IR 05000272/1990004

Insp Repts 50-272/90-04,50-311/90-04 & 50-354/90-01 on 900101-0212.No Violations Noted.Major Areas Inspected: Operations,Radiological Controls,Maint & Surveillance Testing,Emergency Preparedness & Security

ML18094B313
Person / Time
Site:	Salem, Hope Creek, 05000000
Issue date:	02/23/1990
From:	Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18094B312	List: IR 05000272/1990004 ML18094B311
References
50-272-90-04, 50-272-90-4, 50-311-90-04, 50-311-90-4, 50-354-90-01, 50-354-90-1, NUDOCS 9003050139
Download: ML18094B313 (30)

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No /90-04 50-311/90-04 50-354/90-01 License No DPR-70 DPR-75 NPF-57 Licensee:

Public Service Electric and Gas Company P. 0. Box 236 Hancocks Bridge, New Jersey 08038 Facilities:

Salem Noclear Generating Station Hope Creek Generating Station Dates:

January 1, 1990 - February 12, 1990 Inspectors:

Approved:

Thomas P. Johnson, Senior Resident Inspector David K: Allsopp, Resident Inspector Stephen M. Pindale; Resident Inspector Stephen T. Barr, Resident Inspector Ronald~- Nimitz,

~..r'.

Rad~.~tion Specialist

/ --

/

~-

..-----,

,..,,

~*..,

....--

""

--_,I f

I

/ '/"

,-

/ vv::cz:..--:,,-7_---/__,/'

/

J

• '

• ,.

{

............. \\,/",...--:;

....

P. Swetland~ Chief, Projects Section 2A

'

I I

f

,;Ji;__] /? 0 Date'

Inspection Summary:

Inspection 50-272/90-04; 50-311/90-04; 50-354/90-01 on January 1, 1990 - February 12, 1990 Areas Inspected:

Resident safety inspection of the following areas:

opera-tions, radiological controls, maintenance & surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/assur-ance of quality, and licensee.event report and open item follow-u Results:

The inspectors did not identify any violation There was one non-cited licensee identified violatio An executive summary follow *

SUMMARY Salem Inspection Reports 50-272/90-04; 50-311/90-04 Hope Creek Inspection Report 50-354/90-01 January 1, 1990 - February 12, 1990 Operations Salem:

Operators properly initiated several power reductions and one unit shutdown as required by Technical Specification Operators effectively con-trolled_ several plant transient Hope Creek:

Operators effectively implemented emergency and abnormal operating procedures during one reactor scram and several transient One licensee iden-tified licensed operator procedural noncompliance was noted during the post scram revie Radiological Controls Salem:

Radiological protection personnel adequately implemented program re-quirement Hope Creek:

Good performance in radiation protection practices was note Also, attention to minimizing accumulated exposure was goo Maintenance/Surveillance Salem:

Procedural and knowledge weaknesses resulted in an automatic steam line isolation during surveillance testin Hope Creek:

One unresolved item was opened regarding the control of air oper-ated valves and generic implications of system alignment The licensee iden-tified a valve labeling error during maintenance activitie Emergency Preparedness Licensee emergency notification system calls were appropriat No emergency plan procedure implementation was require Security Routine inspections did not identify any unacceptable or noteworthy item *

. - - - - --------

Executive Summary Engineering/Technical Support Salem:

System engineers were noted as being involved in problem resolution regarding the radiation monitoring system, slow closure of the main steam isolation valves, and charging pump problem An unresolved item was opened to track licensee corrective measures to ensure temporary extension cords do not violate electrical cable separation criteri Hope Creek:

Routine inspections did not identify any unacceptable or note-worthy item Safety Assessment/Assurance of Quality Salem:

Two licensee Significant Event Response Teams effectively reviewed underground excavation of electrical cables and scaffolding in electrical rooms, and determined the root cause of ineffective corrective actions which resulted in these recurrent event One plant transient which nearly resulted in a reactor trip, was not evaluated and documented in a timely manne Unit 1 LER 89-30 was evaluated to be of poor qualit Hope Creek:

The licensee effectively determined the root cause of two main turbine trip induced reactor scrams.

i i

DETAILS SUMMARY OF OPERATIONS I.I Salem Unit I Salem Unit I began the report period operating at full powe On January 28, I990, the unit reduced power to 20% to repair an oil leak on the main turbine front standar The unit was returned to full power on January -

29, I99 However, that evening the unit reduced power to 33% in prepara-tion for a Technical Specification shutdown due to an inoperable "IA" safeguards equipment cabine After repairs, the unit was returned to full power and operated throughout the remainder of the perio I.2 Salem Unit 2 Salem Unit 2 began the report period operating at full powe On January 4, I990, the unit began a controlled shutdown after the licensee dis-covered a math error in previous charging pump flow surveillance test re-sult A waiver of compliance was granted that day and the unit subse-quently returned to full powe On January I7, I990, the unit was shut-down to Mode 5 (Col~ Shutdown) due to a leak in a charging system boron injection tank lin Repairs were performed, and the unit restarted on January 23, I990. * On January 25, I990, a power reduction was initiated (to 48%) due to problems experienced during nuclear instrumentatinn sur-veillance testin The unit returned to full power on January 27, I990, and operated throughout the remainder of the perio Hope Creek The unit began the report period operating at 96% powe Power was limited as the 11 IC 11 and "2C" feedwater heaters were isolated due to a le'ak in the 11 2C 11 feedwater drain coole On January 6, I990, the unit auto;._

matically scrammed due to a turbine trip caused by a high level in the "A" moisture separato The unit restarted on January 9, I990, and operated throughout the remainder of the perio.

