IR 05000387/1989031
| ML17156B563 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 12/21/1989 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17156B562 | List: |
| References | |
| 50-387-89-31, 50-388-89-29, NUDOCS 9001080263 | |
| Download: ML17156B563 (18) | |
Text
Report Nos.
License Nos.
Licensee:
Facility Name:
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION I
50-387/89-31; 50-388/89-29 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Al 1 entown, Pennsylvania 18101 Susquehanna Steam Electric Station Inspection At:
Inspection Conducted:
Inspectors:
Salem Township, Pennsylvania October 15, 1989 - November 11, 1989
\\
'G.
S. Barber, Senior Resident Inspector, SSES J.
R. St ir, Resident I
ector SSES Approved By:
P. Swetland, Chief Reactor Projects Section No.
2A, Date Ins ection Summar R
plant operations, physical security, plant events, surveillance, and maintenance.
Results:
During this period, Operations Department personnel generally conducted activities in a professional manner and operated the plant safely.
Routine review of maintenance and surveillance activities noted good control and performance.
A Reactor Protection System actuation occurred in Unit 2 during restoration of the Division I 24VDC Battery due to an apparent over voltage condition in conjunction with the removal of SRM shorting links.
No rod movement occurred since all rods were inserted at the time.
An Actuation of the Main Steam Isolation Valve (MSIV) Logic occurred in Unit 2 as a result of a jumper making contact with a terminal in the main turbine control panel when being placed by a Technician.
No MSIV movement occurred since they were closed at the time.
An unplanned automatic start of the "B" Standby Gas Treatment System occurred due to high inlet header pressure due to its lineup to the suppression pool during the depressurization from the Integrated Leak Rate Tes A failure of the radioactive waste treatment system transformer OX330 resulted in isolation of several Containment Atmosphere Control and Containment Instrument Gas sample valves in both units.
The Unit 2 main condenser mechanical vacuum pump tripped unexpectedly during testing of the "B" Main Steam Line High Radiation Isolation Logic.
The root cause was determined to be procedural inadequacies in the 18 month surveillance procedure.
The wetwell-to-drywell vacuum breakers (VBs) were believed to be degraded due to the lack of a required linkage adjustment.
The required adjustments were made on Unit 2 VBs.
A stress analysis of the linkage for Unit 1 showed acceptable levels.
The Unit
Enforcement Discretion was granted by the NRC due to licensee discovery of the inoperability of the differential temperature detectors upon isolation by the backdraft isolation dampers for Reactor Core Isolation Cooling (RCIC),
Reactor Water Cleanup (RWCU), main steam tunnel, and High Pressure Coolant Injection (HPCI)/RCIC piping area.
This was superceded by an Emergency Technical Specification Amendment approved on October 19,'which eliminated the operability requirement to the differential temperature instrumentation for a period of three month TABLE OF CONTENTS
~pa e
1.0 Introduction and Overview 1. 1 NRC Resident Staff Activities (30703, 71707, 90712, 92701)
1.2 Unit
Summary 1.3 Unit 2 Summary 2.0 Routine Periodic Inspections (93702)
2. 1 Scope of Review 2.2 Reactor Protection System Actuation Unit 2 2.3 Actuation of Main Steam Isolation. Valves (MSIVs) Isolation Logic - Unit 2 2.4 Unplanned Automatic Start of the "B" Standby Gas Treatment, System (SGTS) - Unit 2 2.5 Containment Isolation Valve Closure Due to Electrical Transient - Unit
2.6 Mechanical Vacuum Pump Trip - Unit 2 3.0 Surveillance and Maintenance Activities 3. 1 Surveillance Observations (61726 and 71711)
3.2 Wetwell-to-Drywell Vacuum Breaker Adjustment Inadequacy Unit Common (61726)
3.3 Maintenance Observations (62703)
4.0 Licensee Reports
.
