IR 05000352/1989015
| ML20248E528 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 09/22/1989 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20248E519 | List: |
| References | |
| 50-352-89-15, 50-353-89-24, NUDOCS 8910050274 | |
| Download: ML20248E528 (106) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report No. '89-151 i,
89-24 p-Docket No.
50-352 50-353'
l License No., NPF-39
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V NPF-84
' Licensee:
Philadelphia Electric Company Correspondence Control Desk
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P.O. Box 7520
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Philadelphia, Pa -19101-Facility Name:
Limerick Generating Station, Unit I and 2 j Inspection Period: June 26, 1989 - July 30, 1989
.Inspectorsi T.'J; Kenny, Senior Resident Inspector L. L.'Scholl, Resident Inspector
.R. L. Fuhrmeister, Resident Inspector
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'M. G. Evans, Resident Inspector L
n Approved by:
2$BM M Lawrence-TV Doerflein, chief, Projects Date Section 2B'
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- Summaryi Routine daytime (393 hours0.00455 days <br />0.109 hours <br />6.498016e-4 weeks <br />1.495365e-4 months <br />) and backshift/ holiday (52 hours6.018519e-4 days <br />0.0144 hours <br />8.597884e-5 weeks <br />1.9786e-5 months <br />)
inspections.of Unit I and Unit 2 by the resident inspectors consisting of (a)
plant' tours, (b) observations of. maintenance and surveillance testing, (c)
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review'of LERs and periodic reports, (d) review'of operational events (e)
Y system walkdowns, and (f) monitoring of startup and power ascension testing activities (Unit 2).
Results:
.r IUnit 1: The inspectors reviewed the power transient which was caused by a
- sticking recirculation pump motor generator set scoop tube. A management imeeting was held'with the licensee to review plant performance and areas of NRC concern. The inspectort also determined that the plant operations review committee position 32 improperly provided for improperly utilizing analytical methods for verifying core shutdown margin after refuelings.
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' Unit 2: This; inspection documents the review and closeout'of various Open
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Items, NRC Bulletins, Construction Deficiency Reports,.and TMI Action. Items.
nVarious Preoperational' Tests-Results reviews were also accomplished.. The 1.J
inspectors witnessed the. completion of initial. fuel loading and conduct of
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open vessel testing.
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The 5%' power license was' also issued during this period.
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I, DETAILS
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1.0 persons Contacted
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Within this' report period,-interviews and discussions were conducted with members of. licensee management and staff as necessary to support inspection activity.
2.0 Operational Safety Verification The inspectors conducted routine entries into the protected areas of the plant, including the control room, reactor enclosure, refuel floor, and drywell (when access is possible). During the inspection, discussions were held with operators, technicians (HP & I&C), mechanics, security personnel, supervisors and plant management. The inspections'were conducted in accordance with NRC Inspection Procedure 71707 and affirmed the licensee's commitments and compliance with 10 CFR, Technical Specifications, License Conditions and Administrative Procedures.
2.1 Unit-1(71707,93702)
2.1.1 Inspector Comment / Findings This report period began with Unit 1 at 95% reactor power.
On June 28, 1989, both trains of standby gas treatment system (SGTS) initiated and a nuclear steam supply shutoff system (NSSSS) group 6 (Drywell Purge) isolation occurred when the refuel floor to outside ambient differential pressure dropped below -0.1 inches of water fo.r greater than 100 seconds. The plant Heating, Ventilation, and Air Conditioning (HVAC) was experiencing trouble maintaining the refuel floor secondary containment integrity as required by maintaining a negative pressure of -0.25 inches of water.
In-the process of trying to correct the problem, the differential pressure decayed to the setpoint for SGTS initiation and group 6 isolation. The "B" SGTS fan was immediately stopped and the "A" SGTS fan was stopped after the return of normal. The initial problem was identified as trouble with the Unit 2 refuel floor HVAC cooling coil.
The introduction of cool air to the refuel floor made it
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difficult to maintain the negative pressure.
Problems were also identified with the procedures for stopping the HVAC systams and a possible problem with a Unit 1 interlock which is intended to trip the HVAC supply fans 5 seconds after the exhaust fans are tripped. A similar event occurred on June 29, 1989.
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On June 29, 1989, a steam supply shutoff system group 6 (refueling floor HVAC) isolation occurred due to a low differential pressure isolation signal when the "A" HVAC supply fan tripped. The "A" train standby gas treatment system (SGTS) automatically started as required (The "B" train of SGTS was out of service for maintenance). The licensee restarted the normal refueling floor HVAC.
As a result of the June 28 and 29, 1989 events the licensee has revised operating procedure S76.2.A " Shutdown of Refuel Floor HVAC" to instruct personnel to shutdown refuel floor supply fans prior to the exhaust fans. The reason for the loss of negative pressure on the refuel floor has been attributed to the inflow of cooler air expanding, from heating, faster than the exhaust fan can remove.it.
Flow
. balancing of the refuel floor ventilation was in progress at the end of the period. The NRC was notified of these events via the Emergency Notification System (ENS). The inspectors will review the LER during a subsequent inspection.
On June 29, 1989, the licensee discovered that ST-2-042-635-1, "Feedwater/ Main Turbine Trip System Actuation - Reactor Vessel Water Level-High, Level 8, Channel 'C' Functional Test," had not been performed within its required surveillance period. As a result, the licensee declared the instrumentation inoperable. The previously completed monthly surveillance test performed on May 11, 1989, had not been properly documented on the
' Test Schedule' and therefore, the test was not rescheduled on the Master Test Schedule at the appropriate time. The surveillance test was satisfactorily completed on June 29, 1989, at 10:29 p.m., and the associated instrumentation was declared operable. The appropriate personnel were counseled on the need for attention to detail when recording surveillance test results. The resident inspector has no further questions regarding this event.
On July 8, 1989, at 5:51 p.m., the reactor experienced a
power transient due to sudden movement of the "1B" Recir-culation Pump motor generator set scoop tube. The reactor power decreased to 65%, increased to 107%, then returned to 95%, the initial power level. This occurred in a period of 15 seconds. The operator had been decreasing the speed of the "1B" recirculation pump, and noticed a difference between the demand and deviation meters (demand pegged high and deviation at +2).
The operator adjusted the controller
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i once more and got the demand meter to 92% and the-deviation meter to zero. The transient. occurred approximately five minutes after the last downward adjustment. The licensee's
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. investigation has attributed the transient to a sticking or
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binding of the scoop tube. The licensee has exercised the
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scoop tube since the transient, both automatically and manually, and no further binding was noted.
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management restricted flow to 102% (a flow-equivalent to
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scoop tube position prior to the transient) until testing'
was performed. The testing could not reproduce the binding problem and the restrictions on flow were removed. All licensed operators were informed, via the night orders to be aware of similar situations.
Reactor chemistry and offgas readings did not change from previous readings after the transient. The inspector had no further. question's at this tima.
On July 11, 1989 the licensee reported that contamine. tion of the Unit 2 Condensate Storage Tank (CST) dike area occurred due to a-valving error.. Personnel failed to close a valve after draining the CST dike ia preparation for maintenance activities.
Subsequent operations caused contaminated liquid to flow back through the pipe and.into the CST. dike area. The licensee plans to remove and replace the asphalt.immediately surrounding the CST. The licensee estimates that this operation will cost more than $2000, so an NRC notification under 10 CFR 20.403b was made. There was no offsite release.as a result of the spill. The licensee took immediate action to prevent recurrence by performing a valve lineup which would prevent further drainage to the dike area.
The licensee is currently working to revise procedures involving contaminated water transfer. The inspector will review the licensee's final actions upon receipt of the Licensee Event Report.
On July 16, 1989 at 2:55 a.m., a NSSS group 6C, 7B, contain-ment leakage blocks and vents, and instrument gas blocks and vents isolation signal was generated when the "1C" Reactor Enclosure (RE) Exhaust Radiation Monitor drifted up to the isolation setpoint (1.35 mr/hr). A problem with the
"1C" exhaust radiation monitor had been previously identi-fied and a maintenance request form was issued to I&C. An isolation verification was made using GP-8 with no abnor-malities found. All equipment functioned properly per design to isolate their respective systems. The "1C" exhaust radiation monitor was left in the tripped condition per Technical Specification 3.3.2 Action b.
