ML20034H196
| ML20034H196 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 03/11/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20034H186 | List: |
| References | |
| 50-445-92-60, 50-446-92-60, NUDOCS 9303160154 | |
| Download: ML20034H196 (68) | |
See also: IR 05000445/1992060
Text
{{#Wiki_filter:. i ! . i . APPENDIX B
, U.S. NUCLEAR REGULATORY COMMISSION REGION IV ,
Inspection Report: 50-445/92-60 50-446/92-60
Operating License: NPF-87 Construction Permit: CPPR-127 ' Licensee: TV Electric Skyway Tower 400 North Olive Street Lock Box 81. Dallas, Texas 75201 , Facility Name: Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 Inspection At: Glen Rose, Texas Inspection Conducted: December 6, 1992, through January 30, 1993 9 Inspectors: D. Graves, Senior Resident Inspector W. Jones, Senior Resident Inspector R. Kopriva, Senior Resident Inspector R. Latta, Resident Inspector y L Myers, Resident Inspector. , G. Pick, Senior Resident Inspector ' G. Werner, Resident Inspector P. Goldberg, Reactor Inspector W. McNeill, Reactor Inspector C. Paulk, Reactor Inspector ., M. Runyan, Reactor Inspector
A. Singh, Reactor Inspector R. Vickrey, Reactor Inspector R. Lantz, Reactor Engineer.(Examiner) , Accompanying Personnel: L. Yandell, Chief, Project Section B, Division of Reactor Projects V Gaddy, NRC Intern R. Wise, Allegation Coordinator D. Murphy, Investigator, 01 'R. ' Brady, Special Assistant, Associate Director for i . Advanced Reactors & License Renewal, Office of
Nuclear Reactor Regulation t .! Da>d. tDM Approved: ~ Date
L. A. Yandell, Chief,-Project Section B Division of Reactor Projects ,
f E. 9303160154 930311 ' PDR ADOCK 05000445 G PDR l . . . , . - _ . . . __ .
- - t ' .. s -[~ e Inspection Summary Areas Inspected (Unit 21: Routine, unannounced inspection of onsite followup. , of events; plant status; preoperational program implementation verification; operational staffing; preoperational test procedure verification; preoperational test results evaluation verification; Temporary Instruction (TI) 2500/019, " Reactor Vessel Pressure Transient Protection for Pressurized Water Reactors (PWRs)"; TI 2515/065, "THI Action Plan Requirement ' Followup"; TI 2515/066, " Inspection Requirements for IE Bulletin 84-03, - ' Refueling Cavity Water Seals'"; followup on violations; additional followups; i and followup on construction deficiencies. Areas Inspected (Unit 1): No inspection of Unit I activities was performed. - Results (Unit 2): - The material condition of the plant improved over the duration of - the inspection period-(Section 2.1).
Security's response to two events was appropriate (Section 2.2).
A failure to maintain control of system status in the chemical and
volume control system (CVCS) resulted in a violation (Section 2-3). . The licensee's implementation of the program for. turnover of system
custody from startup to operations was found to be satisfactory, although one noncited violation was identified regarding an ungrouted pipe support (Section 2.5). r The licensee's program for review of deferred work. items was found to
provide the appropriate evaluation and prioritization (Section 2.6). I Preoperational test procedure and test results verifications were
effectively performed by the licensee (Scction 3).
Operational staffing was determined to be appropriate and sufficient for .;
dual unit operation (Section 4). l A review of SAFETEAM activities determined that the program was
effectively implemented (Section 5.1). The licensee had installed equipment and was maintaining it in
accordance with the environmental qualification program and 10 CFR Part 50.49 requirements (Section 5.2). Although no valves were found out of position during the performance of
verification valve lineups, several valves were identified that were not included in the system operating procedure, which resulted in a > ' violation (Section 5.3). ,
.. . -3- . A violation was identified in that corrective actions taken as a result
of previously identified abnormal operating procedure deficiencies were not sufficient to identify and correct additional deficiencies that existed-in other procedurer (Section 5.4). The licensee's short-term corrective actions regarding the Operational
Readiness Assessment Team's inspection findings.were verified to be satisfactorily completed or in progress (Sections 5.3, 5.4, 5.5,_
and 5.6). j Unit 2 had satisfactorily implemented provisions for operation in a
reduced inventory condition to respond to a loss of decay heat removal event (Section 5.7). The licensee's process for evaluating and reporting of defects required l
'/10 CFR Part 21 was satisfactory, although two weaknesses were
t identified (Section 5.8). Results (Unit 1): Not applicable. Summary of Inspection Findings: Violations 446/9260-01, -02, and -03 were opened (Sections 2.3, 5.3,
and 5.4). One noncited violation was identified (Section 2.5).
