IR 05000387/1986014
| ML17146A589 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 09/24/1986 |
| From: | Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17146A585 | List: |
| References | |
| 50-387-86-14, 50-388-86-14, IEB-86-002, IEB-86-2, NUDOCS 8610220055 | |
| Download: ML17146A589 (24) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION l ~
REGION I
Report Nos.
50-387/86-14 50-388/86-14 Docket Nos.
50-387 CAT C
50-388 CAT C
License Nos.
NPF-22 Licensee:
Penns lvania Power and Li ht Com an 2 North Ninth Street Al 1 entown Penn s 1 vani a 18101 Facility Name:
Sus uehanna Steam Electric Station Inspection At:
Salem Townshi Penns lvania Inspection Conducted:
Jul
1986 Se tember
1986 Inspectors:
L.
R. Plisco, Senior Resident Inspector J. Stair, Resident Inspector L. Doerflein, Projec't Engineer R.
Fuhrm ist r, Reactor Engineer Approved By:
Strosnider, Chief, Reactor Projects Section 1B, DRP date Ins ection Summar
Areas Ins ected:
Routine resident inspection of plant operations, licensee events, IE Bulletin and Information Notice followup, open item followup, surveillance, ESF System Walkdown, and Unit 2 Refueling Outage Activities.
Results:
The inspector noted that the TIP probes are being left inside containment contrary to station procedures and GE recommendations (Detail 2. 1); and outage planning and preparations for the Unit 2 first refueling outage were comprehensive and the DCP's reviewed were thorough and complete (Detail 7.0).
One violation was identified in which the Technical Specification LCO concerning the TIP's containment isolation valves was not met.
(Detail 4.2.2).
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DETAILS 1.0 Followu on Previous Ins ection Items 1. 1 Closed Ins ector Followu Item 387/85-36-04
- Procedure SO-030-002 To Be Rewritten and Reissued as an SE Prior to Next Performance In January 1986, the inspector identified several discrepancies with the 18-month CREOASS operability surveillance procedure, S0-030-002.
The licensee was in the process of revising the procedure and reissuing it as a Technical Staff surveillance procedure (SE).
The inspector reviewed the revised procedure, SE-030-002, Revision 0,
18-Month Control Structure Ventilation System Operability Test, and verified that the discrepancies had been corrected.
1.2 Closed Ins ector Followu Item 387/85-36-05
- Followu of Discre ancies Noted Durin DCP Review In February 1985 the inspector identified several discrepancies during the review of Unit 1 Second Refueling Outage Design Change Packages (DCP).
In DCP 85-3097A, the new SLCS suction line did not include a temperature element (TE) such as was provided on the original common line.
In DCP 84-3088, the test procedures TP-149-026 and TP-149-027 established conditions outside the design envelope of analyzed valve performance.
In response to the first finding, the licensee reviewed the applicable design documents and the FSAR and
~de ermined that an additional TE was not required on the additional SLCS suction piping.
FSAR section 9.3.5.3 states that a low temperature alarm will annunciate in the control room if there is a loss of the suction piping heat tracing.
The licensee interprets this paragraph to refer to a total loss of heat tracing.
All of the heat trace circuits are energized from a common power supply.
Because of the amount of insulation on the suction piping and the operation of the tank heaters, it appears unlikely that the current TE could sense the loss of only one heat trace string.
In addition, the operability of each individual heat trace string is indicated at a
local panel which is monitored once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in accordance with Technical Specification 4. 1.5.
The inspector reviewed the engineering work request (EWR) MIS 86-0511 which resolved the issue and verified the survei llances were properly implemente In response to the second finding, test procedures TP-149-026 and TP-149-027 were revised to delete throttling of the F003A(B) valves when the F048A(B) valves were closed.
The revisions were issued before the test was performed.
The inspector reviewed the revised procedures.
1.3 Closed Ins ector Followu Item 387/86-06-02
0 en States Link Identified Durin the Performance of the HPCI Overs eed Test In April 1986, while performing a HPCI Overspeed Trip Test, I&C technicians identified open states links which defeated the low steam supply pressure isolation to HPCI.