The associated RE exhaust radiation monitors were verified to be indicating
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consistently for plant conditions.
I&C was notified to investigate the problem further.
The.results of the investigation will_be reviewed by the. inspector-upon the issuance of the Licensee Event Report.
On July 17, 1989, a chemical technician, intending to remove charcoal sample canisters-for the-standby gas _ treatment system (SGTS)- room filters-for testing, erroneously removed the charcoal sample canisters for both trains of.the SGTS.
inline filters. These installed sample canisters are located-in a flow path parallel to the inline SGTS charcoal filters.
Blank flanges were installed in place of the sample canisters to prevent air leakage. At 9:45 a.m., on July 19,~1989, the licensee noted the error and the blank flanges were removed and the sample canisters were reinstalled. During the time the sample canisters were not installed in the systern, the configuration _ of the charcoal.inside the sample canisters was disturbed. The reinstalled sample canisters containing the disturbed charcoal configuration provided
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the potential for an unacceptable SGTS bypass flow and created a condition that could have prevented fulfillment of the safety function of the SGTS to control the release of radioactive material. At 12:45 on July 19, 1989, the licensee realized the significance of this condition and at 1:25 p.m., the 'B' train sample canister was removed and
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blank flanges were reinstalled. The
'A' train sample canister was subsequently removed. The licensee determined that Technical Specification 3.0.3, which would require a plant shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, had been applicable from 9:45 a.m. until 1:25p.m. This was caused by an inexperienced operator who, due to improper labelling and similarity between the canisters and blank flanges removed the wrong canister. The licensee intends to correct the labelling and conduct training prior to the performance of this test in the future. The licensee made an ENS notification
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regarding this event. The inspectors will review the LER L
during a subsequent inspection.
2.2 Unit 2 (71707, 93702)
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2.2.1 Inspector Comments / Findings I
On July 4,1989, at 1:29 p.m., the "20" Refuel Floor (RF)
Exhaust Radiation Monitor (RISH-026-2K6100) was declared inoperable due to events in which the detector was spiking causing Hi and Hi-Hi trips to occur. Per Technical l
Specifications 3.3.2 Action b, the "2D" RF exhaust radiation
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monitor was placed in the tripped condition (trip unit mode
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- switch was placed in the 'zero' position). On July 7, 1989,
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at approximately 9:30 p.m., the "20" RF exhaust radiation-monitor was reset (trip unit mode switch was placed oack to-the.' operate' position) following the completion of work'on
a the detector.by I&C Technicians as part of Maintenance F
- Request Form 8906361. The I&C technicians did not realize that the "20" RE exhaust radiation monitor had been placed-
.in the tripped condition for compliance with TS and shift i
supervision was unaware of the status of the "2D" RF exhaust
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radiation monitor's trip unit. At 9:57 p.m., control. rod-L-
42-47'was stroked for friction testing violating the Technical Specification for core alterations occurring without the I.
"2D" RF exhaust radiation monitor in the tripped condition as required for 'this period of time. This event was reported 'via the ENS but was later withdrawn because the Unit 1 RF ventilation system was operating at the time
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with all. Unit 1 Radiation Monitors in service. The refuel
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floor can be exhausted by either Unit 1 or Unit 2
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On July 17, 1989, during the Limerick Unit 2 Operational Hydrostatic Test, the Reactor Protection System (RPS)_
non-coincident SCRAM functions were enabled. At 1:06 p.m.
the "B" IRM experienced a 0.1 second upscale spike while on Range 1, causing a full RPS SCRAM.
Since all control rods were fully inserted prior to the event, no rod motion occurred. All systems functioned properly, and the SCRAM was. reset at 1:30 p.m.
The upscale spike appeared to be noise induced.
On July 21,1989, at 10:02 p.m. a half scram was received due.to a trip of the channel
"F" Intermediate Range Monitor (IRM). The trip was attributed to work in progress under the vessel. A full' scram signal was_not generated even though the shorting links were removed at the time. This had been attributed to the duration of the spike being insufficient to pick up all of the relays in the non-concident. logic train.
On July 22, 1989, a full scram was received at 3:10 p.m.,
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due to a trip of the "B" channel of the IRMs.
For 10 minutes prior to the trip there was indication of noise on all IRM channels. Source Range Monitor (SRM) channels
"B", "C" and "D" also showed evidence of some spiking, although of a lesser magnitude (possibly due to the discriminator circuit in the SRM's). Channels "A" and "B" IRM spiked high, but only "B" exceeded the trip setting.
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At the time of the trip there were personnel working under the vessel, and construction personnel were working in the drywell. The undervessel work crew reported no unusual conditions, and no detectors were jostled.
Construction personnel had completed welding and were cleaning the welds at the time of the trip.
Further welding was performed later in the day and no anomalies were noted in the Nuclear Instruments (NI's). NRC Notification call was made via the ENS). The inspector will review the LER during a subsequent inspection.
As a result of the events of July 17, 21 and 22, 1989, the licensee began an investigation into the cause for the NI spikes. To date the liceasee has discovered a bent pin on a cor.nector and is contil ng to conduct their investigation. The inspectors had no further questions and will continue to monitor licensee corrective actions.
3.0 Startup Testing Activities Unit 2 (70322, 70323)
The inspectors reviewed the results of the Preoperational Test procedures listed below to verify test exceptions were noted and resolved, tests were properly signed off and acceptance criteria were met.
a.
Preoperational Test Procedure 2P-59.2, Integrated Leak Rate Test (ILRT) - The inspector reviewe'i the ILRT results package, including Test Change Notices (TCN's) I through 52. The inspector noted that several TCN's had been written, reviewed, and issued by a single individual, qualified as a Level III test engineer. While this does not constitute a violation of requirements, startup management agreed that the intent of Administrative Procedure AD8.3P was to have more than one person involved in procedure changes. These TCN's were promptly reviewed and countersigned by another qualified Level III test engineer. A suppression chamber humidity sensor was found to be not working before the commencement of the test and its volume fraction was reassigned to the other two suppression chamber sensors. The inspector questioned why the step requiring a sensor failure analysis (6.4.5.10(a)) was signed off as not applicable given the noted condition.
It was determined that the sensor failure analysis was used to determine the effects of a sensor failing during the conduct of the test and the affect that would have on the final data. Since there was no affect on the final data in this case the analysis was not required. The inspector had no further questions.
b.
Preoperational Test Procedure 2P-51.1, Core Spray - The inspector reviewed the results of preoperational test 2P51.1 Core Spray, Revision 0.
The inspector verified that all test acceptance
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l criteria were met. The inspector reviewed all test exceptions and verified proper closure ir.cluding retests if required. As a result
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of the test the inspector noted that additional calculations were necessary regarding Suppression Pool Level for Net Positive Suction Head (NPSH) and vortex verification. The calculations were performed and as a result, changes to the FSAR were required. The licensee has taken the proper steps to update the document. The inspector had no further questions, c.
Preoperational Test Procedures 2P-16.1A&B, Rev. O, Residual Heat Removai Service Water (RHRSW) System - Test resrlts were evaluated.
The review verified that the testing was accomplished in accordance with regulatory requirements and license commitments. The results of the tests were compared with previously established acceptance criteria and the results package content was reviewed to assure compliance with administrative procedures. The test results were found to meet established acceptance criteria and the results package was in accordance with administrative procedures. No unacceptable conditions were identified.
4.0 Po:er Ascension Test Program (PATP)- Unit 2 (72300, 72301, 72302, 72400,72504,72508,72509,72510,72524,35501)
l 4.1 Overall Power Ascension Test Program l
Initial fuel loading was completed on July 4, 1989. Operating l
license NPF-84 was issued on July 10, 1989, authorizing power l
operation not to exceed 5% of rated power. At the end of this l
inspection period conduct of Open Vessel testing was complete, with final review and approval of Open Vessel test results in progress.
4.2 Power Ascension Test Procedure Review I
The licensee's PATP startup test procedures (STPs) listed in l
Attachment A were reviewed for their conformance with the requirements and guidelines of the references listed in Attachment B and for the
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applicable attributes listed in Inspection Report 50-353/89-03, Section 2.2.
