IR 05000293/1993009
| ML20045E782 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 06/24/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20045E780 | List: |
| References | |
| 50-293-93-09, 50-293-93-9, NUDOCS 9307060036 | |
| Download: ML20045E782 (17) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.:
50-293 Report No.:
93-09 Licensee:
Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility:
Pilgrim Nuclear Power Station Location:
Plymouth, Massachusetts Dates:
April 27 - June 7,1993 Inspectors:
J. Macdonald, Senior Resident Inspector A. Cerne, Resident Inspector D. Kern, Resident Inspector J. Shedlo ky, Project Engineer Approved by:
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E. Kelly, Chief '
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Date Reactor Projects Sectioh-3 kopg:
Resident safety inspections in the areas of plant operations, maintenance and surveillance, engineering and technical support, and other support functions.
Initiatives selected for inspection included containment integrated leak rate testing, the snubber test program, and response to NRC Bulletin 93-02, " Debris Plugging of Emergency Core Cooling Suction Strainers."
Inspections were performed on backshifts during April 20-23,27, 28, May 4, 6, 7,10,11,14,18,19,24-27, and June 1-4,1993. " Deep" backshift inspections were performed on April 24 (10:00 am - 4:00 pm), April 29 (10:00 pm - 12:00 midnight), May 2 (4:00 am - 4:45 pm), May 4 (10:00 pm - 12:00 midnight),
May 18 (10:00 pm - 12:00 midnight), and May 19 (00:01 am - 1:00 am).
Findings:
Performance during this six week period is summarized in the Executive Summary. An unresolved item (93 09-01) was identified regarding mechanical snubbers with indeterminate rates of drag force change. A previous unresolved item concerning the as left configuration and weld procedures used during the removal of the reactor head spray system was closed (92-28-02).
9307060036 930625 PDR ADOCK 05000293 O
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u EXECUTIVE SUMMARY Pilgrim Inspection Report 93-09 Plant Operations: Safety systems responded as designed to the inadvertent lockout of the startup transformer during generator relay testing on May 19th. Preestablished plant conditions, including the N+1 (additional train) safety system availability concept implemented for the refueling outage, minimized the safety significance of this event. Operator recovery of offsite power was prompt and well controlled.
Radiological Controls: Radiological postings and surveys were properly maintained to support the changing radiological environment associated with outage activities. Of particular note was the close radiological coverage and detailed briefmgs provided to workers during refuel floor maintenance, as well as outstanding foreign material exclusion measures.
Maintenance and Surveillance: The primary containment integrated leak rate test was
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successfully completed at the conclusion of refueling outage No. 9.
Test procedures were detailed and work controls were excellent. On May 31, the unit auxiliary transformer tripped.
resulting in an automatic reactor scram. Troubleshooting to determine the root cause of the event was thorough, although the cause of the transformer protective relay actuation 'was indeterminant as of the end of the inspection period.
Security: Station security controls continued to be excellent during the refueling outage period, particularly in light of increased contractor activity.
Engineering and Technical Support: The technical disposition of a mechanical snubber regarding measured changes in drag force was not consistent with previously provided engineering guidance, although the snubber was eventually replaced. Engineering assessment of minor crack indications on the low pressure turbine axial keyways was thorough.
Safety Assessment and Quality Verification: Appropriate controls were applied in response to the potential for strainer clogging (NRC Bulletin 93-02), to ensure that fibrous material was not installed or stored within primary containment. Licensee event reports were detailed and of high quality. The licensee's Outage Safety Review Team (OSRT) conducted an independent
pre-outage assessment of decay heat removal system and electrical power supply availability, identifying high risk activities and developing contingency plans.
The results of the OSRT assessment were effectively conveyed to plant personnel in the format of a station procedure.
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SUMMARY OF FACILITY ACTIVITIES At the start of the report period Pilgrim Nuclear Power Station was in cold shutdown on the "B" loop of the residual heat removal system with refueling outage No. 9 in progress. Major outage activities, in addition to refueling, included maintenance on the "A" loop of the salt service water and emergency core cooling systems.
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Refueling was completed with reactor vessel head closure on May 12. On May 19 the startup transformer was inadvertently deenergized during planned maintenance.
Safety systems responded as designed, including a reactor protective system scram signal, actuation of the primary and secondary containment isolation systems, and automatic start of both emergency diesel generators. The startup transformer was promptly reenergized and safety systems were returned to normal. Reactor startup commenced on May 27 with criticality achieved at 2:04 pm on May 28. On May 30 the reactor core isolation cooling (RCIC) system was declared inoperable due to pump speed oscillations identified during the 1000 psig RCIC pump and valve operability surveillance.
