IR 05000280/1991026
| ML18153C820 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 10/28/1991 |
| From: | Branch M, Fredrickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153C819 | List: |
| References | |
| 50-280-91-26, 50-281-91-26, NUDOCS 9111220052 | |
| Download: ML18153C820 (18) | |
Text
Report Nos. :
UNITED STATES.
. NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, ATLANTA, GEORGIA 30323 50-280/91-26 and 50-281/91-26 Licensee:
Vfrginia Electric and Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.:
50-280 and 50-281 License Nos.:
Facility Name:
Surry 1 and 2 DPR-32 and DPR-37 Inspection Conducted:
August 18 through_S~ptember 28, 1991
.Inspectors:
a~~..
M. W.Bran~esident Inspector
?L~bv J. W. York~ ~nsp Approved by:
of Reactor SUMMARY Scope:
This routine resident. inspection was conducted on site in the areas of plant*
operations, plant maintenance, plant surveillance, action on previous inspection findings, and emergency safeguards system walkdow During the performance of this inspection, the resident inspectors conducted review of the licensee's backshift or weekend operations on August 25,. 26, and 27, September 4, 5, 7, 12, 14, 15, and 2 *
Results:
In the operations functional area, operations performance during shutdown, outage and startup was identified as a strength (paragraph 3.b).
During the Unit 2 shutdown and startup, operators operated the unit in a safe and efficient manner and adhered to procedure requirement During the brief Unit 2 outage, operators were attentive to their dutie Systems that required maintenance were properly isolated, returned to service, and* tested.
. Communication between operations shift personnel was good and communication 9111220052 911028 PDR ADOCK 05000280 Q
between* operations and other departments was also goo The brief outage was completed with minimal errors and on schedul Operation performance was an improvement over that observed during ~he previous Unit 2 startup which was documented.as a weakness in Inspection Report 50-280, 281/91~1 *
During the inspection period,. two reactor runbacks occurred in Unit In the operations functional.area, operator response to the ~unbacks was generally goo A weakness was identified involving operators overborating following the August 23 reactor runback (paragraph 3.a).
In the m~intenance functional area, the troubleshooting activities associated with the Unit 2 A reactor trip breaker were thoroughly and efficiently accomplishe Management involvement was, evident and the electricians
.
accomplishing the troubleshooting appeared conscientious and knowledgeable
{paragraph 5.a.).
In the maintenance functional area, several problems associated with implemen-
.tation of the new post-maintenance test program were identified {paragraphs and 5.b).
In the maintenance functional area, the lack of deta,led procedures for performing maintenance on certain air operated valves was identified as a weakness (paragraph 5.c).
.
In the.operations functional area, configuration deficiencies-discovered during a walkdown of the emergency service water pump house were identified as a weakness {paragraph 7).
An unresolved item was identified ~hich involved administrative control of containment isolation valves {paragraph 3.d).
An unresolved item was identified which involved resolution of preservice and inservice inspection deviations {paragraph 6.b).
REPORT DETAILS
- Persons Contacted Licensee Employees R. Allen, Supervisor, Shift Operations
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- D. Christian, Assistant Station Manager J. Downs, Superintendent of Outage and Planning D. Erickson, Superintendent of Health Physics_
- R. Gwalt~ey1 Superintendent of Maintenance
- M. Kansler, Statiqn Manager
_ T. Kendzia, Supervisor, Safety Engineering
- H. Kibler, Engineer, Testing
- J. McCarthy; Superintendent of Operations
- A. Price, Assistant Station Manager
- R. Saunders, Assistant Vice President, Nuclear Operations
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering NRG.Personnel
- M. Branch, Senior Resident Inspector
- P. Fredrickson, Section Chief, Division of Reactor Projects
- S. Tingen, Resident Inspector
- J. York, Resident Inspector
- Attended exit intervie Other licensee employees contacted included control room operators,* shift technical advisors, shift supervisors and other plant personnel.*
Acronyms and initial isms used throughout this report are listed in the last paragrap Plant Statu Unit 1 began the reporting period in power operatio On August 26, the unit experienced a turbine runback from 100 to 70 percent power when the A and B RSSTs were deenergized by the loss of switchyard bus On August 27, the unit was returned to 100 percent powe Details of that transient are discussed in paragraph 3.f. Throughout the inspection period, power level was reduced numerous times to clean condenser waterboxe The unit was at power at the end of the inspection period, day 283 of continuous operatio **