In addition, the inspector reviewed the latest l
revisions to 31 additional STPs which had received detailed review
in previous inspections. These procedures were reviewed l
specifically to determine that the changes did not impact the test acceptance criteria.
Ii a.
Control Rod Drive Testing During review of STP-5.4, " Scram Testing of Selected Rods," the inspector noted that for testing done at 600 and 800 psig, no l
analysis of the effects of increasing temperature on the four I
control rod drives selected for continuous monitoring is conducted.
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STP-5.6, " Rated Reactor Pressure Scram Testing," was previously revised to conduct the scram testing of all rods during the Vessel Hydrostatic Test in Test Condition (TC) Open Vessel instead of during TC Heatup. The inspector had determined that conducting the scram testing during TC open vessel was acceptable based upon review of a General Electric Safety Evaluation which stated that the effects of increasing temperature would be adequately determined during the testing of selected control rods during reactor heatup to rated pressure. The inspector discussed this concern with a licensee representative who stated that procedures STP-5.4 and STP-5.7, " Rated Reactor Pressure Insert / Withdraw Checks and Scram Testing of Selected Rods," would be revised to inclub requirements for monitoring the effects of increasing temperature.
Subsequently, the inspector attended the Sub-Pore meeting on July 27, 1989, at which Startup Test Change Notice (STCN) 32 to STP-5.4 was approved.
The inspector verified that STCN-32 revised STP-5.4 to include monitoring of the effect of increasing temperature and pressure.
The inspector had no further questions.
b.
High Pressure Coolant Injection (HPCI) System Testing During review of'STP-15.0, "HPCI System Main Body," and subtests STP-15.4 and STP-15.5, the inspector noted that HPCI injection to the reactor pressure vessel (RPV) at rated pressure would be performed with the reactor power between 40% and 80% of rated during i
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test condition 3.
Regulatory Guide 1.68 states that ECCS high pressure coolant injection system testing should be conducted at a power level in the 25%-50% range. The inspector discussed this apparent discrepancy with a licensee representative who stated that HPCI testing per STP-15.4, " Controller Optimization During RPV Injection at Rated Pressure," is scheduled to be conducted prior to exceeding 50% rated power. The inspector had no further questions.
c.
HVAC System Operation During inspection 50-353/89-12, the inspector reviewed STP-32.0,
" Essential HVAC System Operation and Containment Hot Penetration Temperature Verification - Main Body," and all subtests. At that time, acceptance criteria for the reactor pressure vessel skirt surrounding air temperature being maintained above a minimum of l
70 degrees F was being analyzed by GE.
During this inspection, the inspector further reviewed this issue
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l and noted that based upon tne GE analysis, the acceptance criteria I
was changed to an air temperature above a minimum of 55 degrees F with an air velocity of 15 ft/sec.
In addition GE recommended
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monitoring of temperatures on the RPV skirt during the initiation of a reactor shutdown including cooldown for one hour. The inspector
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reviewed revisions to STP-32.0 and STP-32.1 and the new procedure
' STP-32.7 which incorporated the results of the GE Analysis.
In addition, the inspector attended the sub porc meeting on July 27, 1989 at.which the above procedures were approved. The inspector had no further questions.
4.3 ' power Ascension Test Witnessing The inspector witnessed portions of the power asce.1sion tests discussed below. The performance of these tests were witnessed to verify that:
The current, approved revision of the test procedure was
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available and was used by all participants; The minimum crew requirements, as defined in the approved
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procedure and technical specifications, were being met.
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Required prerequisites and initial conditions were established;
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Test ec,alement was calibrated and operated in accordance with
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procedere;
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The procedure was technically adequate and appropriate to the
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circumstances; Crew performance was correct and timely;
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Coordination of test related activities was adequate;
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A preliminary analysis of all data collected was expeditiously
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performed following completion of the test; and The test.was performed in accordance with all administrative
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requirements; a.
STp-3.1 Fuel Load - Initial Fuel Loading was ongoing at the beginning of the Inspection period and was completed on July 4, 1989. The inspectors witnessed several fuel movements over.
this time period. Monitored activities included inserting fuel assemblies, control rod stroke testing, subtritical multipli-cation checks, and subtriticality verifications.
The inspector monitored activities on the refuel floor and in the control room, verifying compliance with Technical Specifications, plant procedures, and the sequence of movements specified on the Core component 1ransfer Authorization Sheets (CCATS). The inspectors noted that all fuel movements were conducted in a well controlled and professional manrer. Direct communications were maintained with the control room at all times.
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STP-5.1, Insert-Withdraw Check's - The inspector observe'd control rod drive (CRD) stroke testing and timing performed during fuel loading. The inspector noted the presence of Technical. Monitoring Personnel (Quality Assurance) and proper adherence to procedural controls. Also worthy of note were the actions taken by the. shift supervisor to improve the apparent professionalism of the activities.
No discrepancies were=
identified.
STP-5.2,-Zero Reactor Pressure' Function Testing - The inspector c.
. witnessed friction testing for several CRDs performed at the Central Friction Testing Station by a licensed reactor operator. The overall test crew performance was satisfactory. The inspector observed initiation of testing for each rod and data reduction following the testing of each rod. All test results were within acceptance criteria limits.
No discrepancies were identified.
d.
STP-5.3, Zero Reactor Pressure Scram Testing and STP-5.6, CRD Scram Testing - The inspectors witnessed scram testing of several CRDs at both zero and rated reactor pressure. Activities conducted in the' control room and locally at the Hydraulic Control Units were monitored..The inspectors noted that the required communications were maintained during conduct of the testing,.and that the testing was controlled by the Reactor Operator in the control room. The inspectors observed scram time determinations being made from the Scram Control Rod Initiation Timing System (SCRITS) during STP-5.3 and STP-5.6 and also from a strip chart recorder during STP-5.6. All scram times were within the acceptance criteria limits. No discrepancies were identified.
4.4 Power Ascension Tests Results Review The power ascension test results discussed below were reviewed to verify that:
The test was performed in accordance with a current, approved
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procedure; Test changes were approved in accordance with administrative
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procedures;
. Test changes were annotated in the procedure and completed, if
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appropriate; The basic objectives of the test were met;
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I Test deficiencies were documented, as required;
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Test. deficiencies'were resolved and accepted by management, and
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retests were completed,11f required;
. System or process changes necessitated by test deficiencies
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- were properly documented and reviewed; d
Test deficiencies.which constitute reportable occurrences were
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properly reported; Required test data was obtained and was within tolerances;
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Individual test steps and data sheets were properly initialed
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and dated; An engineering evaluation of the test data was performed;
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Test results were evaluated against established acceptance
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criteria; Review and acceptance of test results were documented;
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. Tests results were reviewed by Quality Assurance; and
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Test results were approved by appropriate management;
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a.
STP-1.1, Chemical and Radiochemical (Results approved July 18,1989) - This procedure was performed prior to commencement of fuel loading to determine baseline data for reactor water and selected systems. A Test Exception Report (TER) was generated for the Reactor Enclosure Cooling water ph of 10.3 which exceeded the Level 1 acceptance criteria (GE Water Quality Specification) of 9.0-9.7.
This value was evaluated and accepted as is since it was within the plant specification for ph of 10.5 as required in Chemistry Procedure CH-1010.
b.
STP-1.2, Chemistry Data (Results Approved July 22, 1989) - Specific chemistry and radiochemical analyses on water samples drawn from selected systems were performed following fuel loading. All acceptance criteria were satisfied.
c.
STP-2.1, Radiation Surveys (Results Approved July 22,1989) - This procedure was performed after fuel loading included room and area radiation surveys and the radiation shield survey. All acceptance criteria were satisfied.
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STP-3.1, Fuel Load (Result Approved July 19, 1989) - The inspector independently evaluated the test results including the 1/m plots maintained during fuel loading and the partial core shutdown margin test. All acceptance criteria were satisfied.
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e.