Inspection Followup Item 446/9260-04 was opened (Section 5.4)
Three Mile Island Action Plan Items I.C.I.1, I.C.1.2.B, I.C.I.3.8,
I.D.2.2, II.B.I.2, II.B.I.3, II.B.3.4, II.D.3.1, II.E.1.2, II.E.1.3, II.E.1.2.2.C, II.E.3.1.1, II.F.1.2.A, II.F.-l.2.C, II.F.1.2.D, II.F.1.2.E, II.F.1.2.F, II.F.2.2, II.F.2.4, and II.G.I.1 were closed (Section 7). Three Mile Island Action Plan Item I.D.2.3 was reviewed but not closed-
(Section Fj. Violations 445/91202-01; 446/91201-01, 445;446/9208-02, 446/9225-01,
446/9233-01, and 446/9234-01 were closed (Section 9). Inspection Followup Items 446/9204-02, 446/9221-01, and 446/9251-02 were
closed'(Section 10). Construction deficiencies Significant Deficiency Analysis
Reports (SDARs) CP-85-29, CP-85-35, CP-86-41, CP-86-45, CP-86-82, CP-87-23, CP-87-68, CP-87-71, CP-87-135, CP-92-14, CP-92-18, and CP-92-19 were closed (Section 11).
. . -4- , Attachments: Attachment 1 - Persons contacted and exit meeting
Attachment 2 - Documents reviewed
Attachment 3 - List of acronyms . , a t
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DETAILS 1 PLANT STATUS (71707) During this inspection period, the preoperational test program was essentially completed, with test and retest deferrals identified and approved. All systems, buildings, rooms, and areas were turned over to nuclear operations. ' The radiological control area was expanded to include the Unit 2 containment- and safeguards buildings. All site activities, as of December 21, 1992, came under the control of Nuclear Operations programs, with the exception of identified and management approved items previously initiated under construction and/or startup programs. The licensee has requested an operating license via TU Electric letter, TXX-93001, dated January 30, 1992. - 2 PRE 0PERATIONAL TEST PROGRAM IMPLEMENTATION (71302, 92701) , The inspectors evaluated the licensee's management contrel program to < determine that jurisdictional controls were observed for system turnovers, that systems and components undergoing testing were properly controlled, that ' maintenance activities and preoperational tests were adequately performed, that test discrepancies were properly identified, and that test procedures and operational verifications were satisfactorily conducted. 2.1 Unit 2 Tours , i The inspectors conducted tours of the Unit 2 facility inspecting for hardware deficiencies, procedural adherence, and general plant cleanliness. The inspectors observed numerous concrete expansion anchors installed in walls and/or ceilings that were abandoned. Following discussions with the licensee and the review of Procedure CQP-CV-109, Revision 1, " Structural Embedments," the inspectors concluded that the abandonment of the wall anchors was
acceptable. The inspectors observed a rope attached to a cable in the Train A switch gear room and tied to a support mounted on the room ceiling. The licensee investigated and determined that it was a rope left behind following cable ., pulling activities. The licensee stated that the rope would be cut and
abandoned in accordance with Specification CPES-E-2004, Revision 1, ! " Installation Cable / Wire," Step 3.4.5.14. ' , The Unit 2 containment recirculation sumps were inspected for wire mesh screen l integrity, screen installation, and sump cleanliness. The sumps were verified to be clean, with no loose debris anywhere inside the screen structure. Visual inspection of the residual heat removal (RHR) and containment spray suction piping up to the first bend concluded that the piping contained no foreign material and was also clean. l T
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' . -6- , . One_ repair to one of the inner fine mesh screens was observed and several , missing fasteners were identified on both sump screen. structures. The
inspectors reviewed TU Evaluation (TVE) Form 92-5832, Revision 1, which provided the technical justification for the screen repair, and found
it to be acceptable. The inspectors also reviewed Design Change i Authorization (DCA)-22969, Revision 7, which provided the authorization and j basis for acceptability of the observed fastener configuration, and found it ' , to be acceptable. j 2.2 Security Response
The inspectors observed the security organization's response to two specific ', events involving an unauthorized access into a vital area and the breach of a vital area access during a maintenance activity. Both instances were identified by the licensee and the response was both timely and appropriate. , ! In the unauthorized access event, the determination was made that the individual had been inattentive while entering the room with a group of people and did not realize that his access had been denied. The individual was then escorted to the security office _by a guard. The inspector observed the , guard's response during the event and determined it was appropriate. , In the second event, appropriate compensatory measures were implemented and ~
verified in place by the inspector.