4. 1 In-office Review of. Licensee Event Reports (90712)
4.2 Onsite Followup of Licensee Event Reports (92700)
4.3 Review of Significant Operating Occurrence Reports (90713)
5.0 NRC Regulatory Impact Survey Team 6.0 Enforcement Discretion Granted due to Differential Temperature Detector Inoperability 7.0 Resident Monthly Exit Meeting (30703)
DETAILS 1.0 Introduction and Overview NRC Staff Activities The purpose of this inspection was to assess licensee activities at the Susquehanna Steam Electric Station (SSES)
as they related to reactor safety and worker radiation.protection.
Within each area, the inspectors documented the specific purpose of the area under review and the scope of inspection activities and findings, along with appropriate conclusions.
This assessment is based on actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels or independent calculations when appropriate, and selective review of applicable documents.
1.2 Unit 1 Summar
'Unit 1 operated at or near full power for all of the inspection period.
Scheduled power reductions were conducted during the period for control rod pattern adjustments, surveillance testing, and maintenance.
On November 8, a radioactive waste treatment system transformer failure caused an electrical disturbance which resulted in the automatic isolation of various containment sample valves in both units.
See Section 2.5 for details.
1.3 Unit 2 Summar Refueling outage activities continued in Unit 2 during the period.
Condition 4 (Cold Shutdown)
was established at 2:20 a.m.
on October 29, following reactor vessel reassembly and head tensioning.
During the inspection period, major activities included the completion of core reload and completion of work, testing and system restoration of Residual Heat Removal, Core Spray, DC Batteries, Main Steam Isolation Valves (MSIVs), Reactor Recirculation, Reactor Water Cleanup, Feedwater Injection, High Pressure Coolant Injection, Reactor Core Isolation Cooling, Containment Instrument Gas, and Containment Atmosphere Control.
The Integrated Leak Rate Test, Control Rod Drive friction testing, Diesel Generator LOCA/LOOP testing, and Primary Containment Isolation System testing were also completed.
On October 15; a full Reactor Protection System actuation was received during restoration of the Division 1 24 VDC Battery.
See Section 2.2 for details.
On November 2, an MSIV isolation signal was received when the main turbine stop valves were inadvertently opened.
See Section 2.3 for details.
On November 5, an unplanned start of the "B" Standby Gas Treatment System occurred due
.
to high inlet header pressure.
See Section 2.4 for details.
On November 9,
a trip of the main condenser mechanical vacuum pump occurred while testing the main steamline high radiation isolation logic.
See Section 2.6 for detail.0 Routine Periodic Ins ections 2. 1 Sco e of Review The inspectors periodically inspected the facility to evaluate the safety of plant operations=and determined the licensee's conformance with the general operating requirements of the Technical Specifications (TS)
in the. following areas:
review of selected plant parameters for abnormal trends; plant status from a maintenance/modification viewpoint, including plant housekeeping and fire protection measures; control of ongoing and special evolutions, including control room personnel awareness of these evolutions; control of documents, including logkeeping practices; implementation of radiological controls; implementation of the 'security plan, including access control, barrier integrity, and badging practices; control room operations during regular and backshift hours, including frequent observation of activities in progress, and periodic reviews of selected sections of the unit supervisor's log, the control room operator's log and other control room daily logs; followup items on activities that could affect plant safety or impact plant operations; areas outside the control room; and, selected licensee planning meetings.
The inspector conducted a backshift inspection on November 9, from 2:15 a.m. to 6:00 a.m.
The inspectors reviewed the following specific items in more detail.
2.2 Reactor Protection S stem Actuation Unit 2 On October 15, at 5:30 a.m. with Unit 2 in its third Refueling Outage, an unplanned Engineered Safety Feature (ESF) actuation occurred when a
full Reactor Protection System (RPS) actuation was received during restoration of the Division 1 + 24 VDC Battery System following system maintenance.
The event occurred as maintenance electricians were in the process of restoring battery 2D670.
When the battery charger was placed in the equalize mode, the overvoltage protection relay tripped due to an apparent overvoltage condition.
As expected, a trip signal was
generated to the charger's output circuit breaker (2D672-01)
deenergizing the
VDC positive bus.
This in turn caused a Division I Intermediate Range Monitor upscale/inop trip signal which actuated a
Nuclear Monitoring System (NMS) trip of the RPS, because the shorting links were removed.