Unit 2 began the reporting period at approximately 90 percent power due to
. fuel restrictions associated with the recovery of dropped control rod D On August 20, the unit was returned to 100 percent powe On August 23, the unit experienced a turbine runback to approximately 50 percent power when contra l rod D4 again dropped into the cor Details of that transient as well as the corrective actions associated with the attempts to recover rod D4 are discussed in paragraphs 3.a and The unit operated at 60 percent power until September The unit was shutdown on September 7, in order to troubleshoot rod D On September 15, -the unit was restarted, and was at 100 percent power on September 1 The unit was at power at the end of the inspection period, day 14 of continuous operatio Throughout the inspection period, power level was reduced numerous times to clean condenser waterboxes *. Operational Safety Verification (71707 & 42700)
The inspectors conducted frequent visits to the control room to verify proper staffing, operator attentiveness and adherence to approved procedure The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operations safety and compliance with TS and to maintain awareness of the overall operation of the facilit n*str_umentation and ECCS lineups were periodically reviewed from control room indication to assess operability. Frequent plant tours were conducted to observe equipment status, fire protection programs, radiological work practices, plant security programs and housekeepin Deviation reports were reviewed to assure that potential safety concerns were properly_ addressed and reporte Unit 2 Dropped Rod D4 On August 23, Unit 2 experienced another dropped rod, the same rod (D4) previously dropped on August 1 The.trouble shooting and *
repair of this rod are discussed in paragraph 5~d of this repor The inspectors noted on t_he Tave recorder that after the rod dropped at 4:35 a.m., Tave dropped to 532 degrees F by 4:47 Technical Specification 3.1.E.4 states the reactor shall not be made critical when RCS temperature is below 522 degrees. Since Tave was lower than normal and close to the lowest allowed value, the inspectors questioned the reason for the low valu The licensee state*d that overboration was the cause.. The abnormal procedure used for a dropped rod, O-AP-1~01,* Control Rod Misalignment, dated September 30, 1991, requir~s in steps 4 and 19 that if the delta flux is not in the band that the operator should borate as necessary. This overboration event is identified as an opera ti ans weakness in that operator training and/or procedural guidance did not prevent its occurrenc The inspectors also noted that during the August 14 dropped rod event and subsequent turbine runback, operators al so overborated the reacto The August 14 event and overboration, during which Tave dropped to 551 degrees, was not as significant as the overboration that occurred on August 2 Unit 2 Outage On September 8, portions,of the Unit 2 cooldown from*s47 degree~ F to 160 degrees F were monitore The fnspectors observed the licensee's performance from the control room, and reviewed procedures 2-0P;..J.2, Unit Cooldown From HSD to*345 degrees F, dated August 6~ 1991, and 2-0P-3.3, Unit Cooldown From 345 degrees F to HSD, dated January 1-,
199 The c.ooldown was satisfactorily accomplishe Operators conducted their duties in a safe and efficient manner and adhered to procedural requirement During the brief Unit 2 outage, operators were attentive to their dutie Systems that required maintenance* were properly isolated, returned to service, and teste Conununication between operations shift personnel and other *departments was goo The brief outage was completed with minimal error5 and on sch~dul *
On September 15, portions of *the Unit 2 reactor plant startup were monitore The inspectors observed the licensee's perfonnance from the control room* and safeguards building, reviewed procedures 2-GOP-1.4, Unit Startup HSD to 2 Percent Reactor Power, dated September 12; 1991, and 2-PT-14.2, Main Steam Trip And Non-Return Valve Operability Verification, dated May 28, 199 The startup was satisfactorily accomplishe *
Operations performance during the above evolutions is identified as a strengt AFW Header Temperature Indication
- On September 24, the inspectors noted the temperature readings on the two Unit 2 AFW headers were approximately 100 degrees. These readings appeared to be lower than previous temperature reading Consequently,* the inspectors questioned the accuracy of the thermocouple Additionally, there were MR tags attached to the two meters indicating that a calibration was require One of the MR tags also indicated that the probe was disconnecte The licensee's investigation of the inspectors obs~rvations included reading the piping with thermography instrumentation and evaluating the significance of the notes on the MR tag The licensee determined that the readings were correct and that the note on the MR tags was intended to convey a need to periodically calibrite the meters *.