2.3 CVCS Valve Hispositioning
During the course of performing a fill and vent of the Unit 2 CVCS, the licensee identified several instances of valves not being in their expeued , position. The following chronology was determined by the licensee's team
tasked with determining if the available evidence was sufficient _to warrant a generic concern regarding unauthorized manipulation of station components. ! On December 28, 1992, while performing a valve lineup of the system, e ' Valve 2-8417A, the Charging Pump Suction Valve 2-01 was found closed. It was reopened to place the system in the lineup required by the system operating ! procedure. ! i During the evening shift on December 30, 1992, while attempting to fill the volume control tank, the major flow path for the charging pump was verified to be correctly aligned. Following the pump start, operations personnel did not
observe the rate of level increase expected and secured the charging pump and
dispatched'an operator to investigate. The operator discovered that the l volume control tank drain Valve 2CS-8419 was open, and that Charging Pump 2-01
suction pressure gauge root Valve 2CS-8502B was closed. The valves were repositioned, and the charging pump was restarted in an attempt.to establish
flow to the reactor coolant system (RCS). When the anticipated flow was not -: observed, the operators again secured the charging pump. The operator sent_to . investigate this occurrence determined that the charging pump discharge valve,
2-8485A, was closed. At this point, operations secured the system, security i ! .
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was notified, and a verification lineup was initiated on the system. Operation Notification and Evaluation (ONE) form 92-01663 was initiated to . document and prompt corrective actions for the observed mispositionings. l ' Additionally, licensee management established a team from the nuclear overview organizaticn to investigate the events to determine if there was cause for l ! concern regarding unauthorized manipulation of station components. r Additional immediate corrective actions were taken by the licensee following ' i the event. These included the performance of verification lineups on Unit 1 RHR, safety injection, containment spray, station service water, component cooling water (CCW), and boric acid systems. Other actions included increased I security vigilance by acceleration of the frequency of tours by the officers, posting of a site-wide letter clarifying and restating the authority required - for operating station components, reemphasizing the importance of verifying major flow path lineup prior to major pump starts, and increased emphasis within operations to be attentive to the potential for unauthorized equipment manipulation. The licensee's team concluded, based on their investigation of the circumstances surrounding each of the valves found out of its expected
position, that a generic concern did not exist with regard to unauthorized t manipulations of station components. Considering the impact of clearances, system lineups, and the transition from startup to operations, plausible explanations for the majority of valves found mispositioned were identified. The licensee also determined that the time the charging pump was operating while misaligned was minimal and no pump damage or degradation occurred.as > evidenced by monitoring during subsequent pump runs. , The inspectors reviewed the licensee's efforts and concluded that the licensee had made reasonable efforts to determine the precise causes of the valve l misalignments. Documentation supporting the licensee's conclusions was found - to be satisfactory. Although the immediate corrective actions provided some assurance that the reviewed systems on Unit l were not affected, the inability to maintain control of Unit 2 system status in accordance with Operations Department Administrative Procedure ODA-410. " System Status Control," . Revision 4, was identified as a violation of NRC requirements (446/9260-01). .] u This event was identified as a plant incident by the licensee, which prompted
the initiation of a formal root cause analysis. The results of the root cause- analysis and any subsequent corrective actions will be reviewed following completion of the licensee's activities for this event.
2.4 Emergency Diesel Generator (EDG) Testinq On January 10, 1993, the inspectors witnessed selected portions of the i maintenance testing on the Train A EDG which was performed in accordance with Procedure MSM-P0-3374, Revision 1, " Emergency Diesel Generator Monthly Run _; I Related Inspections." In particular, the inspectors observed the preoperational checks which were performed on the engine and the operation of ! l 4 'e- , ,. . _ . .