LTP-5.1, Insert-Withdraw Checks (Results Approved July 22,1989) - This test was conducted in conjunction with STP-5.1, following completion of fuel loading of the control cell to be tested. All acceptance criteria were satisfied. The inspector verified that all control rod drives (CRD) had normal insert and withdraw speeds of 3.0+/.6 inches per second, f.
STP-5.2, Zero Reactor Pressure Friction Testing (Results Approved July 19, 1989) - Friction testing of all CRDs at zero reactor pressure was conducted during test condition open vessel.
The inspector u M fied that all CRDs satisfied the acceptance criteria for wt hus insert friction testing of differential pressure 5 D estd.
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STP-5.4, Scram Testing of Selected Rods (Results Reviewed (July 22, 1989) - Based upon the results of STP-5.3, Zero Reactor Pressure Scram Testing, four CRDs (with either the slowest scram times to position 05 or with unusual operating characteristics)
were selected to be scram tested three times each at zero reactor pressure with scram accumulator nitrogen pressure set just above the low pressure alarm setpoint.
The inspector verified for the four CRDs that the scram times to position 05 met the 5 '7.0 seconds criteria. However, one TER was written against CRD 22-11 due to extremely fast and inconsistent scram time data. The test results were approved with the TER remaining open pending investigation of the source of the prcblem and retest of CRD 22-11 at zero reactor pressure.
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STP-17.2, Measured Pipe Displacements (Feedwater and RWCU Systems) (Results Approved July 22, 1989) - The inspector reviewed l
the completed results package. Baseline data for thermal expansion l
of the feedwater and reactor water cleanup systems was measured during test condition open vessel. The test had no acceptance criteria.
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STP-17.3, Measured Pipe Displacements (Main Steam Inside l
Drywell and Reactor Recirc) (Results Approved I'
July 19,1989 - Baseline data for thermal exparsion on the main f
steam and reactor recirculation piping was collected during test condition open vessel. The test had no acceptance criteria and required none.
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STP-17.4,' Visual Pipe and Hanger Inspections (Main l
Steam inside Drywell and Reactor Recirc) (Results Approved July 19, 1989) - The inspector reviewed the completed results package and verified that all acceptance criteria were l
satisfied. The test was conducted during test condition open vessel at a reactor water temperature of 90 degrees F and verified that NSSS system piping is capable of free and unrestrained movement due to thermal expansion.
The inspector had no further questions on the test results reviewed.
4.5 Quality Assurance Interface with the Power Ascension Test Program The inspector reviewed Limerick Quality Division Monitoring Guideline PA-01 which provides instructions for monitoring the performance of Startup Test Procedure (STP) testing during the Unit 2 Power Ascension Program.
The inspector reviewed 13 monitoring reports for various power ascension activities including fuel loading, CRD stroking and friction and scram testing, plant walkdowns during the vessel hydrostatic test, and installation of step generator input test boxes for the recirculation flow control system testing. The inspector verified that the monitoring was conducted per guideline PA-01.
No unacceptable conditions were identified.
5.0 Control Rod Drive Withdrawal in Operational Condition 4 During a previous inspection, the inspector reviewed a revision to Startup Test Procedure (STP)-5.6, " Rated Reactor Pressure Scram Testing,"
and noted that the procedure had been changed to allow scram testing for Unit 2 to be conducted during the (50-353/89-19) vessel hydrostatic in operational condition (0p Con) 4, instead of following the initial plant startup. However, the inspector found STP-5.6 inadequate because approo-riate prerequisites for conducting the test in Op Con 4 instead of Op Con 2 were not present. STP-5.6 was subsequently revised (see section 4.3).
Subsequent to that inspection and prior to conduct of the vessel hydrostatic test, the inspector had additional concerns regarding whether the licensee's T.S. permitted withdrawal of control rods for scram testing in Op Con 4.
In addition, the inspector questioned if the requirements of T.S. 3.9.2 for demonstrating adequate shutdown margin (SDM) could be met through an analysis, as has been the position taken by the licensee (PORC Position 32).
TS 4.1.1 requires SDM as determined by measurement.
Both concerns were discussed with representatives of the Office of Nuclear Reactor Regulation (NRR) and the licensee, and resolved as follows.
It is the position of NRR that adequate SDM cannot be demonstrated through analysis. Therefore, PORC Position 32 was incorrect.
The licensee intends to delete it prior to the next refueling.
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Regarding control rod withdrawl in Op Con 4, the Technical Specifications which govern control rod withdrawal are not applicable in Op Con 4.
The
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licensee wrote a safety evaluation addressing this issue which determined that control rods could be withdrawn in Op Con 4 as long as the requirements for withdrawing control rods in Opcon 5 are met. These requirements include Standby Liquid Control System operability (T.S. 3.1.5) and shorting l
links removed (this provides SRM and noncoincident NI. scrams in case of criticality) since adequate SDM was not demonstrated through measurement.
(TS 3.9.2).
The inspector had no further questions.
6.0 Licensee Action on Previously Identified Items (92701, 94300, TI 2515/95)
(Closed) Unresolved Item (50-353/86-18-04). No procedures for seismic walkdowns. The inspector reviewed specification 8031-M-400 for seismic and safety impact study walkdowns, and procedure CP-1-2 for turnover of facilities to PECo. Specification M-400 gives details for identifying and evaluating safety impact situations (seismic class II components which might affect seismic class I equipment) and performing seismic walkdowns, including evaluation of the Unit 1-Unit 2 interface.
Construc-tion Procedure CP-T-2 delineates who is to perform the various walkdowns, along with appropriate time frames fcr their accomplishment. CP-T-2 also assigns responsibility for coordinating the walkdowns and ensuring their documentation is complete. The inspector examined the documentation packages for three facility walkdowns, one with no irregularities, one with irregularities which were evaluated as acceptable as-is, and one where corrective action was required (removal of temporary piping, equipment and supports). This item is closed.
(Closed) Unresolved Item (50-353/89-10-01). Preoperational Test Procedure 2P-59.2, Revision 0, " Primary Reactor Containment Integrated Leakage Rate Test," step 6.3(23) required ILRT instrumentation to be functionally checked after installation in accordance with ANSI /ANS 56.8-1981.
However, the acceptance criteria and data sheets to record the calibration results were not included in the procedure. These deficiencies were corrected by the licensee by adding TCN-006 to test procedure 2P-59.2. The information provided in TCN-006 was adequate and the inspector had no further questions regarding this issue.
(Closed) Unresolved Item (50-353/89-13-03).
Skid mounted valve labeling.
This item cited a lack of tagging and administrative controls on skid mounted equipment, in particular the high pressure coolant injection (HPCI)
system. The licensee has labeled the HPCI skid valves and incorporated the valves in the system checkoff lists. Also the system routine inspection procedure S55.9.A has been revised to include specific instructions on how to establish the required HPCI lube oil pressures using the skid mounted vaives. The licensee also performed a walkdown of other Unit I and 2 skid mounted equipment and corrected any labeling and procedure deficiencies.
This item is closed.
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(Closed) Unresolved item (50-353/89-16-02). Inservice inspectability of Limerick 2 reactor vessel nozzle / safe end welds. All reactor N2 nozzle /
safe end welds were subjected to preservice inspection (PSI) prior to Mechanical Stress Improvement Process (MSIP) and revealed no rejectable or reportable indications. However, after MSIP a second preservice ultrasonic inspection (PSI) was performed on these N2 nozzle safe end welds and reportable ultrasonic indications were revealed.
A meeting between the licensee, General Electric (GE) and NRC Region I representatives was held on June 22, 1989 to review the licensee's disposition of the ultrasonic indications found and to assess the inspectability of those welds subsequent to the application of the MSIP.
General Electric Company and Philadelphia Electric Company made presenta-tions, and a demonstration of the preservice (baseline) ultrasonic examinations of the N2 nozzle welds was reviewed. The examinations were performed by GE using the automated " Smart UT" system. The questioned indications were observed to be discrete signals, appearing above the 15%
full screen height (FSH) noise level, in the weld metal.
Experience shows that indications of intergranular stress corrosion cracking (IGSCC) appear outside of the weld in the heat affected zone so that if IGSCC develops during service, its indications would not be masked by the PSI indications.
Also, the 15% FSH noise level, which is deliberately established to monitor transducer contact and sound penetration in the material is not expected to interfere with significant IGSCC indications.