The licensee is still* trying to determine the intent of the note that indicates the probe was disconnecte Due to insulation, the probe is not visibl The inspectors will continue to monitor the AFW piping temperature and will evaluate the licensee explanation associated with instrument accuracy and probe connectio,f
- Unit 1 RCP B Shroud Cooler CC Water Leak On August 28, the licensee discovered that a weld in the CC piping supply to the Unit 1 RCP B cubicle shroud cooler was cracked and leaking CC water into the containment *. Operators isolated the leak by shutting the shroud cooler inlet and outlet isolation valves and also secured the shroud cooler fa The 1 icensee determined that repair of this leak was not practicable while the unit was operating and decided to delay repairs until a unit outage. Operating with the RCP B cubicle shroud cooler fan secured was not an oper*ational proble After discovery of the leak, the licensee determined that containment integrity was violated due to the failure of the membrane barrier and entered a six hour clock to hot shutdown in accordance with TS 3.0.1. After the leak was isolated, the six hour clock was exite The inspectors reviewed the licensee's immediate corrective actions to restore containment integrity and consider *that the *
corrective actions were adequat The inspectors review of thfs event included section 5.2, Containment Isolation, of the FSA The FSAR provides the design basis for the containment isolation syste The* inspectors noted that the CC inlet piping to shroud cooler contained a manual isolation valve outside containment (1-CC-218) and a check valve inside containment (1-CC-58). * Section 5.2 of the FSAR stated that the manual valve was a containment isolation valve and was required to be administra.tively controlled. The inspectors *noted that valve 1-CC-218 was not administratively controlled and questioned why it was not. This was discussed with the licensee, but was not resolved at the. end of the inspection period. Pending additional information from the licensee, this issue is identified as URI 50-280/91~26-0l, Administrativ~ Control Of Containment Isolation Valve Licensee 10 CFR 50.72 Reports (1)
On September 3, at 8:42 a.m., the licensee made a report in accordance with 10 CFR 50.72 regarding a Virginia Power employee that was transferred offsite via the Surry Power Station *
ambulanc * The employee had severe chest pain No radiological contamination was involve (2)
On September 7, at 10:54 a.m., the licensee made a report in accordance with 10 CFR 50.72 regarding a Virginia Power employee that was transferred offsite via the Surry Power Station ambulance.. The employee had cut his thumb which resulted in severe bleedin No radiological contamination was involve (3)
On September 9, at 5:57 a.m., the licensee*made a report in accordarice with 10 CFR 50.72 regarding the failure of the Unit 2,
11A 11 RTB to open when a manual trip signal was initiated~
At the time of this event, the unit was in cold shutdown with all control rods inserte RTBs "A" and 118 11 were closed to al low paralleling the rod drive MG set in preparation for control rod exercise testing. After paralleling the MG sets, a manual scram
.
signal was initiated. - When the manual trip pushbutton was initially depressed, the 11A 11 RTB failed to open and the "B" RTB opened as require The* same manual trip pushbutton was depressed a second time and the 11A 11 RTB. opene The licensee's investigation of this event concluded that failure of the "A
RTB to initially open was because the operator did not fully depress the manual trip pushbutton. * The inspectors monitored the maintenance associated with the failure of the nA 11 RTB to initially *open and this is discussed in paragraph Th licensee subsequently retracted this lOCFR 50.72 report after they determined that the pushbutton would have properly worked
. if it had been fully depressed (4)
On September 12, at 12:00 p.m., the licens~e ma.de a report in_
accordance with 10 CFR 50. 72 regarding the inopera.bil ity of No *.
2 EOG over the period bf August 12 through 2 On August 26, *
No._ 2 EOG automatically started due to an undervoltage on the Unit 2 H emergency bu No. 2 EOG reached adequate speed for*
its output breaker to close and energized the H bus. However, the opera.tor noted, after approximately ten minutes of operation~ that the frequency was lower than expecte The frequency was approximately 53 hertz in lieu of the required 60 hert Operators took ma.nu al contra 1 of the No. 2 EOG and returned the frequency to norma This event is discussed in the following paragrap _ Evaluation of August 26, Loss of Switch Yard Bus No. 5
. Unit 1 experienced a turbine run back from 100 to 70 percent power due to a momentary loss of the IRPI semi--vita.l power supply as a result of deenergization of switchyard bus No. 5. * Unit 2 remained at 60 percent power* throughout the * tr:ansien Switchyard bus No. 5 supplies power to RSSTs A and_ B which in turn supply power to the 4160 volt emergency buse The lJ and 2H emergency buses were deenergized and this resulted in the autostart and loading of the Nos. 2 and 3 EDG The EDGs remained running for approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> while the failed 34.5 KV switchyard control power transformer was being replace During the transient, the control room operator noted that the No. 2 EDG speed was 800 RPM and not at the required nominal value of 900 RPM so he manually adjusted its spee The failure of the No. 2 'EOG to automatically operate at its nominal speed is discussed in detail later in this section *.