On May 31, at 7:21 pm, the reactor automatically tripped from 25 percent of rated power due to an electrical fault that caused a main generator trip. All plant systems responded to the trip as designed. The reactor was restar.J on June 2. Tne main generator was synchronized to the offsite electrical distribution grid at 11:22 pm on June 3. The reactor was at approximately 50 l
percent of rated power with a thermal backwash of the main condenser in progress at the close
of this report period.
2.0 PLANT OPERATIONS (71707,40500,90712)
2.1 Plant Operations Review The inspector observed the safe conduct of plant operations (during regular and backshift hours)
in the following areas:
Control Room Fence Line Reactor Building (Protected Area)
Diesel Generator Building Turbine Building Switchgear Rooms Screen House Security Facilities Control room instruments were independently observed by NRC inspectors and found to be in correlation amongst channels, properly functioning and in conformance with Technical Specifications. Alarms received in the control room were reviewed and discussed with the operators; operators were found cognizant of control board and plant conditions. Control room and shift manning were in accordance with Technical Specification requirements. Posting and control of radiation contamination, and high radiation areas were appropriate. Workers complied with radiation work permits and appropriately used required personnel monitoring devices.
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Plant housekeeping, including the control of flammable and other hazardous materials, was
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adequate. During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication of equipment status. Records found to be appropriate included various operating logs, turnover sheets, tagout, and lifted lead and jumper logs.
2.2 Inadvertent Startup Transformer Lockout During Testing On May 19,1993 at 1:28 pm, an inadvertent lockout of the startup transformer (SUT) was experienced during testing that was being performed in the switchyard relay house. At the time of the SUT lockout, technicians were in the process of conducting station procedure 3.M.3-39,
" Turbine Generator Calibration of Relays, Lockout Test and Associated Annunciators." The specific section of the procedure being performed was intended to verify the functionality of the lockout relay (86X/MT) to the main transformer which was in an isolated condition (ring bus
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air circuit breakers ACB 104 and ACB 105 open). The performing technician verified the location of the main transformer lockout relay, then moved from the relay location to respond to the plant communications system which authorized operation of the relay. Upon return to the relay cabinets, the operator became disoriented and operated the startup transformer lockout relay (86X/ST) which caused the remaining two ring bus breakers, ACB 102 and ACB 103 to open. With all four ring bus circuit breakers open, normal offsite power was lost.
All plant systems responded to the loss of offsite power event as designed. The emergency diesel generators automatically started and assumed their associated safety related busses.
Although not called upon during the event, the station blackout diesel generator and the
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shutdown transformer (via the 23 KV offsite power supply) were available. The technician
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immediately recognized the wrong lockout relay had been actuated and notified the control room of the error. At 1:41 pm, ACB 102 and ACB 103 were reclosed, and operators began returning electrical busses to their normal power supplies. By 2:21 pm the diesel generators had been secured and the safety system temperature which was being maintained between 80-85 degrees F was essentially unchanged during the event. Because of the pre-established safety system controls, that included the N+1 (viz. more system trains than required by Technical Specifications) safety system availability concept, the event had minimal impact on plant safety.
The inspectors immediately responded to the control room following the event. Operators promptly identified actions to recover offsite power in an orderly manner.
After normal plant power was restored, the licensee convened event critique 93.9260 to gather information and identify contributors to the event. The inspector attended the critique, which r
was chaired by the Maintenance Section Manager. Although personnel error was clearly established as the cause of the event, the critique developed several factors that contributed to the occurrence. Specifically, the cabinets that contain the SUT and main transformer lockout relays are essentially identical, with the individual relays opposite from each other. Also, in
order to communicate via the plant communications system, the technician was required to move from the immediate location cf the lockout relays. Although the relays were properly labeled, the inspector considered that the combination of cabinets with mirror images and movement from
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the relay area in order to accomplish test communications, to have increased the probability of a personnel-induced error. The inspector considered these contributing factors to be both plausible and reasonable causes. Prior to reinitiating the lockout relay testing, personnel were briefed on the event, and retrained on the self verification process. The testing was subsequently completed satisfactorily. The inspector had no fudher questions on this event.
3.0 RADIOLOGICAL CONTROLS (71707)
The inspector reviewed radiological controls in place as well as the radiological conditions of
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selected areas of the plant.
Survey postings, radiological conditions and controls were appropriate with no discrepancies noted.
Radiological brieTmgs given at entry points to
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controlled areas within the reactor building were excellent. The inspector specifically noted radiological coverage and foreign material exclusion practices associated with refuel floor activities to be outstanding.