The licensee concluded that a valid baseline examination for these welds was established, reportable indications can be repeatedly detected, and that a meaningful ASME Code Section XI inservice inspection (ISI) is possible. Based on the above, the NRC agreed with the licensee's conclusion and this item is closed.
(Closed) Violation (50-252/89-09-01) Failure to follow procedure while disassembling Main Steam Safety Relief Valve PSV-041-1F013L. The inspector reviewed the licensee response to this violation, dated June 14, 1989, which delineates corrective actions including additional training of personnel and the revision of Maintenance Procedure M-041-007. The inspector found the response to be adequate and considers this item closed.
(Closed) Violation (50-352/89-10-01).
Failure to follow procedures for Temporary Circuit Alterations, tag out removal (unblocking of equipment)
and restoration of equipment following surveillance testing. The inspector reviewed the licensee response to this violation, dated July 28,1989, which delineates the licensee's corrective actions. The licensee has achieved full compliance with these matters including procedural changes for clarification, personnel training, and the formation of a task force to evaluate root causes for commonality and recommend corrective actions for management consideration. The inspector found the response to be adequate and considers this item closed.
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Non Conformance QA work practices
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(Closed) Violation (50-353/89-200-01).
identified during the NRC Independent Design and Construction Assessment
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(IDCA) inspection.
The inspector reviewed the licensee response to the
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violation, dated July 28, 1989, which delineates the licensee's corrective actions. All of the identified items have been corrected as of March 28,1989. The inspector verified the -licensee actions and considers this item closed.
(Closed) Construction Deficiency (50-353/80-00-10). Cable Separation Violations in PGCC Panels. This deficiency report documented cable separation problems in electrical control panels (Power Generation Control Complex Panels) provided by General Electric.
In NRC Inspection Report 50-353/87-02 Quality Control Instruction RW-1.10 was reviewed and found to contain adequate instructions on how to verify proper cable separation.
PECo Quality Assurance Finding Report 2E-542 documents that all the General Electric provided panels were inspected and any deficiencies corrected. Based on the above information and a review of a sample of the associated inspection records this item is closed.
(Closed) Construction Deficiency (50-353/89-00-08). 'It was identified that t.co Travis Pressure Transmitters for the reactor enclosure
. recirculation system were installed without the internal heating element connected. The heating element is provided to maintain a constant temperature in order to have a tight accuracy tolerance over the specified environmental operating range. The inspector has verified that the aforementioned heaters have been connected per the manufacturer's instructions and are now operable.
The inspector considers this item closed.
(Closed) Construction Deficiency (50-353/89-00-09). Midlock Ferrules in Electrical Penetrations. Ten out of fourteen midlock ferrules of electrical containment penetration 20JX22 (wet well penetration) did not meet the leak rate test criteria due to stress corrosion cracking (SCC).
All fourteen ferrules were replaced and the cracked ones were sent to two laboratories for analysis.
The inspector reviewed both laboratory reports, including nondestructive examinations, metallurgical examination and conclusions. The two labs agreed on the cause of the failures being SCC.
They also reported that the stains on the material indicated that the ferrules may have been wet at sometime.
The licensee performed inspections of additional penetrations, including the only other suppression pool penetration, and found no other indications.
The event which caused the contamination could not be identified with either shipment or storage of the ferrules prior to installation. However, when the ferrules are installed they are kept in a nitrogen atmosphere to keep out moisture. Normal surveillance testing of penetration pressure gages and long-term leak rate testing during refueling outages will detect any leaks of ferrule seals. The inspector considers this item closed.
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(0 pen) TMI Action Plan Item III.D.1.1 Primary coolant outside containment.
l This item was last updated in Inspection Report 50-353/89-11. The inspector reviewed the results of eight surveillance tests required prior to initial fuel load and two surveillance tests required prior to initial criticality for Unit 2.
The results were determined to be satisfactory.
All licensee actions with regard to this item required prior to initial riticality are complete. However, the item will remain open pending licensee performance and evaluation of six remaining surveillance tests which will not be completed until after initial criticality.
(Closed) Generic Letter 88-14. " Instrument Air Supply Systems Affecting Safety-Related Equipment." This issue addressed the need to evaluate instrument air systems regarding air quality, maintenance practices, procedures for operation and design of the system to ensure its operation in order to assure reliable operation to safety-related equipment supplied by instrument air. The inspector reviewed the licensee's responses to this generic issue (dated February 13, 1989) and determined that the licensee responded in the allotted time and addressed all of the concerns.
The inspector reviewed classroom training material and determined that the appropriate training was conducte.d to operate and maintain the instrument air system in accordance with new procedures that had been incorporated. These procedures include surveillance testing, operation, and system maintenance practices. The inspector considers this matter closed based on his review of licensee actions.
(Closed) TI 2515/95. The ATWS Rule "10 CFR 50.62, " Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants," requires improvements in the design and operation of commercial nuclear power facilities to reduce the likelihood of failure to shutdown the reactor following anticipated transients, and to mitigate the consequences of an ATWS event. The requirements for a boiling water reactor are to install an alternate rod injection (ARI) system, modify the standby liquid control system (SLCS)
and to trip the reactor coolant recirculating pumps automatically under conditions indicative of an ATWS.
By letters dated October 17, 1985 and April 23, 1987, PECo provided aesign information on the systems they had installed in Limerick Unit I and that they planned to install in Limerick Unit 2 to meet the ATWS Rule. The station design incorporated the Redundant Reactivity Control System (RRCS) in conjunction with selected equipment in the Control Rod Drive '(CRD), the Reactor Recirculation, and Standby Liquid Control (SLC) systems for ATWS prevention and mitigation.
By letter dated November 3, 1987, the NRC advised PEco that the staff had reviewed the design information they provided and had concluded that the ARI design, the ATWS/RPT design and the SLCS design comply with the requirements of 10 CFR 50.62 and the guidance published in the Federal Register on June 26, 1984 (49 FR 26036) and that all of the systems as installed in Unit I are acceptable.
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As requested in the November 3, 1987 letter, PECo advised the Commission by letter dated April 18, 1989 that the required ATWS modifications had i
been installed and checked-out in Limerick Unit 2.
The licensee has installed a pump trip that is actuated either by Reactor High Dome Pressure or Reactor Low Water Level. The installation of the i
recirculation pump trip systems (both ATWS and end of cycle (E0C) RPT) was L
verified, including the manual and automatic breaker controls in the control
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room and the breaker, panels on elevation 253 of the reactor enclosure.
The records indicate that the RPT breakers have been tested four times on Unit I and twice on Unit 2.
The last of the surveillance tests (ST-1-043-800, Arc Suppression Test) was performed on July 20, 1989 to demonstrate that the ATWS breakers interrupt current to the recirculation pumps when actuated. A review of the surveillance tests indicated-that there was a record of calibration tests, that sign offs had been completed where required or that deletion of a step had been approved by supervision
- and that test results were satisfactory or properly repositioned. TI 2515/95 and MPA C-02 are considered clored.
(Closed)Bulletin 78-14. Deterioration of Buna-N components in Hydraulic Control Units. Maintenance procedure PMQ-600-036 which requires verifi-cation of adequate remaining life for elastomeric used in overhauling the Hydraulic Control Units was issued. This bulletin is closed. All elastomeric material currently installed at Unit 2 meets this requirement.
7.0 Surveillance /Special Test Observations (61726)
During this inspection period, the inspector reviewed in progress surveillance testing as well as completed surveillance packages. The inspector verified that surveillance were performed in accordance with
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licensee approved procedures and NRC regulatory requirements. The inspector also verified that instruments used were within calibration tolerances and that qualified technicians performed the surveillance.
The following surveillance were reviewed:
Unit 2
- ST-1-060-730-2 Suppression Pool to Drywell Bypass Leak Test
- ST-3-048-320-2 Standby Liquid Control Operability Verification
- ST-4-095-952-2 Division 2 Battery Service Test ST-5-048-800-2 Standby Liquid Control Boron Concentration Analysis ST-6-047-200-2 Scram Discharge Volume Valve Exercise Test.