The licensee initiated SOOR 1-86-109 to investigate the cause.
Unit 1 was in a refueling outage when the problem was identified, The inspector reviewed the results of the investigation performed by I&C and the Technical Staff.
I&C could not identify any testing that was performed during the outage that could have repositioned the states links.
In addition, I&C stated that surveillance testing that was scheduled later in the outage would have identified the open states links.
The Technical Staff also could not identify any testing that would have opened the states links, but stated that the 18-Month Logic System Functional Surveillance Test, scheduled later in the outage, would have identified the deficiency prior to declaring the system operable.
Based on previous states link problems, the licensee now performs a panel states link inspection, MT-GE-026, at the completion of the outage, and this inspection should have also identified the open links.
The inspector had no further concerns.
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciators was reviewed.
Nuclear Instrument panels and other reactor protection systems were examined.
Effluent monitor s were reviewed for indications of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability.
During entry to and egress from the protected area, the inspector observed access control, security boundary integrity, search activities, escorting and badging, and availability of radiation monitoring equipmen The inspector reviewed shift supervisor, plant control operator and nuclear plant operator logs covering the inspection period.
Sampling reviews were made of tagging requests, night orders, the bypass log, Significant Operating Occurrence Reports (SOORs),
and gA nonconformance reports.
The inspector observed several shift turnovers during the period.
On August 28, 1986, the inspector noted that the five Unit 1 TIP probes were inside containment at the indexers, with the associated containment isolation ball valves open.
The operators stated that the TIP operations had been completed the previous day.
The system operating procedure OP-178-001 states that when the detector position 0001 (indexer) is reached following use, allow approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> for the radiation level on the detectors to drop before withdrawing the detectors into the shield chambers.
As discussed further in Detail 4.2.2, the inspector has observed that the licensee routinely leaves the TIP probes inside containment while they are not being used.
The inspector noted that this is contrary to FSAR commitments and GE recommendations, and is a safety concern.
The inspector also noted that this routine practice indirectly contributed to a violation of a Technical Specification Limiting Condition for Operation (LCO)
concerning primary containment isolation valves as discussed in Detail 4.2g.
The inspector discussed the deficiency with the control room operators who immediately withdrew the probes after verifying that Reactor Engineering had completed using them.
The inspector also dis-cussed the problem with station management who stated that additional procedural steps were being drafted to prevent recurrence of this problem.
The correction of this concern is to be addressed by the licensee in response to the LCO violation.
2.2 Station Tours The inspector toured accessible areas of the plant including the con-trol room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, diesel generator building, ESWS pumphouse, and the plant perimeter.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identifie.3 ESF S stem Walkdown On August 14, 1986 the inspector independently verified the operability of the Unit 1 Core Spray System by performing a complete walkdown of the accessible portions of the system.
The engineered safety system status verification included the following:
Confirmation that the licensee's system check-off lists and operating procedure are consistent with the plant as-built drawings and as-built configuration.
Identification of equipment conditions and items that might degrade performance.
Verification of proper breaker positions at local electrical boards and indications on control boards.
Verification of properly valved in and functioning instrumentation.
Verification that valves were in proper position, power was available, and appropriate valves were locked.
The following references were utilized during this review:
Operating Procedure OP-151-001, Revision 6, Core Spray System, dated August 4, 1986.
Bechtel Drawing, M-152, Revision 23, Core Spray System GE Elementary Diagram, M1-E21-35, Core Spray System Checklist Procedure CL-151-0011, Revision 0, Unit 1 Core Spray System Checklist Procedure CL-151-0012, Revision 1, Unit 1 Core Spray System Checklist Procedure CL-151-0013, Revision 0, Unit 1 Core Spray System Checklist Procedure CL-151-0014, Revision 0, Unit 1 Core Spray System Checklist Procedure CL-151-0015, Revision 1, Unit 1 Core Spray System with attached PCAF 1-26-360, dated March 17, 1986.
FSAR Section 6.3 PP&L Design Description Manual, Chapter
Technical Specifications
.
The inspector determined that the system was properly aligned in accordance with the operating procedure and the equipment conditions indicated the components were well maintained.
