IR 05000352/1989010
| ML20246C046 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 06/26/1989 |
| From: | Kenny T, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20246C039 | List: |
| References | |
| TASK-2.B.1, TASK-2.E.4.1, TASK-2.K.3.16, TASK-TM 50-352-89-10, 50-353-89-16, IEB-80-16, IEB-86-002, IEB-86-2, IEB-87-001, IEB-87-1, IEB-88-007, IEB-88-010, IEB-88-10, IEB-88-7, IEIN-87-004, IEIN-87-4, NUDOCS 8907100226 | |
| Download: ML20246C046 (39) | |
Text
{{#Wiki_filter:_ _ _ - _ _ _ - - _. __ _ _ _ _ _ __ _ '. . - ., U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report.No. 89-10 89-16 Docket.No.
50-352 50-353 License No.
NPF-39 CPPR-107 Category A/B Licensee: Philadelphia Electric Company Correspondence Control Desk P.O. Box 7520 Philadelphia, Pa 19101 Facility Name: Limerick Generating Station, Unit I and 2 Inspection Period: April 23, 1989 - May 28, 1989 Inspectors: T. J. Kenny, Senior Resident Inspector L. L. Scholl, Resident Inspector R. L. Fuhrmeister, Resident Inspector M. G. Evans, Resident Inspector J. H. Williams, Project Engineer C. H. Woodard, Reactor En ineer Reviewed by: ( ( c er rua J ams/ProjectEngineer flate / ' Approved by: / fnxtf gjf (2c fp Thomas J. K ' ? ~ A 'ti hief, Projects j' Da ty' Section / Summary: Routine daytime (381 hours) and backshift/ holiday (99 hours) inspections of Unit 1 and 2 by the resident inspectors consisting of (a) plant tours, (b) observations of mo'ntenance and surveillance testing, (c) review of LERs and periodic reports, (d) review of operational events and (e) system walldowns.
Areas Inspected: Resident safety inspection of the following areas: i operations, radiological controls, surveillance testing, maintenance, ' emergency preparedness, security, engineering / technical support, safety assessment / assurance of quality, review of licensee event reports and open item followup.
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_ - - _ _ _ - _. l l ~. . \\ . . . -2-Results: Unit 1.
This inspection period documents inspection from the completion of the refueling outage and the subsequent plant startup. An I area of concern is that of procedural compliance. Three examples of l failure of personnel to follow procedures were identified.
(Section ' 2.1.2) A walkdown of the residual heat removal service water system was also performed (Section 2.1.3).
Unit 2.
This inspection documents the review and closeout of open items including, NRC Bulletins, TMI Action Items and Temporary Instructions.
i l Various preoperational test results reviews were also accomplished as well as inspection of the receipt of Unit 2 fuel. An apparent violation, documented in inspecion report 89-202, is reviewed. The apparent violation discusses the discrepant conditions that had not been detected I by QA/QC inspections. A review of the inservice inspection of nozzle welds resulted in an unresolved item concerning future inspections l (Section 10.0).
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! DETAILS ? 1.0 P_ersons Contacted 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 2.1 Unit 1 (71707) 2.1.1 The inspector conducted routine entries into the protected areas of the plant, including the control room, reactor i enclosure, fuel floor, and drywell (when access is possible).
During the inspection, discussions were held with operators, technicians (HP & I&C), mechanics, secu ity 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.
2.1.2 Inspector Comments / Findings On May 3, 1989, the inspector, made an inspection of the Unit I drywell while the reactor coolant system was pressurized. The inspector expressed concern to security force supervisor over the delays which began as a denial of access.
The denial and delay was contrary to NRC requirements, the licensee's Security Plan and Administrative Procedures. The delay was caused by confusion over the proper authorization needed by an NRC inspector to gain access to the drywell. Both Security and Health Physics department provide procedures and controls to restrict entry into the drywell to only those persons with a good cause. The Security Plan specifically defines " facility personnel" as PEco and contrtctor employees and notes that certain NRC personnel are considered special visitors and shall be granteo unescorted access inaccordance with 10 CFR 19.14.
In addition, Administrative Procedure A35.1 " Security Access Control System", Revision 0, paragraph 5.8 states that NRC personnel with Q clearance are considered special visitors l and shall be granted unescorted access after completion of j site specific GET. The paragraph goes on to say that the l inspector should be granted immediate access to all areas of the plant he requests.
The inspector reviewed PP-022 " Operation of Posted Vital Area Portals" and Post Orders j for Drywell Door 306. The Post Orders stated that any ] l I
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3 - person not on the-Reactor Containment Access List be denied drywell access. The post orders have subsequently - been revised to allow prompt access for NRC inspectors
providing they have proper identification.
l \\ After gaining access to the drywell the inspector noted i that t.
] The overall housekeeping and hardware condition of I - the drywell and various components following the completion of most of the outage activities was very good. The reactor plant pressure was being { maintained at normal operating pressure per procedure l GP-10, 0_perational Hydrostatic Test.
Several valve j packing leaks were observed and had been pro,erly identified and tagged by the licensed utilizng equipment trouble tags. The maintenance department
subsequently performed maintenance to correct the j leaks.
On May 5, 1989, the operators manually isolated the control room ventilation system and entered the recirculation mode as per the toxic gas procedure, SE-2.
a A CO2 injection test in the cable spreading room had been f performed several days before. During this test the j normally sealed bottle of wintergreen, used to detect the CO2 was punctured and had not been replaced. A worker in
the cable spreading room noticed the smell of wintergreen and called the control room.
Several control room operators noticed the slight odor and entered SE-2, which specifies isolation of the control room ventilation system. About a minute after this was done, the operators realized the trapped CO2 in the control room was a worse case and decided to return the system from its isolation mode, in order to sweep any toxic gases out of the control j room instead of bottling them up.
There were no alarms on the toxic gas system and no discharge of CO2.
The
licensee replaced the opened wintergreen bottle with a ' sealed bottle, and made revisions to procedure SE-2 that incorporate the means to deal with toxic gases emanating from within the ventilation system instead of from without.
The licensee made an ENS notification.
. On May 12, 1989, during performance of the Main Turbine Control Valve Exercise and RPS Channel Functional Test, a j full RPS SCRAM signal was inadvertently generated. No i control rod motion occurred since they were in the fully inserted position. The SCRAM signal was caused by inserting a turbine trip signal when the turbine first
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__ _ __ _ _ _ _ _ _ _ _ _. - - _ _ _ - _ _ - - - _ _ _ _ . , - . , -5-stage pressure (less than 30% power) bypass circuit was defeated. The occurrence was due to a combination of procedural inadequacy and operator cognitive error. The procedure did not require bypassing the main turbine stop valve (MTSV) closure trip given the existing plant conditions, prior to tripping the turbine. However, the operator failed to recognize that a turbine trip with reactor power simulated to be greater than 30% would generate a SCRAM.
The licensee made an ENS notification.
Corrective actions will be reviewed in a future report upon receipt of the Licensee Event Report ( On May 13, 1989, the Reactor water cleanup system isolated while being placed in service due to a high differential flow signal. The possible cause was partial draining of the system when it was out of service.
The isolation was reset and the system was put in service by using the demineralized bypass valve HV-044-1F044 and the return valve HV-044-1F042 which filled and vented the system.
The licensee made an ENS notification.
At 10:24 a.m., on May 15, 1989, after a 124 day refueling outage, the licensee began pulling control rods to start up Unit 1.
The unit was critical at 6:00 p.m., and continued with the unit heat-up until at 1:45 a.m., on May 16, 1989, the licensee exceeded the Technical Specification allowable heat-up rate of 100F/hr by 13F. The licensee recognized the infraction and put a hold on the heat-up process in order to perform an analysis to determine the affect of the out-of-limit condition on the structural integrity of the Reactor Coolant System as required by Technical Specification 3.4.6.1.
The licensee completed the safety evaluation which indicated no structural damage had occurred. However, the report stated that one design heat-up cycle may have to be eliminated as a result of the excess heat-up rate (design allowance 117 cycles in the 40 year facility life).
The licensee then resumed the start up.
A ENS notification was made.
On May 15, 1989, while observing the unit start up, the inspector noticed the control room operators could not move Rod 14-43.
Upon investigation by the licensee it was identified that the isolation valves to the Hydraulic Control Unit (HCU) were still tagged in the closed position.
Subsequently it was identified that the reasons for the tags not being cleared, prior to start up, were as follows:
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- , _ . - . , -6- > One shift began c haring the tags that had been - placed during the outage for maintenance work on the rod drive system.
- When the second shift took over the tag removal task, the operator did not bring the blocking permit or facsimile into the area with him, rather the information had been transferred to a control rod drive map showing the location of the control rod drives.
The 'information was not transcribed properly in that rod 14-43 had been omitted.
This practice is not in accordance with A-41 " Procedure for Control of Plant Equipment" which requires the individual to sign off of tag removal in a " Sequence and Position of Restoration."
The restoration of equipment also requires - independent verification to insure proper restoration.
In this case, the verification was performed; however, the verifier used the same map as the individual who removed the tags. Again this is not in accordance with procedure A-41.
Later in the plant startup, the operators could not move rod 58-43.
Upon investigation a jumper, which disabled the directional control valve solenoid was found still in place following I&C maintenance. The reasons for the jumper not being removed were as follows: - The blocking permit, being used for maintenance, directed that the control rod be removed from service utilizing procedure S47.8.C " Removal of a Control Rod Drive and its Hydraulic Control Unit (HCU) from Service".