4.0 MAINTENANCE AND SURVEILLANCE (61726,62703,93702)
4.1 Primary Containment Integrated Leak Rate Test (70307,70313,70323)
The inspector reviewed the preparations for the primary containment integrated leak rate test (ILRT), observed portions of the test, and reviewed the preliminary test results. The test was conducted in accordance with station procedures 8.7.1.4.1,8.7.1.4.2 and 8. A.2. The inspector reviewed the test procedures for conformance with Technical Specifications 4.7. A.2.a,4.7.b.(4),
and 10 CFR Part 50, Appendix J.
Portions of the system alignment specified in procedure 8.7.1.4.1 were reviewed for establishing appropriate initial test conditions. The inspector verified selected valve alignments and tagging for conformance with procedure requirements.
Test preparations, procedure implementation, and test instrument calibration records were good.
During the test the inspector observed the work controls used by the licensee to ensure that the test was not influenced by other work in progress and that personnel safety was considered. The conduct of the test was reviewed during portions of the pressurization, leak rate test, and imposed leakage test verification phases. The test was started after a four hour stabilization period. Work controls throughout the evolution were excellent.
The test was successfully completed after accumulating ten hours of data; containment leakage was calculated as 0.1684 weight percent per day (wt%/ day) at the ninety-five percent upper confidence level. This was within the test acceptance criteria of 0.75 wt%/ day. At that time, the calculated leak rates were 0.0873 and 0.0835 wt%/ day by the total time and rnass point methods, respectively. The mass point leak rate at the ninety-five percent upper confidence level was 0.1021 wt%/ day.
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A test verification leak was established at a rate of 1.0106 wt%/ day for a five hour test duration.
At that time, the total time containment leak rate was calculated at 1.0934 wt%/ day. This compared favorably with the test acceptance verification criteria, upper and lower limits, of 1.3479 and 0.8479 wt%/ day, respectively.
The licensee was in the process of including corrections to the test results for water level changes and for Type C penetrations during the inspection. These corrections appeared to have a 3 mall effect on the test results. In accordance with 10 CFR 50, Appendix J, the licensee intends to submit a final test report to the NRC for evaluation. Initial test results were satisfactory, and the inspector 1.ad no further questions.
4.2 Testing the Unit Auxiliary Transformer A unit auxiliary transformer (UAT) protective relay tripped at 7:21 pm, on May 31, as station electrical distribution busses were being transferred from the start-up transformer.
The protective relay logie caused a generator lockout, turbine trip and automatic reactor scram. The plant had been at approximately 25% of rated power. At the time of the event, the licensee was in the process of transi ring the six 4160 volt electrical busses from the start-up transformer to the UAT, the preferred supply. The four non-safety busses (Al-A4) were transferred normally. However when the safeguards bus A5 circuit breaker from the start-up transformer was opened, the "C" electrical phase differential current relay actuated. The non-safety busses fast transferred to the startup transformer as designed, and the safeguards electrical bus A5 transferred to the shut-down transformer as designed. The other safeguards bus A6 remained powered by the start-up transformer. Plant cool-down was accomplished using the main condenser. Shutdown cooling was initiated at 2:52 am on June 1.
Both emergency diesel generators and the blackout diesel were available in stand-by service.
The licensee tested the UAT, the secondary 4160 volt cable to the station busses and examined the distribution breakers. The licensee also tested the transformer protective devices including the primary and secondary current transformers, the auxiliary current transformers and the
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differential current relays. As there were no deficiencies identified, the licensee decided to duplicate the switching transient with the main generator isolated phase bus links open. This wred closing the unit transformer 345 KV output breakers which then energized both the unit MJ c.uxiliary transformers. This arrangement allows an alternate feed to the station busses and is commonly accomplished during plant outages.
Test procedure, TP93-101, was written to control the operation which duplicated the switching transient. Safety evaluation No. 2765 was executed to support the test sequence. The test duplicated the bus transfers of Al through A5; all were successful, without protective relay trips.
Bus A5 was transferred, successfully, four times. Safeguards bus A6 remained powered from the start-up transformer as it had on May 31. The test initial conditions attempted to duplicate the 4160 volt distribution system loads.
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The inspector monitored troubleshooting activities, observed the safety committee review of the test procedure and its safety evaluation, and observed the testing. As previously stated, the 4160 volt bus transfers were successfully completed. During the test, licensee personnel and the inspector observed an unusually high circulating current of approximately 500 amperes between the UAT and the start-up transformer during the brief period when both supply breakers to safeguards bus A5 were closed. This current, while both brief and expected, can cause heating of the transformer but should have no effect upon the protective relays.
