IR 05000338/1989008: Difference between revisions

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{{Adams
{{Adams
| number = ML20244B815
| number = ML20247L737
| issue date = 05/17/1989
| issue date = 05/17/1989
| title = Insp Repts 50-338/89-08 & 50-339/89-08 on 890321-0417 & 0425-0503.Violations Noted.Major Areas Inspected:Plant Status,Maint,Surveillance,Operational Safety Verification, Operating Reactor Events & LER Followup
| title = Confirms 890524 Enforcement Conference in Region II Ofc to Discuss Problems W/Svc Water Flow & Reactor Vessel Level Perturbations Discussed in Insp Repts 50-338/89-08 & 50-339/89-08
| author name = Caldwell J, Frederickson P, King L, Munro J
| author name = Ernst M
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
| addressee name =  
| addressee name = Cartwright W
| addressee affiliation =  
| addressee affiliation = VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
| docket = 05000338, 05000339
| docket = 05000338, 05000339
| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-338-89-08, 50-338-89-8, 50-339-89-08, 50-339-89-8, GL-88-17, NUDOCS 8906130306
| document report number = NUDOCS 8906020244
| package number = ML20244B805
| document type = CORRESPONDENCE-LETTERS, NRC TO UTILITY, OUTGOING CORRESPONDENCE
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 2
| page count = 29
}}
}}


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  . NUCLEAR REOULATORY COMMISSION
MAY 17:1989 L
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  (v, Virginia Electric and. Power Compan ATTN: Mr. W. R. Cartwright, Vice . President, Nuclear Operations 5000 Dominion. Boulevard Glen A11en',-VA 23060~.
  ,g g  101 MARIETTA STREET. * 2  ATLANTA, GEORGI A 30323
i Gentlemen:
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eSUBJECT: CONFIRMATION OF ENFORCEMENT CONFERENCE ARRANGEMENTS DOCKET NOS. 50-338 AND 50-339 This confirms the telephone conversation between R.LF. Saunders of your staff'
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and M. S. Lewis : of my staff, on May 9,1989, . concerning .'an Enforcement Conference to be conducted at the. NRC Region II Office on May 24, 1989, at 10:00-a.m. We requested this meeting to discuss problems with service water.-
L  Report Nos.: 50-338/89-08 and 50-339/89-08 Licensee: Virginia Electric & Power Company Richmond, VA 23261      .
flow and' reactor vessel level perturbations, which have been-identified at North Anna. Enclosed is a proposed meeting agend Should you have any; questions regarding these arrangements', we will be pleased to discuss'the ,
Docket Nos.: 50-338 and 50-339-  License Nos.: NPF-4 and NPF-7
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Facility Name: North Anna 1 and 2 Inspection Conducted: March 21 through April 17, 1989 and April 25 through May , 198 Inspectors: Y < mash /d    6 / /?/3 9 J. L. Caldwell, Se ior Ryident Inspector  Date' Signed
    - L. P. King, Resident I W c1 tor Sf t 7lfr4 Date Signed 91 8. M 1,4  s/,7/r4 J. Munro, Resident' Inspector    Datle Sibned Accompanying Personnel: N. Economos S. Lewis
    . M. Shaeffer Approved y: / / [
P.g Frddricksop(~ Acting Brapief
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Cate/ Signed h
ivision of Reactor Projects SUMMARY Scope: This routine inspection involved the following areas: plant status, maintenance, surveillance, operational safety verification, operating reactor events, licensee event report followup, review of inspector follow-up items, Generic Letter 88-17, refueling activities, and EDG fuel oil storage and handlin During the performance of this inspection, the resident inspectors conducted reviews of the licensee's backshift operations on the following days: March 27, 30, 31, April 3, 5, 6, 10, 12, and 17, 198 Results: Within the areas inspected, there were two violations and two apparent violations identified:
Violation: Failure to have adequate maintenance procedures to ensure proper operation of ESF equipment 480 volt ITE breakers (paragraph 8).
 
Violation: Failure to comply with TS 4.6.1.1.a.1 for containmen penetration vent and drain valves (paragraph 8).
 
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8906130306 890517      ,'
PDR ADOCK 05000338 O  PDC
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Sincerely,
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. Original signed by M. L. Erbst Stewart . Ebneter (for)
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Regional Administrator  ;
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L- _nc10sure:
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Proposed Meeting Agenda cc w/ enc 1:
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G. E.-Kane, Station Manager R.:F. Saunders, Manager - Nuclear Programs and Licensing Commonwealth of Virginia L
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NRC Resident Inspector Document Control Desk e
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Apparent Violation: Potential for the SW and RSHXs to have been inoperable (paragraph 4.b).
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Apparent Violation: Inadvertent loss of reactor vessel level (paragraph 6.d).
 
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I REPORT DETAILS Persons Contacted  -
Licensee Employees
        * Bowling, Assistant Station Manager J. Downs, Superintendent, Administrative Services
        *R. Driscoll, Quality Control Manager
        *L. Edmonds, Superintendent, Nuclear Training
        *R. Enfinger, Assistant Station Manager
        *G. Flowers, Configuration Management Supervisor
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        *M. Garton, Instrument Supervisor G. Gordon, Electrical Supervisor D. Heacock, Superintendent, Engineering
        *G. kane, Station Manager
        *P. Kemp, Supervisor, Licensing
        *J. Leberstein, Licensing Engineer
        * Matthews, Superintendent, Maintenance T. Porter, Superintendent, Engineering
        *J. Stall, Superintendent, Operations
        *A. Stafford, Superintendent, Health Physics F. Termine11a, Quality Assurance Supervisor D. Thomas, Mechanical Maintenance Supervisor Other ' licensee employees contacted during this inspection included engineers, technicians, operators, mechanics, security force members, and administrative personne * Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap . Plant Status On March 21, the beginning of the inspection period, Unit I was in Mode 5, day 24 of an outage, which commenced with the C steam generator tube leak event on February 25. On March 23, Unit 1 experienced a loss of the IH emergency bus while performing tests of the EDG. The de-energization of the IH bus resulted in the tripping of the operable RHR pump (IA). The unit was not in a reduced RCS inventory (pressurizer level at the time was approximately 5 percent) and the IB RHR pump was started within 60 seconds of the 1A RHR pump trip (see paragraph 4.a for details). On April 14, the licensee conducted a SW flow balance test on the RSHXs. The results of the test indicated potential inoperability of the SW/RS systems (see paragraph 4.b for details). On April 16, Unit 1 experienced another loss of the operating 1A RHR pump. The unit had approximately 5 percent level in the pressurizer and the operators started the IB RHR pump in approxi-
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s-mately 6 minutes. The cause of the loss of an RHR pump was a fault in the switchyard caused by a personnel error (see paragraph 6.c for details).
 