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. .. . -8- , the Train.A EDG in both the unloaded and the asynchronous mode. During the i conduct of this test, the engine was successfully' started and loaded; however, , the inspectors identified a leaking fitting on the left bank fuel oil line and unsupported tubing on four cylinder heads. These conditions were relayed to . the system engineering personnel involved with the test, and corrective work l orders / deficiency documentation was properly initiated.
' 2.5 System Operational Readiness Verification
An assessment of the licensee's system turnover process from the startup . ,
organization to plant operations custody was performed in order.to confirm the operational readiness of. safety-related systems. Specifically, the inspectors . examined the implementation of the license's nuclear operations programs which were controlled by Procedures STA-802, Revision 10, " Acceptance Of Station , Systems & Equipment"; and STA-815, Revision 4, "Open Item Evaluation And l Deferral Process." Based on the availability of completed systems which had
been declared operationally ready by the licensee, the fuel pool.-cooling ~ system and the control room heating, ventilation, and air conditioning (HVAC)
system were selected for evaluations. These two systems, which are common to l' Units 1 and 2, have effectively been in the custody of plant operations since December 1989. However, the discrete portions of the control room HVAC system ! and the spent fuel pool (SFP) cooling system which are associated with Unit 2 l were declared operational on December 24 and December 30, 1992, respectively.
, Detailed walkdowns of these two systems were performed using the applicable $ ' system operating procedures and flow diagrams in order to verify that the licensee's system lineup procedures conformed to plant drawings and as-built ! configurations. The inspectors also evaluated equipment conditions and items which could adversely affect plant perturmance, including the proper - installation of hangers and supports, labeling of systems and components, ! housekeeping, control of combustible materials, and the configuration / material condition of system values and components. Additionally, the inspectors i verified that the associated process instrumentation was functioning and that i the indicated values were consistent with expected parameters, required
1 support systems were operational, associated electrical breakers were properly ' positioned, and the control room indications matched the actual system configuration. ,l ! With respect to system status control, the inspectors determined that the i licensee's component tagouts'were consistent with contral room status and that . temporary modifications were properly controlled. During the conduct of these inspection activities, no limiting. conditions for operation were being tracked. 1 for the selected systems. However, it was determined that the' licensee had
established a program defined in Procedure ODA-308, "LC0 Tracking Program," for tracking conditions with potential-operability impact. Relative to the licensee's self-assessment capabilities, it was determined t that neither the Independent Safety Evaluatis Group nor the quality l assurance (QA) organization had performed any specific evaluations of the SFP i cooling system or the control room HVAC system. Therefore, no evaluation of i . e r
. . -9- , this process was performed. However, it was determined that the licensee's deficiency reporting system as defined in Procedure STA-421, Revision 3, . " Operations Notification and Evaluation (ONE) Form," had been implemented and that, in general, the reporting thresholds for deficiencies and the effective prioritization of identified work items was being properly implemented. As previously discussed, the licensee's open item evaluation and deferral process was controlled by Procedure STA-815, "Or.en Item Evaluation and Deferral Process." In order to evaluate the effectiveness of this program, , the inspectors compared the system punch list items with the results of the system verification walkdowns for the selected systems. . Based on the results of this comparison, it was generally determined that the licensee's process for evaluating open items with respect to potential impact on system operational readiness and plant completion schedules was being effectively implemented. Specifically, no items were identified during.the system walkdowns which would have adversely affected plant operations, and the deferred items on the licensee's punch list had bec properly reviewed and characterized. _ However, several discrepancies were identified during the system walkdown which had not been captured in the licensee's open item list. These items are addressed in subsequent sections of this inspection report. 2.5.1 Fuel Pool Cooling System In order to assess the operational readiness of the fuel pool cooling system, the inspector's reviewed the results of Surveillance Procedure OPT-223, Revision 1, " Spent Fuel Pool Cooling System Operability Test," which was performed in accordance with Work Orders 5-92-500441-AB and 5-92-501912-AC. Based on the results of these reviews, it was determined that this surveillance test had been properly performed and that-it correctly addressed the operational readiness of the system as well as the requirements defined in Section XI of the ASME Boiler and Pressure Vessel Code for pump and valve , inservice testing.