During the above transient, while the EDGs were supplying vital bus power, the plant was being operated in an off-nonnal conditio The initial loss of the RSSTs resulted in the plant being in a six-hour to hot shutdown action clock per TS 3.0.2 due to a TS requirement on control room chiller This clock was exited after-- a temporary jumper was installed and the failed switchyard* transformer was electrically disconnected from* bus 5. This allowed the control room chi 11 ers to be aligned for nonna l and emergency power~
To
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_electrically reconnect the new transformer and remove the temporary jumper it would be necessary to reenter the shutdown requirement of TS 3. Since voluntary entry into shutdown LCOs such as TS 3. has beendiscourged by the NRC, the licensee initiated communications with the. NRC on this issue. During a telephone conversation between the licensee and the NRC, it was agreed that entry into TS 3. 0. 2 would be appropriat When the new transformer was ready to be reconnected, the licensee entered the TS action, powered the emergency buses from the EDGs and deenergi zed the* RSST The licensee exited the TS action by restoring normal power to the buses and securing the EDG The inspectors were. onsite * for a major portion of the event and
- moni tared the licensee actions to replace the failed transformer as well as restoring normal electrical power to the statio With the exception of the problems with the No. 2 EOG discussed below, the -
inspectors did not identify any violation or deviations in thfs are The lkensee evaluated the performance of the No. 2 EOG during the above transient and determined that the EOG did not meet all power requirements when operating at the reduced speed and_ frequenc The EOG is required to automatically achieve and maintain the proper frequency after receiving an automatic.start signa The licensee attributed the No. 2 EOG failure to an improperly adjusted governor speed control knob follo_wing surveillance testing that occurred o August 12~
On August 12, a surveillance test was performed on No. 2 EOG in accordance with procedure 2-0P-EG-6.1, Number 2 Emergency Diesel Generator, dated September 13, 1991-. * At the end of the surveillance test, operators failed to properly adjust the governor speed control knob in accordance with the procedur Adjustment of the governor speed control knob was tequired to ensure that the EOG would operate at the required speed and frequency upon receipt of an automatic start sign Adjustment of the governor speed control knob was corrective action implemented in response to a recent -
failure of the No. 3 EOG to operate at the correct.speed which was discussed in Inspection Rep6rt 50-280, 281/91-2 The No. 2 EOG was secured at approximately 8:30 p.m. following the August 26, automatic star The EOG shutdown procedure instructed the operator to manually reset the speed control knob-after the EOG was secured. This action masks the ability to determine the previous manual speed settin However, this action results in restoring the proper autostart setting for the ED The setting of the No. 2 EOG speed control knob was verified correct on September 5, when the N EOG was tested and satisfactorily operated at its required spee The failure of the No. 2 EOG was discussed during the September 17 enforcement conferenc Since the failure of the No. 2 EOG to maintain rated speed and frequency, additional corrective actions have been i~plemented to ensure that EDGs reach and maintain the required speed after receipt of an automatic start signa These
- corrective actions included adjustment of the governor limits switches, increased fast start surveillance frequency, and verifying that the governor gear match marks are properly aligne Unit 2 SW Piping Inspection During the Unit 2 outage the licensee inspected the "D" 96 inch main condenser inlet header and both 48 inch SW supply headers to the Unit 2 containment RSHX The 96 inch header was drained, inspected and cleane Prior to cleaning the 96 inch header, the inspectors also inspected the header. * Hydroi d growth on the header wa 11 s was approximately three to four inches long. Based on this, the licensee concluded that hydroid growth was small. Throughout the summer, main condenser water boxes required frequent cleaning.* One of the major sources of water box fouling was hydroids; The licensee is currently evaluating the source of the hydroids to the water boxe Divers were utilized to inspect the 48 inch SW header Results of this inspection were that hydroid growth was minima The licensee considers that the program implemented to prevent hydroid growth ih the 48 inch headers has been successful in minimizing the hydroid growth in these header Within the areas inspected, no violations were identifie.
Maintenarice Inspectiorts (62703 & 42700)
During the reporting period, the inspectors reviewed maintenanc activities to assure compliance with the appropriate procedure The following maintenance activities were reviewed: Repair of Unit 2 Manual Trip Pushbutton On Septembe~ 9, the inspectors witnessed troubleshooting activities associated with manual trip pushbutton failure to open Unit 2's "A" RTB. This event was previously discussed in paragraph.3.e(3).