On March 21, Unit 2 was defueled, day 30 of the refueling outag The fuel reload commenced on March 26 and completed on March 28. On April 3, Unit 2. experienced a loss of CCW to the operating RHR heat exchanger. The unit was drained to approximately 5 inches below the vessel flange at the time and therefore not in a reduced RCS inventory conditio The operators restored CCW flow in approximately 25 minutes (see paragraph for details). On April 5, the reactor vessel head installation was completed and Unit 2 entered Mode On April 13, the Chairman of the Czechoslovakian Atomic Energy Commission and six of his associates visited the North Anna Power Station at the invitation of the license The chairman and his group were given a presentation and a tour of the station and associated facilities by the licensee. The inspector briefly met with the Czechoslovakia personnel while they were touring the simulator in the training buildin . Maintenance (62703)
Station maintenance activities affecting safety-related systems and components were observed / reviewed to ascertain that the activities were conducted in accordance with approved procedures, regulatory gides and industry codes or standards, and in conformance with lechnical Specifications. The following details the inspector's findings / concerns, ASCO S0V Failure Root Cause NRC Inspection Report 338,339/88-02 identified concerns relating to the failure of air operated containment isolation valve These failures were attributed to problems with the ASCO SOV not performing properly. As a result of these concerns, the licensee committed to perform a failure analysis of the ASCO SOVs. The need for this analysis was further highlighted in Inspection Report 338,339/88-36, which identified concerns relating to instrument air water and oil contamination problems that may have been the cause or at least contributed to the cause of the ASCO SOV failures. The inspector obtained a copy of the licensee's failure analysis report and the following is a brief summary of the report and its conclusion (1) The cause of increased containment isolation valve stroke times was due to the installation of improperly sized tubing on the exhaust portion of the SOVs. Valve stroke times have been consistent since the replacement of smaller exhaust tubing with larger tubing. There are seven SOVs still requiring exhaust tube replacement. The licensee plans to replace the tubing prior to the startup from the present refueling outage .
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  (2) Several SOVs (ASCO mode 1 ~ NPX8321A1E) were found stuck in mid position. Their failure can be attributed to the combination of the water intrusion into the instrument air system, and mixing
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of the particulate contamination with assembly lubricant Consequently, the licensee concluded that ASCO NPX8321AIE SOVs appear to be susceptible to particulat - contamination from the instrument air syste (3) Inspections were made on two SOVs ( ASCO model KX206-380-30)
which failed to operate once deenergize In one case, the likely failure mechanism was the adhesion between the core / spring and solenoid sub-assemblies caused by oxidized silicone lubricant deposits. In the other case, the root' cause is inconclusive; however, a similar failure mechanism is suspected. The licensee concluded that ASCO model KX206-380-3U SOVs that are energized for prolonged periods may be susceptible to the failure mechanism described abov The licensee determined that the number of SOVs , (model KX206-380-3U) which have failed to stroke since February 1988, has been minimal. The two cases that have occurred were inspected as discussed above. Paragraph 5.c of this report contains an additional example of a SOV failure. The licensee's engineering group feels this is an insufficient number to definitely determine the root cause of ASCO SOV failure The licensee initiated EWR 89-166 to replace all SOV Mcdel NPX 8321AIE during the refueling outage. Once this modification is complete, the model of ASCO SOV used on the inside air operated containment ~1 solation valves will be different than those used on the outside containment isolation valves for the same mechanical piping penetration, except for the charging system trip valves. This will help prevent common mode failures on a single penetration. The ISI program has been revised to increase the frequency of stroke time tests for many safety-related trip valves, exceeding ASCO's recommen-dation in this are Also, the quality of instrument air has improved with modifications to the instrument air syste These factors should increase the reliability of safety-related trip valves whose pilot valve is an ASCO SO b. LHSI Pump Maintenance On April 10, the inspector witnessed portions of the overhaul of the Unit 2 LHSI pump (2-SI-P-1A) per MMP-C-SI-1, Low Head Safety Injection Pump Inspection, Repair and Seal Replacement. The inspector observed the installation and torquing of the last two columns on the pump shaft and the installation of one of the wedges between the pump casing and the pump columns. No problems were observed by the inspecto c. Unit 2 Steam Generator Outage Work
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During the present Unit 2 refueling outage, the licensee conducted numerous inspections and maintenance activities concerning the steam generator The following is a list of the activities and the l1
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results:
  (1) : Steam generator eddy current testing was conducted on the tubes of all three steam generators. All of the tubes were inspected through the U-bend, except for several short U-bend radius Row 2 tubes, using the standard bobbin probe (both hot and cold legs).
 