Nonetheless, engineering is evaluating alternative procedures to minimize the circulating current. Although the cause of the protective relay actuation was indeterminate at the end of the inspection period, the inspector concluded that the licensee's investigation was thorough.
5.0 SECURITY (71707)
Selected aspects of plant physical security were reviewed during regular and bt Shift hours to verify that controls were in accordance with the security plan and approved procedures. This review concluded that performance was acceptable and included the following security measures.
Security force staffing, vital and protected areas barrier integrity, maintenance ofisolation zones, behavioral observation, and implementation of access control including access authorization and
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badge issue, searches of personnel, packages and vehicles and escorting of visitors. Security force personnel continued to perform their duties in an alert manner throughout the outage period during which there was increasco contractor activity.
6.0 ENGINEERING AND TECIINICAL SUPPORT (71707)
6.1 Mechanical Snabber Functional Testing During the refueling outage, the licensee co-functional testing of six mechanical
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The testing was conducted in accorounce with station procedure 3.M.4-63,
" Functional Testing of Mechanical Snubbers," in order to demonstrate operability as required by Technical Specification 4.6.I.2. Snubbers are currently functionally tested using an Anchor Darling Series 25000 snubber test stand.
TN cmple population of snubbers were tested satisfactorily. However, due to a change in test ca nptnent from the previous functional test, the operability of a 10 thousand inch-pound (Kip)
snubber (SS-1-10-16) located on the "A" safety relief valve tailpipe was questioned. This was because the licensee could not verify that the drag force of the snubber had not increased by more than 50%since its last functional test, as required by Technical Specification 4.6.I.2.C.1.
Specifically, the snubber was previously tested using a load cell which did not provide either good repeatability or correlation to the Anchor Darling test stand. The previous :est with the load cell provided a drag force of 24.6 lbs; the current test with the Anchor Darling test stand provided a drag force of 95.2 lbs. The licensee issued nonconformance report (NCR) 93-80 to document this test discrepancy. The actual drag force of 95.2 lbs that was recorded during the l
current test was well within the design limitation of 200 lbs. for this snuMw
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The licensee concluded that, due to the change in snubber test equipment, drag force data could not be adequately correlated for the purpose of trending potential snubber performance
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degradation. Therefore, if either a drag force baseline has not been established or if the baseline data is not capable of correlation due to different test equipment or test methodologies, snubber
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operability would be determined per the remaining Technical Specification requirements.' Based upon this interpretation, the licensee concluded that the snubber was operable and dispositioned NCR 93-80 acceptable, as-is. A second NCR (NCR 93-91) was issued because the disposition of NCR 93-80 appeared to conflict with the corrective actions to a previous deficiency report, although it too was dispositioned acceptable, as-is.
In NRC Inspection Report 50-293/90-25, the inspector had addressed a previous issue regarding snubber visual inspections. During closure of that issue, the inspector reviewed a licensee-identified concern raised in QA Deficiency Report (DR 1896). The DR was issued because the drag force of a mechanical snubber had increased by more than 50%, but had been considered (in a separate NCR 90-37) to be acceptabic. In response to the DR, the engineering department indicated that NCRs will not be dispositioned acceptable as-is when snubber functional test results indicate that drag force has increased by more than 50% since the last functional test.
This position was intended to remain in place until the Technical Specification requirement was either revised or removed.
Inspector review of the issues regarding the drag force testing of snubber SS-1-10-16 concluded the licensee has established reasonable technical bases to establish snubber operability.
Additionally, the snubber was removed from service and replaced. Therefore, a current performance concern does not exist. Notwithstanding, it appears the licensee did not take the actions indicated in its earlier response to DR 1896. Further, the anticipated proposed change to Technical Specifications to revise or remove the 50% drag force change requirement has not been completed. The resolution of snubbers with indeterminate rates of change in drag force is therefore unresolved (93-09-01).
6.2 Turbine Generator - Low Pressure Turbine Inspections Since 1980, the licensee has been performing periodic ultrasonic (U.T.) inspections of the low pressure turbine shrunk-on wheel axial keyways for both the A and B low pressure turbines, similar to other licensees. The Pilgrim low pressure turbines are eight stage, double-flow, impulse turbines with the lowest pressure section being the eighth stage. The inspections were initiated following issuance of turbine vendor technical.information letters that detailed techniques to identify stress corrosion cracking.
Stress corrosion cracking is a common
phenomenon in low pressure turbines in nuclear power plant applications due to the saturated steam operating conditions that necessitate relatively large turbines. Until recently, turbine manufacturing processes required shrunk-on turbine manufacture rather than one piece forging.