The requirements of the surveillance procedures preceeded by an asterisk were met by performance of testing other than the surveillance test (ie l
Preoperational Test).
The inspector reviewed administrative procedure l
A-223 which describes the process for verification and documentation of
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performance of surveillance requirements by other than surveillance
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testing. The inspector performed a detailed review of the test result packages for the three asterisked procedures and verified that the surveillance requirements were adequately met through completion of other i
testing and that the results were adequately documented.
The inspector also monitored surveillance testing of the Unit 2 nuclear instruments. The inspector verified use of and adherence to the appropriate procedures and that the data obtained fell within the i
acceptable ranges. The inspector verified removal of the Reactor Protection System (RPS) shorting links upon completion of the testing since fuel loading activities were still underway.
8.0 Maintenance Observations (62703)
The inspector reviewed the following safety related maintenance activities to verify that repairs were made in accordance with approved procedures, and in compliance with NRC regulations and recognized codes and standards. The inspector also verified that the replacement parts and quality control utilized for the repairs were in compliance with the licensee's QA program.
8.1 Unit 2 The inspector observed maintenance work activities associated with the overhaul of the D23 (2C) Emergency Diesel Generator (Maintenance Request Form 0805912).
This became necessary due to the failure of the diesel generator during logic functional testing which resulted from the failure of the engine scavenging air blower. The blower failure appears to be related to inadequate clearances between the lobes of the blower impellers which developed during operation.
A new blower was procured and installed, and the entire engine was disassembled for cleaning and inspection. The inspector also observed portions of the post-work testing of the diesel engine which included bearing run-in and load testing. The inspector also reviewed the work permit and tagging (blocking permits) 2-020-9005, 9005B and 2-092-9055. No discrepancies were identified.
9.0 Review of Periodic and Special Reports (90713)
Upon receipt, the inspector reviewed periodic and special reports.
The l
review included the following:
inclusion of information required by the NRC; test results and/or supporting information consistent with design predictions and performance specifications; planned corrective action for resolution of problems; and deportability and validity of report information.
The following periodic report was reviewed:
Monthly Operating Report - June 1989 The inspector had no questions regarding this report.
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10.0 Licensee Event Report Followup (90712, 92700)
The inspector reviewed the following LERs.to determine that deportability requirements were fulfilled, that immediate corrective action was taken,.
.and that corrective action to prevent recurrence was accomplished in-accordance with technical specifications.
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10.1 Unit 1-LER 89-034..This LER reported isolation valves that were not environmentally qualified.
This was discussed in inspection report 50-352/89-12 and 50-353/89-19. After review of the LER the inspector had no further questions.
LER 89-035. This LER reported control rods 20-35 and 30-15 had their uncoupling. rods misaligned.
This condition was corrected prior to reactor startup following the refueling outage. The
. inspector had no further questions regarding this report.
LER 89-036. This LER reported setpoint drift of the main steam safety relief. valves. Although only one of the 14 valves lifted with the +/- 1% setpoint tolerance, previous analysis performed as a-part of the BWR owners group setpoint drift program indicates that adequate overpressure protection was still present. The inspector had no further questions.
LER 89-037.
This LER reported two initiations of the Standby Gas Treatment System caused by a defective relay. The inspector had no further questions regarding this report.
LER 89-038.
This LER reported a Reactor Core Isolation Cooling System isolation due to personnel error during surveillance testing.
This' item was cited as a violation of plant technical specifications in NRC Inspection Report 50-352/89-10 and the corrective actions will be reviewed with the licensee response to the violation.
LER 89-040. This was a special report which documented a failure of the Seismic Monitoring System Triaxial Response Spectrum Analyser printer. The inspector had no further questions regarding this report.
LER 89-04). This report documents an inadequate calibration of the POST-LOCA radiation monitors which was also cited as a violation of plant technical specifications in NRC Report 50-352/89-12. The corrective actions will be reviewed in a future report as part of the violation closeout.
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-r LER 89-042..This LER documents hydraulic control units (HCUs) which
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were inoperable due to improper interpretation of plant technical
. specifications surveillance requirements. This item was also cited
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.as a violation in NRC Inspection Report 50-352/89-12 Land the corrective actions will be reviewed in a future report upon receipt l
of the licensee response to the violation.
10.2 Unit 2'
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LER 89-001. This LER reported damage to a Unit 2 neutron source pin in excess of $2,000. The inspector had no further questions upon review of this report.
LER 89-002. This report documents a violation of electrical cable separation: criteria affecting the D-22 Emergency Diesel Generator and "B"' Loop of Core Spray.
This inspector had no further questions
.concerning this report.
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11.0 Evaluation of Licensee Quality Assurance Program Implementation and Self-Assessment-Capability (35502 & 40500)
11.1 The resident inspector reviewed documents and reports including LER's, inspection reports, PORC minutes, off site safety review group minutes, the SALP report, and Nuclear Review Board (NRB-minutes for the' period May,1988 to June,1989. As a result of the review the resident inspectors identified the following areas where
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licensee performance was weak.
11.2 Lack of Timely / Technically Adequate Engineering Support Numerous control room isolations over a period of years due to
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chlorine detector location / logic design. (LERs 88-21, 26, 27, 28 plus 7 previous)
Appendix R lessons learned at Peach Bottom not applied to
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Limerick for three years (e.g. Hi-Lo Pressure Interface, Report 89-12)
Technically incorrect position given to PORC on shutdown margin
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determination requirements.
(Section 5.0 of this report).
Technically inadequate justification for battery room design provided to NRC via plant engineering staff.
(Report e
88-20)
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ESW system piping corrosion not addressed until prompted by NRC.
(Report 89-80)
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ESW pump performance and flow balance inconsistencies not-addressed until questioned by NRC. (Report 89-03)
Surveillance test (ST) on Hydraulic Control Unit (HCU) check
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valves was _ technically incorrect. (Report 89-12)
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No engineering resolution to ventilation problems (and resultant' isolations) caused by fatigued air lines. (LERs 88-20,87-50,88-02)
. Spent fuel pool criticality monitor' set point calculation
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failed to account'for concrete shielding.
(Report 89-12)
b.
Failure to Follow Procedures
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Safety relief valves damaged due to improper disassembly.
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Failure to'use Temporary Circuit Alteration (TCA) to control
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HCU jumpers.
(Report 89-10)
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I&C Technician failure to follow ST. (Report 89-10)
HP Technician failure'to follow RWP procedure.
(Report 89-12)
Failure to follow procedure related to use of HEPA filters.
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Operations Plant lineup changes made without verifying expected system
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response.
Loss of vacuum due to isolated offgas flowpath.
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(Section 2.1.1 of this report).
Approximately 240,000 gallons drained to CST moat instead
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of radwaste as intended. (Section 2.1.1 of this report).
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Heatup rate exceeded during startup due to failure to adequately monitor changing plant conditions.
(Report 89-10)
Inadequate system restoration (including independent
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verification of restoration).
I HCU valves not restored properly.
(Report 89-10)
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Jumpers left in junction boxes for HCU.
(Report 89-10)
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Loss of vacuum (cited above).
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Inadequate' Level of Management Oversight of Routine Operations Degradation of EP Program. (Reports 88-01 and 89-11)
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-Radwaste Shipment with excessive dose rate.
(Report 89-14)
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Deportability determinations require excessive time to be
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resolved.
(Report 88-20)
Station management has not aggressively pursued a solution-to
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the problem where technical issues exist for long periods of time without having been reviewed for system operability impact.
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NUPRO valves not per ASME code.
(LER 89-34)
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Agastat locking clips not properly installed.
(LER 88-19)
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. Hydrogen mixing system flow switches not properly
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installed.
(Report 89-03, LER 89-17)
Damper access doors not properly installed.
(LER 88-3u)
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Surveillance Test Program (missed surveillance).
HCU check valve test did not determine operability.
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(Report 89-12)
Battery charger heat run with doors open.
(Report 89-09)
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No procedure for SBLC level instrument calibration.
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(Report 88-17)
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Post LOCA Radiation Monitor calibration procedure inadequate.