In addition to the bobbin probe, the tubes in rows 8 through 12
  /ere inspected to the seventh support plate using the 8 x 1 pancake probe (both hot and cold legs), and all other rows were inspected on the hot leg side through the first support plate using the 8 x 1 pancake probe. Any indication discovered by one of the above methods was verified by the RPC probe. Also, 25 row 2 tube U-bends were inspected using the RPC probe. As a result of the above inspection, four tubes in the A steam generator,10 tubes in the B steam generator and 15 tubes in the C steam generator are required to be plugge (2) Steam generator sludge lancing was conducted on all three steam generators to remove sludge that had collected on the tubes and
  . tube sheet. The results of the lancing involved the removal ~ of 288 pounds of material f rom the A steam generator, 312 pounds from the B steam generator, and 226 pounds from the C steam generator. This is comparable to the amount of that was removed from the Unit 2 steam generators during the 1987 refueling outage, which ranged from 230 to 270 pound (3) As a result of the failed plug that caused a steam generator tube leak event on the Unit I reactor in February of this year, the licensee replaced several plugs in the Unit 2 steam generators. The licensee determined that 13 hot leg plugs in the A steam generator,10 in the B steam generator, and 30 in the C steam generator would have to be replaced because they had been determined to be susceptible to the same type of failure that occurred in the Unit 1 C steam generator. Refer to paragraph 6.d of this report for further details on the tube plug concer (4) The Unit 2B steam generator J-tubes were inspected and determined to be acceptabl The licensee had replaced the Unit 2 carbon steel J-tubes with inconel J-tubes in all three steam generators during the 1985 outage. Since the inspection was satisfactory in the B steam generator, the other two steam generators were not required to be inspecte No violations or deviations were identifie . Surveillance (61726)
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The inspectors observed / reviewed technical specification required testing and verified that testing was performed in accordance 'with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation were met, and that any' deficiencies identified were. properly reviewed and resolve Loss of 1H Emergency Bus and 1A RHR Pump-On' March 23, during the performance of 1-PT-82.3A, 1H: Diesel Generator Test (Simulated Loss of Offsite Power in Conjunction.with ESF Actuation Signal), the licensee inadvertently lost power to the
    .1H emergency bus. The surveillance was intended to test the fast start capability of the 1H EDG using a simulated safety injection and 90 percent degraded voltage signal. At the time of the surveillance, Unit I was in Mode 5 with an RCS temperature of 102'F. Pressurizer level was approximately 5 percent, the 1A RHR pump was operating and the IH emergency bus-was being supplied by the alternate power source through breaker 15H1. When the operator commenced the test, the breaker upsteam of 15H1 (15B11) opened, causing 15H1 to also open and de-energize the IH emergency bus. As a result of the : loss of the bus, the operating 1A RHR pump, which is powered by the 1H bus, also tripped. An operator stationed at the RHR pump controls immediately started the - 18 . RHR pump, resulting in a negligible change in RCS temperature. The IH EDG auto-started and loaded onto the bus in less than 10 seconds as required. The IH EDG was subsequently paralleled tc the alternate power supply and the IH bus was returned to norma The EDG-was secured in approximately 15 minute The inspector reviewed the procedure 1-PT-82.3A and, as stated by the licensee, there were no initial conditions or precautions requiring the emergency bus to be powered by the . normal power' supply. Even l    though the procedure was inadequate in not requiring that the bus be powered by the normal breaker 15H11, the operators stopped the test on March 23 to determine if it was acceptable to continue with the bus being powered from the alternate power supply. The Control Operations Department was contacted and requested to determine if the test switch would block the 15H1 breaker from tripping as it normally does for the 15H11. The operators ' were informed that the 15H1 breaker would not trip; however, the Control Operations personnel failed to check the upstream breaker 15B11, which was not blocked and did trip on the simulated 90 percent degraded voltage signa The operations staff did an excellent job in stopping the test and questioning the abnormal alignment. However, since the test proce-dure did not have a requirement for the emergency bus to be powered from the normal power supply, no formal change was required to proceed in the abnormal alignment. The review conducted by the Control Operations Department was informal and incomplete. This informal review resulted in the failure of the Control Operations personnel to identify that breaker 15B11 was not blocked by the test
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switch and would trip.
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        .The. licensee'has initiated corrective action, which involves placing in- al1~ applicable ' surveillance , tests, deviations that. prevent the test from being performed in an abnormal ' electrical alignment. .The
        ; inspector has-verified that a procedure deviation does exist in 'the'
front of the control room copies of the following' surveillance tests;-
82.2A, 82.2B, 82.3A, 82.38, 82.4A, and 82.48. The licensee -has committed to establishing a formalized approach for obtaining Control Operations assistance, including a method of permanently ' capturing and utilizing the information obtaine This apprea:h . will. be developed and a schedule established for its implementation by May -
17, 198 Service Water to RSHXs Flow Balance On April 4,- the inspector received a briefing on 1-PT-75.6, Service Water System Flow Balance, prior- to performance of the test. Thi procedure was developed to allow for full flow testing of _ the SW system through the RSHXs. The results of the procedure were designed-to allow the licensee to determine if the design basis flow would
        . actually be achieved through the RSHXs and provide data on the maximum flow which could be allowed through the CCW heat.exchangers during normal operation Concerns regarding the ability of the RSHXs-to perform their intended safety function were raised in NRC Inspection Report 338,339/88-1 These concerns involved potential increased fouling factor associated with the RSHXs and the resultant reduction in their heat transfer capabilitie However, during the discussion concerning the increased fouling of the RSHXs, it was assumed that the heat exchangers would receive their design SW flo Also, as documented in NRC Inspection Report 3'38,339/88-31, the licensee identified a potential problem associated with SW flow through the CCW heat exchangers. This concern involved SW pump and CCW heat exchanger flow combinations which could prevent achieving
        .the required SW through the RSHXs during an accident. An additional complication involved the assumption that the SW pumps would deliver a flow of 15,000 gpm per pump. This concern was identified as IF '338,339/88-31-04, pending the SW flow testing that is being conducted this outag The licensee conducted 1-PT-75.6 for the Unit 1 RSHXs on April 1 The test performed head curve verifications on all four SW pumps and indicated that the maximum flow rate for the pumps was actually approximately 13,500 gpm instead of the 15,000 gpm that was expected by the Itcensee. The results of the test also indicated that the SW flow through two of the four RSHXs was below the required design flow of 4500 gpm, as stated in the UFSAR, Table 6.2-2. The SW as-found flow results are as follows:
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A RSHX - 5020 gpm
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B RSHX - 4850 gpm C RSHX - 3740 gpm
    .. D RSHX - 2650 gpm i
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    . The SW flow through the RSHXs is controlled by a throttle valve for each heat exchanger (1-SW-103 A, B, C and D). The licensee was able to . adjust these valves to achieve the following as-left SW flow results:
I A RSHX - 4610 gpm B RSHX - 4610 gpm
    ~C RSHX - 4570 gpm L    D RSHX.- 4660 gpm Based on the discovery' of the SW flow below the required flow of 4500 gpm in two'of the RSHXs, the licensee notified the inspector of their
    - findings and will follow up this notification with an LER in 30 day ,
The inspectors were able to determine that the last time the throttle valves (103 A, B, C and D) were flow tested and adjusted was in 1981.
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Since that adjustment, major modifications have been 'made to the .SW system, ' including the overhaul of the SW pumps, mechanical . and chemical cleaning of the SW piping and' installation of new SW return
    - headers with newly installed spray arrays and associated valves. As a result of these modifications and maintenance, the licensee conducted post modification testing but did -not include the re-verification of the SW flow through the RSHXs (i.e., the throttle settings of the 103 and 203 ~ valves). It is unclear whether the improper throttle settings and resulting low SW flow rates were a result of the modifications or of initially not being adjusted properly. If adequate post ' maintenance testing had been conducted, the licensee would had identified the RSHX SW flow rate discrepancies earlie The combination of the questionable SW pump and CCW heat exchanger configurations (see IR 338,339/88-33), and the identification of two of the RSHXs having SW flow rates below design bring into question the past . operability of the Unit 1 SW and recirculation spray systems. This item will be identified as an apparent violation 338,339/89-08-0 The test also demonstrated that the installed SW flow instrumentation was not accurate. To ensure that the test flow data was accurate, the licensee used temporarily installed ultrastnic flow instrumentation and differential pressure instrumental!on installed across each heat exchanger. The differential pressure instruments agreed with the ultrasonic flow instrumentation for changes in the SW flow during the throttle valve adjustments. This helped confirm the'
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The licensee also determined, based on the SW pump head curves, the maximum SW flow rate which could be allowed through the Unit 2 CCW heat exchanger during normal operation and still meet the design flow through the Unit 1 RSHXs during accident conditions. This determination was made by adjusting the Unit 2 CCW heat exchanger SW flow to the maximum achievable with SW flowing through the Unit 1 RSHXs at their design flow of greater than 4500 gpm each. Then the SW flow through the RSHXs was se;ured and the resulting flow through the Unit 2 CCW heat exchanger was determired based on the SW pump discharge pressure and head curve. This flow rate, as determined by the SW pump discharge pressure, was 10,800 gpm. The installed flow instrumentation indicated approximately 12,500 gpm return header flow and approximately 14,500 gpm supply header flow, demonstrating the installed flow instrumentation inaccuracie . Operational Safety Verification (71707)
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By observations during the inspection period, the inspectors verified that the control room manning requirements were being met. In addition, the inspectors observed shift turnover to verify that continuity of system status was maintained. The inspectors periodically questioned shift personnel relative to their awareness of plant conditions. Through log review and plant tours, the inspectors verified compliance with selected TS and Limiting Conditions for Operation In the course of the monthly activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital areas access controls; searching of personnel, packages and vehicles; badge issuance and retrieval; escorting of visitors; patrols; and compensatory post On a regular basis, RWPs were reviewed and the specific work activity was monitored to assure that the activities were being conducted per the RWP The inspectors kept informed, on a daily basis, of overall status of both units and of any significant safety matter related to plant operation Discussions were held with plant management and various members of the operations staff on a regular basis. Selected portions of operating logs and data sheets were reviewed dail The inspectors conducted various plant tours and made frequent visits to the control room. Observations included: witnessing work activities in progress; verifying the status of l