OPERATIONS (7I707, 93702)_

2.I Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirement Public Service Electric and Gas (PSE&G) Company management control was evaluated by direct observation of activities, tours of the facilities, interviews and discussions with per-sonnel, independent verification of safety system status and Limiting Con-ditions for Operation, and review of facility record These inspection activities were conducted in accordance with NRC inspection procedures 7I707 and 9370 The inspectors performed normal and backshift inspec-tions, *including deep backshift inspection as follows:

• Unit Inspection Salem 2:45 a.m. -

3:15 a.m. -

Hope Creek 2:00 p.m. -

Hours 5:00 :00 ~. :00 Deep Backshift January 22, 1990 January-23, 1990 February 10, 1990 Inspection Findtngs and Significant Plant Events 2. Salem Common 2. Engineered Safety Features (ESF) Actuations Caused By Radiation Monitoring Systems (RMS)

Numerous ESF actuations and reportable events occurred during the inspection period caused by the Unit 1 and Unit 2 RM Attachment 1 is a summary listing of these ESF actuation In each case, the lic-ensee adequately responded to the event, acknowledged the isolations, repaired or restored the RMS instrument as appropriate, made an emer-gency notification system (ENS) call, and informed the resident in-specto See Section 7.1.A for further discussions of this RMS issu Fire Protection Discrepancies The inspector noted two fire protection discrepancie A commonly used fire door (TGA-202) would not latch shu This door has a re-movable center post which when last installed was oriented such that the door latch did not properly engage the pos A fire extinguisher which was last inspected in March 1988 was discovered in the con-taminated area outside the 137 foot containment entranc Both of these discrepancies were promptly corrected when brought to the attention of the license Salem Unit 1 Manual Bypassing of The Main Turbine Mechanical Trips On January 28, 1990, the Salem Unit 1 mechanical (Non-Technical Specification) turbine trips on the main turbine were bypassed for approximately six hours to prevent a turbine trip from an invalid low lube oil pressure indicatio The invalid pressure indication was discovered during preparation for a functional test of the main tur-bine mechanical trip A technician noted that the lube oil pressure to the low lube oil trip device indicated low at 8 pounds (approxi-mately two pounds above the trip setpoint).

Other lube oil pressure indications determined actual lube oil pressure to be at approxi-mately 35 pound The licensee reduced power below 50% and conducted troubleshooting which determined the erroneous low lube oil pressure -

• * 2. *

resulted from a cracked diaphragm on the trip devic With reactor power reduced below 50%, a turbine trip will not induce a reactor tri During troubleshooting and the diaphragm replacement effort (approximately six hours) an operator manually held the auto-stop trip lever against spring pressure in the test position, bypassing the mechanic~l turbine trip The inspectors determined that the licensee had taken appropriate action and that reactor safety was not compromise lN1 Diesel Sequencer Dec::.lared Inoperable On January 29, 1990 at 8:23 p.m., Salem Unit 1 declared the 11 lA

emergency diesel generator sequencer inoperable and commenced a power reduction to achieve Mode 3 (Hot Standby) in six hour At 12:35 a.m. on January 30, 1990, the 11 lA 11 sequencer was declared operable after the fault cleared and the sequencer passed its surveillance test requirement The power reduction was halted at 33%.

The lic-ensee elected to stay at 33% to conduct more extensive troubleshoot-*

ing which identified an electrical card which contained a discolored integrated circuit chi The electrical card was replaced and power escalation to 100% began at 12:15 p.m. on January 30, 199 The in-spector determined that the appropriate notifications and corrective actions had been mad The inspector evaluated management's willing-ness to stay at reduced power to conduct a comprehensive trouble-shooting plan a~ noteworth Salem Unit 2 Unit 2 Shutdown on January 4, 1990 and Related Discretionary Enforcement On January 4, 1990, during a review of a previously completed sur-veillance test, the licensee discovered a math error in the charging system high head safety injection flow rat This resulted in de-claring both injection trains inoperable and the licensee entered Technical Specification (TS) 3.0.3 which requires a shutdow The error resulted in flow being greater than the TS maximum of 550 gpm (553 and 554 gpm, respectively for each injection train). Apparently; the reactor coolant pump seal flow which bypasses the flow instrumen-tation was not added to the flow tota The licensee informed the inspector, NRC Region I and NRC Headquarters, and requested discre-tionary enforcement from TS 3/4.5.2.c and 3.0.3 in a letter dated January 4, 199 Relief was requested based on the small deviation from the acceptance criteria which did not degrade the operability of the pump A unit shutdown was initiated within one hour and the unit was stabilized at 50% while the TS license change request was submitted:

The NRC granted enforcement discretion and a temporary waiver of compliance in letters dated January 4 and 5, 199 A sub-sequent TS amendment will be issued by the NR The unit was re-turned to full powe **

The inspector participated in several meetings and telephone conver-sations; reviewed the licensee's formal request; reviewed the sur-veillance test; held discussions with plant man~gement and technical personnel; and, verified operator actions to initiate the unit shut-down as required by TS 3. The inspector expressed concern that the surveillance error was not initially noted during test review by either operational or technical personne This appears to be an example of a poor review of surveillance test result NRC action regarding the improper conduct_ and review of this surveillance will be determined following NRC receipt of a licensee event repor The inspector did not have any further questions at this tim Unit 2 Shutdown on January 17, 1990 Due to Charging System Leak During a reactor coolant system leak rate determination, the licensee discovered an 8.0 gpm leak on a line in the charging system boron injection tank (BIT).

The leak was on a 1 1/4 11 welded pipe cap on the inlet line of the BI At 12:10 a.m., the licensee isolated the BIT to stop the lea This action caused the cold leg injection path to be inoperable, and Technical Specification 3.0.3 was entered and the unit was shutdown to Mode 4 (Hot Standby).

The leak wa~ re-paired, other maintenance work and testing was performed, and the unit was restarted on January 23, 199 The inspector reviewed licensee actions, observed portions of the plant cooldo~n, reviewed the outage work list, discussed the leak and other charging system problems with the system engineer (see Section 7.1.C), and observed portions of the startu The inspector con-cluded that licensee acti~ns were appropriat Entry Into Technical Specification (TS) 3. During a review of the January 21, 1990 Unit 2 operator's narrative log, the inspector noted a 3:18 a.m. entry into Technical Specifica-tion (TS) 3.0.3 while in Mode 4 (Hot Shutdown) to perform an Emer-gency Core Cooling System (ECCS) check valve surveillance test, SP(0)4.4.7.2.l TS 2.0.3 was entered as required by the test pro-cedure due to the closure of one of the two cold leg injection isola-tion valves (21 or 22SJ49).