No unacceptable conditions were identified.
3.0 Summar of 0 eratin Events 3.1 Unit
Unit 1 operated at or near full power.for most of the inspection period.
Scheduled power reductions were conducted throughout the period for control rod pattern. adjustments, surveillance testing, and scheduled maintenance.
3.2 Unit 2 At 7: 18 on July 17, Unit 2 was manually scrammed from 22 percent power in order to reach hot shutdown as required by Technical Specifications due to excessive reactor coolant system leakage into the drywell.
Following completion of repairs to the 'B'oop LPCI injection testable check valve (2F050B)
and the successful performance of a RCIC injection valve LLRT, the unit was started up and criticality was reached at 8: 13 a.m.
on July 21.
On July 25, the RCIC system was taken out of service to investigate steam blowing by the steam supply valve (2F045).
Steam was leaking enough to cause the RCIC turbine to roll at approximately 300 RPM.
The turbine was tripped and an LCO was declared.
The valve was subsequently repaired and the system declared operable on August 3, 3.3 At 4: 15 a.m.
on August 9, Unit 2 was manually scrammed to commence the first refueling outage.
The'nit reached Condition 4 at 10:52 p.m.
on August 10 and Condition 5 on August 12.
The core offload was completed on August 28.
Forced Outa e
Due to Unidentified Reactor Coolant S stem Leaka e
Unit 2 At 7:18 p.m.
on July 17, Unit 2 was manually scrammed from 22 percent power in order to reach hot shutdown as required by Technical Specification 3.4.3.2 due to excessive reactor coolant system (RCS) leakage into the drywell
~
Unidentified leakage exceeded the Technical Specification limit of 5 gallons per minute at 4:00 a.m.
on July 17 and attempts to identify and isolate the leak were unsuccessful.
The unit was in end-of-cycle coast down and reactor power was at 78 percent prior to reducing power at 2:00 p.m.
July 17 in preparation for shutting dow Starting at approximately 0.35 GPM the drywell unidentified leakage began to increase on July 11 and continued to increase until the, Technical Specification limit was exceeded on July 17.
In addition, the average drywell air temperature increased from 127 degrees F to 132 degrees F and containment particulate levels increased from 2E3 CPM to 2E5 CPM over the same period.
The licensee identified the increasing RCS leakage 'trend early and closely monitored the leakage rate increase and graphed the data points to detect any changes in the trends as various identification methods were performed.
Licensee review of operational occurrences prior to the leakage increase determined that the Main Steam Line Inboard Drain Valve (HV-241-F016)
may be a suspect valve since leakage and containment radiation levels increased shortly after the valve was stroked.
The valve was stroked again and temporarily backseated, but the leakage rate did not change.
On July 16, the off-normal procedure, ON-200-005, Excessive Drywell.Leakage Identification, was commenced but it was not successful in identifying the source of the leakage.
A drywell entry was performed on July 18 and the leakage source was identified as failed packing on the 'B'oop Low Pressure Coolant Injection testable check valve.
Repair s were completed on the valve on July 20 and a
RCIC injection valve LLRT was also successfully performed.
The unit started up and reached criticality at 8: 13 a.m.
on July 21.
4.0 Licensee Re orts 4.1 In-Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit 1
- 86-024, Automatic Start Relays for the Emergency Service Water Pumps Not Seismically qualified
"*86-025, Entry Into Technical Specification 3.0.3 to Perform Surveillance Testing 86-026, Available Weight of Sodium Pentaborate Less Than 5500 Pounds86-027, Entry Into LCO 3.0.3.
to Perform Surveillance Testing
86-028, Transfer of Bus 10 Loads to Bus 20 Due to 230KV Transmission Line Lightning Strike Unit 2
- 86-008, High Pressure Coolant Injection System Inoperable Due to a
Broken Control Valve 86-009, HPCI and RCIC Inoperable During Performance of a Surveillance
- 86-010, Manual Shutdown Due to Excessive Unidentified Drywell Leakage
"86-011, LCO Was Not Entered When a Primary Containment Isolation Valve Was Inoperable
~Further discussed in Detail 4.2.