(Report 89-12)
11.3 An NRC~ licensee management meeting was held on July 24, 1989 in Region I to discuss the licensee's self-assessment and the NRC's assessment of the licensee's peformance as summarized in section 11.1 above. At this meeting, the licensee presented their self-assessment results and future activities to correct the noted problem areas.
(A list of attendees, agenda and meeting content are attached in Attachment C.) The licensee identified similar weaknesses to those of the resident inspectors which indicated a self-assessment
. process that can and will identify problems and management willingness to acknowledge them and take corrective actions.
However, the NRC noted that the engineering department had not been as self-critical as the others represented. As a result the resident inspector had a discussion with engineering management wherein they did discuss weaknesses and future changes to remedy them.
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l-concluded.the licensee had a strong commitment to self assessment
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12.0 Chairman and Commissioners Visit On July 13, 1989 NRC chairman, Mr. K. M. Carr visited the Limerick
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Generating Station and on July 27, 1989, Commissioner K. C. Rogers
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. visited the Limerick Generating Station.
Each commissioner received a plant tour.and attended meetings with the licensee.
13.0 Exit Interview (30703)
Periodically, throughout the inspection period, the NRC resident inspectors discussed the issues in this report with licensee management.
.The inspection findings were summarized at an' exit meeting held with the plant manager, Mr. M. J. McCormick, Jr., on July 28, 1989. No written inspection material was provided to licensee representatives during the-inspection period.
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l-Attachment A Power Ascension Test Procedures Reviewed
.Startup Test' Procedures (STP) - 5.4, Scram Testing of Selected Rods, Revision 2, July 6, 1989 STP-5.6,-Rated Reactor Pressure Scram Testing, Revision 1, with Startup Test Change Notice (STCN)-17, July 7, 1989.
STP-5.7, Rated Reactor Pressure Insert / Withdraw Checks and Scram Testing of Selected Rods, Revision 0, March 27,"1989.
STP-13.2, TIP Alignment at Rated Temperature, Revision 0, March 29, 1989.
STP-13.3, Program Testing at Test Condition One, Revision 0, March 29, 1989.
STP-13~.4, Dynamic System Test Case, Revision 1, March 29, 1989.
STP-13.5, Program Testing at Test Condition Two, Revision 0, March 29, 1989.
-STP-13.6, Program Testing at Test Condition Three, Revision 0, March 29, 1989.
STP-13.9, Program' Testing During Power Changes, Revision 0, March 29, 1989.
STP-15.0, HPCI System, Main Body, Revision 1, June 22, 1989.
STP-15.1, Functional Demonstration CST to CST at 200 PSIG, Revision 1, June 22, 1989.
STP-15.2, Functional Demonstration and Controller Optimization at Rated Pressure CST to CST, Revision 1, June 22, 1989.
STP-15.3, Stability Check CST to CST at 150 PSIG, Revision 1, June 22,1989.
STP-15.4, Controller Optimization During RPV Injection at Rated Pressure, Revision 1, June 22, 1989.
STP-15.5, HPCI Cold Quick Start at Rated Pressure - CST to RPV, Revision 0, June 22,-1989.
STP-15.6, HPCI Surveillance Tests to CST, Revision 1, June 22,1989.
STP-15.7, HPCI Endurance Run, Revision 0, June 22, 1989.
STP-25.0, Main Steam Isolation Valves - Main Body, Revision 1, June 19,1989.
STP-25.1, MSIV Functional Test, Revision 1, June 16,1989.
STP-25.2, Full Closure of Fastest MSIV, Revision 1, June 16,1989.
STP-25.3, Full MSIV Isolation, Revision 1, June 16,1989.
-
_ - _ _ - - -
_ _ _ - - _-
-
D yp c
..
-
.
!
STP-32.0, Essential HVAC-System Operation and Containment Hot Penetration
. Temperature Verification, Revision 2A,.Sub PORC Approval July 26, 1989
'STP-32.1, Primary Containment Temperature, Revision IA, Sub PORC Approval July
,
26, 1989.
L STP-32.7, Reactor. Pressure Vesse1~ Support Skirt Surrounding Air Temperature and Impingement Velocity, Revision A, Sub PORC Approval July 26, 1989.
STP-33.0, Piping Steady State. Vibration - Main Body, Revision 1, June 16,
1989.
STP-33.1, Main Steam Piping (Inside Drywell) Steady State Vibration, Revision 1, June 16, 1989.
STP-33.2, Recirculation Piping Steady State Vibration, Revision 1, June 16, 1989.
STP-33.3, Main Steam (Outside Drywell), Main Steam Bypass, and Feedwater -
Piping Steady State Vibration, Revision 1, June 16, 1989.
.
STP-33.4, HPCI Steam Piping Steady State Vibration, Revision 0, March 31, 1989 STP-33.5, RCIC Steam Piping Steady State Vibration, Revision 0, March 31, 1989.
STP-33.6, Reactor Water Cleanup Piping Steady State Vibration, Revision 0, March 31, 1989.
STP-33.7, RHR Shutdown Cooling Mode Piping Steady State Vibration, Revision 1, June 16, 1989.
STP-33.8, EHC System Piping Steady State Vibration, Revision 1, June-16,1989.
STP-36.0, Piping Dynamic Transients - Main Body, Revision 1, June 16,1989 STP-36.1, Main Steam Piping Vibration During Main Turbine Stop Valve and Control Valve Closures, Revision 1, June 16, 1989.
,
STP-36.2, Main. Steam and Steam Relief Valve Discharge Piping Vibration During SRV Operation, Revision 1, June 16, 1989.
STP-36.3, Recirculation Piping Vibration During Selected Transients, Revision 0, March 31, 1989.
STP-36.4, HPCI Steam Supply Piping Vibration During HPCI Turbine Stop Valve Closure, Revision 1, June 16,1989.
'. STP-36.5, Feedwater Piping Vibration During Reactor Feed Pump Trip /Coastdown, Revisicn 1, June 16,1989.
-
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.
_ _ _ _ _ _ - _
.
.
-
.
Attachment B References Regulatory Guide 1.68, Revision 2, August 1978, " Initial Test Program for Water Cooled Nuclear Power Plant" ANSI N18.7-1976, " Administrative Controls and Quality Assurance for Operations Phase of Nuclear Power Plants."
Limerick Generating Station Unit 2, Technical Specifications, June 22, 1989 Limerick Generating Station Unit 2, Final Safety Analysis Report (FSAR),
Chapter 14, " Initial Test Program."
GE Specification, NEB 0 23A1918, Revision 3, "Startup Test Specification, Limerick Units 1 and 2."
Letter, GE-ENG-10, R.D. Ballou to T. Gettle, dated July 13, 1989.
,
l l..
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _. _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _. _ _
_____.
__
_
ATTACHMENT C
,
.
.
~
AGENDA
OVERVIEW AND SELF-ASSESSMENT LEITCH
'
EFFORT
UNIT 2 STARTUP SUMMA.RY AND ULLRICH j
PLANT MANAGEMENT SELF-ASSESSMENT
UNIT 1 OPERATION SUMMARY AND McCORMICK RECENT PLANT CONCERNS
EVENT INVESTIGATION PROCESS MUNTZ
TCA REDUCTION PROGRAM RESULTS MUNTZ
MAINTENANCE PERFORMANCE TEXTER
RADIOLOGICAL CONTROL PROGRAM DUBIEL
PLANT CHEMISTRY PROGRAM DUBIEL
ENGINEERING SUPPORT LEES 10 TRAINING PERFORMANCE FIRTH 11 QA REORGANIZATION AND NEW MacAINSH PROGRAMS 07/24/89
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LIVIERICK UNIT
-
OPERATION SUVIVIARY
~
264 DAYS OF CONTINUOUS
.
'
OPERATION REDUCED POWER TO N Ah AGE
OFFGAS RADIATiOh LEVELS l
DUE TO FUEL LEAKS SECOND REFUELislG OUTAGE
STARTED JANUARY "3,1989 07/24/89
__ _________
__ _ -
-
- - - -
,.
,
,
.
.
SECOND REFUELING OJTAGE
.