The inspectors also performed a system walkdown using the applicable sections -
of Procedure 50P-506, Revision 6, " Spent Fuel Pool Cooling and Cleanup , 1 System"; and Flow Diagram M1-0235, " Spent Fuel Pool-Cooling and Cleanup System." Based on the results of this walkdown, it was determined that Procedure 50P-506 properly incorporated the required positions for locked , ' valves and no discrepancies in the required valve lineup configuration were- identified. Direct field observations also indicated -that _ radiation areas were properly posted and controlled and that rooms and areas were correctly
labeled. Furthermore, it-was ascertained that danger-tags were properly
applied to components under. clearance and that the operator aids in the j control room used to facilitate system status configuration were appropriately controlled in accordance with Procedure ODA-410, Revision 4, " System Status Control . "
i System and component labeling was determined to be superior and, as confirmed during the conduct of field inspections, all of the enhanced labels accurately . ' reflected the descriptions in the governing system operating procedure. It ,
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- - - -. . . , -10- , ! ' l was also determined that valves which required emergency response guideline
actions were identified with clearly marked labels and that the abnormal- > actions and responses directed by Procedure ABN-909, Revision 2, " Spent Fuel . Pool / Refueling Cavity Malfunction," were correctly addressed and properly '! demonstrated by operations personnel. ~
Based on the results of the fuel _ pool cooling system walkdowns, several
observations were identified and relayed to the licensee. These observations ! included the following items:
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Housekeeping in the fuel building was generally regarded as poor. . Paper, absorbent plastic bags, tape, and tools were observed on the , floor and laying on equipment. -l f Plant lighting in the fuel building was poor in certain areas and the a identification of valves / components was difficult. Loose terminal board lug covers and fasteners were identified in the
bottom of Electrical Panel CPX-E1PRLB-06, " Spent Fuel Pool. Annunciator Panel." Valve access for position verification of Valves XSF-0238 and XSF-0239 { . in the fuel building was difficult. These valves were located , approximately 12 feet above the 839 foot elevation with no' access i equipment available. l i A damaged filter element on the SFP heat exchanger and pump room Exhaust .l . Fan CLR FAN 02 was identified with no work request tag present. ' An oil leak on the SFP Pump CPX-01 was identified ~which was not l
identified on the associated punch list of open work items. i Several work orders were identified which were 6-12 months old: ! e Work Request 121486 dated June 10, 1992, Leaking Flange XSF-0010 outlet l to SFP X02 isolation valve ';
l Work Request 130548 dated September 23, 1992, valve bonnet leak on l Flange XCP-01, SFP cooling water heat exchanger j Work Request 102720 dated January 17, 1992, flange leak on i Flange XCP-01, SFP cooling water heat exchanger Work Request 110203, October 21, 1991, damaged insulation on CCW pipe j (fuel building elevation 803 feet) i i ' A nitrogen bottle was improperly stored'in the demineralizer alley i
Room 233A, 842 foot elevation. ! i ! r ! .
-- - - . . . 1 ~ ! l' . -11- , , l Subsequent to th'e identification of these items, the licensee initiated _ prompt
corrective actions to address the identified conditions. 1 ! 2.5.2 Control Room HVAC System The inspectors performed a field walkdown of the' accessible ' portions of the
control room HVAC system in order to verify _the operational readiness of this i ' system. Specifically, the inspectors utilized the applicable' sections of- Procedure 50P-802, Revision 6, " Control Room Ventilation System," to confirm
the adequacy of the licensee's system status control process. Based on the _ results of this evaluation, it was determined that the system was properly- ! aligned and that the component labels were correctly installed. The; f inspectors' also verified that the label descriptions on valves, dampers, and components generally matched the nomenclature specified in Procedure SOP-802.