During the recent refueling outage, U.T. inspections were performed on the A low pressure turbine (LPT). Previous U.T. inspections were performed on the this turbine during 1980, 1981, and 1987 outages. Throughout the licensee's inspections, various crack indications in the
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higher pressure stages of the turbine (fourth through sixth) had been identified. ~Several
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indications were detected on the seventh stage rotor and wheel keyway area during the current inspections. Four indications of 0.12 inches and one indication of 0.14 inches were measured in the keyway relief groove of the hub portion of the shrunk-on seventh stage wheel turbine side.
Additionally, a 0.14 inch indication was identified in the hub area and a non-measurable irdication was identified in the web area of the seventh stage wheel generator side. Although
not able to be measured, an average dimension of 0.25 inches for all non-measurable indications
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is conservatively assumed.
The licensee evaluated several analyses of the "A" LPT crack indications at the seventh stage wheel on the generator side. Recommendations included prewarming of the turbine during startups or unloading the seventh stage wheel. Subsequent deterministic analysis of(a) fracture appearance transition temperature, (b) fracture toughness variability, (c) prewarming, (d) crack growth rate, and (e) stress intensity models indicated that continued service of the turbine until the next refueling outage was acceptable. NRC Region I and NRR materials specialists reviewed the deterministic analysis and concluded, with reasonable assurance, that normal operation of the turbine through the current Pilgrim operating cycle presents no appreciable safety concern.
At the end of the current operating cycle, the licensee is expected to review turbine performance and take those actions necessary to ensure an acceptably low failure probability.-
6.3 Followup of Previously Identified Items 6.3.1 (Closed) Unresolved Item No. 92-28-02, Removal of Reactor IIcad Spray System Configuration Questions Through a review of a field revision notice (FRN 86-52B-196) to the plant design change (PDC)
removing the reactor head spray system at the Pilgrim Station (PNPS), the inspector had previously determined the adequacy of the current configuration of the abandoned piping and tl.e acceptability of these hardware changes relative to containment integrity. Certain questions were raised regarding the need to provide vent paths in the as-left, nonfunctional pipe sections and the applicability of specific ASME Code criteria used in the containment penetration weld qualification process. These issues remained open pending further licensee evaluation and the presentation of its analysis and results to the NRC on the specific questioned technical topics.
During this inspection, the inspector reviewed Problem Report 93-9005, supporting documentation, and a relevant Nuclear Engineering Division (NED) office memorandum that adequately addressed the questions and concerns identified in this open item and documented a-phn for corrective action, where necessary.
With regard to the question of whether the abandoned piping should be vented in accordance witn the design change criteria documented in section 3.d of the scope of modification of PDC 86-52B, Revision 1, the inspector was directed to the review of a note, dated January 21,1991, in the Design Criteria Specification. This note chrified the rationale for the elimination of the continued maintenance and testing of the valves in the abandoned piping by indicating that the
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capping of the containment penetration, rather than the venting of the pipe line, established the nonsafety utility of these valves, except for seismic Class "H over I" considerations. The
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inspector had previously examined the design analysis of the subject piping for dynamic loadings, including seismic, and had concluded that the proper assumptions and interactive considerations had been taken into account in the validation of existing pipe support adequacy.
Therefore, the installation instructions of FRN 86-52B-196 which specified the closure of those valves which would have provided the vent paths originally discussed in the PDC were found to be consistent with the subsequent note, indicating that venting was not a necessary design criterion.
In response to the other question involving the adequacy of wm/.ing procedures used in the installation of the pipe cap on containment penetration X-17, the inspector reviewed Problem Report 93-9005 and the corrective actions documented therein. The licensee analysis of the procedure for the welding of containment penetration boundary confirmed the fact that impact testing criteria had been inadvertently omitted from consideration, resulting in the use of an unqualified welding procedure.
However, the questionable procedure was subsequently determined to be fully supported by the Procedure Qualification Record (PQR) for a Similar Welding Procedure (WPS) which had been qualified with impact testing. The inspector checked that the licensee comparison of WPS variables included consideration of conservative heat input assumptions, and allowable weld or settings which would affect material impact properties.
Thus, in accordance with the ASME Code,Section IX, the same PQR which supports the impact-qualified WPS was used to qualify the suspect welding procedure.
This analysis substantiated the original operability evaluation, and "use-as-is" disposition of the identified nonconforming condition by establishing full compliance with the ASME Code for the subject primary containment boundary.