"~Previously discussed in NRC Inspection Report 50-387/86-11; 50-388/86-11.
- "Further discussed in Detail 3.3 4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1), the inspector verified that the reporting requirements of 10 CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was adequately reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits.
The following findings relate to the LERs reviewed on site:
4.2.1 LER 86-024: Automatic Start Rela s for the Emer enc Service Water Pum s Not Seismicall uglified On June 2,
1986, a licensee design engineer identified by a nonconformance report, a discrepancy concerning the seismic qualification of the four Emergency Service Water automatic pump start relays.
An Engineering Work Request (EWR) was issued on June 9,
1986 to determine if the relays were seismically qualified as required by the FSAR.
The EWR was completed on July 3, 1986 and concluded that the relays were not seismically qualified.
A Wyle Laboratory test report stated that the General Electric HGA relays chattered during seismic tests.
Both Unit 1 and 2 were shutdown (Condition 4) when the seismic qualification was questioned.
The relays were replaced on June 12 with seismically qualified components, prior to restarting the unit During review of the LER, the inspector noted that the cause of the failure, and the associated corrective actions were not included in the LER.
Specifically, the cause for having the unqualified relays installed was not discussed.
The inspector discussed this discrepancy with the licensee,'ho stated a Supplemental LER would be submitted.
All of the other safety-related HGA relays were replaced by a modification performed during Unit 1 construction in 1981.
This replacement was performed based on the WYLE Laboratory test report and environmental qualification considerations.
For some, currently unknown, reason the ESW relays were not replaced at that time.
The licensee is still investigating the cause of the event.
LER 86-011:
Ino erable Traversin Incore Probe Containment Isolation Valve Unit 2 On July 16, 1986 at 4:25 p.m., the 'C'raversing Incore Probe (TIP) drive control unit on control room panel 2C607 was deenergized due to a burned out computer logic card.
During a reactor shutdown on the following day, July 17 at 7: 18 p.m., reactor vessel level reached the low level isolation setpoint of 13 inches (Level 3), but the 'C'IP did not withdraw from the indexer and the ball valve did not isolate as designed.
Licensee investigation identified that deenergizing the TIP drive control unit (DCU) drawer made the containment isolation function of the TIP inoper-able, since the probe was inserted into containment and could not be withdrawn.
During the shutdown the other
TIP machines functioned properly and isolated.
Upon identification that the TIP did not isolate, the appropriate Limiting Condition for Operation (LCO) was entered.
At 8:53 p.m.
on July 17, the 'C'IP was reenergized with a replacement logic card and the TIP withdrew from the indexer and the isolation valve closed.
When the TIP failed to isolate on July 17, a Significant Operating Occurrence Report (SOOR 2-86-103)
was initiated by the licensee to describe the event and resolve the associated issues.
During the SOOR review process, the event was determined to be reportable per
CFR 50,.73(a)(2)(i)(b) in that the unit operated in a condition prohibited by Technical Specifications.
On July 16, when the 'C'IP was deenergized, LCO 3.6.3 for Primary Containment Isolation Valves should have been entered, since the TIP could not be withdrawn automatically on an isolation signal.
Technical Specification LCO 3.6.3 states that with one or more of the primary containment
isolation valves inoperable, maintain at least one isola-tion valve operable in each affected penetration that i,s open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> restore the inoperable valve to operable status or isolate the penetration.
If this action cannot be completed, the unit is to be placed in hot shut-down within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Since the operators did not recognize that deenergizing the TIP drawer defeated the containment isolation function, the appropriate LCO was not entered and the action statement was not performed.
Since the TIP shear valves (explosive valves) were still operable the first portion of the action statement was satisfied, however the penetration was not isolated nor was the inoperative valve restored to operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
In addition, the unit should have been in hot shutdown by 8:25 a.m.
on July 17, but it was not shutdown until 7: 18 p.m.
on July 17 due to high RCS leakage (See* Detail 2.3).
The failure to meet the action statement of LCO 3.6.3 is a violation of Technical Specifications.
(388/86-14-01)
This violation of a Technical Specification LCO is of lesser significance due to the operability of the backup isolation function and available control room indication of the pene-tration status.
