IR 05000272/1989022
| ML18094B159 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/07/1989 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18094B158 | List: |
| References | |
| 50-272-89-22, 50-311-89-20, NUDOCS 8911150002 | |
| Download: ML18094B159 (15) | |
Text
Report N License Licensee:
Faci 1 ity:
Dates; -
Inspector-s:
.Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/89-22 50-311/89-20 DPR-70 DPR-75 Public Service Electric and Gas Company P, o. Bc:ix 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station - Units 1 and 2 September 5, 1989 - October 16, 1989 Kathy Halvey Gibson, Senior Resident Inspector Stephen M. Pindale, Resident Inspector
. Swetland, Chief, Reactor Projects Section 2A tl/7/f-;
Date Inspection Summary:
Inspection 50-272/89-22; 311/89-20 on September 5, 1989 - October 16, 1989 Areas Inspected:
Resident safety inspection of the following areas:
operations, radiological controls, surveillance testing, maintenance, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and review of licensee report Results:
Several instances of prompt licensee response to incidents and good attention to detail were noted during this inspectio Three'unre~olved it~ms were identified concerning the improper implementation of a Technical Specifi-cation required action (Section 2.2.3.A), the import of motor operated valves with heaters energized (Section 5.2.C), and overdue calibration of various security computer system meters (Section 7.2.B) *
Details SUMMARY OF OPERATIONS At the_beginning*of the inspection period, Unit 1 was operating at 55%
power due to a feedwater system valve failure and Unit 2 was operating at 100% powe Unit 1 returned to full power operation on September 10, and continued until September 18, when power was once again reduced to 55%
due to feedwater system problems.. The unit was returned to full power on September 25 and continued until the end of the ihspectio Unit 2 reduced power to 90% on October 5 due to a main transformer p~oblem, and on October 13, a controlled shutdown was initiated to replace the degraded ph*ase B transforme At the end of the inspection, Unit 2 was in Mode 5 (Cold Shutdown) for an approximate two week outag.
OPERATIONS (71707, 71710) Inspection Activities On a daily basis throughout the report period, the inspectors vetified
.that the facility was 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 facility, interviews and discussions with personnel, independent verifi;..
cation of safety system status and Limiting Conditions for Operation, an review of facility record These inspection activities included 278 inspection hours including weekend and deep backshift inspections on September 11 (4:25 p:m. - 10:00 p.m.), September 20 (2:15 a.~. - 5:00 a.m.),
and October 11, 1989 (4:00 a.m. - 5:00 a.m.).
2.2 Inspection Findings and Significant Plant Events 2. Unit 1 On September 18, Unit 1 reduced power from 100% to about 55% to remove No. 12 steam generator feedwater pump (12SGFP) from service due to high vibrations. A plant oper*tor noted an abnormal* operating sound at the pump, and followup vibration monitoring by an offsite vendor indicated higher than normal values, although installed vibration equipment indicated normal value The licensee identified a wiped bearing upon pump disassembl Additionally, the 12SGFP turbine had experienced about a 30 mil upward growt The licensee attributed the pump and turbine problems to a possible shaft misalign-men The licensee stated that the pump/turbine unit, which is
connected to the large diameter feedwater p1p1ng, is very sensitive to minor misalignment The pump was subsequently repaired and properly aligned, and the unit wa~ returne~ to full power on -
September 2 No similar problems occurred upon startup and subsequent operatio The licensee used more precise vibration monit6ring to measure component growth during startup to detect problems in a timely manne In this case, prqmpt identification by station personnel assisted in early detection of the problem and possibly prevented an operational transien The 1nspector had no further question *
2. Unit 2 On September 21, a system.engineer recognized that a phase B MPT local instrument indicated a high total combustible gas (TCG)
concentratio The system engineer immediately requested that a transformer oil sample be drawn and analyze The results yielded a TC~ concentration of 2400 ppm, as compared to the previous weekly samp 1 e result of 907 ppm.-
No acetylene was detected in the
- analysis._ Daily samples were taken and the TCG concentration reached approximately 3100 ppm on September 2 The licensee then began taking three samples daily to monitor TCG trend Additionally, unit load was reduced to 90% reactor power on October 5 to reduce the heat load on the main power transforme TCG concent.ration peaked at about 4500 ppm, which is indicative of an internal hot spot in excess of 700 degrees Licensee review of the TCG concentration trend charts revealed a significant amount of fluctuation between sample Therefore, the licensee concluded that the appropriate and most prudent action would be to take the unit off-line and repair the transformer before conditions seriously degrade On October *13, a Unit 2 controlled shutdown was initiated to replace the phase B main power transformer (MPT).