A 4:15 a.m. entry noted TS 3.0.3 termi-natio TS 3.0.3 was again entered for the test at 5:25 a.m. for the same valve closure (21SJ49), and terminated at 6:24 a.m. *

During a follow-up review of TSs, the inspector determined that TS 3.0.3 entry was not necessary due to an applicable Action requirement in TS 3.5.3, 11 ECCS-Mode 4.

The licensee informed the inspector that thi procedural precautions had been in effect prior to a recent TS Amendment (No. 70, May 2, 1989).

The related TS 3.5.2, 11 ECCS-Modes 1, 2, 3 11 did not previously provide a specific Action requirement for the above testing, and therefore TS 3.0.3 was entered when the te~t was performed in Modes 1, 2, A precaution in the procedure was

provided to instruct operators to enter TS 3.0.3 when an SJ49 is close However, TS Amendment No. 70 resolved the need to enter TS 3.0.3 by adding a specific Action requirement for when both trains of ECCS subsystems become inoperabl In summary, although the test was performed in Mode 4 and TS 3.0.3 entry was not required, TS 3.0.3 was entered due to an existing procedure precaution that should have been deleted with the implementation of Amendment No. 7 NRC Unresolved Item No. 50-272/89-21-03 addresses the adequacy of, the licensee's program to implement TS amendment The problem described above indicates that weaknesses remai The licensee initiated pro-cedure changes on both units to resolve the specific concerns, and stated that a broader review will be initiate The inspector will review the effectiveness of the licensee's programmatic actions during followup for this ite The inspector questioned the licensee's position concerning exiting TS 3.0.3 just before one hour expires (and restoring system to nor-mal) to preclude a unit shutdow The licensee stated that revised guidance was recently approved and issued to station operators con-cerning proper implementation of TS 3. Subsequent TS 3. entries and implementation will be evaluated by the NR Technical Specification 3.0.3 Entry and Power Reduction On January 25, 1990, during the performance of an 18 month surveil-lance test (channel calibration) on the Unit 2 Nuclear Instrumenta-tion System (NIS) power range channel 2N43, Technical Specification (TS) 3.3.1 was entered due to the Channel (one of four) being taken out of servic The unit was ope~ating at full powe One of the TS Action requirements specifies that while one channel is out of ser-vice, quadrant power tilt ratio (QPTR) must be monitored once per 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> The test began at 9:36 a.m. on January 25, 1990, and the channel calibration normally takes about six hour However, the technician performing the test encountered procedural flaws that caused delays in performing the tes At about 4:00 p.m., the unit operators were informed that a QPTR must be performed since it was likely that the test would not be completed by 9:36 p.m. (within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />).

The Action requirements of TS 3.3.1 also specify that the QPTR must be verified consistent with the normalized symmetrtc power distribu-tion obtained using the movable in-core detectors once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when reactor power is greater than 75%.

An alternate option allowed is to reduce power to 75% and reduce the power range neutron flux trip setpoint~ to 85% reactor powe At 4:30 p.m., the licensee be-gan a flux map, however, computer and data problems were encountere Operations personnel were notified that the flux map results would l

• not be available within the required time, therefore, at 8:58 p.m.,

Operations supervision directed a load reduction to less than 75%

powe The unit reached 74% power at 9:36 Operations supervision then directed the reduction of the neutron flux trip setpoints (to 85%).

Unit personnel could not determine whether removing the other channels (one at a time) for the setpoint reduction was permitted by TS Action 2.b of TS 3.3.1 allows one additional channel to be bypassed for up to two hours for surveil-lance testing, but changing the setpoints was not a surveillance tes Therefore, TS 3.0.3 was entered at 10:21 p.m., and a power reduction, as specified by TS 3.0.3 was initiated at 10:40 The licensee notified the NRC of this event*as required by 10CFR50.7 On January 26, 1990 at 12:57 a.m., the 2N43 channel calibration was successfully completed and the Actions required by both TS 3.0.3 and TS 3.3.1 were terminate The load reduction was stopped at 48%, and the unit commenced a load increase to full powe The licensee completed a root cause investigation for this even The causes i~clude:

deficient Instrument and Control Surveillance procedure, and lack of contingency plan (flux map system operability not pre-verified, untimely notification of Reactor Engineering person-nel, and ineffective com*municatio The inspector reviewed the licensee's root cause investigation, which also documented the corrective actions taken and recommended addi-tional corrective actions to station managemen The inspector found the root cause evaluation to be adequ~t No additional concerns were identifie Operational Transient During Startup On January 23, 1990, while in Mode 2 (Startup), a Unit 2 operational transient requiring prompt operator action occurred, due to an apparent equipment failur Reactor power was about 3%.

During startup activities, steam generator (SG) water levels began to de-crease rapidl Plant operators did not immediately know the reason for the decrease, however, it was subsequently determined that the steam dump system had inadvertently actuate The operators imme-diately isolated the steam dump system and stabilized SG water level During the transient, the water levels had dropped signi-ficantly, and one out of the three low-low water level reactor trip setpoints initiated conservatively on the No. 22 S The actuation of two out of the three channels on any SG generates a reactor trip

2. signa Systems were stabilized, the steam dump system was opera-tionally restored, and the unit startup continue No further sig-nificant problems were encountere The inspectors were in the control room during the transien The inspectors discussed the unit and operator response to the event with the involved licensed personnel and Operations managemen The cause was determined to be a spurious actuation of the steam dump syste The 1 icensee informed the inspector that 'a detailed investigation would be performed and documented, since the event jeopardized reac-tor operation and nearly resulted in a reactor tri On February 9, 1990, the inspector questioned the licensee regarding the status of the investigation, and found that the review of system and operator response had not yet been initiate The inspector de-termined that licensee followup to this event, including review of the appropriateness of operator action, was not aggressiv This concern was brought to the licensee's attention, who committed to initiate the appropriate revie Hope Creek Reactor Scram on January 6, 1990 Sequence of Events and Licensee Review