' Housekeeping and the material condition of the rooms that contained control ! room HVAC equipmant were judged to be excellent. ' With respect to the operational readiness of the control room HVAC system,'the inspectors concluded that the required surveillance tests had been properly .! performed, that there were no outstanding limiting conditions for operation, .
and that the control room indications corresponded to the electrical and' fluid j , system configurations in the plant. It was also determined that system punch - t list items had been properly addressed, including the prioritization of
corrective actions, and that there were no outstanding temporary
modifications. Additionally, the inspectors confirmed that the operator l actions for abnormal conditions specified in Procedure ABN-203, Revision 2, ! " Control Room Ventilation System Malfunction," appropriately implemented the l required responses. As determined by the-inspectors, the majority of these ! procedural actions were executed remotely from the control room. However, two j distinct functions required operator actions in the plant. These actions l involved the local starting of a portable air compressor and the blocking of ! an intake on a ventilation radiation monitor. Based on the observed operator i actions, no discrepancies were identified and it was determined that the l auxiliary operator was knowledgeable of both functions. q , During the conduct of system verification walkdowns, the inspectors identified several minor discrepancies which were subsequently conveyed to the licensee. l These items included a construction hold tag which was attached to a conduit. Followup determined that the licensee failed to remove tne-tag but that the
equipment deficiency had been corrected. An information-tag that specified q the requirement to perform a special test following performance of' maintenance ! on a blower had not been removed although the special test had been performed. Indicating lights on a 480V alternating current control center were not , illuminated. Subsequent to the inspectors' identification of this issue, the
licensee determined that the control power to the indicating lights was not ' available, but the motor control breakers were powered. The licensee i initiated a ONE form to investigate the. loss of control power to the lights. l The inspectors also examined the CCW system valves which were associated with- l the control room HVAC system. Although the CCW system was not considered' . operational at the time of this in!,pection, it was established that the , !
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, i licensee was actively reviewing and correcting discrepancies in accordance with their turnover programs. The inspectors independently verified the i positions of 46 CCW valves. Based on the results of this walkdown, it was i determined that one valve was missing an enhanced label; however, a metal ! label which was attached to the valve provided for accurate identification. The enhanced label valve descriptions did not agree with the procedure ,' descriptions on four other components; however, the inspectors determined that the licensee was processing a procedure change to correct these descriptions. , Flow Diagram M1-0230, Sheets 1-8, indicated the normal mode of operation for valves located in the CCW system. Based on this reference, the inspectors questioned the system status of several cross-tie valves to the air conditioning units between Units 1 and 2 CCW. Specifically, these valves were - depicted as closed on the flow diagram; however, they were listed as open on - the valve lineup sheet and- they were confirmed as open in the plant. In ) response to this issue, the licensee indicated that the reference drawing- reflected the planned configuration for operating the CCW trains subsequent to declaring the systems operational and the licensing of Unit 2. The inspectors also noted numerous work request tags on control room HVAC and fire protection equipment which were over 1 year old. In response to this issue, the licensee confirmed that the work requests which were older than [ l year had been completed and that the only action remaining was the removal ' of the work request tag from the equipment. The remaining work requests, which were minor in nature, had been appropriately assigned a low work priority.
Additionally, the inspectors identified a discrepancy in the actual position l of dampers versus the required position per the flow diagram. The flow l diagram required Dampers CPX-VADP00-49 and CPX-VADP00-47 to be locked open due to flow balancing. .The as-found position of the dampers was open, but not . f locked. The licensee evaluated this condition and determined that the existing configuration of the dampers was acceptable-and that they were not required to be locked open. Accordingly, the licensee initiated Design' Change . Notice (DCN)-5519 to remove from the flow diagram the provision that the } i dampers be locked open. This resolution appeared reasonable in that there are currently two methods available for assuring the dampers are in the correct l position. The first method incorporates an alarm in the control room, which i would annunciate on high temperature if the dampers were closed. The second
method relies on the conduct of Procedure OPT-102, " Operational Shiftly
Routine Tests," which is performed shiftly and verifies the control room i temperature. During the walkdown of the control room HVAC system, the
inspectors . identified a questionable configuration on a pipe support base i pl ate. Subsequent to the identification of this condition, the
licensee confirmed that the gap under the support plate of Pipe j Support CC-1-135-707-F-63R exceeded 1/16 inch for approximately 50 percent.