All control rods were fully inserted, prior to the actuation, thus, no rod motion occurred.
Charger 2D673 was placed in the float mode and 2D672-01 was reset.
Control Room operators reset the actuation logic at 5:36 a.m.
and an ENS notification was completed in accordance with 10CFR50.72(b)(2)(ii) at 6:45 a.m.,
October 15.
The root cause was attributed to the type of relays used in the +24 VDC bus overvoltage trip circuit.
The overvoltage relays used in the system
're GE NGV relays, typically used in undervoltage applications.
These relays are designed to de-energize between 19 and
VDC and energize at 105 percent or less of the dropout voltage.
The overvoltage trip circuit utilizes the relay in a normally deenergized state, with an actuation setpoint of 29 +0.5 VDC.
When the charger is in the equalize mode, output voltage is 28. 5 VDC.
This mode is primarily used for recharging the battery.
The overlap of the relay operating range with battery charger equalizing voltage caused the charger's output circuit breaker to trip due to an apparent overvcltage condition, as sensed by the relay.
Following the event the setpoint for the overvoltage relay was found to be 28.6 VDC.
2.3 The RPS actuation occurred when only one NMS channel tripped due to Source Range Monitor "shorting links" being removed.
When the shorting links are removed, the NMS coincidence trip is no longer
"one out of two taken twice", but is one out of two.
Any single one out of
, eighteen trip functions can satisfy the logic in this configuration and result in an RPS actuation.
The shorting links are replaced prior to startup, restoring the "one out of two twice" logic.
After a proper s'afety evaluation, the licensee implemented a temporary modification to the Division I overvoltage trip circuits by installing a
300 ohm, 5 watt resistor in series with each overvoltage relay's operating coil to minimize battery charger trips.
This allows the relay to monitor system voltage within its operating range, reducing the likelihood of nuisance overvoltage trips.
The licensee has committed to replace these overvoltage relays in both the Unit 1 and Unit 2 + 24 VDC battery systems with a relay better suited,to this application.
The inspector had no further questions on this issue.
Actuation of Main Steam Isolation Valves MSIVs Isolation Lo ic-Unit 2 At 11:00 a.m.
November 2, while Instrument 8 Control (IKC) technicians were performing continuity checks in a control panel for the main turbine, a
"SPEED SELECT" signal was inadvertently generated which caused the main turbine stop valves to open.
The opening of these valves disabled the low condenser vacuum MSIV isolation bypass circuit.
Since the unit was in Cold Shutdown with no condenser vacuum
established, this actuated the MSIV isolation logic.
No valve movement occurred since the MSIVs were closed at the time.
This event was considered an unplanned Engineered Safety Feature (ESF) actuation since an isolation signal resulted.
The licensee made the required.4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notification to the NRC at 12:35 p.m..
The Control Room operators subsequently closed the turbine stop valves and reset. the isolation logic.
The root cause of the event was determined to be personnel error.
An 18C technician made contact between a jumper and Terminal 13 of the 24 VDC system.
Final resolution of this event was not determined by the end of this inspection period, however, a Licensee Event Report (LER) is scheduled to be submitted within 30 days.
The inspector will evaluate the licensee's resolution and corrective actions to prevent a future recurrence during the LER review.
Un lanned Automatic Start of the "B" Standb Gas Treatment S stem SGTS
- Unit 2 At 2: 18 p.m.
November 5, the "8" train of the SGTS, auto-started on high inlet header pressure while depressurizing from the Containment Integrated Leakage Rate Test ( ILRT) in order to perform the Drywell to Suppression Chamber Bypass Test.
In accordance with the test procedure, the test director instructed the Plant Control Operator (PCO) to trip the
"A"- SGTS fan which had been in use for the test.
This was done in order to prevent drawing a vacuum on the wetwell.
The PCO proceeded as directed, however, the suppression chamber pressure of 0. 1 psig was sufficient to cause an initiation signal to start SGTS on inlet header high pressure ( 1.5 inches water column or.054 psig).
The "B" train was subsequently shutdown at 2:43 p.m..