• The Hope Creek unit automatically scrammed at 1:20 a.m. on January 6, 1990, from 96% power due to a main turbine tri The cause of the main turbine trip was a high level trip of the 11A 11 moisture separa-to Weekly surveillance testing was in progress on the turbine overspeed protection system in accordance with OP-ST.AC-00 The turbine main stop valves were successfully stroked and the combined intermediate valves* stroking was in progress when the high level moisture separator trip and reactor scram occurre Pl ant response to the scram was norma Reactor pressure increased to approximately*

1075 psig and the two low-low setpoint safety relief valves opened as require Reactor level was recovered by the reactor feed pump The licensee performed their normal post scram review as required by procedure OP-AP.ZZ-10 In addition, a Significant Event Response Team (SERT) was convened to review the scra The licensee's root cause analysis identified the following causal factors:

one of the three normal drain paths had been inadvertently isolated; failure of the normal drain and emergency dump systems to respond to high mois-ture separator level; and a licensed operator procedural non-compliance during testin This non-compliance was two-fold: the correct order of testing valves was not followed; and a required one

---

---

~

minute wait between valves was not don The operator did verify that the electrohydraulic control system was stabilized which the procedure stated was the basis for the one minute wait perio Licensee corrective actions included the following:

restoration of all normal drain paths, modification of setpoints, gains, and reset ratis; and recali-bration and at-power tuning/testing of both normal and emergency moisture separator level control systems, satisfactory performance of the surveillance test at 20-25% and again at 80-85% reactor power, revision to procedure OP-ST.AC-001, re-emphasis by plant management regarding operations expecta-tions in a memorandum dated January 7, 199 In addition, the SERT also performed a root cause analysis and made recommendation The SERT concluded that the scram was caused by mis-operation of the 11A 11 moisture separator level control system due to a non-optimum setting of the normal drain level controller, slug-gish response of emergency drain level controller and instrument air being isolated to one of the normal level control valve The licensee completed post scram reviews and implemented corrective action The unit restarted and achieved criticality at 6:25 on January 9, 199 The turbine generator was synchronized at 1:22 a.m. on January 10, 199 The licensee successfully completed sur-veillance testing and tuning of the moisture separator level control and drain systems at 20% power and again at 85% powe The unit's power was then increased to near full powe NRC Review and Conclusions The inspector reviewed post scram plant conditions and assessed lic-ensee action The inspector reviewed control room instruments and recorder traces, interviewed on-shift operators and management per-sonnel, reviewed emergency procedure implementation and reviewed the post scram review checklist (OP-AP.ZZ-101).

The inspector noted that licensee plant and operations management had responded to the site for scram followu The inspector also reviewed the January 7, 1990, 110perations Expectations 11 memorandum from plant managemen This memorandum reemphasized procedure compliance to all licensed and non-licensed operator The inspector also reviewed the SERT report, including the root cause analysis and recommendations. * *

Th~ licensee identified procedure violation is a non-cited violation because it.meets the criteria specified in Section V.G of the Enforcement Policy (NCV 50-354/90-01-01).

The inspector expressed concern regarding the isolated air supply valve and any potential generic issues associated with the control of system alignmen The licensee committed to review this issue in LER 90-001 (section 9.1).

This item remains unresolved pending completion of licensee actions and NRC review (UNR 50-354/90-01-02).

The inspector concluded that the licensee performed an adequate review of the scram, and imple-mented or proposed adequate corrective action High Pressure Coolant Injection (HPCI) System Isolation on January 19, 1990 The HPCI system isolated o~ high room differential temperature at 7:17 a.m. on January 19, 199 With the HPCI system.in a standby mode, the steam supply outboard isolation valve (F003) automatically close The high differential temperature resulted from a combina-tion of the normally high room temperature (104 degrees F) and a re-duction in the ventilation supply temperature (36 degrees F).

The room is normally hot due to the steam piping in the roo The supply temperature was reduced when plant heating steam was isolated to the building due to rece~t warmer outside temperature The HPCI room cooler was manually placed in service, the heating system steam was returned to service, and the HPCI isolation was reset, and HPCI was returned to its normal standby lineup at 8:02 The licensee noted that the isolation setpoint was 70 degrees and the isolation occurred at 68 degree An ENS call was also made as required by 10CFR50.7 The inspector was in the control room at the time of the even The inspector verified that licensee actions were in accordance with system and abnormal operating procedure The inspector checked actual room temperatures, and confirmed that the room temperature was about 105 degrees System drawings, the FSAR and Technical Speci-fications were also*reviewe The inspector noted that the HPCI room temperature was within the design bound However, the temperature was also only several degrees from the automatic starting of the room coolers, and at a temperature of 115 degrees F, entry into emergency operating procedure OP-EO.ZZ.103, Reactor Building Control is re-quire The licensee stated that a HPCI room temperature of 100-105 degrees F was normal at Hope Cree Engineering personnel stated that a further review of HPCI room temperatures would be undertake The inspector had no further questions at this tim Feedwater Heater Isolation Event on January 23, 1990 At 11:00 a.m. on January 23, 1990, during feedwater heater drain valve troubleshooting, heater isolations and level oscillations occurre Moisture separator 11A 11 and 118 11 levels increased to the

high level alarm.* The setpoint and co~troller changes that the lic-ensee implemented (see Section t.2.4.A) were effective i~ controlltng leve The operators implemented procedures OP-AB.ZZ.113 and 300; and reduced unit load to 82%.

The operators recovered the tripped feedwater heaters in a timely fashion; thus avoiding a high' level moist~re separator trip, turbine trip, and reactor scram~

The inspector was in the control room during the recovery and troubleshooting phase of this transient. The inspector discussed plant and human response with the operators, ihift supervisor and management personn~ Th~ inspector verified procedural compliance

• and reviewed incident report 90-0 The inspector concluded that the licensed control room oper~tors responded to the event in a timely manner to prevent a unit scra In addition, a thorough incident report was written the same da One item that was noted by the licensee during post event review, was*

• that one of three level switches {Magnetrol float type) for moisture separator 11A 11 high level turbine trip was actuate Apparently, this had been actuated during the unit scramon January 6, 1990 (See Sec-tion 2.2.4.A) and had never rese This item was missed during that scram revie A high-level alarm i~ annunciated in the.control roo A high-high level trip is annunciated if the 2 of 3 coinciderice logic is satisfied.. If only one of the high-high *1evel devices actua~es, th~ control room is unawar The licensee initiated actions to address this~ including a CRIDs (comp~ter) display of the status of all partial (e.g, 1 of 3) main turbine trip logic initiati6n..