of the base plate area, which was in excess of the requirements of Specification 2323-SS-9, Revision 11, " Concrete." As a result of the nonconformance, the licensee initiated ONE Form 93-095 which provided the technical resolution of this issue and directed immediate repair of the
subject pipe support base plate. The licensee also evaluated this condition ! . h _._,--___ ___ __ n ., ..e , -.,m. , , ,
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to determine its effect on plant operability and concluded that the structural
integrity of the support was not affected and that the support would have . , performed its intended safety function. Based on the minimal safety. significance of this isolated condition and the- - , prompt corrective actions initiated by the licensee to repair the. support base . I plate, this violation involving a failure to follow procedures.is not-being cited because the criteria specified in Section VII.B.1 of Appendix C.to 10 CFR Part 2 have been met. o 2.5.3 Summary The fuel pool cooling system and the control room HVAC system, which are , common to Units I and 2, were properly controlled by operations programs. System lineups were in conformance with required operational conditions, and- applicable surveillance tests had been properly performed._ Operations , programs involving the acceptance of systems and equipment and the processes ' associated with_ the open item evaluation and deferral were being effectively ! implemented. One strength was identified with respect to the superior , labeling of systems and components. One noncited violation was identified which involved an improperly installed pipe support base plate associated with the control room HVAC system. 1 2.6 Deferred Item Evaluation Review lhe inspectors reviewed a sampling of the licensee's open work items. proposed for deferral of work completion to post fuel load, including. items proposed i for deferral past commencement of commercial operations. The inspectors
evaluated the process used to assign milestone codes to each work item and the , tracking system used to propose, review, approve, and schedule those deferred work items. The inspectors also evaluated the effectiveness of the licensee in identifying and conducting required 10 CFR 50.59 Safety Evaluations during the deferred work item review process. - 2.6.1 Discussion The inspectors conducted interviews with four licensee employees directly
involved in the open item evaluation and deferral process to assess their ! understanding of the process and observe their implementation of the program ~; as outlined in Procedure STA-815, "Open Item Evaluation and Deferral Process." l The employees displayed adequate. knowledge of the process and a conscientious- and thorough approach in reviewing and evaluating proposed deferred items. i The inspectors requested to review 15 specific action requests, work orders, i and commitments at random from the "815 Open Item Review Status" and "CDF Review Status" summary lists. These items were in various stages of.the review and approval process and, in each' case, the review package was j , retrieved.and produced for review. Of the 15 items, 9 items had received 10 CFR 50.59 safety screens, resulting in one safety evaluation for the deferral of testing of the Public Address & Emergency Evacuation Alarm System. I The nine safety screens and one. safety evaluation were properly conducted and l - . -- . - . _
. . -14- , approved, and the remaining six items were properly evaluated as not . requiring safety screens. None of the safety screens.resulted in a decision to schedule the work item prior.to fuel load, although many of the items were subsequently completed through normal maintenance scheduling. The inspector noted that three additional safety evaluations were in progress, associated with. 11 commitments on the "CDF Review Status" list. ' The inspectors utilized the facility's computer tracking system, PR-ISM (Plant- Reliability - an Integrated System for Management), to review the' status of 38 action requests and work orders listed as recommended for deferral on:the "815 Open Item Review Status" summary list. Three items were found to be- e listed under the wrong system heading but were otherwise properly evaluated. ' and milestoned. All items reviewed were evaluated as being assigned' a proper milestone code for deferral or converted to a work order or commitment and , forwarded to scheduling. The inspector noted that a majority of.the items reviewed, although milestoned for postfuel load, were completed and closed out. Through interviews with licensee personnel, the inspectors' determined , that, if the system in question was scheduled for work prior to fuel load,-the i item would be completed unless higher priority tasks interfered. . ' The inspector asked the licensee to produce a list of all action requests and work orders with milestone codes that would defer work past fuel load. The i licensee produced the list using PR-ISM within 30 minutes, which contained - approximately 100 pages with eight items per page. The inspectors observed ! that approximately 40 percent of the items were milestoned as NI (No clearance required, minor impact), 20 percent as NR (Outage not. required, clearance required), and the remaining 40 percent were distributed among' restrictions at
' various power levels and modes. The inspectors reviewed approximately 150 items at random for appropriateness of milestone assignments. - Three items