Immediate actions taken were to temporarily suspend the ILRT, determine the cause of the SGTS initiation, and isolate SGTS from the suppression chamber by closing the outboard i sol ati on va1 ve (HV25104).
~Discussion with the licensee indicated that they intend to revise the ILRT procedure to provide direction to shutdown SGTS in accordance with the operating procedure when suppression chamber pressure reaches zero psig.
This will isolate SGTS from the suppression chamber by closure of the suction dampers from the containment/suppression chamber and therefore should preclude a future recurrence of this event.
Milestones for the final resolution had not been determined as of the end of this inspection period, but will be evaluated by the inspector following its issuance.
Otherwise, the inspector considered the licensee's corrective actions in response to this event acceptabl.5 Containment Isolation Valve Closure Due to Electrical Transient Unit I At 9:37 a.m.,
November 8, an electrical transient resulting from the fai'lure of radioactive waste treatment system transformer OX330 caused various containment sample valves to close on both Unit I and Unit 2.
The licensee transferred all affected transformer loads to an alternate off-site power source.
The valves which were affected were the "A" inboard and outboard Contaihment Atmosphere Control, sample valves of both units I and 2, the Containment Instrument Gas (CIG) to the Traverse Incore Probes of both units I and 2, and the CIG to suppression pool vacuum breakers of Unit 2.
The valves closed due to an undervoltage condition on their associated instrument bus as a result of the electrical transient.
OX330, which is common to both units failed,- due to a short in the "B" phase windings.
It was noted that OX330 had been removed from service on October 19, for cleaning, but it is not believed that this was related to the failure.
Following the failure and the temporary transfer of the loads from OX330, the licensee replaced OX330 with a transformer from stores, restored the associated loads, and continued their investigation into the failure.
The inspector considered the licensee's actions in response to this event acceptable.
2.6 Mechanical Vacuum Pum Tri Unit 2 The licensee reported that the main condenser mechanical vacuum pump tripped unexpectedly at 9:20 a.m.,
November 9.
The trip occur red while testing the Channel
"8" Main Steamline High Radiation Isolation Logic for an 18 month surveillance (SI-279-307).
The licensee reviewed the event and noted that the automatic trip of an unfiltered release path via the mechanical vacuum pump was an Engineered Safety Feature (ESF)
actuation.
The licensee reported the event at 12:27 p.m.,
November
per
CFR 50.72 and the resident inspector was notified at 12:30 p.m.
The root cause of the event was procedural inadequacy.
The monthly surveillance procedures warns the operators that the mechanical vacuum pump will trip if running.
However, the 18 month surveillance did not have this note.
A procedure change was issued to prevent recurrence.
No further inadequacies were noted.
3.0 Surveillance and Maintenance Activities On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that specific programmatic elements described below were being met.
Details of this review are documented in the following section.1 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, if applicable to the specific test, were met:
the test conformed to Technical Specification requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; Limiting Conditions for Operations were met; test data was accurate and complete; removal and restoration of the affected components were properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the requi red frequency.
These observations and/or reviews included:
SE-200-003, Primary Containment Integrated Leakage Rate Test ( ILRT), performed on November 3, 1989.
TP-149-029, Residual Heat Removal (RHR)
Pump Flow'erification, Loop B, performed on November 3, 1989.
SE-259-200, 18 month Logic System Functional Test of the Primary and Secondary Containment Isolation System, step 6.3, Test of Primary and Secondary Isolation Division 1 Valves and Dampers, performed on November 7, 1989.
S0-024-001B, Monthly Diesel Generator (D/G) Operability Test of the
"B" D/G, performed on November 9, 1989.
No unacceptable conditions were identified.
3.2 Wetwell-to-Dr well Vacuum Breaker Adjustment Inade uac
- Unit Common Wetwell-to-Drywell Vacuum breakers (VBs) are provided to equalize pressure between the drywell and wetwell under various conditions.
There are five pairs of vacuum breakers that open whenever the pressure in the drywell is approximately 0.5 psid less than that of the wetwell.