- Within procedure S47.8.C Step 8.2.2 states ! " Coordinate with I&C to install HCU
directional control valve jumpers per procedure RT-11-00-427 Procedure for Electronically Disarming Control Rods."
Procedure S47.8.C is PORC approved and - procedure RT-11-00-427 is not and is a hold over from research and testing.
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,. -7- ! I l Procedure RT-11-00-427 requires that a ! - Temporary Circuit Alteration (TCA) be . j written for the jumper installation.
This was not done because the operator performing.the blocking permit: (1) did not coordinate with I&C as per procedure because it had been determined that the jumper installation could be done by the- ) operator (2) beliend that only the PORCl approved procedure was in effect and therefore, did not go to the uther procedure as directed and (3) installed the jumper using a TCA.
Because the blocking permit did not specify - " returning the CRD/HCU to Service" S47.8.D.
the jumper was not removed.
Both of the above instances of failures to follow procedures constitute an apparent violation of Technical Specification 6.8.1 which requires that written procedures be established, implemented and maintained to control i various plant activities (50-352/89-10-01).
' The licensee has taken corrective actions regarding these events by issuing a summary of the events to all operations personnel for review and has begun a Human Performance Evaluation System (HPES) study in order to determine the root cause. Both control rod drives were eventually returned to service after corrective actions were taken by the licensee. The resident inspector will review the HPES when issued.
On May 18, 1989 the Reactor Core Isolation Cooling (RCIC) failed to achieve the Technical Specification (T.S.)
required 920 psig discharge pressure during surveillance testing. This was due to binding of the linkage between the servo solenoid and the turbine governor. The licensee , met the required T.S. action statement since the High ' Pressure Coolant Injection system was operable. The RCIC turbine control linkage was subsequently cleaned and lubricated resulting in a satisfactory retest.
During construction of Unit 1, 19 test valves were installed downstream of various excess flow check valves had were determined by the licensee to unsuited for tneir intended accident environmental s < ice conditions.
Tliis is due to the effects of radiation on the valves' V4 ton o-ring seal forming the pressure boundary between j the valve plug and body. The purpose of the test valve ' was to test the excess flow check valve in the instrument - - -__ - - - - _.-___ ___ ______- -___ -_-__ _ _ _ _ _ _ _ _ _ _
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.- -8- ) . l ' lines.
Based on an engineering evaluation, the Viton , j ' o-rings will remain ' functional for up to 8 hours under { accident conditions.
Consequently, it was determined to { remove and cap'39 test valves in processing / sensing lines ' which are required to be functional'for more than 8 hours after a Design Basis Accident (DBA). The test valves i failure under post-accident conditions could have affected { the safety related function of the associated instruments.
This event was reported via the ENS on May 24, 1989.' A subsequent review by the resident inspector noted that the reporting'of these valves was not done in a timely manner.
An investigation into the untimely reporting revealed the f following: February 8, 1989 A corrective action request (CAR) LC89006-413 was issued stating that the above valves were not on the as built drawings.
March 6, 1989 The Nuclear Engineering Department ' (NED) gave the site a use-as-is verbal disposition and Engineering Work Request (EWR) LOO 239 was written to document this acceptance.
April 27, 1939 During EWR approval, NDE determined that Environmental Qualification (E.Q.) problems may exist and issued a Non-Conformance Report (NCR).
April 28, 1989 NCR L89171-312 was written.
i Deportability Evaluation Form (REF) 89-04-25 was written by NED identifying the fact that non-ASME non-Q NUPRO valves were installed in ASME designated lines and were not installed to any design guideline, modification procedures or Q-considerations. The REF referenced EWR L-00239 and CAR LC89006-413 and stated an NCR was being written.
May 6, 1989 NCR L89174-312 was issued to address additional Non-Q "NUPRO valves".
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. May 12, 1989 '~ l ' The response from NCR L89171-312 was that NUPRO valves have been found to '- be acceptable for one additional ' operating cycle (18 months) provided ' that an inspection plan be implemented , , and that they be removed / replaced - during the third refuel outage.
May 16, 1989 The Regulatory group tracked down the NCR L89171-312 response and determined ' that the REF was closed as not reportable.
May 19, 1989 The regulatory group became aware of the 19 NUPRO valves being removed per NRC L89174-312.
The regulatory group was unaware of this NCR at this point.
May 22, 1989 The Regulatory Group determined that the event may be reportable and solicited I&C's assistance to determine the potential consequence.
May 24, 1989 ENS notification was made.
This event will be discussed further when the Licensee Event Report is issued by the licensee.
, On May 25, 1989, Breaker Relay, No. 81-BY24801, tripped on an under-Reac - , frequency signal for unknown reasons.
. caused a loss of rwr to RPS distribution panel No.The relay trip Treatment (SBGT) Systsu, fan and Nuclear Stea Shutoff System (NSSSS) Group 6 (Drywell Furge Valves) - isolation.
c.roup 6 valves were already closed.
The The NRC was notified via the ENS. systems were returned to n l. ] On May 26, 1989 RPS circuit breaker relay, No. 81-BY24801 tripped again.
finally replaced the relay.The licensee investigated the problem and - On May 28, 1989, during the restoration phase of ST-2-049-614-1 NS4 - Reactor Core Isolation Cooling Equipment Room Temperature - High, Division 3 Functional i Test, the I&C Technician did not remove the Volt-Ohm meter prior to returning keylock switch B21B-55C to normal.
This resulted in the isolation of the RCIC steam _.. _ _. _. . _ _ _. _ _ p N , .9 -
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, i i lE May 12, 1989 The response from NCR L89171-312 was { L that NUPRO valves have been found to ' l-be. acceptable for one additional.
! operating cycle (18 months) provided- 'I that an inspection plan be implemented j and that they be removed / replaced
, l during the third refuel outage.
/ \\ ' May 16, 1989 The Regulatory group tracked down the NCR L89171-312 response and determined that the REF was closed as not reportable.
.May 19, 1989 The regulatory group became aware of the 19 NUPRO valves being removed per NRC L89174-312. The regulatory' group was unaware of this NCR at this point.
May 22, 1989 The Regulatory Group determined that the event may be reportable and solicited I&C's assistance to determine the potential consequence.
May 24, 1989 ENS notification was made.
This event will be discussed further when the Licensee Event Report is issued by the licensee.
On May 25, 1989, Reactor Protection System (RPS) Circuit Breaker Relay, No. 81-BY24801, tripped on an under-frequency signal for unknown reasons. The relay trip caused a loss of power to RPS distribution panel No.
2BY160 which caused the start of the train B Standby Gas Treatment (SBGT) System fan and Nuclear Steam Supply Shutoff System (NSSSS) Group 6 (Drywell Purge Valves) isolation. Group 6 valves were already closed. The ~ systems were returned to normal after the relay was reset.
The NRC was notified via the ENS.
On May 26, 1989 RPS circuit breaker relay, No. 81-BY24801 i tripped again. The licensee investigated the problem and finally replaced the relay.
On May 28, 1989, during the restoration phase of ST-2-049-614-1 NS4 - Reactor Core Isolation Cooling Equipment Room Temperature - High, Division 3 Functional Test, the I&C Technician did not remove the Volt-Ohm meter prior to returning keylock switch B218-55C to normal. This resulted in the isolation of the RCIC steam _ - _ ______ _ - _ _ - _ _ - _ _ _ - _ _ - _ _ _ _ _ _ - _ _ - - _. .______ __
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. , -10- ! inlet isolation valve (HV-49-1F007) and a resultant turbine trip. The test equipment was then removed and the
isolation was reset. The RCIC steam inlet isolation valve was reopened and the turbine trip was reset at 06:30 a.m.
The licensee made an ENS report.
Subsequent investigation by the resident inspector identified that the test was being conducted using a controlling procedure located in the control room. The I&C technician in the main control room told the other technician to return the switch to normal and deviated from the procedure which stated that the test equipment should be removed prior to returning the switch to normal.
This is another instance of failure to follow procedures.
The licensee has disciplined the individual.
(50-352/89-10-01) l 2.1.3 Engineered Safety Feature (ESF) System Walkdown: (71710) The inses. tors verified the operability of the residual i Saat removal service water system by performing a walkdown of the system to confirm that system lineup procedures match plant drawings and the as-built configuration. This ESF system walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that instrumentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriate. The inspectors also utilized methods prescribed in a study prepared for the NRC by Brookhaven National Laboratory using the Limerick Probabilistic Risk Assessment (PRA).
The study, entitled PRA-Based System Inspection Plan, dated May 1986, provides inspection guidance by prioritizing plant safety systems with respect to their importance to risk. An abbreviated system checklist on Table 5-3 which identifies components that are considered to have a high contribution to risk as determined in the PRA, was also used.
The following procedures, drawings and tests were also reviewed: Drawing M-12 Residual Heat Removal Service Water Piping and Instrumentation Drawing l FSAR Section 9.2.3 Residual Heat Removal Service Water System i l _ _ _ _ _ _ _ _. _ _ _ _ . _ _ _ _ _ _ _ _ _ _
-_-_- _ _ --- .. ., ~. . , , -11-IV 12 Instrumentation Valve List S12.1.A RHR Service Water System Startup S12.2.A Shutdown of RHR Service Water Pumps and System S12.7.b Utilization of Cooling Tower or Spray Pond as a Heat Sink for RHRSW and ESW 0512.1.A (COL-1) Alignment for Normal Operation of Residual Heat Removal Service Water System - Loop A.