RADIOLOGICAL CONTROLS (71707, 83750) Inspection Activities PSE&G's compliance with the radiol~gical protection program was verified on a pe~iodic basi These inspection*activities w~re conducted in accordance with NRC inspection procedures-71707 and 8375.2 Inspection Findings and Review of Events 3. Salem The inspector toured the Unit 2 containment on January 17, 199 This inspection was conducted after a unit shutdown due to a leak in the charging syste The inipector accompanied licensee operations,

• maintenance, engineering and radiation protection personne The in specter noted the following:

the c'onta i nment was adequately main-ta i ned; licensee personnel pe~formed in~pections per procedural re-quirements; minor deficiencies were documented and adequately dis-positione **

3. *

Hope Creek Plant Tours

A specialist inspector toured the station periodically during the period January 8-12, 199 The following items were reviewed:

Posting, barricading and access control (as appropriate) to radiation, high radiation, and airborne radioactive area Posting, labeling, and control of radwaste and contaminated materia Personnel contamination control, including personnel use of friskers and portal monitor Proper wearing of dosimetry by personne Efforts to reduce the volume of contaminated trash including steps to minimize introduction of uncontaminated material into contaminated area Housekeepin Industrial safety practic The following observations were made:

Radioactive and contaminated material was properly labeled and controlle Personnel contamination control and monitoring devices were used properl Personnel were observed to be wearing dosimetry properl The following matters were brought to the licensee's attention:

Housekeeping in general was considered goo However, the Hot Machine Shop exhibited dirty and dusty condition The licensee immediately initiated action to clean up the are Several signs were noted to be obscured:

A sign specifying hearin~ protection when entering the con-denser bay from elevation 102 1 *

• An unsafe scaffolding sign on the 102' elevation of the condenser ba A radiological excl~sion area sign in the control rod drive maintenance roo The licensee immediately initiated action to move these sign Overall, tour observation findings indicated good radiation protec-tion practice ALARA Performance The inspector reviewed selected aspects of the licensee's efforts in 1989 to reduce occupational radiation exposure to as low as reason-ably achievable (ALARA).

During 1989, the licensee experienced several outages, including a refueling outag The licensee attained an aggregate exposure of 419 person-rem, 294 person-rem which was attributed to work performed during the refueling outag The lic-ensee had established an outage goal of 217 person-re During the refueling outage, the licensee experienced problems with a higher degree of crud in the reactor cavity than expecte The licensee established a task force to review the problem and recommend a solution for next outag The implementation of the task force recommendations will be reviewed during the next refueling outag The licensee performed ALARA planning for over 80% of the exposure receive Also, ongoing job reviews were performed for selected job During the refueling outage, the licensee encountered some jobs (e.g. control rod drive pulling and refueling floor activities)

that resulted in the accumulation of personnel exposures at a rate faster than expecte The licensee suspended the jobs and held special ALARA committee meetings to discuss the work activitie Overall licensee attention to minimizing accumulated exposure was goo.

MAINTENANCE/SURVEILLANCE TESTING (62703, 61726)

4.1 Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate indus-trial codes and standard These inspections were conducted in accordance with NRC inspection procedure 62703.

• • *

Portions of the following activities were observed by the inspector:

Unit Salem 2 Hope Creek Work Order or Procedure 90-117181/M6E Rev. 3 900121060 89-0811090/MD-GP.Zz~oo3 90-0205066/MD-GP:ZZ-041 91-0414169/lBFSV-139 Description 23 Charg~ng Pump Replace valve 24SW58 Repack valve F025 Replace amplifier diaphragm on 1B-VH407 fan activator Scram solenoid pilot valve maintenance The maintenance activities inspected were effective with respect to meet-ing the safety objectives of the maintenance progra Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance package The inspectors verified that the surveillance tests were per-formed in accordance with Technical Specifications, approved procedures, and NRC regulation These inspection activities were conducted in accordance with NRC inspection procedure 6172 The following surveillance tests were reviewed, with portions witnessed by the inspector:

Unit Hope Creek Salem 1 Salem 2 Salem 2 Procedure N HC.MD.ST.PJ-004(Q)

lC-FT.AB-033 lC-CC;SN-004 lPD-2.6.030 SP(0)4.3. III-1. Test Battery 100413 Performance Test Functional Test of Safety Relief Valve Acoustic Monitor Channel Calibration of Division 4 Automatic Depressurization System Timer No. 11 Steam Generator Steam Pressure Protection Channel I Test Turbine Overspeed Protection Turbine Valve Tests The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra *

4.3 Inspection Findings 4. Salem Automatic Stearn Line Isolation During Surveillance Testing On January 17, 1990, while in Mode 4 (Hot Shutdown), a Unit 2 steam

. line isolation (SLI) actuation occurred during surveillance testin Instrument and Control (I&C) technicians were performing a monthly channel functional test using surveillance procedure 2IC-2.6.025, 11 2PT-506 First Stage Turbine Impulse Pressure - Channel II 11 *

The procedure is designed to be used at power, however, it included a precaution which directed the performer to immediately notify the supervisor if the required indications cannot be obtaine Procedure steps required that the safety injection low Tave and safety injec-tion low steam line pressure reactor protection status panel lights (8) are of Since the unit was in Mode 4, the normal configuration

_ is that the lights are lit (bistables tripped).