These breakers perform the three specific functions listed below:
Relieve vacuum in the drywell during an inadvertent drywell spray/small break LOCA event Maintain the structural integrity of the drywell floor during a
LOCA with ECCS spillage Maintain containment integrity by preventing bypass steam from entering the wetwell atmosphere directly
The licensee performs periodic surveillances to ensure these functions
~
During the most recent 18 month surveillance (SM-259-002) to check the lift setpoints of these 10 valves, the licensee determined that seven out of 10 valves for Unit 2 were out of specification.
During the investigation, the licensee identified that a required setting was not being checked per the vendor's recommendation.
The Installation, Operations and Maintenance Manual ( IOM) for the vacuum breakers ( IOM-166), specifies that the spring cylinder lift be set between 0. 1 and 0.9 inches.
The licensee was unaware of the IOM-166 requirement to check and, adjust this setting.
If the adjustment is greater than 1.25 inches, the swing check valve will stop opening due to the breaking action of the linkage.
This would impose large shear stresses on the linkage.
The licensee calculated these stresses and found them to be acceptable.
Because of the missed adjustment, the licensee decided to check it for all 10 VBs.
Five of the 10,VBs had lifts outside the required range and two VBs were mechanically limited from reaching'their full open position.
Five of the seven failed VBs. were adjusted to within tolerance for their lift settings.
The remaining two could not be adjusted and had their seals replaced.
The lift setting was then adjusted to within tolerance.
All ten VBs met their SM-259-002 acceptance criteria and were returned to an operable status.
Unit 1 was also susceptible to an out-of-specification lift setting.
Thus, the licensee examined the shear stresses imposed on the linkage to ensure that they remained acceptable.
The analysis showed that the linkage remained within its elastic range.
Therefore, the Unit
VBs were still capable of performing their intended function and were operable.
The licensee will make the necessary adjustments at the first outage of sufficient duration.
No inadequacies were noted.
3.3 Maintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered, as applicable, during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and quality control hold points were established where required; functional testing was performed prior to declaring the involved component(s)
operable; activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
These observations and/or reviews included:
Scheme Checks and Calibration of Instrument Loops for LI-21587 and PI-21587, per Work Authorization (WA) U-96092 performed on October 30, 1989.
Replacement of Bearings and Buildup of Fan Shaft on Condenser Bay Area Fan, per WA V93410, on October 30, 1989.
"D" Diesel Generator (D/G) Auxiliary Air Compressor OK50702 preventive maintenance per WA P93382, performed on November 3, 1989.
Annual Freeze Protection Inspection and Testing on the Condensate and Refuel Water Storage Tanks Heat Trace Circuits per WA P92834, performed on November 9, 1989.-
Disassembly, Investigation and Repair of Condensate Transfer Pump OP155A due to Seal Leak and Bearing Noise per WA S94097, performed on November 9, 1989.
No inadequacies were noted.
4.0 Licensee Re orts 4. 1 In-office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC 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
89-002-01 Operator Error Caused Feedwater Flow Transient and Reactor Scram.
This event is detailed in NRC Inspection Report 50-387/89-01.89-024 Diesel Generator
"C" Crankcase Overpressurization.
This event is detailed in NRC Inspection Report 50-387/89-30.
Unit 2 89-008
- 89-009 Drywell Purge Air Supply Outboard Isolation Valve Failed Closed During Drywel1 Deinerting Activities.
This event is detailed in NRC Inspection Report 50-387/89-27.
Control Power Lost to Several Containment Isolation Valves During Application of Protective Blockin '9-010 Main Steam Line Penetrations Exceeded Maximum Allowable Leak Rate During Local Leak Rate Testing.
This event is detailed in NRC Inspection Report 50-388/89-27.89-011, Instrument Air Leak Due to an Improperly Madeup Fitting Results in Initiation of a Full RPS Actuation.
This event is detailed in NRC Inspection Report 50-388/89-27.89-012 RPS Actuation Received During Restoration of Division I
'+24VDC Battery System.
This event is detailed in Section 2.2
~
No unacceptable conditions were identified.
4.2 Onsite Followu of Licensee Event Re orts 4.2.1 For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1), the inspector verified that the reporting requirements of
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 opera.ion of the facility was conducted in accordance with Technical Specification limits.