Troubleshooting was accomplished in accordance with WO 380011581 A special SNSOC meeting was convened to discuss and approve the troubleshooting instructions for this W The troubleshooting centered around checking the "A" RTB and its manual trip pushbutton for proper operatio Testing of the 'RTB's shunt trip and under~
voltage* coils proved that the breaker operated satisfactoril Testing of the manual trip pushbutton revealed that if the button was only partially depressed, the 118 11 RTB received an open signal -and the 11A 11 RTB would not receive an open signa When the pushbutton was fully depressed, the 11A" RTB also received an open signal and opene Operation of the pushbutton was discussed with Westinghouse who stated that*the pushbutton was operating correctly. Attached to the back of the manual trip pushbutton is a stack of five contact block Each contact block contains two sets of contacts, one set is normally open and the other set normally shu When the manual trip
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pushbutton is depressed, the first coritact block deener~izes the "B" RTB undervoltage coil and energizes the "B" RTB shunt trip coil. Th * third contact block accomplishes the same function for the A RT In order to enhance the operation of the pushbutton, the first and third contact blocks were replace After replacement of the two contact blocks, the "A" and "B" RTBs opened when the manual trip pushbutton was partially depresse The inspectors reviewed the completed work package-for troubleshooting the failure of the "A" RTB to open *. With the exception of post maintenance testing, no discrepancies were not~ The inspectors considered that the troubleshooting activities were thorough and efficiently accomplishe Management involvement was evident and the electricians accomplishing the. troubleshooting were conscientious and knowledgeabl The PMT. for this maintenance required that 2-PT-8.2, Reactor Protection Logic, be performe The inspectors reviewed the performance copy of 2-PT-8.2 and considered that the PMT did not recognize the proper retes However, the manual pushbutton was properly retested because the electrician accomplishing this maintenance went beyond the PMT scope. The maintenance required the removal and installation of all five of the contact blticks attache to the right hand manual trip pushbutto The inspectors considered that improper assembly of the contact blocks could result in improper operation of the pushbutton, and that a correct PMT would have required that all ten contacts enclosed in the five coritact blocks be tested to ensure th~t they properly repositioned when the pushbutton was depresse '2-PT-8.2 did not accomplish thi The inspectors discussed testing of the pushbutton with the electricians who *
performed the maintenanc The electricians stated that, although not documented, the contacts were tested after installation of the pushbutto The failure to specify.a correct PMT for this maintenance was identified as a weaknes Repairs to Valve 2-RC-63 Valve 2-RC-63 is a manually operated three *inch diameter gate valve in the Bloop RTD bypass line. There was a 10 to 12 drops per minute body-to-bonnet leak in this valve identified during the Unit 2 forced
- outage which commenced on September Since there were no other valves downstream to isolate this valve, the licensee utilized two redundant freeze seals approximately ten feet apar Upstream isolation of the valve was satisfied by closing valves 2-RC-55 and 2-RC-56. *
.
The inspectors reviewed the 10 CFR 50.59 safety analys1s (91-211) and noted that the licensee had considered actions that would be taken if the freeze seal was los At 50 psig RCS pressure, a leak of 1140 gpm would be experienced from the 3 inch diameter pip The low head SI pump can deliver approximately 3200 gpm and this would be.
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sufficient to prevent uncovering the cor In addition, if the seal were lost, the loop stop valves would be utilized to isolate this_
loo WO 3~00115884 was uied to remove the valve bonnet and i~ternals; to cap the valve packing drain line, and to install a blind flang Engineering analysis determined that it was not necessary to have this isolation valve in the syste WO 3800115883 was used to install the freeze seal Mechanical maintenance procedure n O-MCM-0401-01, Valves and Traps In General, dated Augtist 1, 1991, was used for the valve repai Corrective mechanical maintenance procedure MMP-C-FS-260, Freeze Sealing-Liquid Nitrogen Method-Single Freeze, dated July *9, 1991, was used twice to install the double*
freeze sea The freeze seal procedure did require that temperature detection devices be used to warn against the possibility for thawing the freeze seal (as recommended in IN-91-41).
During the same type of maintenance repair on valve 2-RC-95 (ref. Inspection Report 50-280, 281/91-14) there was some concern about and a weakness id~ntified on operations in~olvement with authorization to melt the
- freeze sea.l The inspectors noted improvement in this activity, in that the procedure had been changed and the shift supervisor is aware when this operation begins and end On September 14, d~viation report S-91-1404 identified the fact that post maintenarice testing did not require the performance of periodic test PT-53.lA, ASME System Pressure Tests, dated October 3, 1989, after performance of the previously described valve maintenanc After opening and reclosing of a system, the ASME Code,Section XI, requires that a Class 1 system have a leakage test conducted after pressurization to normal operating pressure. Operations detected this deviation and the periodic test was performed before returning this system to servic The failure of the PMT program to properly identify the correct post maintenance test requirements is identified as a weakness similar to the one identified in paragraph 5.a. Other PMT problems were also identified in Inspection Reports 280,281/91-21
. and 24, associated with an ESW pump and No. 3 EDG. * The PMT problem associated with the EDG resulted in escalated enforcement actio The inspectors concluded that PMT implementation problems are hindering the effectiveness of the new PMT program and that more management attention is needed to properly implement this progra Past Maintenance on Valve TV-DA-200A During the reactor trip/safety injection event that occurred on August 2, _(ref. Inspection Repo_rt 50-280, 281/91-21) SI Phase I isolation occurred which requires certain valves to close for containment isolatio Valve TV-DA-200A, which is the containment sump trip isolation valve, failed to fully close~
The licensee performed a Cause Determination Evaluation (licensee report n ). A memorandum from the system engineer dated August 5, 1991, stated that disassembly of this valve after the trip/safety injection
1 revealed that there were more springs installed in the valve seats than were recommended on the drawing (40 installed versus 20 required
. *on*the drawing).