operating and standby safety systems and equipment; confirming valve
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positions, instrument and recorder readings, and annunciator alarms; and l  observing housekeepin Tornado Watch
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On March 31, the licensee was notified that the area in which the '
!  North Anna station is located was under a tornado watch. The control room operators entered AP-41.1, Severe Weather Conditions, and took
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H the necessary actions ' associated witho the tornado watc Th inspector reviewed the AP, conducted a tour, of the station grounds
      'and : randomly selected portions of ;the' abnormal procedure action
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requirements to' be - verified. : The . inspector determined, based on-observations, that the licensee was ' in' compliance with' the AP. A severe weather condition did not develop.in the area:of the plant, z Tour of High Radiation Areas On April 12, the inspector made a ' tour of the following high radiation areas with the Superintendent of Health Physic (1) The B' gas stripper room (lower level).
.No problems noted.
l l-      (2) The A gas stripper room (lower level).
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The inspector observed the following:
      (a) A leak downstream of a shut' capped drain valve on a heat l3      exchanger.
l (b) A broken stem off of air operated valve IBR-P-108.
I, (c) A loose ground strap on gas stripper discharge pump 1-BR-P-78.
l      (d) Excessive boron on the gland of gas stripper discharge pump l-      1-BR-P-7 '(e) A . leaky gland on the suction valve to gas stripper l-      circulating pump 1-BR-P-10B.
l      The inspector informed the Superintendent of Operations of the:
I      above findings. The Operations Superintendent stated that an I      operator would be sent to these areas to document the problems and ensure that a maintenance work request was written on each'
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ite (3) Primary plant demineralized valve alle This area was generally clean, with the exception of two bags of tras (4) Unit 2 seal injection filter are Health Physics had stopped work in this area due to housekeeping problems. There was evidence that valve repacking had been in progress. The gasket for the 4A filter head showed signs of
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The inspectors will conduct followup tours of these areas to determine if the maintenance items are being corrected and if housekeeping has improve c. Equipment Failures During February 25, 1989, Unit 1 Reactor Trip and Cooldown to Mode The licensee has identified two valves in the list of equipment which malfunctioned during the S/G "C" tube leak and subsequent cooldown to Mode 5 of Unit 1. The identification of these valves and the related failures are as follows:
      (1) "C" Steam Generator Blowdown Trip Valve (1-BD-TV-100F) failed to clos (2) Inlet Valve to the RHR System (1-RH-MOV-1701) failed to stay open following the reactor tri The inspector reviewed applicable deviation reports, work orders and root cause analyses, performed by Maintenance Engineering to address the problem In reference to blowdown isolation valve,1-BD-TV-100F, results of the licensee's investigation show that the valve malfunctioned because the ASCO SOV was stuck in the energized position. The valve's function is to close on loss of power and/or air to the 50V, which is its "f ail-safe" positio Because the application requires the solenoid to remain ' energized during plant operation, heat is generated and the licensee believes that this heat causes the small amount of silicone lubricant, used by the manufacturer during valve assembly, to oxidize and behave like a mild adhesive holding together the core / spring and solenoid subassemblies, as previously discussed in paragraph 3.a. With these SOV parts stuck together, the solenoid was prevented from repositioning itself when de-energized on reactor trip, and the pilot valve remained open. To overcome this problem, the licensee has increased the frequency of stroking these type valves and plans to replace five redundant SOVs used for outside containment isolation, as discussed in paragraph In reference to 1-RH-MOV-1701, residual heat removal suction isolation valve, the inspector ascertained that the valve failed to stay open because relay PC-143 failed to operate. However, at the time of this inspection, the subject valve was open and the suspect breaker was locked out in the off positio The licensee was delaying stroking this valve until after fuel had been removed from the reacto Steam Gencretor "C" Tube Leak Resulting from a Mechanical Plug Failure, Unit .
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11-The inspector met with the licensee's cogniza'nt engineer to. discuss
  'the status of planned corrective actions'and obtain a progress report
  .on the mechanical plug failure analysis by Westinghouse. The failed
  . plug was located in S/G tube R3C60 of S/G "C". This failure has been ,
discussed in 'NRC Inspection Reports 338,339/89-03 and 89-0 The-plug was used by Westinghouse in November 1985 to remove the~ subject tube from. service when eddy current inspection showed it .to be defective. The plug in question vas made from inconel-600 material-produced from one of the two heats identified as NX3513 or NX396 The material was processed by 'Huntington Alloy per ASME SB-166 and furnished' as one 'nch, rough turned - round bar in the as annealed conditio A recent- Westinghouse proprietary report on the failure analysis performed on a leaky mechanical plug, removed from tube R3C6 of S/G
  "A", North Anna Unit 2 in July 1987, reported that the plug had been made from the same heat of material. The report described the microstructure as one exhibiting various degrees of carbide- network in the grain boundaries which is indicative of inadequate solution annealing, i.e., low annealing temperature, insufficient time at temperature or both. The material in question contains 0.018% carbon
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and exhibited a hardness level of HRB 104 or HRC 28.5. Further, the report stated that .this hardness level was indicative .of a significant ' amount .of cold work resulting from manufacturing practice The failure mechanism was identified as primary water
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corrosion cracking with an intergranular fracture. Mechanical plugs made from those two heats of material include 515 in North Anna Unit I and 319 in Unit A -review of photographs of the failed plug, following its removal from S/G "C", showed that is had failed circumferentially at the second landing. The-licensee is inspecting the tubes around R3C60 to verify wall integrity and stated that the adjacent tube sustained sufficient damage (dented) to preclude inspection with a standard i  size 0.720" diameter probe. The licensee will attempt to inspect the tube with either a 0.610" or a 0.580" diameter probe to determine the
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degree of damag In Unit 2, the licensee's tentative plans were to remove those plugs in which an engineering evaluation could not demonstrate safe
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operation when left in place (see paragraph 3.c for further details).
In Unit 1, plugs which are shown as unacceptable for safe operation will be plugged with a specially designed appliance to preclude the -
recurrence of a similar failur No violations or deviations were identifie . Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed reactor event The review included determination of cause, safety
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significance, performance of personnel and systems, and corrective actio The inspectors examined instrument recordings, computer printouts, operations journal entries, scram reports and had discussions with operations, maintenance and engineering support personnel as appropriat Transportation Problem with a Reactor Coolant Pump Motor On March 27, the licensee informed the inspectors that the Westinghouse contracted trailer containing an RCP motor had broken down approximately 12 miles from the North Anna station. The inspector responded to the site of the breakdown and discovered that the box containing the motor was still upright and intact on the traile It appeared that the trailer, which was a low-boy, had fatigued in the center on the right hand side, allowing the bottom of the trailer to come in contact with the highway and generating several brush fires along a two mile stretch. The truck driver noticed that the load was getting much heavier, stopped the truck and notified the licensee at approximately 11:00 The HP technician at the site of the breakdown informed the inspector that the radiation levels were as follows:
      (1) The highest contact reading on the box external was 2 mr/ hour (2) General area around the box was 0.3mr/ hour one meter from the box (3) The highest reading inside the box next to the RCP was Smr/ hour at the top of the moto The inspector was also informed that no external or internal contamination to the box was detected. The motor itself was in a herculite bag and was reported to have both fixed and loose
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contamination, but none of the contamination was detected outside the I    bag. The licensee also informed the inspector that the activity of the RCP motor was estimated to be approximately 254 milicurie The licensee transported a crane and another low boy trailer to the site and lifted the motor from the damaged trailer to a new traile The motor was then transported back to the station. The motor was in the process of being shipped by Westinghouse to their facility in Pennsylvania for overhaul when the trailer failure occurred, Loss of CCW to Unit 2 RHR Heat Exchanger On April 3, the licensee experienced a loss of CCW to the Unit 2 RHR heat exchangers. The unit was in Mode 5 with the reactor vessel level at approximately 73 inches as indicated by the level standpip This level is approximately five inches below the reactor vessel flange; therefore, the licensee was not in a reduced vessel level inventory condition as defined by Generic Letter 88-17. The