The following findings relate to the'ERs reviewed on site:
LER 89-009 Control Power Lost To Several Containment Isolation Valves Durin A
lication of Protective Blockin On September 17, 1989 at approximately 4:30 a.m. with Unit 2 in the refueling condition, an unplanned Engineered Safety Features (ESF)
actuation occurred when control power was lost to several containment isolation valves.
Containment Atmosphere Control and Containment Instrument Gas containment isolation valves were affected by the event.
The event occurred when personnel protective blocking was being applied in support of planned outage work.
Specifically, a
modification was being performed to the drywell sump logic.
When the sliding links were opened to de-energize the drywell sump logic, the control logic for several containment isolation valves was de-energized as well.
The electrical drawing the work group used for the blocking point selection did not reflect the other control schemes connected downstream of the selected blocking points.
Further review of the panel wiring diagrams and connection lists would have identified multiple schemes powered from the sliding links.
In addition, subsequent required reviews of the blocking request failed to identify the deficiency.
The causes of the event were determined by the licensee to be failure of the P.P.5 L. construction planning group to identify all the effects associated with the requested protective blocking and of personnel involved in the review of the Equipment Release Form and protective permit to identify the deficienc Specific guidance which enhances and refines the method for determining the correct protective blocking points has been issued and reviewed by the work group.
Training on the event and guidance has been provided to the work group, stressing that the use of schematics or elementary drawings alone is not sufficient to determine points of protective blocking.
In addition, changes to the electrical schematic, reflecting the other schemes powered from the sliding links, will be evaluated.
All licensed operators were briefed on the subjects of ESF actuation recognition and specific actions required to be taken when one is determined or suspected.
The inspector determined that the licensee's corrective actions and review of the event were adequate and that Technical Specification limits were met.
4.3 Si nificant 0 eratin Occur rence Re orts Significant Operating Occurrence Reports (SOORs) are provided for problem identification tracking, short and long term corrective actions, and reportabi lity evaluations.
The licensee uses SOORs to document and bring to closure problems identified that do not merit an LER.
The inspectors reviewed the following SOORs during the period to ascertain whether:
additional reactive inspection effort or other NRC response was warranted; corrective action discussed in the report appeared appropriate; generic issues were assessed; and, prompt notification was made, if required:
1-89-321, 1-89-322, 1-89-329, 1-89-330, 1-89-336, 1-89-337, 2-89-151, 2-89-152, 2-89-159, 2-89-160, 2-89-168, 2-89-169, 2-89-175, 2-89-176, 2-89"182, 2-89-183, 2-89-191, 2-89-192, 2-89-198, 2-89-199, 1-89-323, 1-89-331, 1-89-338, 2-89-153, 2-89-163, 2-89"170, 2-89-177, 2-89-184, 2-89-193, 2"89-200, 1-89-325, 1-89-332, 1-89-340, 2-89-154, 2"89-164, 2-89-171, 2-89-178, 2"89-185, 2-89-194, 2-89-201.
1-89-326, 1.-89-333, 2-89-112, 2-89-156, 2-89-165, 2-89-172, 2-89-179, 2-89-186, 2-89-195, 1-89"327, 1"89-334, 2-89-147, 2-89-157, 2-89"166, 2-89-173, 2"89-180, 2-89-187, 2-89-196, 1-89-328, 1-89-335, 2-89-150, 2-89-158, 2-89-167, 2-89-174, 2-89-181, 2-89-190, 2-89-197, No inadequacies were noted.
The following SOORs required inspector followup:
1-89-324 documented a crankcase overpressurization in the "C" Diesel Generator.
This event is discussed in Inspection Report 50-387/89-30.
1-89-341 documented the failure of radwaste transformer OX330 and the resulting ESF actuations.
See Section 2.5 for detail documented a full RPS signal actuation due to the trip of a charger out'put breaker.
See Section 2.2 for details.
2-89-189 documented an MSIV isolation signal d'ue to the inadvertent opening of the main turbine stop valves.
See Section 2.3 for details.
2-89-192 docu'mented the automatic start of the SGTS on high inlet header pressure.
See Section 2.4 for details.