JANUARY 13 TO MAY 15
3500 mal \\TENANCE TASKS
COMPLETED 91 VIODIFICATIONS INSTALLED
+
UNIT 1/ UNIT 2 TIE IN e
WORK CONPLETED FUEL REPLACEMENT /
RECONSTITUTION ON1LY 9 OF 26 LERS
REPORTED DUR NIG OUTAGE l\\lVOLVED OUTAGE ACTIVITIES
!
07/24/89
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ -
'
.
.
.
-
.
THIRD OPERATING CYCLE S
e REACTOR STARTUP MAY: 15
.
MAIN TURBINE TORSIONAL TEST
LIMITED POWER ASCENSION TO
MANAGE FW COPPER LEVELS MAXIMUM POWER LEVEL LIMITED
UNTIL AUGUST 15 DUE TO THERMAL LIMITS
,
JET PUMP NOZZLE INDICATION
- .
MONITORING SHOWS NO GROWTH
,
70 DAYS OF CONTINUOUS
OPERATION WITH NO G4DiGATIOh OF FUEL LEAKS
<
RECENT PLANT CONCERNS
07/24/89
_____________-___ _ _ _ _
,
..
.
,
RECENT 3 _Al\\ T CO \\ C E l\\ S
.
. FAILURE TO FOLLOW PROCEDURE VIOLATIONS
- MSRV REPLACEMENT
- HCU JUMPERS
- HCU BLOCK REMOVAL
- HEPA FILTER MONITORING
- RWP USE
- PLANT INCIDENTS
- ERROR RELATED TO PERFORMANCE OF SGTS CHARCOAL FILTER ST
- VALVING ERROR IN ESW/SW SUPPLY TO HPCI AND RCIC ROOM COLLERS
- VALVING ERROR IN OFFGAS SYSTEM ALLIGNMENT
- EXCEEDED 100 DEGREE / HOUR I
HEATUP RATE DURING U/1 START UP
- RADWASTE SHIPMENT VIOLATION 07/24/89 i
i
_ _ _ -
..
.
STEPS TAKE\\1 TO ANALYZE
~
CAUSE OF EVENTS ROOT CAUSE INVESTIGATION OF a
PROCEDURAL NON-COMPLIANCES j
PLANT DIVISION MANAGEMENT
PROBLEM ANALYSIS MEETING OPERATING SECTION PROBLEM
=
ANALYSIS MEETING CAUSES
=
- NOT ALLOWING ENOUGH TIME i
TO DO THE JOB RIGHT
- INFORMAL WORK PRACTICES
- NOT SUFFICIENT SUPERVISION INVOLVEMENT
- PROCEDURES INCOMPLETE OR INCONVENIENT 07/24/89
_ _ _ _ _ _ - _ - - _ _ _ - - _
-
_ - _
-
- - - - -
- -
-
--
- -
- -
-
,.
STEPS TAKEN TO
'
REVERSE TREND l
1 AWARENESS PROGRAMS
-
PROCEDURAL REVISIONS
SST CRITIQUE DURING TRAINING
OPERATORS ROUND TABLE REVIEW
.
. INCREASED MANAGEMENT
.
PRESENCE
.
- STATION SUPERVISORS MEETING SCHEDULED FOR THIS WEEK
- ADDITIONAL ACTIONS UNDER CONSIDERATION 07/24/89
____-___ ___- _ _
_ -
.
.
.
.
.
-
.
I STEPS bel \\G CO\\Sl]ElbJ TO REVERSE TRE\\ J SUPERVISION PLANT
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WALK AROUNDS SUPERVISOR OBSERVATION
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TRAINING EMPHASIZE STRICT
PROCEDURAL ADHERENCE l
ANALYSIS OF POTENTIAL
ADVERSE CONSEQUENCES
- IMPROVE COORDINATION OF SUPPORT FOR MAINTENANCE WORK 07/24/89 i
--
-
--
.
.
.'
'
EVEN-' INVESTIGATION PROCESS
.
DISCOVERY AND IDENTIFICATION WHAT i
- SIGNIFICANT PLANT EVENTS (SCRAM, FIRE, ACCIDENT,ETC.)
-SLER'S-UNEXPECTED / UNANTICIPATED RESULTS
- EQUIPMENT MALFUNCTION
- PERSONNEL ERROR
- QA/ISEG/OTHER OBSERVATION HOW
- 8:00 AM MORNING MEETING
- TRIPOD
- CLOSEOUT / STAFF MEETINGS
- DVX
- OEAP PROGRAM
- ENGINEERING SUPPORT (PROCEDURE WRITING, NCR'S, ETC.)
-
_ _ _
__
__
-
__
_
_ _ _ _
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_ _ _ _ _
._
_ _ _ _ _ _
._
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.
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.
PROCESS FLOWPATHS i
i
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..HPES
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-G P-18-PORC FEEDBACK FEEDBACK-BlWEEKLY PORC-OEE-TRENDING-NETWORK-ANALYSIS
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.. QUARTERLY
- - -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
._
_.
_ _ _ _ _ _ _ _
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,
.4-
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PIT ANALYSIS TOTAL S /15-P R ES E N T l-
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l EQUIPMENT PROBLEM /
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PROCEDURES.
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CONFIG. CONTROL
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162
TOTAL 5/15-PRESENT
.
______ _ _ -
- - -
- - -
- -
_
-
_ _ - -
-____
'
,.
'
.
TCA REDUCTION
- TEMPORARY CIRCUIT ALTERATIONS
- Electrical / Fluid /HVAC/ Control Systems
- A-42 Procedure
- " Lifted Leads" Log
- "TPA" at PBAPS
- Large Number-and Resulting Burden on OPERATIONS reduction effort
- Configuration Control
- Safety Concern
.
- ---_ --- _ -
,_
,
_
.
_
_ __ _. _ _.. _ _ _ _ _ _ - _ - _. _=_ _ _ _
_ _ - _ - _ - - __
_
l, t.
qc CURRENT STATUS
,
,
LIMERICK UNIT 1 & O TCA REDUCTION STATUS ~
226 (12/87)
\\
4-NUMBER OF TCA*S APPLIED'
l 4 00
'
-
I 'tNO l REFUELING
' OUTAG E
'
150 -
-
- - -
-
100-
- - - - -
- --
- - -
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.
10 07/10/89
.,iii,1 i i
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MB8 A M J J A S O N D J89 F M A M J J A S O N D MONTH ENDING-ACTUAL PROJECTED LIMERICK UNIT 2 TCA STATUS NUMBER OF TCA*S IN USE
40
- - - - -- -
- - - - -
-
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- - - - ~
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07/10/89
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WORKOFF EFFORT
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MODIFICATIONS-NED 92 MODS 107
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STATION 33 MODS-
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MAINTENANCE
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4 217 ABOUT 400. TCA'S ARE APPLIED AND REMOVED ANhUALLY TO SUPPORT BLOCKING OR TEMPORARY STATION OPERATIONS L
L J'-
- - - _ _ - - - - - _ - _ _ - _ _ -
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TCA PHILOSOPHY ABSOLUTELY NECESSARY
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SHIFT NIGHT ORDERS
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INTERIM MODIFICATION PROCESS
ALL CURRENT TCA'S HAVE REMOVAL
MILESTONES / MECHANISMS WHICH ARE BEING ACTIVELY PURSUED i
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- _ - - - - _ - - _
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Attachment C
Meeting Attendees NRC S. Collins, Deputy Director, Division of Reactor Projects (DRP)
R Bellamy,: Chief, Facilities Radiological Safety and Safeguards, Division of Radiation Safety and Safeguards (DRSS)-
J. Linville, Chief, Projects Branch No. 2, DRP P. Eapen, Chief, Special Test Programs Section, Engineering Branch, Division of Reactor Safety (DRS)
R. Conte, Chief, Boiling Water Reactor Section, DRS T. Kenny, Senior Resident Insp~ector,. Limerick M. Evans, Resident Inspector, Limerick
.PECo G. Leitch, Vice President - Limerick Generating Station M. McCormick, Plant Manager J. Muntz, Senior Engineer - Technical W. Ullrich, Project Manager-J. Spencer,- Superintendent of Maintenance l:
R. Dubiel, Superintendent of Services R. Krich, Licensing R. Lees, Nuclear Engineering S.-MacAinsh, Manager --Quality Assurance E. Firth, Superintendent of Training
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