The TIP shear valve was operable throughout the event, and the containment isolation function could have been performed by control room operator action.
In addition, the penetration status was continuously monitored on a con-trol room front panel vindication, and would have alerted the operators to an abnormal condition if an isolation was required.
Previously, on May 12, 1986, control room operators detect-ed another burned out computer logic card in the 'A'IP drawer.
The TIP's were not in use, but they were again being stored in containment.
An operator cycled power to-the TIP panels and then attempted to withdraw all of the TIPs to the shield chambers.
All of the TIPs withdrew ex-cept for the 'A'IP, and the associated ball valves closed.
The appropriate LCO (3.6.3)
was then entered and repairs were performed on the drawer under Work Authorization WA V66509.
Isolation of the TIP drive guide tubes normally is accomplished by a solenoid-operated ball valve whenever the TIP cable and fission chamber are retracted.
Upon receipt of a containment isolation command, all of the TIP machines are put in automatic full speed withdrawal, removing the TIP detectors from the containment and allowing the ball valves to close.
.The detectors are
retracted until the chamber shield proximity switch is actuated, closing the ball valve.
An explosive shear valve is also provided as a backup to ensure integrity of the containment penetration in the event that the other isolation valve fails to close or the drive cable fails to retract if it should be extended in the guide tube during the time that containment isolation is required.
This valve is designed to shear the cable and seal the guide tube upon a manual actuation signal using a control room keylock switch.
The continuity of the shear valve squib circuits is monitored by indicator lights in the control room on a back panel (valve control monitor), where the normal condition is with the light not illuminated.
There is also a front panel indication for all of the valves in series, showing all open or all closed.
During this event, the 'C'IP cable was inserted into containment although the TIP was not in use.
FSAR Section 6.2.4.3.2. 11 states that the TIP drive cables are normally retracted except during calibration of the power range neutron detectors or an actual TIP mapping operation is in progress.
Operating Procedure OP-278-001, Traversing Incore Probe System, states that after performing TIP traces, to wait 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> to withdraw the probes in order to allow for the radiation levels to decrease.
In addition it provides a precaution to never turn the DCU mode switch off if the TIP detector is outside the shield chamber.
GE also recommends against the storage of the TIP detectors inside containment and the removal of DCU power in SIL's 57 and 166.
A previous occur rence was also identified in September 1983, as described in LER 83-138.
Although the TIP drive mechanisms were deenergized for a different reason (i.e.
ALARA concerns),
the appropriate LCO was not declared when the TIP ball valves were prevented from performing their containment isolation function.
In this case, the LCO action statement was not exceeded.
As corrective action, the licensee reviewed the event with the operators emphasizing the need to evaluate all work documents for Technical Specification impact.
Two specific areas of concern were identified during the inspectors review of this event which should be addressed in the licensee's response to the violation.
First, it appears that the routine practice of leaving the TIP probes inserted into containment for excessive periods of time is in direct conflict with the station operating procedures and the vendor recommendations.
(The inspector later identified the TIPs inserted into containment on
12; August 28, as discussed in Detail 2.1).
Secondly, additional procedure precautions, training and/or warning labels should be provided to the operator to make them more aware of the DCU power interface with the containment isolation functions.
The LER describing the event stated that to prevent recurrence, the procedure governing the use of the TIP system was to be revised to caution against deenergizing the TIP machine while the detector is inserted past the ball isolation valve.
In addition, placards are to be installed to alert the operator of the applicable Technical Specifications if a TIP system failure occurs.
Mith respect to the two burned out computer logic cards, the inspector noted that the licensee contacted the vendor.
The vendor was not aware of any generic problems with these logic cards and provided the licensee with some troubleshooting recommendations.
The inspector will continue to monitor licensee actions on this problem during subsequent inspections.
4.3 Review of Periodic and S ecial Re orts Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to determine that they included the required information; that test results and/or supporting information were consistent with design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems; and whether any information in the report should be classified as an abnormal occurre'nce
~
The following periodic and special report was reviewed:
Monthly Operating Report July 1986, dated August 11, 1986.
The above report was found acceptable.