OS12.1A (COL-2) Alignment for Normal Operation of the Residual Heat Removal Service Water System - Loop B.
Procedure A-8 Locked Valve List The following items were identified to plant personnel who promptly corrected the deficiencies: - Root Valve RV-12-101 was not locked as required by nrccedure A-8.
Floor drains in the pits below the RHRSW pump - discharge piping had debris which could result in flooding of electrical junction boxes if a leak developed and drainage was not adequate, i Valve HV-12-032A packing gland nut did not have full - thread engagement.
i Otherwise, the system was found to be in good condition I and the inspector had no further questions concerning this system walkdown.
2.2 Unit 2 2.2.1 New Fuel Receipt Activities (60501) The inspector monitored the receipt, inspection, and handling of new fuel assemblies. The inspector reviewed the following related documentation, j ,
- Materials License SNM-1977 ' - Procedure M-071-053, " Unloading of New Fuel at New Fuel Storage Area" l l l
_ _ _ _ _ ! I '. . - , , -12-l l The inspector verified the capacity of the fork lift truck used to handle the boxes of fuel and that of the standby forkli f t.
The capacities of both were found to exceed the requirements of M-041-053.
The inspector observed the-security measures that were in place and determined that i they were in accordance with license conditions. Health Physics personnel performed proper radiation and cr<ntamination surveys, and reminded a driver that the new , l-fuel storage area is a no-smoking area when fuel is present.
The inspector noted that the. existing piles of fuel in the storage area were covered by plastic sheeting over a scaffolding framework. This is contrary to Condition 9 of SNM-1977 which requires "five-sided boxes
manufactured out of corrugated steel placed over each pile of fuel." The inspector pointed out this deficiency to PEco Technical Monitoring personnel, and was provided a copy of Corrective Action Request LM89-0413-01, which identified the deficiency on April 28,1989,(the inspector observed the condition on May 4, 1989). On May 6, 1989, metal enclosures were erected around the piles of fuel.
In addition, procedure M-041-053 was revised to include all requirements of SNM-1977. The revised procedure was signed, authorizing its use, on May 31, 1989. This violation is not being cited because the c iteria specified in Section V.G.1 of the Enforcement Policy were satisfied (NCV 50-353/89-16-01).
2.2.2 Startup Testing Activities (63050/70313) 2.2.2.1 Structural Integrity Test (SIT) 2A-59.2 The inspector witnessed portions of the Structural Integrity Test April 29, 30, and May 1, 1989, in concert with regional specialist inspectors. Valve lineups and other preparations for the test were independently verified.
Crack mapping areas were verified to be in conformance with the design specification.
Compressed air quality checks prior to pressurization were monitored with Bechtel Specification 8031-C-112.
Portions of the periodic crack mapping and containment displacement logging were observed, as were the full test pressure crack mapping and data logging, and maximum deflections were observed to be significantly less than predicted.
Difficulties were encountered in performing the drywell floor slab differential pressure (d/p) test due to r,umerous leaks on downcomer caps, and leakage on st veral main steam safety-relief valve discharge linrs.
,fter correcting leaks, the drywell floor slab J/p test was
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w . . .. . , -13-successfully completed on May 4, 1989. An FSAR change was drafted to describe the actual test and to allow pressurizing at a rate of 8 psi /hr on the retest. Access to the areas next to the containment wall was properly controlled during , l pressurization and peak pressure. hold time.
This l test is discussed.further 1,n Inspection Report l 50-353/89-18.
' 2.2.2.2 Integrated Leak Rate (ILRT) 2P-59.2 The. resident inspector witnessed the pressurization for the ILRT, conducted on May 6,1989.
Valve lineups were 1-dependently verified, pressurization ,. I rates were moni.ored, and leak location and isolation activities were monitored. This test will be reviewed in a futme inspection when the approved test results are available.
2.2.2.3 High Pressure Coolant lnjection Preoterational Test-The inspector reviewed the preoperational test results for the High Pres:ure Coolant Injection System (HPCI) 2P-52.1 Rev. O.
The test summary accurately reflected that the test was run in accordance with the procedure, and was properly controlled by test exceptions where warranted. All exceptions to the test were properly closed out by j alternate testing that was properly documented. The j inspector concluded that the intent of the test was accomplished and that at the completion of the . testing the HPCI system was operable.
The inspector had no questions regarding the review.
2.2.2.4 Fire Protection System Testing The licensee performed 2P.13.2 Rev. O. Fire Protection CO System for the cable spreading room.
The procedure stated that the test would be satisfactory if the concentration in the room remained 509s or greater (CO ) f r a peri d of one
4 hour.
However, one of the three instruments (3 ft.
above the floor, 6 ft. above the floor and 10 ft.
about the floor) did not hold at 5094 for one hour.
The instrument at 30 ft. sustained a reading of 50% for twenty-five minutes. The test was originally deemed a failure and a safety evaluation was ! performed (SFR 213C-003). As a result of the ' evaluation the test is considered acceptable for the following reasons:
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The NFPA 12 1958 Fire Code page 12-17 paragraph 2-4.1 states. "The quantity of carbon dioxide for deep-seated type fires is based on fairly tight enclosures. After the design concentra-tion is reached, the concentration shall be maintained for a substantial period of time, but not less than 20 minutes. Any possible leakage shall be given special consideration since no allowance is included in the basic flooding factors."
The lowest time held for greater than 50% concentration was 25 minutes.
2.
The procedure was written to satisfy the Fire Protection Evaluation Report (FPER) Section 2-B which stated that the C0 Storage tank has
sufficient capacity to maintain a 50% concentration in both Unit 1 and 2 cable spreading rocms simultaneously for a period of one hour and still have enough capacity to supply a hose station. The test showed: The combined 3 minute rapid discharge and 18 minute extended discharge into the Unit 2 Cable Spreading Room (CSR) used 4600 lbs.
of the 20,000 lbs. of CO in the tank. The
extended discharge is at a rate of 100 lbs./ min.
If the extended discharge were to continue for one hour, (60-18)x100=4200 lbs. additional CO w uld have been discharged.
Hence, a total of 4600+4200=8800 lbs. would have been discharged to one CSR, or double this (17,600 lbs.) to both CSR's over a one hour period. This would leave 2400 lbs. remaining in l the tank af ter a one hour discharge period.. Since a hose reel requires only 750 lbs. of CO
(150 lb/ min x 5 min), the 2400 lbs. remaining in the tank is adequate reserve for hose reel operation following the one hour discharge.
Hence, the test adequately demonstrated the tank ' capacity requirement specified in both the FSAR i I and FPER.
3.0 Update of Open Items (92701/92701) 3.1 Unit I a.
None i _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ -. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _. _ _ _ _ .- _ _ _ _ ___
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3.2 Unit 2 a.
(Closed) Inspector Follow Item 50-353/86-12-03. This item was opened when the inspector identified that supports and snubbers were not being adequately protected during grinding operations.
The licensee responded by conducting training for construction personnel and performing weekly walkdowns of all systems. The inspector reviewed the training records and weekly walkdown logs and considers this matter closed.
b.
(Closed) Unresolved Item 50-353/86-18-01. This item identified that the alert list was last revised in 1984. The inspector reviewed the following documentation.
j - PECo QA Finding Report 2N-537 Nuclear Quality Assurance Plan (NQAP) - Limerick Generating Station Quality Assurance Plan, Volume - III Bechtel letter BLP-41246, Dated September 1, 1987 - - Alert List Evaluated Suppliers List - Th' current revisions of the NQAP and Limerick QAP have dropped the reference to the Alert List for procurement. The current instructions direct one to the Evaluated Suppliers List and the Evaluated Vendors List, which are maintained by Nuclear Engineering. These lists are alphabetical, by name of Vendor / Supplier and include references to NRC bulletins, circulars, notices, and PECo significant deficiency reports.
The alert list was previously a Limerick project product used for reference at the site. Nuclear Quality Assurance (NQA) has recently proceduralized the alert list as a tool for their use, along with the Evaluated Suppliers List. NQA has updated the list to account for the NRC issuance since 1984 and performs updates quarterly.
This item is closed.
c.
(Closed) Violation 50-353/87-14-01.
FSAR requirements had not been incorporated into applicable design and installation documents. The licensee responded by letter dated January 6, 1988 which described corrective actions.
For the specific case cited in the violation, the licensee demonstrated that the installed components met the intended design function with no decrease in safety.
FSAR Licensing Document Change Notice (LDCN) FS-1239 was prepared to correct the description in the FSAR of the requirements for the off-skid portion of the emergency diesel auxiliary systems.
FS-1239 was initiated December 12, 1987 and the FSAR was revised June 1988 (Rev. 52).
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. _ - _ _ - _ _ - - . . . - , ., -16-The licensee reviewed the FSAR for inclusion of supplementary requirements. Those identified were examined to insure that the requirements were addressed. This review resulted in the following LDCN's: FS-1290 FS-1269 FS-1037 FS-1277 FS-1280 FS-1285 FS-1641 FS-1711 FS-1278 Finally, to help assure that omission of FSAR requirements will not occur again, the LDCN form was revised to require: - listing of new commitments - listing of design documents implementing new commitments indication of status of incorporating commitments into - design documents document Bechtel re-review of PEco comments.
- All appropriate .2 connal will be trained to use the newly revised LCCN forms. The inspector found that Bechtel had revised their f orm but PECo had not revised theirs.