In conformance with the procedural precautions, the appropriate I&C supervisor was noti-fied, as well as control room licensed operators, and the technician*

was directed to continue the surveillance tes When the second (of four) safety injection high steam line flow bistables were tripped for the test, an automatic SLI occurre The main steam line isola-tion valves (MSIVs) received a closure signal, but were already close The MSIV bypass valves were open and they automatically closed as designe Control room operators subsequently reset the SLI signal and reopened the bypass MSIV The licensee notified the NRC of the ESF actuation in accordance with lOCFRS0.72 reporting re-quirement Inspector followup and review of this event identified several con-tributing causes and concern The surveillance procedure, designed for power operation, provided no specific testing limitations or guidance for performing the test in different operational mode The technicians, supervisors and licensed operators who discussed the off-normal indicatio~s failed to. recognize and expect a SLI when the low flow bistables were to be trippe The control room display in-cludes a "steam line isolation safety injection blocked A and 8

status light, which becomes lit only when the steam line differential pressure safety injection signal is blocke This indicator was lit during the test, and personnel involved with this event incorrectly believed that the lit display indicated an SLI bloc By design, the SLI cannot be blocke Discussions with I&C and Training personnel identified that both Operator and I&C training inconsistencies may have contributed to the incorrect assumption Due to the numerous contributing causes for this event, on January 25, 1990, the inspector questioned the licensee whether a systematic human performance type of evaluation had been initiated or planned.

The licensee stated that none had been considered, however, agreed

• that this event would be a good ~andidate for such an evaluatio Pending completion of the licensee's evaluation and inspector review of the licensee 1s corrective actions, this item is unresolved (UNR 50-311/90-04-01).

4. Hope Creek Scram Solenoid Pilot Valve Maintenance Deferred The inspectors observed portions of hydraulic control unit (HCU)

isolation (OP-SO.BF-002) and preparation for dual solenoid valve re-placement (work standard lBF SV-139).

This HCU work was elective and intended to reduce outage wor During performance of the work standard, it was noted that the 139 valve associated with each of the 185 HCUs was mislabeled as a 129 valv The electrical supervisor discovered the discrepancy and took appropriate compensatory meas-ure The electrical supervisor submitted a work request to cor-rectly label the 139 valves and to enhance the labeling of all HCU valves by adding an HCU specific designator in the valve identifie The four HCUs chosen for 139 valve replacement were all deferred as their respective nitroge~ isolation valves (Vl16) leaked sufficiently to raise concerns of scram initiation if the scram air header bled down sufficiently.

EMERGENCY PREPAREDNESS (71707) Inspection Activity The inspector reviewed PSE&G 1 s compliance with 10CFR50.47 regarding im-plementation of the emergency plan and procedure In addition, licensee event notifications and reporting requirements per 10CFR50.72 and 73 were reviewe.2 Inspection Findings No unacceptable conditions with respect to licensee event notifications were note The licensee was not required to implement any emergency plan pr~cedures during the inspection perio.

SECURITY (71707) Inspection Activity PSE&G 1 s compliance with the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundarie These inspection activities were conducted in accordance with NRC inspection procedure 7170 **

. Inspection Findings The inspector reviewed the Salem/Hope Creek Safeguards Event Log and associated report dated January 31, 199 No unacceptable conditions were note.

ENGINEERING/TECHNICAL SUPPORT (71707, 92700)

7.1 Salem Salem Radiation Monitoring System (RMS) Problems Th~ RMS has initiated numerous ESF actuatitins since 198 These events were discussed in previous NRC resident inspection reports; in NRC Inspection 272/89-10; 311/89-09; in Section 2.2.l.A of this re-port; and in NRC open item 272/89-06-01., Sixteen reportable events have occurred during this current inspection perio The licensee believes the prevalent root cause to be equipment failure/radiation monitoring spikin The RMS is primarily composed of Victoreen in-strument The problems are caused by voltage spikes, dirty RMS module connectors, and the overall aging of the equipmen The lic-ensee is pursuing modifications to the syste The inspector reviewed these RMS problems by:

discussing the issue with the system engineer and plant man-agement, reviewing Technical Specifications and related system drawings, and reviewing a memorandum dated January 17, 1990 that addresses the licensee 1 s corrective action plan, touring the plant inspecting RMS equipment in the field and in the control room, and reviewing recent LERs regarding the RM The inspector concluded that the licensee has initiated adequate cor-rective actions to address these RMS problem However, the time frame for these actions is such that they will not occur until later in 1990 and into 199 Main Steam Isolation Valve (MSIV) Slow Closure Times As reported in Unit 2 LER 89-16, 3 of 4 MSIVs exhibited slow closure times in October 1989 and at other previous time The licensee has contacted the vendor (Hopkinson-Ferranti) and other users of this valve (D.C. Cook Plant and several French plants).

The other users

• • *

believe the root cause for slow closure times to be leaking vent valve Each MSIV operator has two vent valves (MS-169 and 171),

which when open, cause the MSIV steam cylinder to depressurize re-sulting in valve fast closur A leaking vent valve apparently re-stricts the internal self-draining feature of the steam cylinde This action cause~ a moisture buildup inside and atts as a hydraulic loc A modification to iricrease the size of the internal drain has been performed at other plant This modification is also being pur-sued at Salem, pending results from the other plant The inspector reviewed the LER; discussed the item with system engi-neers, operators and licensee management; reviewed technical infor-mation and drawings; and inspected the Unit 1 and Unit 2 MSIVs in the fiel The inspector had no further questions at this tim Salem Charging System Problems Over the past several months, the licensee had experienced numerous operational problems with the ch~rging system for both unit Each unit uses two centrifugal charging pumps, which function as high pressure safety injection (SI) pumps, and one positive displacement pump, primarily used for normal plant operatio Each unit 1 s system contains a boron injection tank (BIT).

However, the system was modi-fied to eliminate the use of highly concentrated boric acid solution in both unit The particular charging system problems have been various, and in-clude the inability to satisfactorily meet a high pressure SI flow test on May 20, 1989 due to having four flow metering orifices in-stalled backwards, charging system relief valve le~ks, inoperable centrifugal pumps due to increased bearing temperatures, a leaking welded pipe cap from 1 1/4 11 line connected to the BIT, a leaking BIT manway cover, and several positive displacement pump problems (in-cluding cracked cylinders).