5.0 Monthl Surveillance Observations The inspector observed the performance of surveillance tests to determine that: the surveillance test procedure conformed to technical specification requirements; administrative approvals.,and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriate-ly resolved; and the surveillance was completed at the required frequenc These observations included:
S0-024-001, Diesel Generator Monthly Operating Test, performed on August 14, 1986.
No unacceptable conditions were identified.
6.0 IE Bulletin and Information Notice Followu 6.1 IE Bulletin No. 86-02: Static-0-Rin Differential Pressure Switches IE Bulletin No. 86-02, "Static 'O'ing Differential Pressure Switches",
was issued on July 18, 1986 to request that licensees determine whether or not they have Series 102 or 103 differential pressure switches supplied by SOR, Incorporated, installed as electrical equipment important to safety.
In response to the bulletin, the licensee verified that there were no SOR Model 102 or 103 differential pressure switches installed as safety-related electrical equipment in either unit.
Fourteen SOR Model 103 switches were previously ordered for a planned modification but were not instal led.
All of the switches have been located, tagged, and segregated in the warehouse.
In addition, SOR Model 102 and 103 differential pressure switches were added to the licensee's defective device list to preclude any future procurement.
The licensee response to the bulletin was submitted on July 28, 1986 (PLA-2691).
7.0 Unit 2 First Refuelin Outa e and Modifications Review 7.1 Outa e Overview Briefin In the Systematic Assessment of Licensee Performance (SALP) Report No. 50-387/85-99; 50-388/85-99 dated July 15, 1985, NRC Region I management listed several recommendations concerning Outage Management and Modification Activities.
The report requested the licensee to meet with NRC Region I to discuss outage planning prior to refueling outages.
It also stated inspections would be conducted of engineering support effort at the corporate office prior to the refueling outages.
On July 21 23, 1986 an inspection of the design change and modification program was conducted at the site and the Allentown, Pennsylvania corporate offices.
A meeting was conducted on July 21 at the site to provide a general overview of the Unit 2 first refueling outage, the modifications to be installed, snubber inspection plans, Fifth Diesel Generator Project status, Limitorque MOV inspections, ISI program, and licensing commitment 'r A'
7.2 Im 1 ementation of Pl ant Modification Pro ram The the implementation of the Plant Modification Program was reviewed at corporate office to verify the following:
Changes were reviewed and approved in accordance with'0 CFR 50.59 and Technical Specifications, and the technical content of the safety evaluations was satisfactory.
As-built drawings were changed to accurately reflect the modification.
Independent design verification was adequately performed and documented.
Applicable documents were updated to reflect the modification (i.e. procedures, vendor manuals, Technical Specifications, and FSAR).
Adequate post-modification testing was identified to be performed.
Documentation of calculations and analyses were included or referenced in the modification package.
Adherence to PPEL NDI and EPM procedures.
The following Design Change Packages (DCPs) were reviewed and discussions were held with several of the responsible engineers:
DCP 83-0449A DCP 83-0669 DCP 84-3083 DCP 84-3114 OCP 85-3019 DCP 85-3062 OCP 85-3098A DCP 85-3134 DCP 85-3143 DCP 86-7017 RHR Throttle Valves Modification Piping RPS Channel Trip Indication Backup Scram Valve Power Monitor Circuit Degraded Grid Voltage Protection Test Connection for XV-B21-2F009 LCS High Leakage MSIV - Flow Timers ATWS Modifications SLC System RPV Mater Level Setpoint for MSIV Closure Feedwater LLRT Modification 250VDC Battery Charger Load Circuit All of the packages reviewed were determined to be complete and in accordance with the applicable procedures.
7.3 R
i tt*
.
The last guality Assurance Audit of the Plant Modification Program was reviewed to ascertain whether the-required audits are being performed and whether any significant deficiencies had been identified.
Audit 86-002 was conducted in January and February 1986 and concentrated on the installation, testing and closeout of modifications.
The audit identified two findings requiring corrective action.
Both findings identified anomalies with post modification testing activities.
Post modification testing was also the subject of two of the four observations.