Despite the fact that no hardware repair or rework was required for the installed penetration X-17 weld cap, the licensee recognized that corrective actions are necessary to preclude problem recurrence and establish the appropriate guidance regarding the selection of the correct WPS to be used for the installation of any given weld. Accordingly, the inspector confirmed that Problem Report 93-9005 specified the need to revise certain NED specifications and PNPS procedures. A change request has already been initiated to revise an NED procedure to include welding considerations in the design input. The inspector considered this measure, along with the other proposed corrective actions addressing procedural accuracy, to be both appropriate to the root cause of the identified deficiency as well as commensurate with the significance of preventing future welding material and qualification problems.
The inspector identified no actual conditions adverse to quality in the installed piping and containment penetration material. The inspector also verified that the licensee's response to the technical issues adequately addresses ASME C(xic and design criteria, and determined that no further questions or concerns exist in this area. Therefore, this unresolved item is considered closed.
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7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (92701)
7.1 Licensee Event Report (LER) Review e
LER 92-17
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LER 92-17, " Primary Containment Isolation System Group 2 and Group 3 Actuations During Reactor Protection System (RPS) Power Supply Shift," dated January 13, 1993, describes the December 14,1992 inadvertent deenergization of both RPS electrical buses that occurred with the reactor shut down and all contro rods fully inserted. During a planned transfer of the "A" RPS bus to its alternate power supply, a non-licensed operator inadvertently operated an incorrect breaker which deenergized the "B" RPS bus after the normal supply breaker to the "A" RPS bus had been opened. Safety system response included Group 2,-3 and 6 primary containment isolations and initiation of the reactor building isolation and standby gas treatment systems.
The cause of the event was the failure by a non-licensed operator to properly verify breaker identification during performance of the power transfer. Operators promptly restored power to the RPS busses, and returned the affected safety systems to their standby condition. The event was of little safety significance as the reactor was shutdown, with all control rods fully inserted.
Corrective actions were appropriate. This LER accurately described the event, in detail, and appropriately addressed the reporting criteria.
e LER 92-18 LER 92-18, " Reactor Scram and closing of Main Steam Isolation Valves Due to Trip Settings of Main Steam Radiation Monitors," dated January 18,1993, describes the December 20,1992 automatic reactor protecdon system (RPS) trip from 75 percent reactor power. The trip resulted from the improper adjustment of main steam line high radiation protective setpoints to values below those specified by procedure. The root cause was technician inattention to work detail when adjusting protective setpoints. Human performance factors, including setpoint notation (decimal versus scientific), contributed to the event which was previously documented in NRC Inspection Report 50-293/92-28. This LER appropriately addressed all reporting criteria.
- LER 93-01 LER 93-01, ".High Pressure Coolant Injection (HPCI) System Declared Inoperable Due to No Flow Indication During Surveillance," dated February 25,1993, describes the January 26 failure of the HPCI pump flow indicator during a monthly operability surveillance test. All other HPCI system parameters responded normally during the test. The licensee declared HPCI inoperable, based on inability to measure pump flow at the controlling station. As documented in NRC Inspection Report 50-293/93-03, the cause of the failure was a blown fuse in the flow controller circuit. The fuse was replaced and the HPCI system was satisfactorily retested and returned to service on January 26.
The most probable fuse failure mechanism was exposure to an
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overcurrent surge. The existing slow blow fuse is designed to accept two times its rated current for 12 seconds at 77 degrees F.
The HPCI flow controller requires removal for periodic calibration and is therefore exposed to periodic current surges. The manufacturer indicated that -
the fuse would degrade over time if surge currents in excess of the fuse specifications occurred.
Long-term corrective actions include an engineering evaluation of this fuse application to preclude recurrent failure.
The blown fuse did not prevent automatic HPCI initiation or operation and posed no threat to
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public health and safety. The LER accurately described the causal analysis of the HPCI pump flow indication failure, and documented all followup corrective actions.
- LER 93-02 LER 93-02, " Reactor Core Isolation Cooling (RCIC) System Declared Inoperable During Surveillance Testing Due to Valve Position Indication and Overload Alarm", dated March 29, 1993, describes the February 25 failure of the RCIC turbine steam supply valve (MO 1301-61)
to fully open during a routine surveillance test. The valve bonnet chamber and stem galled and bound tightly during an open valve stroke, which caused the motor operator to fail. The cause of the galling was minimal clearance between the stem and bonnet chamber combined with the effects of thermal expansion associated with the operating environment of the valve. The valve, which was installed during the November 1992 midcycle maintenance outage, had been recently redesigned to incorporate a " smart stem." This design incorporates a machined-in sensor to support improved accuracy during motor operated valve thrust testing. Clearances between the valve stem and the bonnet chamber were verified to be within specified manufacturing tolerances. Engineering review concluded that the stem-to-bonnet clearance should beincreased.