In addition, Bechtel personnel had been trained on use of the new form. After discussion with the ' licensee, the PEco form was revised on May 26, 1989. The inspector will review training on the PECo form at a later date and considers the corrective actions taken to date to be sufficient to close this item.
d.
(Closed) Unresolved Item 50-353/88-202-01. Mechanical Fastener Discrepancies. This item related to concerns developed by the NRR team performing followup inspection of the Stone and Webster Engineering Corporation (SWEC) activities under the Independent Design and Construction Assessment (IDCA). The inspector reviewed completed PEco QA Finding Report 2N-638 and determined the following: - Residual Heal Removal (RHR) Heat Exchanger foundation bolting is sufficiently strong to withstand loading imposed if zero cleerances are assumed.
RHR heat exchanger supporting steel was originally - designed oversized in order to account for as then undefined pipe support loadings, which subsequently were determined to be an additional 1% over the original load.
-
_ - _ _ _ _ _ _. _ _ _ - _ _ - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ . _ - - ... , l , -17-AISC manual, 8th edition states that " tests have shown that - washers play only a minor role in distributing the pressure due to bolt tension, except where oversized or short slotted holes are used.
The manual further stated that "the use of flat circular washers is not required with 9325 bolts installed in standard holes."
Construction Mechanical Engineering personnel received - formal training to reemphasize thorough reviews of drawings and vendor manuals being required.
General Note 5 of Drawing C-626.
" Reactor Building - Equipment Foundation, specifies the use of two nuts for anchor bolts securing vibrating equipment, however, details showing specific equipment foundations may, or may not, call for double nuts.
For example, Detail 6 of drawing C-631, " Equipment Foundations", calls for double nuts for pumps 2A, 2B, and 2CP221, while detail 11 of the same drawing does not require double nuts for pumps 2A and 2BP223, indicating that jam nuts are not an across-the-board requirement.
- Bechtel Construction inspected all mechanical equipment in l the Reactor Enclosure and Diesel Generator Etclosures for conformance to equipment foundation details. Six items were found to be missing required washers and 13 items were found to be missing required jam nuts.
Nonconformance Reports or Balance of Plant Condition Reports, as applicable, were issued to document the conditions noted and to effect correction of those-conditions.
Work packages are not Quality Control documents, but - rather a means for Construction Engineering to provide information to the craftsmen in the field to assist them in performing their job.
The work package system was created in 1986 based upon lessons learned during the i completion of construction at Limerick 1.
- The conditions noted by the NRR team have been corrected or satisfactorily dispositioned and further work was performed by Bechtel to ensure that generic aspects were addressed and resolved.
This item is closed.
e.
(Closed) Unresolved Item 50-353/89-13-01. Mislabeled Temperature Recorder. The inspector reviewed PECo QA Finding !
_ - - _ _ _ _ _. ..... . .. 3 ' *' . -18-Report SN-641, and examined temperature recorder FR-56-2R605 on panel 200614 in the control room. The recorder has been relabeled to show the correct identification for the points being monitored. A review of preop test 2P-52.1 determined that the correct points were used. A review of preop test 2P-35.1 determined that no points from this recorder were used.
Reviewing 2P-49.1 determined that the mislabeling was not identified due to all the points being within a 2F band, and the Test Review Board decided no retesting is necessary.
This item is closed.
f.
(Closed) Unresolved Item 50-353/89-10-01. This item identified a concern that Preoperational Procedure 2P.59.2, Rev 0, Step '6.3(23) did not provide instructions or acceptance criteria listed in ANSI /ANS-56.8 nor did it provide means of documenting calibration data. The inspector reviewed Test Change Notice (TCN) Number 6, which incorporates calibration criteria given in ANSI /ANS-56.8 and provides for documenting calibration data.
This item is closed.
g.
(Closed) Unresolved Item 50-353/89-09-01.
Licensee to revise Startup Test Procedure STP-4.1, In Sequence Critical, to include limits on control rod withdrawal during initial criticality.
The licensee's changes to STP-4.1 were previously reviewed and found to be acceptable as documented in Inspection Report No.
50-353/89-12.
The item remained open pending final revitw of STP-4.1 by the Plant Operations Review Committee (PORC).
During this inspection, the inspector verified that the revised procedure was approved by the PORC on March 23, 1989 and the Plant Manager on March 27, 1989. This item is closed.
h.
(Closed) Unresolved Item 50-353/89-09-02.
Licensee to revise STP-70.0, Reactor Water Cleanup System, and review the overall Startup Test Program to ensure that all testing has proper administrative controls.
' The inspector previously reviewed and found acceptable the licensee's actions in response to this item (Inspection Report 50-353/89-12). The item remained open pending final review of STP-70.0 by the PORC. During this inspection, the inspector verified that the revised procedure was approved by the PORC on March 23, 1989 and the Plant Manager on March 27, 1989. This item is closed.
i.
(Closed) Unresolved Item 50-353/89-11-01.
Technical Specification - FSAR Inconsistencies.
Technical Specification Figure 3.2.1-4 shows a slightly lower number than FSAR Table _ _ _ - _ - - _ _ _ _
- - _ _ - - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - . l = < , "
< _19 6.3-4 for Maximum Average Planar Linear heat Generation Rate vs. Average Planar Exposure at 45,000 mwd /T.
Information supplied by PEco Engineering shows the FSAR table number was corrected in Revision 45, thus the technical specification figure includes more margin.
Instrument setpoints shown on Technical Specification Bases Figure B 3/4.3-1 differed from those shown in the FSAR. Table 15.0-2.
The Technical foecification numbers provided more margin than the FSAR numbers, w:ich were used as inputs to the accident analysis. This item is -losed.
j.
(Closed) Unresolved item 50-353/89-11-02.
High Pressure Coolant Injection System (HPCI) Pun,p Room Coolers Sizing. This item dealt with steam leakage into the HPCI pump room on a loss of the HPCI barometric condenser. This issue was reviewed by engineering and determined to be applicable to the Reactor Core Isolation Cooling System (RCIC) pump room as well. Analysis determined that with one cooler inoperable, the room temperature could rise to 12GF in the six hour postulated run of the HPCI or RCIC turbine with the barometric condenser failed.
This was determined to be acceptable, as all equipment in both the HPCI and RCIC pump rooms has been environmentally qualified to a temperature of 148F.
Licensing Document Change Notice (LDCN) LS-1730 has been issued to revise FSAR Section 9.4.2.2.1 to reflect the actual capabilities, and to change the design temperature of the HPCI and RCIC pump rooms to 120F. This item is closed.
k.
(Closed) Construction Deficiency 50-353/E3-00-11. Agastat Relays. The inspector reviewed the following documentation.
PECo letter notification to NRC of Significant Deficiency - (SDR) 107 dated December 28, 1983.
NRC Inspection Report 50-353/84-11 dated September 21, - 1984.
GE letter to PECo dated June 26, 1984 (approval to replace - Agastat GP relays with EGP relays).
PECo letter dated April 11, 1984 (evaluation and ' - replacement directions).
PECo Procedure FE20 - Procedure to Control Replacement of - Agastat Relays.
- PECo Startup Division letter dated May 17, 1989 confirming replacement of all relays The deficiency involved Agastat GP series relays which were unreliable and prone to malfunction. This deficiency was i mm___ _ _ _ _ _ _ _ __...__ _. _ _ _ _ ___.._ _ _____m_ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ ___.._ ____ -_
b.. .. ,
' .. -20-corrected by replacing these relays with Agastat EPG/ETR series relays in all Class IE applications. This item is closed.
1.
(Closed) Construction Deficiency Repo/t 50-353/88-00-10.
Defective Westinghouse motor starters.
This item identified defective insulation (sleeving) on flexible wire connecting the contacts to the field termination point. The sleeving was electrically conductive and resulted in a fire in the 250 volt DC motor control center during testing.
The inspector reviewed the following documents: Telecon Record of 10 CFR 50.55e Initial Report dated - October 20, 1988 PEco 10 CFR 50.55e report, S. S. Kowalski to W. T. Russell - dated December 2, 1988 Management Corrective Action Report 233422 - Bechtel Nonconformance Report 13649 - Bechtel Nonconformance Report 13686 - Purchase Order 18240-F2-22671 - The folla.,ing actions were taken to resolve this condition: All similar contactors were inspected on Unit 2 with a - total of four identified as having the incorrect-type of sleeving. Three of these were in the valve control circuitry for High Pressure Coolant Injection (HPCI) system motor operated valves and the fourth was a spare.
The defective wiring was rep 1Eced as documented by NCR 13686.
The defective pigtails were returned to the vendor.
Unit I contactors were inspected and no deficiencies were - identified.
- All spare contactors in the Unit I storage were inspected and found to be satisfactory.
(Closed) Construction D.yficiency 50-353/89-00-02.
Inadequate m.
degraded grid undervoltage relay setpoints. ihe inspector reviewed the following documentation.
- PEco Significant Deficiency Reports (SDR) L2-88-11, dated - initial telecon January 6,1989, interim February 7, 1989, final April 10, 198 _ - _ _ _ - _ _ - - - _ - - - +. , . .- , -21-PECo letter response to NRC request for calculations, ' - dated April 28, 1989.
PECo Undervoltage Calculations 6300E-23, Revision 3 dated - March 18, 1989 - PECo Modification Design Change Package (MDCP) 5972-2, Revision 0 dated March 21, 1989.
- NRC letter PECo-Technical Specification Changes to Reflect Revisions to Degraded Grid Undervoltage Relay setpoints (TAC 72712) including Safety Evalua' tion dated April 14, 1989.