Licensee management elected to shutdown the unit to Mode 5 (Cold Shutdown) so that additional shutdown work activities could be performed, such as solid state protection system wire pull testing, control rod drive mechanism ventilation repair work and a main steam isolation valve circuitry modificatio An outage duration of about two weeks was anticipate Mode 5 was reached just prior to the end of the inspection period on October 1 Salem has experienced similar transformer problems in the past. -The deficiencies have been attributed to*a susceptible transformer design, aggravated by environmenta*1 geomagnetic induced currents.
- 2. *
The presence of such induced currents were confirmed on September 19 by the electrical system load dispatche The Unit 1 transformers have been ~eplaced with a l~ss susceptible design, and the same change is planned for Unit. 2 during the next refueling 6utage (April, 1990).
The degraded phase B transformer will be replaced with a rebuilt sp~re. The licensee plans to develop preventive action recommendations for plant operators in the event that further reports are received of geomagnetic solar flare Such actions include immediate power reductions of predetermined values and duratio The inspector concluded that the licensee's actions with *
respect to iaentifying, trending and addressing this issue were appropriat The licensee's early detection and prompt outage scheduling/planning, and subsequent decision to shutdown the unjt to prevent either an un~xpected forced shutdown or ultimate transformer failure were particularly no~eworth Both Units On September 9, the licensee* identified that a Technical Specification (TS) required action had not been properly implemente Unit 1 TS 3.3.2.1, Table 3.3-3 requires that when one channel of the auxiliary feedwater (AFW) system automatic start function from an emergency*
trip of the steam generator feedwater pumps (SGFP) is expected to be inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, the affected channel is to be jumpered to start of the motor driven AFW pumps upon the loss of the other SGF On September 4, 12SGFP was removed from service to perform check valve maintenance and was returned to service on September 9, without installing the necessary jumpe Both motor driven AFW pumps are designed to automatically start when both main SGFPs emergency trip (two out of two logic).
The circuitry prevents the automatic start of the auxiliary feedwater pumps when
- the SGFP tr1p is due to a steam generator high water level or when they are tripped manually from the control room consol TS 3.3. requires that a jumper be installed for a SGFP t~ken out of service so that an emergency trip of the operating SGFP will satjsfy the actuation logic and automatically start the motor driven AFW pumps as per design (one out of one logic).
Licensee review of this event identified that during a routine tagout process for a SGFP, a normal evolution was to shut the associated suction valv With the suction valve shut, the licensee stated that a SGFP low suction pressure trip is generated, which is equivalant to a jumper for the associated train of the AFW pump automatic start circuitry. Therefore, upon an emergency trip of the operating SGFP, the AFW actuation function would have been availabl Based on this review, the licensee concluded that this event was not a TS non-compliance issue.
- The licensee also conducted a review of Unit 2 TSs to determine whether a similar concern existed. It was found that the Unit 2 TSs were incorrect in that Table 3.3-i listed two actuation chann~ls per SGFP when in reality there is one per pum Additionally, the Unit 2 TSs do not provide any similar requirement to install a jumper when one SGFP is taken out of service, although system and actuation*
design necessitates such acti The licensee stated that they would administratively implement the appropriate actions on both unit~ and that TS change requests were in process for both unit Although not specifically covered during this ins~ection period, the licensee identified on October 17, that contrary to the previous position, closing the SGFP s.uction valve would not provide the appropriate AFW pump.start logic actuatio The system engineer identified that the standard tagout process included the removal of the 125 voe power supply for the associated circuitry, which de-energizes the trip signal from the out of service SGF ~he licensee was continuing a review of this event at the close of the inspection, including permanent corrective actions, TS and procedure changes and a 10CFR50.73, "Licensee Event Report", applicability determinatio Pending resolution of the issue; this item is unresolved (UNR 50-272/
89-22-01). ESF System Walkdown The inspector independently verified the status of engineered safety feature (ESF) systems by performing system walkdown System components.and support systems were verified to be operable, such as hangers and supports, electrical cabinets, insulation, area ventilation, valves and pumps, and component lubrication and coolin subsystem Proper calibration status for installed instrumentation and proper housekeeping were.also verifie The inspector performed detailed walkdowns of the-auxiliary feedwater (AFW) system The overall status and condition of these systems was acceptabl Individual deficiencies were brought to the licensee's attention for resolution, including examples of materials (e.g. gloves, tools, lubricants) found in normally locked closed AFW instrument panels and missing lock wires associated with Bailey valve positioner The inspector selected for review three NRC Information Notices (INs), 89-48, "Design Deficiency in the Turbine Driven Auxiliary Feedwater Pump Cooling Water System, 89-58, "Disablement of Turbine-Driven Auxiliary Feedwater Pump due to Closure of One of the Parallel Steam Supply Valves, and 89-61, "Failure of Borg-Warner Gate Valves to Close Against Differential Pressure", which were related to the AFW syste The inspector verified receipt and
distributio~ of the INs, reviewed the licensee's internal re~ponses
_and actions~ and concluded that the actions taken were appropriate and timel No concerns were identifie.