2-89-202 documented the unanticipated trip of the mechanical vacuum pump when a high mainsteam line radiation condition was simulated.
See Section 2.6 for details.
5.0 NRC Re viator Im act Surve Team The NRC is conducting a survey of its regulations and activities to determine what, if any, changes are warranted or needed.
The survey will question licensee personnel at 13 plants in 5 regions.
The personnel to be questioned range from senior corporate and plant management down to the worker level.
A similar survey was conducted in 1981 and their recommendations were published in NUREG-0839.
A Regulatory Impact Survey was conducted at the Susquehanna Training Center on October 27 to solicit comments from Pennsylvania Power and Light (PP5L)
on the regulatory process.
Five sessions were conducted throughout the day.
The survey team's review was completed independent of the resident inspectors and their findings will be published in 1990 in a NUREG.
6.0 Enforcement Discretion Granted due to Differential Tem erature Detector Ino erabi lit Differential temperature (DT) sensing systems are installed in the RCIC and RWCU equipment rooms, the HPCI/RCIC piping area, and in the main steam tunnel.
These systems are designed to measure ventilation supply and exhaust differential temperatures and initiate an isolation signal when a steam leak is present.
In the course of determining steam leak time/temperature profiles for the RCIC room, room pressure transient studies were also performed.
This was done to determine whether interaction existed between the differential temperature circuits and the backdraft isolation dampers (BDID) HVAC isolation function.
These BDIDs isolate the RCIC room upon sensing a high differential pressure between the RCIC room and atmospheric pressure.
The licensee found that BDID operation (HVAC Isolation) would render the differential temperature sensing instrumentation inoperabl ~,
The DT detectors are installed on the room side of the BOIDs.
If a steam leak were to occur and the BDIDs would close, then the individual sensors would register the same temperature which corresponds to a zero degree DT.
The licensee noted that in this case the DT detectors would not perform their function and declared them inoperable.
A similar configuration was also found to exist in the RWCU equipment room, the main steam tunnel and in the HPCI/RCIC piping area.
However, the li'censee believed that the impact of this inoperability was minimal since their are other diverse and redundant methods for detecting, alarming, and automatically isolating steam leaks.
For example, i'n the RCIC system, in addition to the differential temperature instrumentation, safety related instruments cause automatic isolation of the RCIC system for the following abnormal conditions:
High RCIC room ambient temperature High RCIC room cooler inlet temperature High RCIC steam flow Low RCIC steam supply pressure High RCIC steam turbine exhaust vent pressure In addition to the above automatic isolation functions, the following other instruments provide operators with alarms which are indications of a reactor coolant pressure boundary leak in the RCIC room RCIC room high ambient temperature RCIC room cooler high inlet temperature RCIC room high radiation RCIC room flood detection Also, the fast closure of the BDIDs which will be annunciated in the main control room through a system trouble alarm, can be considered another diverse method for warning operators of a steam leak.
The other systems affected by the existence of BDIOs have similar levels of diverse and redundant methods for detecting, alarming, and automatically isolating steam leaks.
Also, the associated alarm response procedures will include direction to the operator that upon receipt of an alarm there is potential that the alarm was caused by a steam leak.
The licensee identified this concern to the ins'pector on October 18.
A conference call was conducted between the licensee and the NRC and it was determined that enforcement discretion would be granted until such time as an Emergency Amendment Request could be processed.
The Regional
'
Administrator granted this discretion on October 19, 1989 for Unit 1 and 2 Technical Specification 3 '.2(b)
and (c) related to the LD instrumentation described in Table 3.3.2-1 items 3g, 4c, 5e, 5g and 6h.
The discretion was to remain in effect until such time as the Office of Nuclear Reactor Regulation (NRR) acted upon the amendment request.
The licensee processed their emergency amendment request on October 19, 1989 in PLA-3279 which requested the elimination of the operability requirement to the DT instrumentation for a period of three months.
This request was approved by NRR on October 20.
The inspector had no further questions on this issue.
7.0 Resident Monthl Exit Meetin The inspector discussed the findings of this inspection with station management at the conclusion of the inspection period.
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.