The memo also stated.that -these excess springs have the possibility to cause binding in the valve operation and to increase the stroke tim *
The repair on this valve wa,s performed in October 1988, using a generic procedur The CFE report stated that the usage of a detailed procedure for this valve would have prevented this error of installing too many springs. * There are a total of four of these valves, two in each uni The other three valves have been evaluated through data from perodic tests, stroke times, etc., and are functioning properl A previous* station* deviation, S-91-0515 dated April 17, 1991, reported that the cage spacer was left out on pressurizer spray valve no. 2-RC-PCV-2455A during a maintenan~e repair *. The corrective action plan for this deviation stated that the lack of a detailed procedure was a contributor to leaving the spacer out of the valve during reassembl It was point~d out in this response, that the lack of specific mainteriance repair procedures for some of the air operated valve is a generic proble The inspectors reviewed a request for new procedures from maintenance engineering to the procedure group dated August 23, 199 This request gave a list of the valves and the priority for developing the procedure This lack of adequately detailed procedures for performing maintenance on certain air operated valves is identified as a weaknes Repair of Dropped Control Rod D4 During the last inspection period, the inspectors reported the dropping _of the D4 control rod in Unit 2 on August 14 (re Inspection Report 50-280, 281/91-21).
The licensee replaced the fuses, took electrical measurements, visually examined the circuit, and extracted the *dropped ro No.apparent root cause for dropping the rod could be determine On August 23, at 4:35 a.m. the same rod was dropped agai The licensee performed additional tests such as meggering the cables, visually examining cables in the containment and in the rod control cabinet, and installing a separate DC power supply for *testing the circuit at a higher amperage and voltag None of these tests identified the proble The licensee, in conjunction with Westinghouse, decided to install a temporary modification in the rod control circuitr This modification wou 1 d a 11 ow the D4 * rod to be removed * from the core and
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held by both the moveable and the stationary gripper coils. Both of these coils had their own separate circuits and were.connected.to the DC hold bu This would allow the rod to be tripped but not move When an attempt was made to lift the rod out of the core the moveable gripper coil shorted out and the licensee decided to shutdown to make the necessary repair WO 3800115065 and corrective electrical maintenance procedure EMP-C-EPCR-39, Control Rod Position Detector Assembly and the Operating Stack Assembly Removal and Repair, dated December 18, 1988,*
were used to make the repair The licensee decided to replace all thr~e coils and the control rod drive electrical cabl Electrical testing showed only the moveable coir was defectiv In addition, some cracking was observed ii:i this coils insulation. A cold rod drop test showed that the D4 rod moved and tripped successfull No discrepancies were identified by the inspector Within the areas inspected, no violations were identifie.
Surveillance Inspectioni (61726, 42700)
During the reporting petiod, th~ inspectors revi~wed surveillance activitie~ to assure compliance with the appropriate ~rocedures as follows:
Test prerequisites were me Tests were performed in accordance with approved procedure Test procedures appeared to perform their intended functio Adequate coordination existed among personnel involved in the tes Test data was properly collected and recorde The following surveillance activities were either reviewed or observed:* Hot Rod Drop Testing On September 11, the i_nspectors witnessed the performance. of periodic test NPT-RX-007, Hot Rod Drops, dated September 11, 1991, performed only on rod D4 which was repaired during the outag The inspectors observed testing from the control roo The rod was withdrawn 225 steps and then droppe The cycle allowed for this test was a maximum of 2.4 seconds and the actual time measured by the reactor engineer was 1.26 second No discrepancies were identifie Inservice Testing of Welds Inspection Report 50-280,281/91-21, discussed the potential problem*
_ that existed at Surry concerning the inclusion of longitudinal welds
in the ISI progra The licensee issued a memorandum outlining the approach to be used for resolution of this potential proble It was also stated that a deviation would be written and dispositioned for
- any variations from the ISI progra The licensee's initial ISI program co1T1Tiitted to the 1974 ASME Code