RADIOLOGICAL CONTROLS (71707)
3.1 Inspection Activities PSE&G 1 s compliance with the radiological protection program was verified on a periodic basis. These inspection activities were conducted in accordance with NRC inspection proced~re 7170.2 Inspection Findings On September 17, the licensee identified a 6 Rem/hr radiation hot spot'inside the Unit 2 auxiliary building. A firewatch supervisor noted that the firewatch rovjng personnel had received a small, but abnormal radiation dose (less than 5 mRem) following a recent tou The supervisor then notified Radiation Protection (RP) personnel, who performed radiation surveys and identified the 6 Rem/hr hot spot on a section of piping which runs along the floor of the *
demi~eralizer alley cubicl The cubicle is provided with two access points, neither of which can *be locke RP personnel immediately roped off the area and posted it as a high radi~tion.
- area (greater than 1 Rem/hr) in accordance with station procedure Since the acc~ss areas could not be blocked, an RP person was posted at the area to restrict personnel acces Calculations performed by RP determined that the whole body radiation dose 18 inches from the hot spot was 1.2 Rem/hr and about 125 mRem/hr in the adjacent pathwa P~eparations were also made to install lead blankets to shield the hot spot in accordance with station procedure However, the lin~
was flushed before the lead blankets were installed. -
\\~*:;
Withi~ about six hours, the operations department flushed the line with demineralized water and removed the hot spo General area dose rates were 'then at about 2-4 mRem/h The portion of piping which contained th~ hot spot is used for resin sluicing operation The general area had been recently surveyed (about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> earlier),
and no abnormalities existe The licensee performed a review to identify whether any* valves associated with the spent resin storage tank or any other lines tied to the piping were manipulated, however, none were identified. Additionally, operations verified that all lines leading to the piping section were isolate The licensee suspected that.valve leakage, allowing a hot resin particle to reach the line accounted for the high radiation sourc The licensee requested system engineering to perform an additional evaluation to determine the root cause.and source of the hot spot
and if any-long term corrective actions are necessar The inspecto-r concluded that RP action in respon-se to this event was prompt ind effective and the fire protection ~upervisorts efforts to quickly identify and report the unexpected dose for further review
_were very goo.
SURVEILLANCE TESTING (61726) Inspection Activity During this inspection period, the inspector performed detailed techn1cal procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance packages:
The inspector verified that the surveillanc~ tests were performed.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:
lIC-18.1.013 M3Q-2 M3T SP(0)4.0.5-P-'AF( 11)
4.2 Inspection Findings Solid State Protection System semi-annual reactor trip breaker operability test Reactor trip breaker semi-annual inspection,
-lubrication and testing 28 vital bus undervoltage and underfrequency trip setpoint check and time response surveillance test Inservice testing - Unit 1 auxiliary feedwater pump No. 11 The surveillance activities inspected were effective with respect to meeting the safety objectives of the surveillance progra.