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operators determined the cause of the loss of CCW to be a loss of instrument air to the CCW containment isolation valves which caused j the valves to fail close Instrument air was restored and the valves were reopened in approximately 25 minute The RCS temperature, as indicated by the RHR pump discharge temperature, increased from approximately 91 F to 96 F during the 25-minute period. Details of the event are listed belo At approximately 1:00 p.m., the control room operator responding to an annunciator for RHR pump cooling low flow discovered the CCW containment isolation valves which also supply the RHR heat exchangers indicating shut in the control room. Operations personnel were immediately dispatched to the area in the auxiliary building where the CCW valves are located to determine cause for the closure and to reopen the valves. This effort was hampered due to the CCW valves being located in a contamination area requiring full anti-contamination clothing. At 1:21 p.m. the operators reported that there was no instrument air pressure to the CCW isolation valves. These valves are air to open and spring pressure to clos The operators proceeded to determine the cause for the loss of instrument air and in parallel to prepare a jumper to get an air supply to the CCW valves. At approximately 1:23 p.m. an operator discovered an instricent air manual isolation valve closed which isolated the air supply to the CCW valves. This valve was opened and both CCW valves were reopened by 1:25 p.m., resulting in RCS temperature (as indicated by RHR pump discharge temperature) to decrease back toward the original temperatur l The licensee determined, based on interviews with personnel in the area, that a contract painter had t'een working on piping just above the instrument air valve. This painter admitted to brushing up against the instrument air valve handwheel, but reportedly stated that he did not intentionally shut the valve. This instrument air valve is located approximately 12 feet in the overhead, and has approximately three turns from full open to full closed. The inspector along with the Station Manager and the Operations Superintendent entered the valve penetration ar2a where the instrument air valve was located to inspect the valv Based on observations and physical manipulation of the valve handwheel, the licensee determined that the valve was very easy to operate and could have been closed by the physical contact of the painte Consequently, the licensee concluded that the valve had been inadvertently closed by the painte The inspector had entered the control room shortly after the operator had discovered the CCW isolation valves closed., The inspector observed the operations staff to be very sensitive to the loss of cooling water to the RHR heat exchangers and that prompt actions were being taken to restore the cooling wate These actions included notification of station management who responded to the control room, discussions by the operations coordinator with both the electrical
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4 e l14    l t r and instrument shops .to determine if L any work that they were
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performing could~have' caused the valve closure, dispatching operators
    ' to the area and trending '.the .RHR pump discharge temperature. The emergency plan .' procedures 'were consulted to determine if. any -  .
notifications'were required and the abnormal procedures 'for loss of-RHR were consulte . . Loss of IH and 2J Emergency Busses On' April 16, 1989,'at 1115, with both units in Mode 5, the station lost the "C" Reserve Service Station (RSS) bus due to improper bus rework and relay testing in' the switchyard. The function of the "C" RSS bus is to provide power.. to the IH .and 2J emergency buses. The inspector was- in the control room at the' time of the event and observed the operations personnel response. Pressurizer levels during.the event were 8 percent and_6 percent by cold calibration for Units 1 and 2 respectivel The units were not in a midloop operation at the time of.the even The event. occurred while contract personnel were performing' an approved energizing procedure to rework the existing feed from the-34.5kv bus 4. The procedure did not detail all of the leads to be pulled or landed for the rework of the bus 4 feed. ' A technician had marked up a panel-drawing, indicating the bus 4 leads to be pulled by an' electrician. However, various leads from bus 3 were also marked on the drawing from another step in the procedure. The technicia failed to . inform the electrician.not to pull the leads for bus 3 and left the immediate area. Consequently, when a bus 3 lead was lifted c and went to ground, a 300 millisecond timer was ' activated and timed out,: which - then deenergized the "C" transformer. The technicia .upon realizing that had occurred, immediately notified the operations personnel of the' occurrenc The loss of the "C" RSS power supply ~to the IH and 2J emergency buses resulted in the IH and 2J EDGs being auto-started. Component cooling pumps auto-started and loaded as designed on both units. The Unit 1
    "A" RHR pump, which was running at the time of the event, tripped on undervoltage. Operations personnel entered 1-AP-11, Loss of.RHR, and successfully started the Unit 1 "B" RHR pump. The decision to vent the "B" pump prior to starting was made because operations personnel were in the area at the time of the event and the pump had not been run recently. This did not significantly delay the reestablishment of shutdown cooling to the uni All other major equipment functioned normally, and operator response was appropriate.
l    As part of the corrective actions to the event, the licensee l    discussed the evolution with the contractor technicia Further discussions were held with the contractor management on the impact of
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contractor actions on the safety of the plant. The licensee made a four-hour report on the even .
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d. RCS Vessel Level On April 26, Unit I was in Mode 5 with vessel level being maintained in a level band of 68" to 72" above nozzle centerline. This level band maintains level 26" to 30" above the " Reduced RCS Inventory" level of 42". The vessel level was being monitored by a standpipe located in the containment with a CRT monitor in the control roo The operators were maintaining this level band by periodically pumping any RCS leakage from the Primary Drain Transfer Tank (PDTT)
to either the RCS via the RHR System or to the Gas Stripper syste Additionally, a head purge had been in progress for approximately 20 hours. During head purge, vessel level was erratic in indication but remained on-scale. On observing a decrease in process vent flow, the operators secured the head purge at 022 When the purge was secured, the RCS standpipe level dropped below the lowest ruler mark indicated on the control room CRT monitor (68"). Personnel were dispatched to the containment to investigate, and a makeup was commenced to the RCS. RCS level was returned on scale in the control room at 0315. A total of approximately 546 gallons was added to the RCS from the VCT and level increased to 71". No problems were found with the system line up in the containment, and the licensee concluded the decrease in water volume was caused by diverting of inventory from the PDTT to the Gas Stripper system to keep RCS standpipe level on scale during the head purge. (Disc Pressurization of the RCS loop isolation valves from an Accumulator causes a positive in-leakage to the RCS of approximately .35 .5 gpm.) The licensee further concluded that the head purge affected standpipe indicated level by causing it to be erratic and indicate hig On April 27 at 0500, with Unit 1 plant conditions as described above, RCS standpipe level was again observed to be excessively erratic in its indicatio Head purge which had been in service at that time for approximately 18 hours was secured to check standpipe leve When the head purge was secured, standpipe level again went off scale low (below lowest observable indication on CRT monitor - 64").
Makeup from the VCT and PDTT was started and 860 gallons were added to restore level to 66". At 0545, a containment entry was made and verified level was at 54". Thus, level decreased less than 54" to a value that could have approached 42". Head purge was restarted and level increased to approximately 70".
The inspector reviewed the controlling procedures for the plant conditions and evolutions occurring at this tim These are 1-0P-5.4, Draining the Reactor Coolant System, and 1-0P-11.3, Purging the Reactor Vessel Head. Neither procedure 1-0P-5.4, nor any other procedure, addresses the methodology being utilized for the mainte-nance of reactor vessel leve Specifically, the PDTT would be pumped, as appropriate, to either the RCS (theough a temporary jumper to the RHR system) or to the Gas Stripper system. Interviews with the operators indicated a satisfactory knowledge of this system line-u The operators were also knowledgeable concerning RCS
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      -leakage rates and accumulator in-leakage rates (calculated by the STA
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      ' once a shift). However, since neither .the RCS leakage calculations or the operators ' tracked the amount'of inventory transferred from the'
  .. PDTT to the Gas Stripper system, the maintenance of adequateLreactor vessel level became primarily a function of an accurate standpipe level indicatio ~
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Procedure 1-0P-11.3 precluder draining of. the RCS with a reactor vessel head. purge in progres Similarly, procedure 1-OP- cautions that. draining of the RCS is not allowed while purging the-reactor head. Interviews with the operators indicated that they felt in compliance with these procedures during a reactor. head purge'even-when transferring.the RCS inventory f rom the PDTT. to the Gas Stripper system. The: operators indicated that the purpose of the inventory transfer was for maintenance'of reactor vessel level between 68" and 72" and not a purposeful lowering of level that would be accomplished by a draining operation. The operators recognized that the reactor head purge could cause standpipe l level to be erratic and indicate inaccurately high. The assumptinn was made.that although this. level indication could be inaccurate, as regards the exact reactor vessel level, it could be relied on as a trending indicator to insure that vessel level was being properly maintained during PDTT pumping operations. This assumption proved to be incorrect with respect to pumping of the PDTT and associated diversions of.RCS inventory to the Gas Stripper system. The operators' actions over a period of hours,
  ,    although intending to maintain level,. effectively established an RCS draining evolutio Procedure .1-OP-11.3 provides no guidance or precautions with respect to conducting evolutions that have the -
potential for reduction of reactor vessel level. Procedure 1-0P-5.4, Step 5.31 also cautions that during Reactor Vessel Head Purging operations, the RCS standpipe may inaccurately indicate low. This statement is at variance with what was actually observed to occu The failure to control RCS stardpipe level and the failure to identify and correct the problem after the April 26 event is identified as an apparent violation (338,339/89-08-04). j 'L'icensee Event Report Follow-up (90712)  l i
The following LERs were reviewed and closed. The inspector verified that 1 reporting requirements had been met, that causes had been identified, that corrective actions appeared appropriate, that generic applicability had been considered, and that the LER forms were complete. Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations of regulations or TS conditions had been identifie (Closed) LER 339/89-006, Pressurizer Code Safety Valves Out of Toleranc This LER documents the testing of the Unit 2 pressurizer code safety relief valves which is performed every refueling outage. The relief valves are removed from the plant and shipped to Wyle labs to be setpoint and leak tested. The results of the test indicated that the as found lift
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setpoint pressure for the C relief valve. (2-RC-SV-255IC) was below the TS
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3.4.3 criteria of. 2485 11% psig (actual setpoint was 2444)>and that the A
  - relieff valve;(2-F.C-SV-2551A) leaked by the seat following the as found
  - testing. The vendor performed maintenance on the' valves and the as left setpoints were reported to be within the TS 3.4.3 criteri During the L ,  previous Unit 2 outage in 1987, the A and B reliefs exceeded the TS criteria and again: the C relief was below the TS criteria-(as found 2447  '
psig). .The licensee has not b?en able to determine a root cause for the setpoint drif J
  ' (Closed) LER 339/89-05, Main Steam Safety Valve Setpoints Out! of
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L  Tolerance. The LER-documented the ~ testing performed at Wyle labs of all 15 of the Unit 2 main steam code safety relief valve Five of the safeties exceeded the' TS criteria of  1%, two of which were lower and l:  three were higher than the TS criteria. The licensee conducted a evaluation and determined that the design pressure of the steam generators would not be exceeded even though three of the safeties had setpoints higher than the criteria. .The LER also stated that all 15 valves exhibited some seat leakage following the as found testing. During the 1987 Unit 2 refueling outage, the licensee reported that 11 of the 15 code safeties exceeded the TS pressure setpoint criteria (all higher) and.14 of the~15 exhibited seat leakage following the as found testing, p  The vendor refurbished and retested the valves to ensure that the as left