This deficiency involved undervoltage relay setpoints which were inadequate to assure satisfactory voltages to Class 1E electrical equipment under degraded voltage power supply conditions. This deficiency was corrected by replacing the voltage sensing relays with more precise relays which permitted accurately setting their trip points at a higher voltage level and by raising the tap settings of the 4160/480 volt Class 1E transformers. This item is closed.
n.
(Closed) Construction. Deficiency 50-353/89-00-04.
Improper Installation of Temporary Support Brackets. The inspector reviewed the following documentation.
- PECo letter, Kowalski to Russell, dated March 10, 1989, "Significant Deficiency Report (SDR) L2-88-10" Memorandum OPS-0673, dated December 7, 1988, " Potential - Personal Injury / Equipment Damage" Startup Nonconformance Report (SNCR) 2049-125 - Procedure S92.8.A, " Installing / Removing 4KV Breakers" - The brackets in question were designed and fabricated by PECo to allow installation of safety barriers for personnel protection during maintenance and testing.
The barriers and support brackets were originally intended to be temporary installations.
It was determined that the support brackots were being left in place after completion of the work and removal of the barriers. All support brackets have now been removed from the Unit 2 switchgear.
Procedure 892.8A has been revised to include a step for verifying that the barrier support bracket is removed before installing the circuit breaker. This item is closed.
l l - - - _
- - - _ _- . q . . , -22-o.
(Closed) Construction Deficiency 50-353/87-00-05..Undervoltage l trips associated with transformer fault.
The inspector, ' reviewed the following docunantation: PECo telecon notifications to NRC dated December. 3 and 30, - 1987 of potential 10 CFR 50.55(e) significant deficiency.
- Bechtel letter BLP-42059 dated December 15, 1987.
- Bechtel Design Change Package (DCP) 2052 dated September 26, 1988.
- Startup work orders 217A-010, 217A-001, 217A-012 and
217A-041.
- Bechtel DCP 2052 Closure dated April 25, 1989.
- PECo DCP 2052 Startup Report dated May 3, 1989 i This deficiency involved a deficiency in the design of the i Class 1E electrical power systems which was revealed when a short circuit in a Unit 2 non-1E load center transformer caused a severe momentary (12 cycles) voltage dip (less than 60%) I I which propagated through the startup and auxiliary buses to the Unit 1 Class 1E 4160 and 480 volt buses.
The fault was l properly cleared by its 13kV feeder breaker - there were no ' coordination malfunctions.
However, since the 480 volt load i center circuit breakers were equipped with instantaneous undervoltage trip devices they tripped open.
Similarly AC contactors tripped open.
The licensee finds that a similar electrical fault in Unit I would cause similar problems in Unit 2.
This deficiency was corrected by replacing the instantaneous I undervoltage trip devices on selected Ciass IE 480 volt load ' center circuit breakers with time delay trip devices and by replacing AC powered contactor coli: with DC power contactor coils on selected AC contactors. Thi: item is closed.
, p.
(Closed) Construction Deficiency 50-353 E-00-01.
Diesel . Generator fuses is a reportable signif'. cant deficiency item in i , I accordance with 10 CFR 50.55(e).
This item involves the fact that a fire or fault in one of the EDG panels could disable control (ability to start and operate) of the EDG from either the control room panel or the remote control panel. This type of deficiency was identified by IE Information Notice 85-09 ano specifically addressed by Bechtel in their letter to PECo (BLP-40501) dated June 16, 1987.
i e _ - _ _ _. _.._
._ _ .. .
- ... . -23-l Based upon this information the EDG control circuits were modified to provide sep2 rate fused control circuits to prevent l L this type of failure.
The modification was completed in December 1987.
Subsequently (during an Appendix R review) the-item was.
l identified by PEco as being a reportable significant deficiency.
l Accordingly after the fact the item was reported by telecon and ' letter to NRC 'in January and February 1989 along with a commitment to provide a root cause analysis.
The item has been technically addressed and the work completed.
From a safety standpoint the item is closed.
q.
(Closed) Construction Deficiency 50-353/89-00-07.
This deficiency involves the replacement of cable entry seals on electrical enclosures to provide environmental qualification.
This same deficiency was reported for Unit I and the work was completed and accepted.
The same type replacements are currently underway for Unit 2.
The documentation and job in progress was reviewed. There were no discrepancies in the EQ or in the performance of the work observed.
This item is closed.
3.3 Response to NRC Bulletin 88-07, Supplement 1 " Power Oscillations in Boiling Water Reactors" In combined inspection report 50-352/89-09 and 50-353/89-15 the NRC reviewed licensee a'ctivities with respect to the subject bulletin and identified that the facility had not fully implemented the bulletin in their procedures in two areas.
The two areas were the use of periodic upscale and downscale LPRM alarms as evidenced of power oscillations and scramming of the reactor whenever power oscillations were evident in the region of potential power oscillation. The inspector reviewed the documents listed below and determined that the licensee had revised the procedures to include the two areas of concern.
Specifically, the facility procedures avoid the region of potential power oscillation during normal operations and during power reductions in response to plant _ _ _ _ - _ _ _ _ _ _ - _ _ - _ _ _ --
- _ - _ - - _ _ - _ - _ _- _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ .__. -.. _ _ _ _ _ ______._ _ -__- _ _ _ _ _ _ _. - ....
. , -24~ operational transients, include the LPRM alarms as evidence of power oscillations and direct manually scramming of the reactor if the region of potential power oscillations is entered and power oscillations occur. Training of the operators is accomplished by required reading in Shift Training Documentation " Core Hydraulic Instability Procedure Revisions".
Based on the above findings and the previous findings, this bulletin is closed for both Unit I and Unit 2.
List of Documents Reviewed: GP-2 Normal Plant Startup, Revision 22 dated 4/14/89.
j GP-3 Normal Plant Shutdown, Revision 19 dated 4/20/89.
GP-4 Rapid Plant Shutdown to Hot Shutdown, Revision 10 dated 4/14/89.
GP-5 Power' Operations, Revision 19 dated 4/14/89.
OT-100 Reactor Low Level, Revision 5 dated 6/2/89.
OT-102 Reactor High Pressure, Revision 3 dated 1/23/89.
OT-103 Main Steamline High Radiation, Revision 3 dated 4/27/89.
OT-104 Unexplained Reactivity Insertion, Revision 8 dated 4/14/89.
OT-112 Recirculation Pump Trip, Revision 7 dated 4/14/89.
ON-114 Loss of Stator Water Cooling Runback, Revision 5 dated 5/9/89.
RE-201 Reactor Maneuvering Shutdown Instructions, Revision 5.
3.4 Emergency Diesel Generator (EDG) Fuel Oil (FO) (TI 2515/100) For proper operation of the standby diesel generators, it is necessary to ensure the proper quality of the fuel oil. Appendix B to 10 CFR 50, as supplemented by~ Regulatory Guide (RG) 1.137, serves as an acceptable basis for licensees to maintain a program to ensure the quality of diesel generator (DG) fuel oil.
. _ _. _ - _,. _. -. -... _ - - - - - -
. _. ._ _ - _ - ____ - _____ .-. . . . , -25- -In response to recent industry problems, the NRC issued an NRC Information Notice on January 16, 1987 to alert licensee and NRC ,arsonnel of potentially significant problems pertaining to 1ing-term storage of fuel oil.
In addition, temporary inspection guidance was prepared to assess current licensee practices.
This inspection was performed to determine the licensee's program l i for the procurement, receipt, storage, handling and control of EDG ! Fuel Oil (FO) to ensure adequate quality, NRC Inspection Manual ' Temporary Instruction 2515/100 was used as a guideline in performing this inspection.
l Since the EDGs for Limerick Units 1 and 2 are identical including their fuel systems, fuel program, and procedures, this inspection applies to both units.
Observations and findings are the following: - Assurance of the proper FO requires purchasing the correct F0, then receipt inspection to verify that the F0 is proper prior to addition to the storage tanks.
Since F0 degrades with time and external sources contribute contamination, periodic l inspection is required to assure continued F0 quality.
The inspector determined that the licensee technical specification and purchase orders required the proper ASTM 0975 fuel oil for the EDG units.
F0 receipt inspection, in accordance with the technical specifications, requires verification of a portion of the ASTM D975 fuel parameters prior to adding new fuel to the tank with the remainder of the
fuel specification parameters determined by an outside ' laboratory within 31 days after fuel addition to the tanks.
Thereafter at least once each 31 days, tests are performed on the stored fuel in the tanks to verify that particulate are within the ASTM D975 F0 requirements.
Since new F0 is not know to be "in spec" for 31 days and ".out of spec" F0 would cause i l all EDGs with affected tanks to be inoperable, the licensee has a policy of adding new fuel to only one EDG tank for each unit l from a new load.
"Out of spec" F0 then would cause only one of the four EDGs to be inoperable wh ch would not in and of itself require plant shutdown.
However, in order to assure proper EDG new fuel offloading to only one tank, the licensee committed to converting the unwritten policy into a formal procedure.
IE Information Notice (IN) 87-04 documents EDG F0 starvation - event at another facility which involved fuel filter clogging sufficiently to shutdown the EDG. The licensee performed a design review and safety evaluation of the F0 system and implemented changes to make it less susceptible to clogging.
The inspector reviewed the licensee's internal documented _ _ _ _ _ _ _ _ _ - - _ _ _ - - _ _ _ _ _
- - __-_-_ .
.'... - . , -26-response to the IN, the design review and safety evaluation, and actions taken.