On September 21, 1989, -the licensee informed the NRC that the Unit 1 11A 11 reactor trip bypass breaker (RT88) undervoltage trip attachment (UVTA) failed the as-found output force measurement test with 460 grams of weight added to the trip bar. This test measures the excess margin that the RT8 will overcome to trip the breake Pre-ventive maintenance (PM) activities were then performed on the UVTA in accordance with procedure M3Q-The UVTA retested satisfactorily and the breaker was returned to servic __
On October 2, 1989_, *the NRG.was informed that the Unit 1 118 11 reactor trip breaker (RT8) UVTA also failed the as-found output force measurement tes Following PM on the UVTA, the third trial of the post-mainfenance output force measurement test faile A new UVTA was insta~led on the b~eaker and tested satisfactoril The breaker was then returned to servic Previous inspection results related to RT8 UVTA test failures are ~iscussed in combined inspections 50-272/89-20; 50-311/89-1 The UVTA must be capable of tripping the breaker with 460 grams of weight adqed *to the trip bar three consecutive times in order to be consider~d operable during periodic te~ting. In addttion, the licensee' continues to add weight in 60 gram increments until the breaker fails to trip to determine the margin of force above 460
- grams that the UVTA is capable of trippin The results for the lA RT88 and 18 RT8 were as follnws:_
lA RT88 18 RTB Old UVTA New UVTA As found T~ial 1 failed
3 As left Trial 1 580 (following PM)
580
580 failed 460 460 failed 1300 1300 1300 same as 11as fou-nd 11 Following notification of the as-found failures for these two breakers the inspector requested the licensee to reduce the weight incrementally from 460 grams to determine the ma~gin of force the UVTAs were capable of trippin The results were as follows:
lA RT8B 460 failed*
440 passed (breaker tripped)
460 failed
-
440 failed 420 failed 400 failed 380 passed 400 passed 420 passed 440 passed 460 failed 18 RTB 460 failed 390 passed 440 failed 420 passed
The inspector observed that although the UVTAs did not meet the 460 gram test acceptance criteria, the UVTAs exhibited a margin of force of at least 380 gram The inspector concluded that based upon these results the UVTAs had considerable margin remaining to trip the breakers had they been called upon to do s The licensee. is continuing their dialogue with Westinghouse concerning the cause of the apparent marginal lot of UVTAs received at Salem that* had margin's of force in the, range of 460-640 grams. The most*
recent UVTAs purchased appear to be consistent in quality with previous lots of UVTAs evidenced by the new one installed on the 18 RTB which exhibited a margin of force of 1300 gram The system engineer is keeping the inspector informed with regard to continuing licensee efforts*to resolve the UVTA problem and the continu-ing review to amend RTB commitment.
MAINTENANCE (62703) Inspection Activity
.
During th~s inspect~on period, the inspector observed portions of.selected maintenance activities to ascertain that these activities were conducted
- in accordance with approved procedures, Technical Specifications, and appropriate industry codes and standard These inspections were conducted in accordance with NRC inspection procedure 6270 Portions of the following activities were observed by the inspector:
Work Order 890918112 870813022 890925117 890306121 890913088 Procedure MP M3L-1 14.1.001 M3Z Description Boric acid transfer pump-replace casing gasket 12SJ134, No. 12 safety injection pump to cold leg MOV; Limitorque limit switch setup and MOVATS testing Investigate 23AF21 demand indicator
Surge suppressor diodes Repair service water system elbow leak*
- *
Inspection Findings The maintenance activities inspected were effective with.respect to meeting the safety. objectives of the maintenance progra During preparations for casing gasket replacement of the boric acid transfer pump, the radiation protection (RP) technician assigned to this ar~a of the RCA identified that the maintenance workers had not signed-on a Radiation Work Permit (RWP) for _work involving a primary system breac The RP technician questioned whether the workers would exit the RCA and.reenter on a special RWP prior to breaching the boric acid syste The pump had not yet been disassembled, and the job was stopped until the workers signed-on an appropriate RWP and the RP t~chnician ensured that RWP requi~ements were ~e Th~ inspector observed that an RWP number was not specified on the work order (WO)
and noted that this discrepancy was not identified during ~he pre-job briefin The* inspector was concerned that adequate radiation and contamination controls may not be implemented when an incorrect RWP is utilized; This situation was discussed with the RP and maintenance engineers to ascertain whose responsibiiity it is to ensure maintenance is performed utilizing the correct RW The inspector was informeo that the RWP should be specified on the WO prior to issuanc However, up.to this point, because of the large number of was issued at times and only one RP person matrixed to planning to assign the RWPs, WO~
have sometimes been issued without the RWP specified. It was assumed that the maintenance supervisor would assign the RWP on the WO before giving it to the worker In this case, however, the supervisor left it up to the workers to choose the RWP for the jo The licensee acknowledged that several other similar discrepancies had previously occurred as a result of this practic To correct the problem, planners and maintenanc~ supervisors have been i~structed that WOs are not to oe issued or accepted without an RWP specified, if an RWP is required as noted on the WO. In addition, the inspector was informed that RP personnel will continue to monitor compliance with station procedures and RWP The inspector concluded that attention to detail by the RP technician was noteworthy, and the licensee's corrective actions are acceptabl c~