Initial corrective actions included motor replacement and overhaul of the MO 1301-61 operator; machining of the bonnet chamber and valve stem to provide a greater clearance; and, diagnostic rctest of the valve. Repairs were completed and the RCIC system was returned to service on February 28. An improved valve bonnet chamber / backseat assembly was redesigned and installed during this reporting period to prevent recurrence of the failure an' improve overall d
system reliability.
The high pressure coolant injection system was verified operable in accordance with Pilgrim Technical Specil. cations during the period that RCIC was inoperable.
The inspector had no further questions regarding this LER.
- LER 93-03 LER 93-03, " Settings of Reactor Water Cleanup (RWCU) High Flow Sensors Found Out of Tolerance During Surveillance", dated March 29,1993, describes the March I failure of both RWCU high flow sensors to satisfy technical specification settings. The function of the high flow sensors is to initiate an isolation signal upon sensing high RWCU flow during a system rupture.
Both sensors, DPIS-1243 and DPIS-1244, were found set above the maximum permitted value of 300 percent rated flow during a routine surveillance test. The RWCU high temperature sensors, which also function to generate a protective Group 6 primary containment
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isolation signal in the event of a RWCU system piping rupture, remained operable. The cause of the improper flow sensor settings was setpoint drift. The flow sensors were promptly calibrated and retested to verify the repeatability of the correct trip settings.
System engineers had previously identified the flow sensor drift problem in 1990 and initiated an engineering service request (ESR 90-527) to evaluate the problem.
However, in the evaluation process ESR 90-527 was inappropriately associated with the solution to a separate RWCU system ESR and was prematurely closed out. Problem report (PR) 93-9057 was initiated in March 1993 to address the RWCU flow sensor drift described in this LER. The inspector independently confirms that corrective actions had been assigned and were properly tracked within the PR system.
The inspector reviewed DPIS-1243 and DPIS-1244 calibration data for the past two years and determined that previous mechanical alignment of sensor linkages to address setpoint drift had been ineffective. The licensee intends to install an upgraded replacement instrument during refueling outage No.10 if pending efforts to replace instrument contact switches does not correct the setpoint drift problem. Additional corrective action includes evaluation of the adequacy of the existing setpoints as impacted by instrument accuracy. Improved accuracy would support establishment of a higher trip setpoint and provide a greater margin between normal operating system flow and the isolation setpoint. This in turn would reduce the probability ofinadvertent isolation durir g minor pressure transients which have been experienced when placing the RWCU system in service.
The inspector concluded that corrective actions to PR 93-9057 were appropriate and properly tracked. The LER properly addressed all reporting criteria.
7.2 Protection of Reactor Decay Heat Removal Systems (2515/113)
The inspector reviewed the licensee's policies and practices to safeguard the plant decay heat removal systems and their electrical power supplies during the refueling outage. The licensee established an Outage Safety Review Team of four persons to independently review the scheduled outage activities prior to the outage and to identify conditions where equipment availability was less than that established by procedure 1.2.2, " Administrative Operations Requirements". These requirements are more restrictive than those of the Operating License Technical Specifications.
The licensee examined specific plant evo'utions and maintenance activities to determine their impact on the availability of systems and components relied upon for decay heat removal, reactor coolant inventory, on-site and off-site electrical power sources and distribution, reactivity control, secondary containment and ventilation. The inspector reviewed the analysis for conditions that were a departure from the defense in depth specified by station administrative requirements. In each case, the licensee identified high risk activities scheduled during that period, and established requirements to minimize the : Jety impact of those evolutions.
Contingency plans were established along with estimated quipment restoration times. The specific issues and compensatory measures for this refueling outage were published in station procedure TP93-042.
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i The inspector observed the licensee's practices for instructing their personnel during the outage.
The overall status of decay heat removal, emergency core cooling and electrical power systems was clearly identified by plant management during daily planning meetings. Protected equipment was also defined. This information was also promulgated to station personnel on entrance-way status boards. Plant personnel interviewed understood the established process for maintaining acceptable levels of safety system availability. The inspector also reviewed the licensee's planning and contingencies for evolutions which interrupted decay heat removal.
The interruptions were necessary to allow local leak rate testing of shutdown cooling pump suction containment isolation valves, and also to disassemble the "C" Salt Service Water pump discharge piping for inspection while the B-6, 480 volt safeguards electrical bus was ce-energized for
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preventive maintenance.