During long term' storage of EDG F0, oxidation of the fuel and-biological growth can occur. The resulting products can clog EDG filters.
Chemical F0 additives can be used to retard both oxidation and biological growth; however, the EDG manufacturer does not approve using these substances in the EDG fuel system.
Therefore, the licensee does not use additives.
In order to provide for the removal of F0 contaminants which could clog EDG filters, the licensee is planning the use of a portable skid-mounted F0 recirculation / filtration system.
This system will be used on a rotating basis for both Unit 1 and 2 F0 tanks.
Licensee monthly F0 analysis determined the amount of particulate contamination in the storage tanks.
During EDG operation F0 pressures and differential pressures are monitored for any evidence of F0 lines or filter fouling. These parameters are indicated and alarmed locally as well as remotely on a general alarm in the control room.
The F0 fil ers and strainers are cleaned / replaced on a schedule basis in accordance with procedures which incorporate the vendors recommendations.
The internals of the FO wye otrainers for each EDG were modified to prevent clogging. Tne filters are of the dual element display type which permits switching elements in the event of fouling te permit continuous EDG operation.
- Detection and correction of stored F0 contaminants which could cause the EDG units to become inoperable is vital to the licensee's F0 program.
The inspector determined that the licensee's sampling / analysis program procedures require at least monthly F0 tanks sampling i for water and particulate contamination.
Provisions are made ! for the immediate removal of water by draining or pumping. The itcense's procedures require the immediate replacement of F0 in a tank when it is determined to be "out of spec".
The inspector determined that the licensee had found "out of spec" fuel in the D13 EDG fuel tank in 1987. The tank was pumped out, cleaned and refilled all in less than a week. The licensee's technical specifications and procedures require cleaning F0 tanks at least every 10 years. The inspector determined that all of the tanks were last cleaned in accordance with this procedure in 1983.
Conclusions The licensee's EDG F0 program satisfactorily addresses all of the TI 2515/100 issues.
The licensee's F0 procedures are in accordance with { Regulatory Guide 1.137. Actions taken to minimize F0 filter clogging by procedures, filter modification, and by the addition of _ - _ _ _ _ _ _ _.. _ _
. _ _ - - ._- -_ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ... .. i ' .- .. -27-l i a portable F0 recirculation / filtration system represent improvements
in the F0 syste.m. By converting the new F0 offloading policy into a l formal procedure, the possibility of a common mode failure'of all-four EDG units from improper F0 is significantly reduced. This TI is closed for both Unit I and Unit 2.
l 3.6 (Closed) Bulletin 87-01 Pipe Wall Thinning ' This bulletin was written to instruct licensees to develop a program to perform inspections and monitoring of high energy line carbon steel piping for wall thinning in single phase and two phase systems.
Inspection Report 50-352/87-24 closed this bulletin for Unit 1; however, the two phase program was still in the development stage at the time. The inspector has reviewed the entire program for Units 1 and 2, which includes single and two phase systems and addresses the following: 1.
The scope and purpose of the program.
2.
Codes necessary to implement to program 3.
Responsible department for implementation of the program.
4.
Selectia criteria for the selection of inspection points.
I 5.
Frequency of inspection.
6.
Methods for inspection.
7.
Analysis of inspection results.
8.
Documentation of findings.
The inspector considers this bulletin closed for Units 1 and 2.
3,7 (Closed) Bulletin 80-16 Potential Misapplication of Rosemont Inc.
l Models 1151 and 1152 Pressure Transmitters With Either "A" or "D" Output Codes.
Rosemont Pressure Transmitter models with the "A" or "D" amp or calibration board installed, when submitted to excessive over or reverse pressures, could produce an ambiguous signal output from the transmitter to the control circuits which would result in an erroneous control. The licensee identified 59 transmitters with "A" or "D" boards and has either replaced the board, or replaced the entire transmitter with an 1153 model. The inspector has verified that the transmitters, of the type delineated in the bulletin, have been repaired or replaced. The inspector considers this bulletin closed for Unit 2.
! 3.8 (Closed) Bulletin (86-02) Static "0" Ring Differential Pressure l Switches.
This bulletin was previously reviewed in Inspection Report (IR) 50-353/88-18. The technical issues surrounding the bulletin were resolved at that time. The bulletin was left open pending review of the corporate tracking system.
PECo has determined that the
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _._
- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _.
. . _ _ _ _ -. _ _ _ _ - _. ,. ., - . , -28-bulletin was incorrectly entered into the computer-based tracking system as being not applicable to Limerick 2.
When this error was identified, it was corrected and the appropriate response submitted.
A review of the entire computerized tracking system was performed to verify that all other bulletins and circulars-received proper entry and timely responses.
Bulletin 86-02 was confirmed to be the sole exception. This item is closed for Unit 2.
, '
3.9 (Closed) Bulletin (88-10) Nonconforming Molded-Case Circuit Breakers.
The inspector reviewed the following documentation: NRC Letter, Kane to McNeill, dated January 10, 1989 - PECo Letter, Gallagher to USNRC, dated April 3,1989 - NRC letter, Frottier to Hunger, dated May 9,1989 - All circuit breakers being maintained as stored spares for Unit 2 have been verified traceable to the manufacturer.
The response has
been evaluated by the NRC staff and found to be in accordance with ! the bulletin requirements. This item is closed for Unit 2.
j 3.10 (Closed) Regional TI (352/R1-86-01; 353/R1-86-01) Standby Gas Treatment System (SGTS).
This regional. initiative was instituted due to the discovery that the SGTS at a BWR 3 was not designed single-failure proof. A cursory review of SGTS systems of plants of similar vintage showed.
marked differences in system designs. The particular failure mode was related to initiation of a fire suppression deluge system and the use of air-operated, fail-open dampers, combined with having all the station air compressors fed from non-Class IE electrical busses which would be shed on a LOCA initiation.
The SGTS dampers at Limerick use electro-hydraulic actuators which fail closed on a loss of power. The fire suppression deluge system at Limerick is j manually actuated by station operations personnel, if necessary, ' after receipt of high temperature alarms. The SGTS fans and filter trains are located in the control structure which also supplies the cooling air intake. This eliminates the possibility of the cooling flow providing an unfiltered release path. The Limerick SGTS does not exhibit the single failure susceptibility described in the TS.
This item is closed for both Units 1 and 2.
3.11 (Closed) Region TI (352/R1-86-02; 353/R1-86-02) Inspection of General Electric Type AK-F-2-25 Breakers.
This Region 1 TI was issued due to four failures of these breakers to open on demand at a single unit in 3 years. Three of the
_ _ _ _ - _ _ l ' i. p* g -
-29- ! failures were associated with the recirculation system motor generator (M-G) set field breakers. At the unit referenced, the M-G set field breaker is tripped to provide both the End of Cycle-Recirculation Pump Trip (EOC-RPT) and the ATWS-RPT.
Limerick uses 2 separate cit uit breakers to effect the ATWS trip. These l breakers are covered in the Technical Specifications (Section l-4.3.4.2). and are functional tested every 18 months and [ arc-suppression-time tested every 60 months. This item is closed I for both Units 1 and 2.
3.12 (Closed) Region TI (352/R1-86-03; 353/R1-86-03) Inspection of HGA Relays.
, This regional' initiative addressed a concern that HGA relays may be in use in safety-related circuits and that the relays may not be
seismically qualified (contact chatter occurred during seismic l testing performed by Wyle Laboratories).
The inspector reviewed memorandum 0C5-4052, Harding to Helker, dated August 3, 1988, which documents that GE HGA relays are not used in safety-related applications at Limerick. This item is closed for both Units 1 and 2.
l 3.13 Three Mile Island Action Plan Items (Unit 2) (Closed) II.E.4.1 Dedicated Hydrogen Penetrations a.
The NRC staff reviewed the design of the Limerick Combustible gas control system and found it to be acceptable, as documented in Section 6.2.5 of the Limerick Safety Evaluation Report (SER). The SER left, as a confirmatory issue, the verification of operational controls to ensure that initiating the hydrogen recombiner system will not provide a steam bypass path. The > inspector reviewed procedure 558.1.B Rev. 0 "Startup of a Containment Hydrogen Recombiner frcen Standby Condition or Following a Trip." Prerequisite 5.3 requires drywell pressure to be less than 22 psig before starting up the system.
In addition, precaution F.1 indicated that the system is not to be placed in service until after the reactor has been depressurized.
These conditions will preclude steam bypass through the recembiners from pressurizing the primary containment beyond design.
This item is closed.
t b.
(Closed) TMI Item II.K.3.16 Reduction of challenges and Failures of Relief Velves - Feasibility Study and System Modification.
This item required the licensee to investigate methods to reduce challenges to relief valves and implement desirable changes.
Safety relief valve failtae to reclose had been determined to be the most probable cause of a small-break -__ _-_____-- -
-_ _. _ - - '
- *
,, ' ' ... -30-L LOCA. The licensee endorsed the BWR owners Group response described in NE00-24951 and proposed to implement the following: (1) RPV water level isolation setpoint for MSIV closure is lowered from Level 2 to Level 1.
(2) Manually open SRV's as necessary.
(3) Reduce MSIV test frequency.
NRC found these measures acceptable and approved their implementation in the SER.