During performance of limitorque preventive maintenance (PM) and surveillance activities associated with motor operated valve (MDV)
12SJ134, the maintenance crew identified burn damage to wire insulation internal to the motor operator, apparently due to their close proximity to an energized limit switch compartment heate An action request (AR) was submitted for engineering dispositio Licensee immediate corrective actions included repairing the wires and tagging open all MOV heater power supply breaker Valve 12SJ134 was subsequently tested with satisfactory result The licensee
- inspected 11SJ134 and identified that a limit switch compartment heater was present but was not wired and therefore not energize No wiring damage was identifie The inspector discussed the wire damage issue with station management and engineering personnel with regard to valve operability, applic~
ability to other MOVs, and actions taken in 1986 in response to
- Information Notice (IN) 86-71, Recent Identified P~oblems With Limitorque Motor Op~rator~, which discussed MO~wiring damage due to internal heater The licensee informed the inspector that the 12SJ134 insul~tion damage was not severe enough to prevent the valve from ~erforming its intended functio Ho~ever, the inspector was informed that_since the licensee thought that the heaters had been removed in 1986 as a result of the IN; licensee management elected to-perform a sample inspection of Unit~ valves since it was in an outage
- to determine the extent of the proble The Unit 2 MOV inspections were in progress at the end of the inspection perio Further, the licensee was attempting to verify what other MOV related_actions were taken in 198 The inspector noted the attention_ to detail displayed by the maintenance workers in identifying the damaged wire insulation and raising the issue to the appropriate levels for proper resolutio Pending the tesults of the licensee's investigation and resolution of the problem, this item is unresolved (UNR 50-272/89-22-02). EMERGENCY PREPAREDNESS (71707) Inspection Activity The inspector reviewed the licensee's procedures for reporting and response to hurricane activity and observed several training drills performed by the licensee in preparation for the upcoming graded Emergency Plan exercis.2 Irispection Findings The inspector reviewed Emergency Classification Guide (ECG) Section 12, Earthquake/Severe Weather and Abnormal Operating Procedure (AOP), AOP-WiND-1 to verify licensee procedures and preparations for potential hurrica~e activity due to Hurricane Hug The inspector identified that the entry conditions for the ECG and AOP were discrepant in that the ECG requir~d declaring an Unusual Event at 70 mph wind speed while the entry condition for the AOP was 90 mph wind
_spee This discrepancy was discussed with the.senior nuclear shift supervisor (SNSS) who determined that the ECG had been revised to the more restrictive wind speed value, but the AOP had not been update An on-the-spot change was made to the AOP to resolve this
- issu The inspector ~uestioned plant manageffient as to whether a generic review of the ECG and related procedures to verify consis-tency was planned in light of this recently jdentified discrepanc The inspector was informed that -this type of review was previously planned to be performed as part of the Procedure Upgrade Project (PUP).
The inspector was further informed that the_AOP upgrade is scheduled to be completed during the first quarter of 199 The i.nspector discussed this issue with the Salem General Manager (GM-SO)
and expressed concern that ECG requirements for emergency response may not be implemented in the necessary time frame if similar dis-crepancies e~ist. The GM-SO acknowledged the concern, but stated that the rational, planning and priorities for the PUP were estab-lished and sound and he did not feel that redirection was necessary since the AOP 1s were one of the top priority groups of procedures to
_be processe The inspector had no further question With regard to inspector observation of training drills, several minDr concerns were discussed with the licen~ee 1 s Lead Controller who factored them into the drill critique for resolutio The inspector concluded that-conduct of the training drills was effective in that perfor~ance improvements were noted~ (Closed) Violation 272/89-17-01; Inadequate Event Classification Guide (ECG) procedur The ECG has been revised to clearly identify the proper reporting requirement The appropriate sections were*
revised to facilitate usag Additionally, the Emergency Preparedness Department conducted detailed training on the.revised ECG for the senior shift supervisor Licensed operators will receive similar training during their requalification cycle.- The inspector reviewed the revised ECG and determined that the appropriate 10CFR50 reporting requirements were clearly identifie This item is close SECURITY (71707, 62703) Inspection Activity PSE&G 1 s compliance with the security program was verified on a periodic basis, including the adequacy of staf,fing, entry control, alarm stations, and physical boundaries. -The inspector reviewed design change package (DCP) 1SC-2l56, 11Modification of Secur-ity Fence Routing 11 and observe portions of DCP implementation.