The inspector found triat an appropriate level of management attention was focused on the planning and conduct of these evolutions. The planning was detailed and clearly communicated to staff. An example of such contingencies was staging of emergency power supply cables.
7.3 Plant Training e
Water Level Instrumentation Errors During and After Depressurization Transients (TI 2515/119)
The inspector evaluated training and guidance to ensure operator actions in the event of i
discrepancies in indicated reactor water level are consistent with current plant Emergency Operating Procedures (EOPs). During this inspection, a simulator scenario was observed that resulted in gradual failure of the reactor water level instrumentation. EOPs led the operators into initiating appropriate depressurization and reactor vessel flooding from this condition. The scenario was not complicated by an anticipated transient without scram (ATWS). However, the EOPs and a scenario that was complicated by an ATWS, were reviewed to ensure that depressurization and reactor vessel flooding were required on failure of all reactor vessel water level instrumentation.
The safety parameter display system (SPDS)is now functional in the plant simulator, and models reactor vessel water level failures and icvel indication similar to that available to the operators in the plant. This modeling included the color changes that accompany pre-determined water level indication differences. Operators were knowledgeable of the operations of the SPDS and the significance of the information displayed.
The inspector reviewed the instructional modules for the continuing training (requalification)
program that covered the Nuclear Boiler Instrumentation (NBI), and EOPs -16 and -26. The modules appear clear and unambiguous, and address the areas of concern with respect to reactor vessel water levelindication problems experienced at Pilgrim. The training of the operators with respect to this issue was also previously documented in NRC Inspection Report 50-293/92-17.
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j 7.4 NRC Bulletin 93-02
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On May 11,1993, the NRC issued Bulletin 93-02, " Debris Plugging of Emergency Core Cooling Suction Strainers," that identified the potential for fibrous air filters or other temporary sources of fibrous material, that are installed or stored in primary containment, to clog emergency core cooling system (ECCS) suction strainers during a loss of coolant accident. The bulletin requested licensees to 1) identify fibrous air filters or other temporary fibrous air filters or other temporary fibrous materials installed or stored in primary containment,2) take any immediate corrective measures which may be necessary to assure functional capability of the ECCS, and 3) take prompt action to remove any such material. The bulletin further requested that for plants currently in a shutdown condition, such material be removed prior to restart.
The licensee uses temporary fibrous filters in the drywell (primary containment) to maintain the cleanliness of the cooling coils of unit coolers during outages when the drywell is expected to be open for more than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. Station procedure 3.M.4-59, "Drywell Unit Cooler Roughing Filter Installation and Removal," establishes the controls for the use of the temporary filters.
Temporary components of fibrous material are not stored within the drywell. Station procedure 3.M.1-38, " Primary Containment Closcout," was revised to confirm all temporary fibrous material is removed prior to final drywell closcout. The inspector reviewed these procedures and concluded adequate controls exist to ensure the temporary filters are removed from the drywell at the conclusion of plant outages.
P The plant was shutdown in a refueling outage when the bulletin was issued. The licensee conducted a visual inspection of the torus and the drywell-to-torus vent pipe and vent header.
No fibrous material was identified. On May 27,1993, the inspector accompanied the Operations Section Manager during the final drywell closecut inspection at the conclusion of the refueling outage. The filters were verified to have been removed from the unit coolers and the drywell.
Additionally, the overall cleanliness of the drywell was good, with no loose material or equipment observed. On June 7,1993, the licensee submitted their written response to the
bulletin. BECo letter 93-73 accurately described station practice with the use of temporary fibrous materials in the drywell, and appropriately addressed the actions requested by the bulletin. The inspector had no further questions with respect to this subject.
8.0 NRC MANAGEMENT MEETINGS AND OTHER ACTIVITIES (30702)
l 8.1 Routine Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss licensee activities and areas of concern to the inspectors. At the conclusion of the reporting period, the resident inspector staff conducted an exit meeting on June 14, with licensee management summarizing the preliminary findings. No proprietary information was identified as being included in the report.
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8.2 Other NRC Activities On April 26-30, an NRC Region I electrical specialist conducted an inspection to followup issues -
identified during a previous NRC Instrumentation and Control Setpoint team inspection (50-293/91-201). Inspection results will be documented in NRC Inspection Report 50-293/93-08.
On May 3-7, three NRC Region I inspectors conducted an inservice testing program inspection.
Inspection results will be documented in NRC Inspection Report 50-293/93-07.
On May 10-14, an NRC Region I radiation protection specialist conducted an inspection of outage radiological controls and practices. Inspection results will be documented in NRC Inspection Report 50-293/93-12.
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