- through 1975 Summer Addendum for inspection and testing of equipmen Table IWC-2520, Examination Categories, Section C-G, requires that longitudinal weid joints in pipe fittings (i.e., in tees, elbows, recesses) b~ included in the ISI program unles~ approval is given to exclude these weld This code does not require longitudinal welds in piping to be inspecte The licensee's evaluation of the program resulted in two station deviation Station deviation S-91-1183 stated that the possibility ex-isted that main steam fittings having longitudinal welds may not have been included in the initial ISI prog~am~
There were no weld maps (Grinnell drawings) for the main steam fittings and a records search of inspections performed during the first ISi interval indicated that no longitudinal welds were examine The licensee stated that this did not constitute a Code violation because there are five types of welds in this category (i.e., circumferential but welds, longitudinal weld joints in pipe fittings,. etc.) and 50 percent of the total number of the five types of welds are to be inspected during the life of the plan The corrective action associated with* this deviation als6 stated that the Code is not clear that the overall sample be prorated to the number of each type of weld rior is it clear that each type of weld has to be considered in the representative sample for a specific interva The action plan for this deviation requires that one main steam weld in Unit 1 (located on the longitudinal weld of a fitting) and two welds in the same system on Unit 2 be examine This is the same population that would have b~en examined had the system's longitudinal welds been in the first ISI interva The two Unit 2 MS system welds examined during a recent forced outage were found to be acceptabl This leaves only ~he one Unit 1 MS system weld to be inspected during*a shutdown outag The second station deviation (S-91-1197) was written when the records review revealed that preservice examinations were not performed on 10 inch diameter recirculation spray system piping (for both units) that was replaced by DCP 87-22 and DCP 87-2 These welds had been inspected, but _the preservice base line inspection (surface inspection) required by ASME Section XI was not performe Pending further NRC technical review of these deviations, this is identified as Unresolved Item 280,281/91-26-02, Resolution of Pre~ervice and ISI Deviations~
Within the areas inspected, no violations were identified *
- 13 Action on Previous Inspection Findings {92701, 92702)
(-Closed)
.V,olation 280,281/89-34-02,.Failure to Implement Adequate Control Measures To Prevent The Use of Incorrect Materials Or Parts. The issue involved the use of incorrect gasket material during maintenance associated with the installation of Units 1 and 2 pressurizer safety valves and the assembly of SI check valves 2"'.'SI-79 and 2-SI-9 The licensee responded to this violation in a letter dated February 6, 199 In the letter the licensee stated that corrective action had been implemented which established an Engineering Parts Validation Program whereby engineering personnel are required to ensure that correct parts/components (with regard to technical data. and materials) are installed in the respective system per design*and licensing r~quirement During a previous inspection period, the inspectots were unable to close this violation because the original Engineering Parts Validation Program had been cancelled.. The licensee has replaced the Engineering Parts Validation Program with other methods of material contro The licensee
- has implemented a comprehensive material procurement program which is described in Station Administrative Procedure VPAP-0702, Identification and Control of Material, Parts, and Components, dated September 17, 199 VPAP-2002, Work Requests and Work Orders, dated July 1, 1990 was revised to require craft.*personnel to verify correct gasket material by measurement or inspection prior to installation. The inspectors reviewed VPAP-0702 and VPAP-2002 and consider that these corrective actions were satisfactorily implemented~ therefore this item is close Within the areas inspected, no violations were identifie.
ES~ System Walkdown* (71710)
The inspectors walked down the ESW syste Drawings 11448-FM-071A and 071E were utilized for this walkdow Additionally, procedures OP~49.2A, Emergency Service Water System Valve Alignment, dated February 25, 1991; 1-PT-25.3A, Emergency Service Water Pump 1-SW-P-lA, dated September 12, 1991; OP-49.2, Diesel Driven Emergency Service Water Pump Operation, dated February 25, 1991, were used to accomplish this walkdow The following discrepancies were'.identified during the walkdown:
The instrumentation valves associated with flow instruments l-SW-FE-121A, Band C were not aligned in accordance with OP-49.2 or 1-PT-25.3A restoratio.n step These procedures require that the instrument drain valves be opened and remain open when the ESW system is not in us The drain valves ~ere shut with pipe caps installed over the drain line The ESW system was n6t operating when the walkdown was performe *