The inspector verified that the reactor pressure vessel low water level setpoint for MSIV closure is Level 1 (minus 129 inches). This setpoint was satisfactorily tested during the performance of preoperational test 2P59.1 " Containment Isolation and Nuclear Steam Supply Shutof f System." The inspector reviewed procedure T-101 "RPV Control" to verify the inclusion of manual control of the SRV's. MSIV test frequency is specified in the technical specifications and implemented in surveillance test procedure ST-6-041-200. The inspector had no further questions and this item is closed.
c.
(Closed) TMI Item II.B.1 Reactor Coolant System Vents This item required reactor coolant syste" and reactor vessel head high point vents operated from the.pntrol room.
Requirements for venting the reactor coilent system are discussed in sections 15.9.1 and 7.5.2.i nf the Limerick SER.
NRC approved the licensee's design which primarily utilizes the Automatic Depressurization System (ADS) in the SER.
The inspector verified the installation as shown on P&ID M-41,, Results of a test (2P-83.2) to demonstrate proper operation of the ADS was reviewed as well as procedure, for testing and maintaining the system.
Technical Specification 3/4.5.1 provides operability and testi,ng requirements.
In addition, tF-inspector reviewed Procedure T-116, RPV Flooding, which i 3vides directions to the operator for venting the reactor coolant system.
This procedure incorporates the following vent paths in addition to ADS: - SRV's - Main Steam to Turbine Bypass Main Steam Drains - - HPCI Steam Line via Turbine to Suppression Pool __ _ - - _ _ _.. -_ ._
. a - . .- - .. , -31-s - RCIC Steamline via Turbire to Suppression Pool - Head Vents No unacceptable conditiens were noted.
4.0 Surveillance /Special Test Observations (61726, 64704) Durirg 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 licensee approved procedures and NRC regulations.
The inspector also verified that instruments used were within calibration tolerances and that qualified technicians performed the surveillance.
The following surveillance were reviewed: Unit 1 ST-6-055-023-1 HPCI Pump, Valve and Flow Test ST-6-057-200-1 Containment Atmospheric Control Valve Test ST-3-107-790-1 Control Rod Scram Timing ST-3-097-355-1 Core Post-Alteration Verification ST-6-107-632-1 One Rod Out Interlock Verification Testing 4.1 Scram Time Testing The inspector observed portions of the control rod scram time testing on May 2, 1989 and reviewed the completed surveillance test.
Technical Specification 4.1.3.2, 4.1.3.3 and 4.1.3.4 require all contral rods to be scram time tested following core alterations.
ST-3-107-790-1, Control Rod Scram Timing, Revision 9, implements ' this requirement.
T,he inspector witnessed testing and operation of "SCRITS" (Scram Control Rod Initiation Timing System) from the control room.
Control rod over-travel was checked routinely when pulling rods.
The reactor operator also checked lights and alarms and verified the
selected rod scrammed and was at position 00.
Communications between the reactor operator and the optrator at the hydraulic control units (HCOs) were excellent. All scram times observed were well within the acceptance criteria.
Testing was also witnessed at the HCUs which was posted as a con-taminated area. The licensed reactor operator closed charging water valve 47-1-13, p~1 aced switches A and B on the HCU junction box in the test position and observed inlet and outlet scram valves open.
Switches A and B were returned to normal quickly to limit the amount of water passing to the scram discharge volume and radwaste. The operator observed the valves closed and also checked limit switch operation. The charging water valve was returned to the open - --
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Each HCU was checked for leaks during this test. One leak of about 4 drops per minute was found by the operator..The e inspector noted there was no unusual noise at the HCus such as chattering or AC hum on solenoid valves. All accumulators were charged to about 1050 psig.
After the testing was finished and the data analyzed, the inspector reviewed the completed test.
Except for one asterisked step, all procedural steps were completed satisfactorily.
Step 6.4.4 requires verification that all rods scrammed to positions 05 in less than or equal to 7 seconds.
This step was signed off as satisfactory when one control rod (30-15) could not be tested and therefore all rods did not meet the criteria. Section V of the Test Results section requires documenting unsatisfactory results, identifying corrective action and notifying management.
This section was not completed.
The concern was discussed with the licensee.
Based upon discussions, it was concluded that this was a unique case and not a general practice The licensee indicated that the appropriate , personnel were instructed on signing off procedural steps.
In ! addition, the procedure was revised to include a new step 6.6 which specifically states that all 185 control rods are required to be tested after core alteration.
' Except for the above, licensee personnel were knowledgeable, alert and thorough in performing this test.
4.2 Core Alteration Testing The inspector reviewed the following surveillance tests: ST-3-097-355-1, Core Post - Alteration Verification, completed March 30, 1989, and; ST-6-107-632-1, One Rod Out Interlock Verification Testing, completed May 7, 1989 Ge discussed these tests with licensee personnel. Quality Assurance monitoring r/ core alteration verification was also reviewed.
No concerns wa s 'dantified.
5.0 Maintenance Observations (62703) 5.1 Unit 1 i 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 on the repairs were in compliance with the licensee's QA program.
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. ., -33-i - 8904880 Rework RCIC Governor Linkage which included-disassembly and reassembly using work instruction 4730.
The retest of the RCIC turbine was- - sa ti s factory.
8882943 Preventative Maintenance Procedure for Crosby -- 8882940 Main Steam Turbine Cross Around Relief Valves. Set Pressure testing'PMp-001-012, Rev. O. for valves.
PSV-001-121C and 121A.
This' procedure was for . testing the lift set point and resetting it if necessary.
6.0 Review of a gnodic and Special Reports (90713) Upon receipt, the inspector reviewed licensee required periodic and special reports. The 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 - April, 1989 The inspector had no questions regarding this report.
7.0 LicenseeEventReportFollowup(90712,9270_0_) 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.
7.1 Unit 1 LER 89-022 and 89-022 Revision 1 reported two violations of electrical cable separation criteria. The initial separation violation was promptly corrected by wrapping the cable with an insulating material.
The second violation was found and corrected during followup cable separation inspections performed to determine if other similar conditions existed.
The inspector had no further questions concerning these events.
LER 89-023 reported that the existing suppression pool level and temperature instrumentation is not protected from fire damage such that these indications may not be available to support safe shutdown in the event of a fire.
Permanent plant modifications are planned from the third refueling outage to correct this condition.
Interim level and temperature measuring provisions are in place to support cycle two operations.
The Hcensee is performing & reevaluation of _ - _ _ _ _ - _ _ _ _ _ _ _. - _ _ _ _ - _ _ _ -
_ .-_-._ ______ _ . .- ,, . ., -34-the entire safe shutdown analysis. The NRC resident and Region I ( staff are reviewing the results of this evaluation and the adequacy of any compensatory measures and permanent corrective actions taken.
LER 89-024 reported an event in which a craftsman removed the packing from a valve other than the valve intended to be repacked.
This resulted in the leakage of approximately 25 gallons of reactor coolant from the valve. The leak was promptly isolated by plant operators and the packing was reinstalled. This occurrence was initially reviewed in NRC Inspection Report No. 50-352/89-09 Section 2.1.2.
Licensee corrective actions include: - Work package preparation instructions will be revised to ensure component location drawings are included.
- Incomplete (construction) valve markings have been removed from the affected valve.
- Updated craft personnel training to address the proper method of identifying components.
The inspectors had no further questions concerning this event.
LER 89-025 reported Emergency and Residual Heat Removal System Service Water Systems cable separation violations in safety related manholes. These violations have existed since initial Unit I construction and were due to a lack of inspection during facility turnover and inadequate separation criteria instructions in the manhole installation specification. All safety related manholes have been inspected and any discrepancies have been corrected. The inspectors have no further questions concerning this report.
LER 89-026 reported electrical cable separation criteria violations associated with the emergency diesel generators. The violation occurred during a plant modification which added non-Class IE wires associated with the exhaust stack heat trace circuitry lhe wires were subsequently wrapped to correct the installation and other modifications were reviewed with no additional deficiencies noted.
The construction procedures have been revised to ensure physical separation criteria inspections are performed during the modification process. The inspectors had no further questions.
LER 89-027 and Revision 1 reported a valve mispositioning which resulted in the loss of approximately 2 inches of reactor vessel level during 1) cal icak rate testing of a reactor water cleanup system valve.
The coolant inventory loss occurred when the test personnel attempted to drain the piping adjacent to the valve to be tested with the isolation valve in the open position instead of the closed position as required by the test procedure. The handwheel on the raispositioned valve has open/close direction arrows and was ! .-_._ __-_ - _ -
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. -35-installed backwards. This condition along with the position that the person was in relative to the valve when the valve position was verified, lead to the determination that the valve was closed when it in fact was open. The handwheel was subsequently installed correctly and this action, along with procedural clarifications and personnel training should preclude recurrence. The inspector had no further questions regarding this event.
LER 89-028 reported safety related instruments which did not have their temperature compensating heating elements connected.
The heating elements are utilized to maintain the electronics at a constant temperature thereby eliminating the effects of ambient temperature on the instrument accuracy. The vendor, Tavis Corporation, originally indicated that the heating circuits were not necessary to achieve the design accuracy; however, Tavis in a letter dated February 24, 1989 now indicated the circuits are required to be in operation. A review of the affected instruments indicated that this condition could have rendered the Reactor Enclosure Recirculation System inoperable.
The affected instruments were corrected by a plant modification during the second refueling outage, lhe inspector had no further questions concerning this report.
LER 88-029 reported a manual isolation of the Control Room Emergency Fresh Air System (CREFAS) due to a high toxic gas alarm. The toxic gas alarm was due to mineral spirits which were being used during painting near the gas. detector wb Nh causea a fclse upscale vinyl chloride indication. Additional controls on exterier painting have been instituted to prevent recurrence.
