements were met. On April 25, 1988, the licensee identified that the secondary level undervoltage relays, another portion of safeguards logic, had not been tested during the Spring 1087 refueling outage as required by TS 4.4. Unit 2 was placed on a four-hour LCO, and relay calibrations were successfully perfonned prior to the need to initiate a reactor shutdown. The calibrations verified that the secondary level undervoltage relays would have performed as designed in the event of an acciden l
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Regarding LER 295/88010, this event is discussed in paragraph 7 of
this report, l
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Regarding LER 304/88002, the sequence of events involving discovery )
and immediate corrective actions is described in Inspection Report
, Numbers 295/88009(DRP);304/88010(DRP). TS Table 4.7-1 lists steam generator safety valve lift setpoints with a tolerance of + 1%. The
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licensee has determined that for Units 1 and 2, since 1978, there
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have been 16 cases in addition to the ones described in the LER in
which steam generator safety valves had as-left lift setpoints more that 1% above the value specified in TS Table 4.7-1. In none of
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less than that required for the most limiting accident (loss of
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'. The cause of this event was incorrect acceptance criteria listed in maintenance procedure P/M003-5N, "Bench Testing Section XI Safety / Relief Valves for Use on Vapor / Gases."
10 CFR 50, Appendix B, Criterion V, as implemented by Commonwealth Edison Company's NRC-approved Quality Assurance Topical Report, CE-1-A, . requires in part that activities affecting quality be prescribed by procedures of a type appropriate to the circumstances and which include appropriate acceptance criteria for determining that important activities have been satisfactorily accomplishe Failure to provide correct acceptance criteria to evaluate test results in test procedure P/M003-5N, performed during refueling outages from 1978 to 1988, is considered a violation (295/88012-Old; 304/88013-Old).
Three violations and no deviations were identifie . Training (41400)
During the inspection period, the inspectors reviewed abnormal events and unusual cccurrences which may have resulted, in part, fr:m training deficiencies. Selected events were evaluated to determine whether the classroom, simulator, or on-the-job training received before each event was sufficient to have either prevented the occurrence or to have mitigated its effects by recognition and proper operator actio Personnel qualifications were also evaluated. In addition, the inspectors determined whether lessons learned from the events were incorporated into the training progra Events reviewed included the events discussed in this repor In addition, LERs were routinely evaluated for training impac During the investigation of the events surrour. ding the failure of the 1 SI 8956A accumulator backup check valve, the inspector noted that
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several operations personnel were unaware of a standing order which ;
effectively imposed the requirements of proposed TSs 3.3.3.F and I 4.3.3.F. The proposed TSs define the surveillance requirements and '
limiting conditions for operation associated with PIV testing. Other ,
than documented reviews of the standing order, no evidence that members l of the operations staff had received additional training on this subject j was foun !
During review of changes to performance tests (pts), the inspector noted that steps which previously required management verification (MNVR) now requiredonlyindependentverification(INVR). Discussion with the operations assistant superintendent revealed that this change would allow for future relaxation of a commitment to the NRC for MNVR following certain important activities. The pts were being changed in anticipation of discussions with the NRC which would permit relaxation of this comitment with NRC concurrence. An administrative procedure, ZAP 0,
"Conduct Of Operations," was also revised (change request TA88-082) to require INVR to be performed only by management personnel, thus keeping
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the commitment until discussions with the NRC could be held. The inspector
- asked whether training on these changes had been conducted to prevent INVR by persons other than management. The licensee produced a memorandum dated April 19, 1988, explaining this change, but subsequent investigation revealed that the memorandum was inadvertently left out of the shift required reading boo The memorandum was immediately added to the required readin No violations or deviations were identifie . Followup of Region III Request (92701)
By a memorandum dated April 21, 1988, resident inspectors were requested to determine whether valve operability decisions were made properly and in accordance with an enclosed interpretation dated April 15, 198 The interpretation stated that in the case of containment isolation valves (CIVs), a closed CIV could not be considered operable. The interpretation, based on the definition of operability in TSs and action statements regarding CIVs, stoted that if an inoperable isolation valve is inadvertently opened, it may not close when automatic isolation is needed. In addition, a CIV may be a dual function valve and may need to be-opened to allow operation of another system, such as emergency core coolin The inspector verified that the licensee considers CIVs to be operable based on proper interpretations of TS definitions of operability and containment integrity. In adoition, dual functions are considered when making operability decisions as described in the licensee's PT-14,
"Inoperable and Required Redundant Surveillance Test Sheet."
No violations or deviations were identifie . Open Items Open Items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. One Open Item disclosed during this inspection is discussed in paragraph l 16. Unresolved Items 1 Unresolved items are matters about which more informacion is required in order to ascertain whether they are acceptable items, items of noncompliance or deviations. One Unresolved Item disclosed during this inspection is discussed in paragraph . Licensee Identified Violations In accordance with 10 CFR Part 2, Appendix C, General Statement of Policy and Procedure for NRC Enforcement Actions, the NRC will not generally issue a notice of violation for a violation that meets all of the following tests:
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, It was identified by the licensee; It fits in Severity Level IV or V;- It was reported, if required; It was or will be corrected, including measures to prevent recurrence, within a reasonable time; and It was not a violation that could reasonable be expected to have been prevented by the licensee's corrective action for a previous violatio One licensee identified violation disclosed in this inspection is discussed in paragraph 10 of this repor . Exit Interview (30703)
The inspectors met with licenseo representatives (denoted in Paragraph 1)
throughout the inspection period and at the conclusion of the inspection on May 26 and June 3, 1988, to sunnarize the scope and findings of the inspection activitie The licensee acknowledged the inspectors'
comments. The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectorc during the insptation. The licensee did not identify -
any such documents or processes as proprietary, i
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