The inspectors noted that the instrument root valves associated with l-SW-FE-121A were shut and the same val~es associated with l-SW-FE-1218 and C were ope OP-49.2 and 1-PT-25.3A provided conflicting restoration instructions for aligning instrumentation valves associated with flow instruments 1-SW-FE-121A,B and After
- discussing* this issue with the system engineer, the inspectors concluded that 1-PT-25.3A was correc OP-49.2 specified that the instrument root isolation valves be shut while 1-PT~25.3A specified that the instrument root. isolation valves be opene The system
~ngineer stated that it was desirable to leave the*instrument root
- valves and instrument drain valves open so the lines would be drained for freeze protectio System drawings illustrated that flow instruments l~SW-FE-121A, Band C existed, but did not illustrate the instrument valves associated with the flow instrumentation~
This was discussed ~ith eng~neering who stated the these flow instruments were recently installed as a design change and that~ through the design change process, these drawings will be revised to show that these valves exis Valve lineup proc~dure OP-49.2A did not provide instructions for aligning the instrument valves associated with flow instruments 1-SW-FE-121A, B and However, the procedures that operated and tested the ESW system, OP-49.2 and 1-PT-25.3, did provide instructions for aligning these valve The inspectors rioted several components that were not labeled. Air dampe~s 1-VS-DMP-102,103,104,105, and 106, vent valves for pressure instruments 1-SW-PI-107A, B and C, duplex strainer 1-s*w-STR-4A, and the instrument valves associated with 1-SW-FE-121A, Band C were not l abe 1 e The inspector noted that the system drawings and system yalve lineup provided conflicting instructions for positioning valves 1-SW-291, 555, 554, 560, 561, 566, and 56 After discussions* with engineering, it was concluded that the valve positions specified in the valve lineup procedure was correc The valves were in the positions specified by the valve lineup procedure when the inspectors walked down the syste The inspectors were informed that station policy did not require that system drawings show correct valve positio Procedures and valve lineups were utilized to align systems not station drawing The system drawing did not illustrate the level indication system for the ESW diesel fuel oil storage tank and did not illustrate the vent valves located upstream of pressure gages 1-SW-PI-107A, Band The inspectors consider housekeeping in the ESW pump house to be goo The deficiencies noted were not significant but indicated that a weakness existed in the area of configuration control of the ESW syste In previous inspections periods, the inspectors have walked down other ESF system and did not identify s.imilar deficiencies. However, the inspectors*
have noted that instrument valves throughout the station are not always numbered or identifie The licensee promptly initiated actions t correct these deficiencies after identification by the NR. I
- Within the areas inspected, no violations were identifie. * Exit Interview-The inspection scope and results were summarized on October 2, 1991 with those individuals identified by an asteris~ in paragraph 1. The following summary of inspection activity was discussed by the inspectors during this exi Item Number Status Description and Reference URI 50-280/91~26-01 Open URI° 50-280,281/91-26-02 Open _
VIO 50-280,281/89-34-02 Closed Administrative Control Of Containment Isolation Valves, paragraph. Resolution of Preservice and ISI Deviations, paragraph Failure to Implement Adequate Control Measures To Prevent The Use of Incorrect Materials Or Parts, paragraph The licensee acknowledged the inspection conclusions with no dissenting comment The licensee did not identify as proprietary any of the materials provided to or reviewed by_ the inspectors during this inspectio.
Index of Acronyms and Initialisms AFW ASME cc CFE CFR DC DCP ECCS
FSAR GPM HSD IN
!RPI ISI AUXILIARY FEEDWATER AMERICAN SOCIETY OF MECHANICAL ENGINEERS COMPONENT COOLING COMPONENT FAILURE EVALUATION CODE OF FEDERAL REGULATIONS DIRECT CURRENT DESIGN CHANGE PACKAGE EMERGENCY CORE COOLING SYSTEM EMERGENCY DIESEL GENERATOR ENGINEERED SAFETY FEATURE -
EMERGENCY SERVICE WATER FAHRENHEIT FINAL SAFETY ANALYSIS REPORT GALLONS PER MINUTE HOT SHUTDOWN INFORMATION NOTICE INDIVIDUAL ROD POSITION INDICATION INSERVICE INSPECTION
KV KILOVOLT LCO LIMITING CONDITION OF OPERATION MG MOTOR GENERATOR MR MAINTENANCE REQUEST NA NOT APPLICABLE NCV NON-CITED VIOLATION NRC NUCLEAR REGULATORY COMMISSION PMT POST MAINTENANCE TEST PSIG POUNDS PER SQUARE INCH GAUGE RCP REACTOR COOLANT PUMP RCS REACTOR COOLANT SYSTEM RPM REVOLUTIONS PER MINUTE RSHX RESIDUAL HEAT EXCHANGER RSST RESERVE STATION *sERVICE TRANSFORMER RTB REACTOR TRIP BREAKER RTD RESISTANCE TEMPERATURE DEVICE SI SAFETY INJECTION SNSOC STATION NUCLEAR AND SAFETY OPERATING COMMITTEE TS TECHNICAL SPECIFICATIONS URI UNRESOLVED ITEM VPAP VIRGINIA POWER ADMINISTRATIVE PROCEDURES WO WORK ORDER