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pressure setpoints where within the TS tolerances and exhibited no seat leakage. The licensee has not been able to determine a. root cause for the:
setpoint drift and leakag . Action on Previous Inspection Findings (92701)
  (Closed) Unresolved Item 338,339/88-33-07, Review of root cause analysis and corrective actions regarding ECCS pump breaker problems. In NRC Inspection Report 338,339/88-33, the inspector identified this URI pending determination by the licensee of root cause analysis and corrective actions concerning ECCS pump 480 volt breaker problems. A vendor representative from Brown Boveri overhauled and cleaned several 480 ITE u  breakers. The result of the inspection indicated that the roller surfaces
  - and latches were sticky and difficult to rotat Dried mud and debris were found inside the mechanism, and there was evidence that both degreaser and oil based solvents had been used on the breakers. It-is suspected that a contributing factor to the breaker malfunction was the use of improper lubricant in non-compliance with the technical manual
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recommendation combined with leaving the doors to the building housing the breakers open with a far. blowing in dust and debris from outside during the hot weather months. As a result, the licensee is planning to initiate an EWR to be performed during this outage. The EWR will install a filter and fan in the room housing the breaker. The inspector will monitor the    '
licensee's action during the hot summer iaonths to determine if the breakers are maintained free of dust and debri .
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In NRC Inspection Report 338,339/88-33 the inspector requested the-    i
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licensee to provide information regarding operability of the B Quench Spray System since the pump breaker failed to close properly. Based on Technical Specification 4.3.2.1.3 and Table 3.3-5, the Quench Spray Pumps are required to develop an acceptable discharge pressure within 58 seconds. Periodic Test 1-PT-36.7.5 determined the response time for QS pump 1-05-P-1B. The response time of 22.4 seconds was obtained during the last performance of 1-PT-36.7.5 and the operator approximated the time delay of the breaker closing to be 30 seconds. This places the pump performance very close to the Technical Specification limit. Pump 1-QS-P-1B could have been inoperable depending on the exact breaker closing time. The licensee submitted LER 89-001 " Sluggish Operation of ITE 480 Volt Breakers Due to Inadequate Lubrication" to document the problem. A review of this LER, revealed that the 480 volt breaker for the inside recirculation spray pump (1-RS-P-1A) failed to close within the time allowed by T During the investigation of the maintenance procedure EMP-P-PL-01, 480 Volt Load Centered Air Circuit Breakers, the inspector determined that the procedure did not include the specific lubrication requirements, specified in the technical manual. The technical manual states that no lubrication is required during the circuit breaker normal service life. However, if the grease should become contaminated or if parts are replaced, any lubrication should be done with NO-0X-ID or Anderol grease as applicabl Technical Specification 6.8.1.a requires written procedures shall be established, implemented and maintained, covering the applicable proce-dures recommended in Appendix "A" of Regulatory Guide 1.33, Revision 2, February 1978. Section 9 of Regulatory Guide 1.33 requires procedures for performing maintenanc The failure of the licensee to have adequate maintenance procedures to ensure proper operation of ESF equipment breakers will be identified as a violation 338/89-08-0 (Closed) Unresolved item 338,339/89-03-03, NRC review of TS 4.6.1.1. The situation associated with this item involves the failure of the licensee to verify the position of the three quarter inch up to two inch capped vent and drain valves which are located within the containment penetration boundary as recuired by TS 4.6.1.1.a.1. The licensee informed the inspector that they had not considered these vent and drain valves as containment isolation valves. The licensee believed that the TS requirement only applied to manual isolation valves which isolated the main pipe penetration. Consequently, the licensee admitted that they did not perform the TS surveillance on these vent and drain valve TS 4.6.1.1.a.1 states, in part, that at least once per 31 days the if censee will verify all penetrations not capable of being closed by operable containment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in their position Periodic tests 1-PT-60.1 and 2-PT-60.1, Containment Integrity, is the test performed by the licensee every 31 days to comply with TS a.6.1.1.a.1. This procedure
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inspects approximately 43 containment penetrations to verify that the closure mechanism is closed (e.g. valve hatch, etc.). Howevar, the vant and drain valves located between each containment isolation valve and the containment penetration (outside of containment) were not listed in this procedur The failure of the licensee to comply with surveillance TS 4.6.1.1.a.1 will be identified as a violation 338,339/8S-08-0 . Generic Letter 88-17 Loss of Decay Heat Removal (TI 2515/101)
The inspectors reviewed Generic Letter 88-17 and the licensee's response to the generic ' lette At the time of the review, the licensee was preparing Unit 2 for entry into a reduced RCS inventory condition as defined by.the generic letter. Prior to entry into a condition with' RCS level less than three feet below the vessel flange of the applicable limit, the licensee experienced three events involving loss of RHR'
capability (see paragraphs 4.a 6.b and 6.c). During these events, the operators demonstrated a heightened sensitivity concerning the loss of RHR-and took prompt and aggressive corrective actions to restore RHR cooling .
      -capabilit ~The inspector has reviewed the li,ensee's procedures and controls regarding loss of RHR. The following is a brief description of the inspector's review, Training As discussed'in NRC Inspection Report 338,339/88-36, the inspector attended the operator's tcaining session associated with the loss of RHR events. The inspector _ felt the training was excellent for the l-      time; allotted. The inspector also attended a training session for maintenance personnel on April 5. This session discussed the effect maintenance activities can have on RCS level and the operating RHR pump and components. The training also described the additional controls which will be placed on ' any maintenance . activity that can affect RCS inventory. The inspector felt that this training session covered the concerns and controis associated with performing
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maintenance during a reduced RCS inventory conditio One observation made by the inspector was that the licensee did not document the briefings conducted with maintenance personnel-subsequent to the initial training sessions. This observation was discussed with the license Containment Closure l
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The inspector reviewed 2-OP-5.4, Draining the Reactor Coolant System, and determined that the procedure required containment integrity to be established in accordance with 2-PT-91, Containment Penetrations,
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prior to RCS' level being reduced to less than 42 inches above nozzle centerline. 2-PT-91 step 5.26 also requires that the containment closure team be established prior to RCS level reaching 42 inche .
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    : The inspector . verified that the SRO log listed. the names of the ,
maintenance personnel who were assigned to the containment closure team during a particular shif The inspector also reviewed the
,    containment breach log which was attached ' to 2-PT-91 listing all    '
penetrations other than the equipment hatch and personnel hatch which L    had to'be closed to establish containment closure.
l One weakness identified > hy the inspector was the lack. of procedural-requirements for the establishment of the closure team, the training and briefing requirements for the team and the documentation of personnel attending briefings. However, during the present outage i
the inspector did not detect any lack of understanding of the purpose
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and requirements for the tea The reason appears to be the heightened sensitivity by both management and the operations staff to i    the issues concerning Generic Letter 88-17 and loss of RHR. However, in the future, if these requirements are not formalized, they may not I    get implemented as effectivel The inspector has discussed this observation with the licensee and
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they have agreed to review the situation and provide some additional I,    procedural guidance and controls. The inspector will review the l    licensee's actions again during the Unit 1 outage and will include a i    review of the licensee's procedural guidance associated with I
containment closure requirement RCS Temperature The inspector reviewed 2-0P-5.4, Draining the Reactor Coolant System.
l    This review revealed that step 4.9 and step 5.26 of the procedure required the operator to verify that two core exit thermocouple are operable prior to RCS level reaching 42 inches above nozzle center-line (three feet below the vessel flange). The core exit thermocouple are displayed on the core cooling monitor in' the control roo The inspector verified on several occasions while the Unit' 2 reactor was in a reduced inventory condition that at least two thermocouple were operable and that the operator knew which ones were operable.
L    During the times checked, the inspector. observed five operable L    thermocouple indicating in the control and being logged by the l    operator in 1-Log-4 The inspector compared the thermocouple l    temperature readings to the RHR pump discharge temperature and they l    were very close confirming the operability of the thermocouple. The RHR pump discharge temperature was also being recorded via a strip char The inspector reviewed 1-AP-11.2, Loss of RHR. Attachment 7 of the procedure included a set of curves illustrating the heatup of the RCS following the loss of RHR. Even though Attachment 7 is located at the back of 1-AP-11.2, the inspector could not find any reference to
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21    i this set of curves in the body of the procedur This observation was discussed with the license d. RCS Water Level .
North Anna presently has only one means of RCS level indication during reduced inventory conditio This means of indication is a temporarily installed tygon hose with a TV csmera and continuous monitor in the control roo In a letter from L. Engle, Project Manager, NRR, to W. Cartwright, Vice President, VEPCO, dated February 13, 1989, the NRC concurred with the use of only one means of RCS level indication for the short term at North Ann The inspector observed the RCS level indicatior via the TV monitor on each tour of the control room. The level indication was clear and easily rea The operators were monitoring the RCS level periodically and are required to log the results every 4 hour During RCS draining evolution, the inspector observed an operator in the control room on a head set monitoring the TV monitor while in communication with an operator in the containment locally monitoring the RCS standpipe level. The inspector observed portions of the level standpipe hose during a tour of containment on April 1 No problems were observe e. RCS Perturbation The inspector reviewed 1-MISC-37, Assessment of Maintenance Activities for Potential Loss of Reactor Coolant Inventory. This procedure requires the Shift Superviser to assess all work orders associated with the RCS, 51, RHR, RP or CVCS systems using the following criteria:
  (1) Component cannot be isolated completely from RC (2) Operator action is required to maintain system level to permit maintenanc (3) Positive identification of component may not occur due to similar devices in a surrounding are If the assessment of the above indicates there is a potential for loss of RCS inventory, then the following actions are required:
  (1) If maintenance requires an opening on the cold leg during mid-loop operation, establish and verify a hot leg vent path.
'    Ensure proper administrative controls are established to inaintain the hot leg vent path until system integrity is restore .
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    (2) Conduct a pre-job briefing with maintenance personnel. Discuss loss of inventory ' potential and contingency action (3) Have .an operator accompany maintenance personnel to positively identify the component and establish communication (4) Ensure makeup capability to the RCS is readily availabl (5) Establish communications between work site and control roo (6) Notify the control room at the time work is started and when work is suspende (7) Monitor RCS level (standpipe, pressurizer level, cavity level, reactor vessel level) and containment sump level frequently during the proces (8) Notify the control room when the component is closed and system integrity is restore All of the above items were discussed in detail during the maintenance training session attended by the inspector on April 5.
l    2-OP-5.4, Draining the Reactor Coolant System step 3.0 requires that l    MISC-37 be entered into the action si iement status log and a copy forwarded to the Shift Supervisor. This procedure also requires the
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following:
    (1) An operator to be stationed in containment in communication with the Control Room to monitor RCS level during draining evolutions.
l    (2) All personnel involved in the draining evolution must attend a pre-job briefin (3) No draining of RCS while purging the vessel hea (4) The pressurizer PORVs and their isolation valves to be open venting the RC The inspector found the procedure to be somewhat confusing, but did not observe the operators having any problems maintaining compliance with the generic letter requirements. The inspector discussed the procedure deficiencies with the license f. RCS Inventory Addition The inspector verified that 2-OP-5.4 required that one HMSI and one LHS1 pump be operable prior to the RCS level being lowered three feet I
below the vessel flang MISC-35.1, CR0 Turnover Checklist (Modes 5 and 6), step 7 requires the offgoing and oncoming CR0s to
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7. i st the two operable pumps and flow paths any time RCS level is three feet or more below the vessel flange. The inspector periodically verified based on control room indication the operable pumps and flow path .
Abnormal procedure 2-Ap-11.2, Loss of RHR, establishes the criteria for using the ECCS pumps to feed and bleed the reactor vessel. This  l procedure provid'.s attachments with the requirements for the use of  J either the HHSI pump or LHSI pump to maintain the core covered and to remove decay hea Nozzle Dams      ,
North Anna has loop stop valves and, therefore, does not use nozzle dam Loop Stop Valves The inspector reviewed a memorandum from J. O. Erb, VEPCO, to A. Heacock, VEPCO, dated March 30, 1989, which stated that the  ,
required vent path for the hot leg side of the vessel should be greater than 19.19 square inches. This vent path is established to prevent the hot leg side of the vessel from pressurizing with all three of the hot leg stop valves closed and a hole in the cold leg side. The lice.nsee's assumptions included 52 new fuel assemblies and 35 days since shutdown in determining the required vent siz The licensee chose the vent path to be the flange opening for two of the removed pressurizer safety relief valve The licensee determined that one opening was greater than 19.19 square inches but to be conservative, they elected to use two opening To prevent foreign material from entering the opening, the licensee installed screens over the openings. During a tour of containment the inspector observed the openings and the screens. It appeared to the inspector that the metal of the screens took up approximately half of the area of the openin The inspector questioned the licensee and requested a calculation be performed determining the effective area of the openings minus the ?rea of the screen meta The calculation was performed and reported to the inspector. The report stated that the sum total of both openings was just over the requirement of 19.19 square inches (actual 21.22 square inches).
The inspector's overall observation of the licensee's actions regarding the potential loss of RHR was favorable. Both management and the operation staff demonstrated increased sensitivity toward any evolution potentially affecting RCS inventory. The actions and procedures, even though several procedural upgrades are needed, were more than adequate to comply with their commitments to the generic letter. The minor procedural inadequacies were compensated for by the operator training and resulting knowledge level of the
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requirements for operating in a reduced RCS inventory conditio Although the licensee's program for operating during a known reduced inventory condition was favorably reviewed, an RCS level control event, which occurred after the generic letter inspection effort, revealed a . fundamental problem with knowing the actual level when using the standpipe system. This issue is discussed in paragraph . Refueling Activities (60705, 60710)
The inspector reviewed the completed refueling master procedure 1-0P-4.3, Controlling Procedure for Refueling. This review verified that the precautions, initial conditions and action steps were completed and signed off. The inspector observed that the applicable TS were listed in the procedure and verified each time they were applicabl The inspector interviewed the refueling coordinator and the refueling shift supervisors. The inspector discussed the training activities for the Westinghouse refueling personnel. The coordinator informed the inspector that the contract refueling personnel were experienced refueling personnel and received the training wel During the 1987 refueling outages, the refueling activities went well with the exception of two problems, one on each unit. These problems resulted from the contract refueling personnel failing to follow procedure During the present Unit 2 refueling outage, the refueling shift supervisors informed the inspector that the contract refueling personnel were very receptive to their requests, unlike the previous outag The inspector was also informed that the refueling personnel followed the procedures and their supervisor was very diligent in making sure that all refueling steps were complete and properly signed of The inspector reviewed the deviation reports documented against the refueling activities. This review did not reveal any problems similar to the two reported problems during the 1987 outages. There were a couple of minor discrepancies, but these errors did not have the potential for fuel damage and were discovered by the refueling shift supervisor and correcte The core off load commenced on March 14 and the reload was completed on March 29. The only problem experienced during the fuel movement in the reactor cavity involved new fuel assembly X44. This assembly would not line up ar.d seat on the lower core plate. The assembly was removed and inspected. The lower flow nozzle suffered some damage due to the lower core plate alignment pens coming in contact with the lower nozzle fee The assembly was replaced with the same type of new fuel assembly scheduled for Unit I refueting. The damaged assembly X44 had the bottom nozzle removed and both the assembly and nozzle were shipped to Westinghouse. The bottom nozzle will be replaced with a new one and the fuel assembly will be shipped back to the station for use in Unit .
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11. Storage.and Handling of EDG Fuel Oil (25588)
On January 16,1967, the NRC issued IE Information Notice 87-04 to alert the licensee of potentially significant. problems . pertaining to long-term storage of fuel oil for EDGs. The , inspector reviewed the licensee's
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programs . for maintaining adequate quality of the EDG fuel oil stored on-site. Through reviews and interviews, the inspector determined that the licensee:
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Evaluated the aforementioned Information Notice 6nd other similar industry events,
  - Took actions as a result of the evaluation, including lean out of fuel oil tanks, evaluation of samples for biologio. growth, and evaluation of the use of additives to the fuel,
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Routinely. samples the fuel oil for viscosity, water, and' sediment in accordance with TS, and
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Inspects and cleans fuel oil filters and strainers during outage No violations or deviations were identifie . Exit The inspection scope and findings were summarized on April 17, 1989, with those persons indicated in paragraph  1, The issue discussed in paragraph 6.d. was summarized with the licensee on May 2, 198 The inspectors described the areas inspected and discussed in detail the inspection results listed belo The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspectio Dissenting comments were not received from the license Violation 338/89-08-01, Failure to have adequate maintenance procedures to ensure proper operation of ESF equipment 480 volt ITE breakers (paragraph 8).
Violation 338,339/89-08-02, Failure to comply with TS 4.6.1.1.a.1 for containment penetration vent and drain valves (paragraph 8).
Apparent Violation 338,339/89-03-03, Potential for the SW and RSHXs to have been inoperable (paragraph 4.b).
Apparent Violation 338,339/89-08-04, Inadvertent loss of reactor vessel level (paragraph 6.d.).
A licensee oral commitment to develop a formalized approach for obtaining control operations assistance and establish an implementation schedule by May 17, 1989, was discusse .
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CDA  Containment Depressurization Actuation
  ~CR Control Room Operator DCP'  Design Change Package DHR  Decay Heat Removal DUR  Drawing Update. Request EDG    Emergency Diesel Generator EP    Emergency Procedure ESF    Engineered Safety Feature EWR    Engineering Work Requests GPM  Gallons Per Minute HP    Health Physics IFI    Inspector Follow-up Item IR    Inspection Report LCO    Limiting' Condition for Operation LER    Licensee Event Report MCC~  Motor. Control Center MOV  Motor Operated Valve MPC  Maximum Permissible Concentration MREM  Millirem MSSV  Main Steam Safety Valve NRC  Nuclear Regulatory Commission NSE    Nuclear Safety Engineering PDTT  Primary Drain Transfer Tank PES    Plant Engineering Services PORV  Power Operated Relief Valve PROM  . Programmable Read Only Memory PSIG  Pounds Per Square Inch Gauge PTSS  Periodic Test Scheduling System RCS  Reactor Coolant System RHR    Residual Heat Removal RMS    Radiation Monitoring System RS_    Recirculation Spray RSHX  Recirculation Spray Heat Exchanger RTD    Resistance Temperature Detector RWP    Radiation Work Permit S/G    Steam Generator SALP  Systematic Assessment of Licensee Performance SI    Safety Injection SNSOC  Station Nuclear Safety and Operating Committee 50V    Solenoid Operated Valve STA    Shift Technical Advisor SW    Service Water TS    Technical Specification TSC  Technical Support Center UE    Unusual Event URI  Unresolved Item
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ENCLOSURE PROPOSED MEETING AGENDA Virginia Electric and Power Company (VEPC0) Meeting with NRC May 24, 1989 I. Opening Remarks    NRC II. Issues of Concern    VEPC0 Service Water Flow Issues as Described in Inspection Report Nos. 50-338,339/89-08 Reactor Vessel Level Perturbations as Described in Inspection Report Nos. 50-338,339/89-08 III. Closing Remarks    NRC
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Revision as of 04:55, 10 February 2021