7.2 Inspection Findings The activities observed relative to the security fence modification were effective with respect to meeting the objectives of the securi~y plan and procedures and the design change implementation proces.
During a walkdown of the security computer power supply equipment, the inspector observed that various meters associated with*the system were overdue for calibration as indicated by the calibration stickers affixed to the The inspector had discussed this issue previously with security personnel, but noted that the problem has not ~et been re~olved. The ins~ector discussed this observation with the security engineer and was informed that a security inverter maintenance procedure is being written for this equipment which will include the calibration frequencies and procedure A recurring task in the licensee's maintenance tracking ~ystem (MMIS) will be developed to ensure the calibrations are performed at the required frequenc The licensee has committed to complete these actions. by December 31, 198 This matter will be unresolved pending completion of the licensee's ~orr~ctive actions (UNR 50-272/89-22-03).
. ENGINEERING/TECHNICAL SUPPORT (Closed) Unresolved Item 272/89-20-01; Failure of 12SGFP discharge check valves.* The licensee manufactured a new hinge pin and repaired the check valve, and Unit 1 returned to full power on September 1 All loose parts -
were recovered except for the tip of the hinge pi Inservice loose parts monitoring was performed at several potential locations in an attempt to.
locate the loose part, however it was not foun The licensee concluded that the failed hinge pin had been damaged for a relatively long time based
- on the evidence of.erosion, therefore the loose part had most likely traveled and subsequently lodged itself. The system engineer contacted the valve vendor for the spring loaded check valve (mounted 45 degrees from vertical) to determine a permanent corrective actio A permanent resolution has not yet been reached, however, the licensee's efforts are continuin The licensee currently plans to inspect the Unit 2 swing check and spring loaded check valves during the upcoming refueling outage (April 1990).
Acoustical monitoring is also under consideration for both units. Dis-cussions with the valve vendor indicated that sustained plant operation* at certain power levels can increase the likelihood of check valve bumping against its closed or open seats and therefore damaging the valve internal The licensee stated that guidance will be provided to plant operators, restricting plant operation in the trouble zones. *
- 9.
Failed check valves of various types and applications had been the subject of several NRC Information Notices and other gen*eric.industry correspon-denc On October 15, 1986, INPO issued Significant Operating Experience Report (SOER) 86-3, "Check Valve Failures or Degradation 11 *
The SOE~
addressed the various industry generic check valve concerns and provided recom~endations with respect to valve maintenance and valve desig ~h licensee received the SOER and issued* action requests to the appropri~te station group The licensee's valve program consists of three stages; 1) identify, 2)
inspect, and 3) surveillanc A contractor performed st~ge 1, using EPRI NP-5479, 11Application Guidelines for Check Valves in Nuclear Power Plants 11,
as a guideline for valve selectio Ninety-eight valves per unit were identified. A procedure development program is currently in place to*
generate specific maintenance/surveillance procedur~s for the various types of check valve The licensee is also pursuing 11Non-Intrusive Inspection Techniques 11, to develop ba~eline data (acoustical monitoring) to minimize the number of those valves required to be disassembled for inspection. *
The licensee's program is_continutng. Its effectiveness will be monitored routinely by the inspector SAFETY ASSESSMENT /QUALITY VER! F.ICATION ( 40500)
During this inspection period; the inspectors noted several examples of good attention to detail by various levels of the licensee's organizatio The licensee's recent efforts to increase station sensitivity to identi-
.fyi ng prob 1 ems, communicating them to the appropriate 1eve1 of management, and performing work activities in a deliberate manner appear to have been effective thus fa The inspectors will coritinue to monitor the lic~nsee 1 s programs to resolve recent problems as identified in the latest NRC SALP repor.
LICENSEE REPORT REVIEW AND OPEN ITEM FOLLOWUP (92700, 92702)
10.1 The inspector reviewed the following licensee reports for accuracy ~nd timely submissio *
Unit 1 Monthly Operating Report - August 1989 Unit 2 Monthly Operating Report - August 1989
- 10.2 Reference to Open Items The follo~ing open item~ from previous inspections were foll6wed up during this inspection and are tabulated below for cross reference purpose Closed Closed UNR 272/89-17-01 UNR 272/89-20-01 1 EXIT INTERVIEW (30703)
Section 6~C Section The inspectors met with Mr. L. Miller and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of ~heir 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 restrictions.