The inspector had no further questions regarding this report.
LER 89-502 This Safeguards Event Report reported the use of illegal drugs by contractor personnel. The involved employees have subsequently had their employment terminated.
The licensee has provided the information to this local law enforcement agency. The inspectors had no further questions, j 8.0 Unit 2 Power Ascension Test Program (PATP) (72400) Overall Power Ascension Test Program The inspector held discussions with the Startup Test Program Supervisor I and the Startup NSSS Test Supervisor and verified that as of l March 31, 1988, the 158 Startup Test Procedures (STPs) needed to implement the PATP had received formal station approvals. The inspector also reviewed the licensee's current staffing plans for the startup test organization and noted that adequate staffing levels existed for proper administration of the test program.
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.. -36-Training i The inspector witnessed portions of the simulator training provided for ' startup test personnel. The licensee utilizes the plant simulator to train test personnel on startup test procedure use.
In addition, the training is a method of familiarizing the control room operators with the startup test program since it is conducted during one day of the operators regularly scheduled requalification training.
Representatives of the QA Technical Monitoring organization also participate in the training.
The inspector witnessed training in the following procedures: STP-4.1, In Sequence Critical; STP-6.2, SRM Response to Control Rod Withdrawal; STP-6.3, SRM Non-Saturation Demonstration; STP-30.1, Recirculation System, One Pump Trip; and STP-27.4, Turbine Trip at TC6.
The use of the simulator appeared to be very useful for verification of the procedures and in providing training to both test personnel and control room operators concerning procedure use and expected plant performance.
Results of the testing for the Unit I startup were discussed in detail.
In addition, the training should be very useful for strengthening the working relationship between the startup test personnel and the control room operators.
The inspector also witnessed a portion of the licensee's classroom training on administrative procedures for the PATP.
Startup Test engineers from GE and Bechtel and representatives of the QA Technical Monitoring Organization participated in the training.
The inspector witnessed training on administrative procedures A-200, Startup Test Procedure Format and Content and A-203, Startup Test Program Personnel Training and Qualification. The training appeared to be a good method to y familiarize the startup test program personnel with the administrative requirements of the program.
No unacceptable conditions were noted. The inspector found the status of licensee's startup test procedures, staffing and training to be acceptable.
9.0 Emergency Planning (82701) On May 26, 1989, the resident inspector attended training sessions regarding emergency planning.
Specifically an extensive review of Emergency Plan was presented to Emergency Directors, Shift Superintendents, Shift Technical Advisors end Radiological Assessment Technicians.
During this training, the participants reviewed: EP-101 Classificati a f Emergencies EP-102 Unusual Event Response EP-103 Alert Response I EP-104 Site Emergency Response { EP-105 General Emergency Response i EP-317 Determination of Protection Action Requirements - _ _ _ _ - _ _ _ _ _ _ _. - - - _ _ _ - _ _ _ - - . _ _ _
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Upon completion of the review, the participants took a ten question examination which demonstrated their proficiency in the use of the above procedures. The participants were also examined to demonstrate their proficiency of fast breaking scenarios regarding emergency planning as related to certain plant accidents.
The inspector reviewed training documentation that had been administered to all shift personnel who are members of the emergency preparedness team.
p The inspector verified that all key personnel had received the above ' training, noting that three radiological assessment technicians had failed the exam. Two were subsequently retrained, one during the training session attended by the resident inspector, and passed the second examination. The third individual was from the corporate office and will receive the retraining at a later date.
The training session for all emergency response personnel, listed in the first paragraph of this section, satisfied the cone.itments of the licensees letter, written May 26, 1989 and, therefore, satisfies the immediate action of the letter.
The remaining commitments stated in the letter will be inspected as the licensee completes them. The inspector has no further questions at this time.
10.0 Mechanical Stre.ss Improvement of Limerick Unit 2 Nozzles During the week of April 18-21,.1989, the inspector reviewed the licensee's' activities regarding the Mechanical Stress Improvement Process (MSIP) which had been employed on sixteen Limerick 2 reactor vessel nozzle / safe end components in January and February 1989. The nozzles were identified as N5, N17 and N2. The purpose of the review was to l evaluate the licensee's assessment and disposition of ultrasonic indications found in the N2 nozzle safe end components after being subjected to MSIP.
MSIP is a mechanical (squeezing) process that does not employ heat but uses a hydraulically actuated mechanical clamp.
It is intended to produce a more favorable state of compressive residual stress on the inner surface of piping components in the vicinity of weldments in order to mitigate the propnsity of intergranular stress corrosion cracking (IGSCC) in austenitic stainless and nickel base alloys.
The process was developed by O'Donnell and Associates, Pittsburgh, Pennsylvania a'- l upproved for use by NRR in February 17, l'987 on the basis of a stu;y conducted by Argonne National Laboratory.
Positive test results were also generated by EPRI in October 1987. The EPRI study utilized a 28 l inch diameter type 316 stainless nuclear grade pipe and elbow mockup; the l Argonne study utilized 12 inch and 28 inch type 304 stainless steel l mockups.
In the case of Limerick 2, the MSIP was employed on the installed RV { nozzle / safe end/ piping components with the specific objective to impart i the compressive stress to the RV nozzle to safe end welds.
Two different _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ \\
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s , ' -38-grades of materials are used in the nozzle safe ends, SB 166 - alloy 600 (Inconel) fo-the N5 and N17 nozzles, and SA 182 - F316L (stainless) for . the N2 nozzles. The N2 recirculation inlet nozzles originally had SB 166 alloy 600 safe ends, but were modified in the field to incorporate type 316 stainless steel crevice free safe ends.
Both designs used combinations of Ni-Cr-Fe weld metal designated as INC0 82 or INCO'182.
After the MSIP operation, all welds were subjected to a second preservice ultrasonic inspection; the first inspection was performed prior to MSIP and revealed no rejectable indications. However, in the post MSIP examination, all ten 14 1/4" diameter N2 nozzles exhibited significant ultrasonic indications which, except for two nozzles (N2B and N2D), appeared to originate on the I.D. surface and extend through the wall to { a height of approximately 40s of the thickness. None of the N5 or N17 nozzles exhibited rejectable indicat bns, although minor scattered indications were observed.
In order to determine the origin of the UT indications, the licensee implemented a comprehensive metallurgical and NDE evaluation program l utilizing two mockups which closely resembled the Limerick H2 nozzles.
' The mockups were subjected to the MSIP followed by various NDE inspection's including UT, PT, VT and X-ray.
The mockups e2hibited i similar UT indications in terms of s(ze and location as the Limerick i nozzRs. No X-ray, PT or VT indications were observed.
The mockups were sectioned through the UT locations, examined metallographically, and the results were compared to pre-MSIP specimens. As verified by the inspector, the metallurgical samples showed no dHcernable evidence of defects or metallurgical anomalies which could be considered responsible for the UT indications.
In addition, the samples showed no apparent i evidence of work hardening or strain lines.
No significant differences in hardness were observed between the pre and post MSIP specimens. This is not surprising since the amount of the reduction as measured by OD , measurements is minimal.
In addition, the licensee reradiographed four i N2 nozzles by placing the film between the nozzle wall and the thermal sleeves. No significant indications were observed.
The inspector reviewed the MSIP experiences at Dresden and Brunswick sites and found no similar problems.
UT indications were found at Brunswick nozzle-safe ends, but were attributed to IGSCC that occurred inservice prior to MSIP; no significant indications were found at Dresden but these components were reported to be pipe to safe-end rather than RV components. The inspector agreed with the licensee's explanation that the UT indications in the N2 nozzles appears to stem from changes in the grain interfaces caused by the MSIP in a unique combination of materials , L present in the weldment (i.e., 316 SS, INCO 82 and 182, and remnants of
the original Inconel safe-ends) which was not the case with the N5 and i N17 nozzles. The inspector concluded that the licensee had provided adequate evidence that the MSIP had not damaged the RV nozzle-safe end components, but pointed out that future ISI tasks may require special techniques to evaluate UT indications which may develop in service as they may be affected. This item is unresolved pending licen:.ee ! ,
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developn'ent of ISI techniques which will enable the evaluation to clearly distinguish any new indication from those which presently exist.
(UNR
50-353/89-16-02).
11.0 Assurance of Quality (35502) 11.1 Unit 1 ) i During'the inspection period,' assurance nf quality was not evident 'in the area of adherance to procedures. On three occasions plant personnel failed to follow plant procedures resulting in mispositioned valves, failure to remove a temporary jumper and a system isolation.
(Section 2.1.2) These violations, along with that issued in Report 50-352/89-09, indicated that this problem is not unique to a particular plant department. Those errors which result in improper system restorations are of particular concern to the inspectors.
11.2 Unit 2 There appears to be a lack of responsiveness to Quality Assurance findings on the part of PECo middle management as exhibited by the fact that six days after PECo Technical Monitoring identified a license condition violation (See Section 2.2.1), corrective action apparently had not been taken as the inspector identified that the violation was still extant.
12.0 Unresolved Items Unresolved items are matters about which more information is required in order to cietermine whether it is an acceptable item or a violation. An unresolved item identified during this inspection is discussed in paragraph 10.0.
13.0 Exit Interview (30703) The NRC resident inspectors discussed the issues in this report throughout. the inspection period, and summarized the findings at an exit meeting held with the Plant Manager, Limerick Generating Station, on June 2, 1989. No written inspection material was provided to licensee representatives during the inspection period.
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