Confirms 890524 Enforcement Conference in Region II Ofc to Discuss Problems W/Svc Water Flow & Reactor Vessel Level Perturbations Discussed in Insp Repts 50-338/89-08 & 50-339/89-08
ML20247L737
Person / Time
Site: North Anna  Dominion icon.png
Issue date: 05/17/1989
From: Ernst M
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To: Cartwright W
VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
References
NUDOCS 8906020244
Download: ML20247L737 (2)
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Text

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MAY 17:1989 L

(v, Virginia Electric and. Power Compan ATTN: Mr. W. R. Cartwright, Vice . President, Nuclear Operations 5000 Dominion. Boulevard Glen A11en',-VA 23060~.

i Gentlemen:

eSUBJECT: CONFIRMATION OF ENFORCEMENT CONFERENCE ARRANGEMENTS DOCKET NOS. 50-338 AND 50-339 This confirms the telephone conversation between R.LF. Saunders of your staff'

and M. S. Lewis : of my staff, on May 9,1989, . concerning .'an Enforcement Conference to be conducted at the. NRC Region II Office on May 24, 1989, at 10:00-a.m. We requested this meeting to discuss problems with service water.-

flow and' reactor vessel level perturbations, which have been-identified at North Anna. Enclosed is a proposed meeting agend Should you have any; questions regarding these arrangements', we will be pleased to discuss'the ,

Sincerely,

. Original signed by M. L. Erbst Stewart . Ebneter (for)

Regional Administrator  ;

L- _nc10sure:

Proposed Meeting Agenda cc w/ enc 1:

G. E.-Kane, Station Manager R.:F. Saunders, Manager - Nuclear Programs and Licensing Commonwealth of Virginia L

bec w/ encl:

NRC Resident Inspector Document Control Desk e

8906020244 890517 DR MDOCK 0 % y8 I

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ENCLOSURE PROPOSED MEETING AGENDA Virginia Electric and Power Company (VEPC0) Meeting with NRC May 24, 1989 I. Opening Remarks NRC II. Issues of Concern VEPC0 Service Water Flow Issues as Described in Inspection Report Nos. 50-338,339/89-08 Reactor Vessel Level Perturbations as Described in Inspection Report Nos. 50-338,339/89-08 III. Closing Remarks NRC

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