The report stated that post modification testing is an area that needs attention by Plant Staff and NPE management to assure all necessary post modification testing is properly defined, conducted, documented and evaluated in order to ensure modified system operability.
This area has also been a concern to the NRC and is being tracked by open item 50-387/85-16-01.'.4 Review of Com leted Modification Packa es Completed DCP packages from the Unit 1 Second Refueling outage were reviewed to verify the following:
As built drawings changed to reflect the modification.
Operator training programs revised to reflect the design change.
Operating and surveillance procedure revisions performed and approved.
Adequate post modification testing conducted.
The following DCP's were reviewed:
DCP 84-3113 4KV Degraded Grid Voltage Protection DCP 82-0186 250VDC Battery Charger Load Circuit No unacceptable conditions were identified.
8.0 Unit 2 First Refuelin and Ins ection Outa e
8. 1 Refuelin Outa e Summar The Unit 2 First Refueling Outage began on August 9, 1986 when the unit was manually scrammed from 20 percent powe Fg
'L'
.
The unit reached cold shutdown on August 10, and entered Operational Condition 5 (Refueling)
on August 12.
The reactor vessel head was removed on August 13, and core offload started on August 16.
Defueling was.suspended on August 21 due to damage to the Unit 2 fuel mast.
Attempts to use the Unit 1 fuel mast proved futile due to previous damage sustained during the Unit 1 second refueling outage.
Fuel movements recommenced on August 25, following replacement with a fuel mast purchased from Philadelphia Electric Company, and core offload was completed on August 28, 1986.
An evaluation of the cause of the damage to the fuel masts is being performed by General Electric Company.
The results of this evaluation will be reviewed in a subsequent inspection (388/86-14-02).
Major outage work to date has consisted of work on RHR and Core Spray Divisions I and II, Local Leak Rate Testing, Containment Modifications, CRD Changeouts, HP Turbine refurbishment, and In-Service Inspections.
8.2 Refuelin Activities The inspectors monitored portions of the refueling activities to ascertain whether pre-refueling activities specified in the Technical Specifications were completed and whether refueling activities were conducted as required by Technical Specifications and approved procedures.
The observations included:
Verification that selected surveillance testing required by Technical Specifications was completed prior to fuel handling.
Verification that fuel handling activities were conducted in accordance with approved procedures (RE-081-032, Refueling Operations).
Verification that containment integrity was maintained.
Verification that good housekeeping was maintained in the refueling area.
Verification that staffing was in accordance with Technical Specifications.
Confirming that Technical Specification requirements and other pre-refueling requirements were scheduled in the master outage plan.
No unacceptable conditions were identifie.0 Safet Committee Activit
On July 23, 1986, the inspector attended a meeting of the Susquehanna Review Committee (SRC), which is the offsite safety review committee for Susquehanna.
The meeting was attended by all eleven members and consisted of presentations on various safety topics by members or other PP&L staff, followed by discussions by committee members.
Among the topics reviewed were:
1) recent plant scrams and other operational events, 2) safety review of the Unit 2 first refueling outage, 3) plant labeling program status, and 4)
ESW pump failures.
In the inspectors view, the topics reviewed were relevant and important to plant safety.
10.0 Alle ation Followu On August 21, a concern was received at the Region I office from a former contractor employee who stated that he had been fired for refusing to put on,a plastic "bubble suit" which had just been taken off by another worker.
Licensee health physics and management personnel were contacted to determine the potential for HP practice deficiencies.
The work areas in question were toured by the Resideat Inspector and a region-based inspector.
The work involved hydro-lasing of the cooling water sides of the main condenser and the Residual Heat Removal System heat exchangers.
It was determined that there were no radiological controls required since the work areas had been decontaminated and cleared for unrestricted access.
It was further determined that the "bubble suits" were being used as an aid to worker comfort.
The work involved water-lancing vertical U-tube heat exchangers and large quantities of water would typically cascade down on the worker.
The "bubble suits" were being used essentially as rain gear to help keep the water and entrained marine growth off the individuals performing the work.
No radiation safety concerns were identified.
i.
~Ei M
On September 8,
1986 the inspector discussed the findings of this inspection with station management.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to
CFR 2.790 restrictions.