On January 19, 1990, the inspectors met with licensee engineers to ascertain whether the problems were related to a common cause and whether maintenance practices were adequat The licensee stated that they were involved in attempting to identify common causes, how-ever, to date, none have been identified. Additionally, maintenance activities (corrective and preventive) are monitored and trended by the licensee to identify and correct adverse performance characteris-tic The inspectors did not identify any specific deficiencies associated ~ith the licensee 1 s plan to address charging system fail-ure Performance in this area will continue to be monitored during routine inspections.

• Potential Cable Separation Deficiencies During periodic plant tours of Salem Units 1 and 2, the inspecto identified several potential cable separation deficiencies in that the required separation criteria may not have been me During the last routine resident inspection (No. 50-272/89-26; 50-311/89-24),

the inspector identified an extension cord in the radiologically con-trolled area that was routed via two separate cable trays (one tray was safety-related) to a radiation portal monito During this in-spection, the inspector noted several more long extension cords routed to temporary/portable equipment al9ng various components throughout the plan There did not appear to be adeq~ate admini-strative controls to ensure that cable separation requirements were not compromise Also, in several plant areas, such as the control and cable spreading areas, there were many examples of communication cabling routed oµtside of cond~it in a fashion similar to the exten-sion cord The licensee stated that they had previously identified that as a concern, however, have not yet addressed and resolved the proble The communication cables are low voltage cables, thereby reducing the safety impact with respect to separatio The inspector also performed a walkdown of selected cable raceways and identified several concern Licensee representatives from the Operations and Technical Departments accompanied the inspector and noted the specific concerns for resolutio Many of the concerns appeared to be related to dressing/housekeeping of the cables and tray Pending further review by the inspector, and licensee resolu-tion of the above concerns, including a review of the licensee's com-pliance with cable separation requirements, this item is unresolved (UNR 50-272/89-04-01).

7.2 Hope Creek Leak in Recirculation Flow Transmitter Line The licensee identified a leak in a non-isolable flow transmitter instru-ment line on the 118 11 recirculation loop on December 31, 198 (See NRC Inspection 50-354/89-20).

The leak occurred in a socket weld joining a type 304L-SS Schedule 40-1 11 diameter pipe to the recirculation loop elbo Liquid penetrant examination revealed two rounded indications (1/32 11 to 3/64 11 ), which were apparently responsible for the leakag Repairs con-sisted of cutting out the failed weld and replacing it with a new pipe to elbow assembl The failure was apparently an isolated case that was re-lated to weld defects which originated during installatio This explana-tion was supported by the fact that liquid penetrant inspection of four-teen other similar joints in the same system did not reveal any defect The licensee is planning to perform a metallurgical examination of the

failed joint.to positively determine the cause of failur The investi-gation will also include radiography to determine possible fit up defi-ciencie the inspector will revie~ the final repor It is noted that the failure does not appear to be related to the previous failure involving four branch connections in the vent and drain line In those cases the defects were found to be due to circumferential cracks caused by vibrating fatigue that resulted from cantilevered load The inspector concluded that licensee actions were appropriat.

SAFETY ASSESSMENT/QUALITY VERIFICATION (40500) Salem Significant Event Response Team (SERT) and Root Cause

. The Salem General Manager initiated two SERT reviews of abnormal event On January 22, 1990, a SERT was convened to review the cir-cumstances regarding 3 recent excavation incidents that impacted on underground electrical cable On January 31, 1990, another SERT was convened to review the circumstances regarding 3 plant events caused by scaffold crews in plant electrical room Each SERT independently determined the root cause to be previously ineffective corrective actions, and made new recommendation The inspector concluded that each SERT appeared to have conducted a timely in-depth review, accu-rately determined the root cause of the events, and made effective short and long term recommendation Slow Follow-up to a Plant Transient As discussed in Section 2.2.3.E, a 11 near miss" reactor trip on Unit 2 during startup was not reviewed in a timely manne.2 Hope Creek Significant Event Response Team (SERT) and Root Cause The Hope Creek Ge~eral Manager initiated one SERT review during the inspection perio Another SERT was initiated last inspection perio These SERTs reviewed the two recent automatic scrams (December 30, 1989 and January 6, 1990) that occurred during main turbine testin The inspector concluded that each SERT effectively reviewed the scrams in a timely manner, determined root cause and recommended corrective action In addition, the inspector noted that plant management is not hesitant in concluding that personnel error or ineffective management to be root cause For example, the December 30, 1989, scram 1 s root cause.was co~cluded to be failure of management to implement a design change (see LER 89-25 in Section

9.1).

Also, the January 6, 1990 scram's root cause was failure of the technical group and maintenance to adequately set the moisture separator drain tank level controller.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOW-UP (90712, 90713, 92700) LERs and Reports PSE&G submitted the following licensee event reports (LERs) and special and periodic reports, which were reviewed for accuracy and adequacy of the evaluatio The asterisked (*) items identify reports which involve lic-ensee identified Technical Specification violations which are not being

cited based upon meeting the criteria of 10 CFR 2 Appendix Salem and Hope Creek Monthly Operating Reports for December, 1989 Salem Unit 1 Supplemental Special Report 88-3-17 and 88-3-18 concerns an update addressing fire barrier penetration seal impairment Salem Unit 2 Special Report 90-01 concerns a Unit 2 emergency diesel gene-rator valid failure that occurred on January 9, 199 The failure was due to a defective governor, which was identified during surveillance testing and subsequently replace No inadequacies were identified with respect to this repor Sal em LERs Unit 1 LER 89-030 concerns an event on October 11,.1989, in which a worker inadvertently pushed the emergency trip button for the 111c

diesel generator, rendering the emergency power supply for the associated containment fan coil unit (CFCU) and con-tainment spray (CS) header inoperabl Inspector review of this LER identified several concern The inspector de-termined the root causes Qf the event to be personnel error and inattention to detail with human factors design defi-ciencies as a contributing cause; the licensee determined the root cause to be solely human factors design concern The inspector determined that the LER 1 s safety assessment of the event was inadequat It provided inaccurate in-formation and did not assess the event based upon actual and design basis conditions. Specifically, it failed to address the conditions for the actual design basis accident which assumes only one CFCU and one CS header is availabl The inspector determined that the overall quality of the LER was poor and should be resubmitte The licensee acknowledged the inspector 1 s concerns and agreed to re-submit the LE,.

LER 89-033 LER 89-034

• LER 89-035 LER 89-036 LER 89-037 LER 90-001 Unit 2 LER 89-024

concerns a controlled plant shutdown due to an inoperable charging pump on November 28, 198 This event is dis-cussed in NRC Inspection Report Nos. 50-272/89-26; 50-311/89-2 The LER documented the root cause of the event to be equipment failur However, further LER review and subsequent inspector followup determined that the root cause of the resulting equipment problem.was unknow See Section 7.1.C of this report for a discussion on other charging pump problem concerns containment ventilation isolations caused by radiation monitor 1R41C spiking on December l, 9, 14 and 15, 198 (See Sections 2.2.1 and 7.1.A of this report).

No inadequacies were noted relative to this LE concerns a licensee identified noncompliance with Technical Specification 3.0.4 in that the unit entered Mode 4 (Hot Shutdown) from Mode 5 (Cold Shutdown) without satisfying a particular Mode 4 requiremen Specifically, on December 10, 1989 a containment compressed air supply valve (1SA118)

was found open while in Mode The valve is required to be closed for containment isolatio The licensee subse-quently verified that a downstream check valve (1SA119) was operable, thereby providing containment integrit The inspector did not identify any deficiencies associated with this LE concerns a steam generator blowdown radiation monitor 1Rl9C failure resulting in an ESF actuation on December 20, 198 (See Section 7.1.A).

No inadequacies were noted relative to this LE concerns a steam generator blowdown radiation monitor spike (1R19) during channel calibration which caused an ESF actu-ation on December 30, 198 The 11censee identified the root cause to be system desig See section 7.1.A of this repor No inadequacies were noted relative to this LE concerns two January 6, 1990 ESF actuations isolating containment ventilation due to containment particulate radiation monitor (lRllA) electrical spike See Sections 2.2.1.A and 7.1.A of this repor No LER inadequacies were identifie concerns a December 1, 1989 ESF actuation (emergency diesel generator start) due to personnel erro See NRC Inspec-tion Report Nos. 50-272/89-26; 50-311/89-2 No LER in-adequacies were identifie *

LER 89-025 LER 89-026 LER 89-027 LER 90-001 LER 90-003 LER 90-004

concerns a control room ventilation isolation caused by a radiation monitor 2R1A spike on December 20, 198 (See Section 7.1.A).

No inadequacies were noted relative to this LE concerns a plant vent noble-gas radiation monitoring (2R41A) system spike which initiated an ESF actuation on December 28, 198 See section 7.1.A of this repor No inadequacies were noted relative to this LE concerns a steam generator blowdown radiation monitor

,(2R19B) system spike which caused an ESF'actuation on December 31, 198 See section 7.1.A of this repor No inadequacies were noted relative to this repor concerns a control room radiation monitor spike (2RlA)

which caused an ESF actuation on January 1, 199 See sec-tions 2.2.1.A and 7.1.A of this repor No inadequacies wee noted relative to this LE concerns an ESF actuation (steam generator blowdown) due to an electrical spike on a radiation monitor on January 5, 199 See Sections 2.2.1.A and 7.1.A of this repor No inadequacies were note toncerns an ESF actuation (containment ventilation isolation) due to a failed monitor on January 6, 199 See Sections 2.2.1.A and 7.1.A of this repor No inadequacies were noted relative to this LE Hope Creek LERs LER 89-025 LER 89-026 LER 90-001 concerns an automatic unit scram on December 30, 1989 during main turbine thrust bearing wear detector (TBWD)

testin This event was reviewed in NRC Inspection 354/89-2 The licensee's initial root cause analysis de-termined that failure of the TBWD limit switch caused the scra However, failure to_ implement a design change iden-tified in 1986 was the licensee's final root cause of the scra No inadequacies were noted relative to this LER.-

concerns a reactor coolant pressure boundary leak identified during a drywell inspection on December 31, 198 (See section 7.2.A of this report)

concerns an automatic unit scram on January 6, 1990 during main turbine combined i_ntermediate valve testing. This event is discussed in Section 2.2.4.A of this inspection report.

9. 2 Open Items The following previous inspection items were followed up during this in-spection and are tabulated below for cross reference purpose Salem 272/89-23-01 272/89-06-01 1 EXIT INTERVIEW ( 30703)

Section 2.2.. Status Open Open The inspectors met with Mr. L. Miller and Mr. J. Hagan and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activitie Based on_Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restric-tion ATTACHMENT 1 RADIATION MONITORING SYSTEM ENS CALLS Date/Time Un1t Rad Monitor Effect/Cause 1/1/90 9:05 R1A Control room radiation monitor spike and isolation 1/5/90 5:00 R19B Steam generator blowdown radiation monitor spike and isolation 1/6/90 2:04 a.rr lRllA Radiation monitor spike and containment ventilation isolation 1/6/90 10: 11 lRllA Radiation monitor spike and containment ventilation isolation 1/12/9_0 7: 52 R41A Radiation monitor spike and containment ventilation isolation-1/17/90 8:05 R41A-Radiation monitor spiki and containment ventilation isolation 1/17/90 10: 40 R1A Control room radiation monitor spike and isolation 1/19/90 8:30 R41A, B Containment ventilation violation during restoration after maintenance 1/20/90 5:08 R41C Maintenance on 2R45 caused 2R41C to.spike resulting in containment ventilation isolation 1/22/90 7:24 R41C Monitor spike during source check and containment ventilation-isolation 1/22/90 8:07 R41C Containment ventilation isolation during pressure relief 1/23/90 10:51 R41B Radiation monitor spike and containment ventilation isolation 1/24/90 11 :25 Unknown Containment ventilation isolation for unknown reason

\\

Attachment 1

1/30/90 7:08 p; R41B Radiation monitor failed resulting in containment ventilation isolation 1/31/90 6:33 R418 Radiation monitor spike and containment ventilation isolation 2/1/90 1:12 R41A Radiation monitor failed causing containment ventilation isolation