were questionable based on the abbreviated data on the 1.ist and, upon detailed review using PR-ISM, were found to be properly milestoned. , , 2.6.2 Summary i , The inspectors concluded that the' licensee appeared to be effectively i evaluating, classifying, and tracking open items for postfuel load using i Procedure STA-815, "Open item Evaluation and Deferral Process," with' appropriate milestone assignments. For items that required a 10 CFR 50.59 ) safety screen, the licensee conducted a thorough screen and subsequent l evaluation when required, with acceptable results. The inspectors noted that. l several items had been entered into the STA-815 process with milestone codes of 50 (required for system operability); however, each of these items.was _i completed and not initially scheduled for postfuel load. Additionally, the i inspectors noted that Station Procedure STA-815-uses postfacility license i issue, and not postfuel load, as a cutoff point for work item deferral. 2.7 Conclusions f I The condition of the plant improved steadily throughout this inspection period ' as observed during plant tours. Security response to the two noted events was i
.] . _ _ -- - .-. .. . ,
. - . . F - , -15- ! ,
, appropriate. The observed testing activity regarding the EDG was properly performed. One violation was identified regarding the failure to maintain . control of the CVCS status. A noncited violation was identified regarding a ' pipe support in the CCW system that was not grouted as required. The system turnover process from startup to operations was being properly implemented. Deficiencies were being properly identified, and work items recommended for deferral were properly identified, evaluated, and prioritized. The , 10 CFR 50.59 reviews performed by the licensee were satisfactory. 3 PRE 0PERATIONAL TEST. PROCEDURE AND TEST RESULTS EVALUATION VERIFICATION (70311,70329) , During this reporting period, the inspectors conducted a review of the , programmatic implementation of the licensee's preoperational test procedures ! and the corresponding test results evaluation process. The purpose of this " review was to ensure that the preoperational test program properly incorporated the initial test criteria contained in Regulatory Guide 1.68 and the commitments stated in Chapter 14 of the Final Safety Evaluation Report. P 3.1 Discussion , With respect to the development of preoperational test controls, the inspectors reviewed the scope of the procedures listed in Attachment 2 of this inspection report in order to determine if they proper'sy addressed the - required areas / systems. This review examined the adequacy of the primal test ~1 . procedures which had not been specifically examined during previous > preoperational test evaluations. Additionally, the inspectors compared these , procedures to the requirements which were specified in Startup Administrative Procedure CP-SAP-078, "Preoperational Testing," Revision 3. i Based on these reviews, no discrepancies were identified ard the listed ! ' preoperational test activities were determined to be properly addressed in approved procedures. ! The inspectors also reviewed the licensee's preoperational te t results evaluation process which was administratively controlled by Procedure CP-SAP-07B and the associated commitment data forms. This review included an examination of the completed preoperational test results for. the l procedures listed in Attachment A_of this inspection report. Specifically, ' this review was performed in order to verify that the licensee had established 1 a program to review and approve the required test data packages, which was
consistent with the commitments stated in Chapter 14 of the Final. Safety l Analysis Report (FSAR) and the criteria specified in Regulatory Guide 1.68. 1 Based on the results of this review, it was determined that the licensee had ! instituted appropriate procedural guidance to control the results review and i certification of preoperational test attributes, including the development of I test summaries, comparison of recorded data to acceptance criteria with justifications for exceptions, documentation of test deficiencies and procedure changes,-and conclusions regarding system / component adequacy. No i
_ _ _ _ , .-
- i -16- . , i deficiencies were identified and it was generally-concluded that the licensee had effectively implemented a preoperational test results evaluation program that satisfied the established preoperational testing commitments. 3.2 Conclusions , Within the areas examined, no deficiencies were identified and it was , ' determined that the licensee had effectively implemented programmatic controls to address the development of comprehensive preoperational test procedures and that the corresponding test results reviews were properly. performed. ' 4 OPERATIONAL STAFFING (36301) t The objectives of this inspection activity were to ascertain that all , necessary staff positions were filled and to determine that the positions were -! filled with personnel that have the necessary training and experience for i ' their designated assignments. 4.1 Discussion j The inspectors compared the existing management organization to the i organization described in the proposed Technical Specifications and in ! Chapter 13 of the FSAR. During this review, the inspectors determined that , ! several positions and functions had been deleted, retitled, or reassigned responsibility. These same observations were identified by the Operational , Readiness Assessment Team (0 RAT) and will be documented in more detail in NRC , Inspection Report 50-446/92-201. TU Electric Letter TXX-93046 dated
' January 22, 1993, identified the changes made to the operating organization and stated that the FSAR will be updatea in a future amendment and that a . license amendment request will be submitted to revise the Technical l Specifications to incorporate these and any additional changes.
The FSAR training requirements were compared to the guidance in l ANSI N18.1-1971, " Selection and Training of Nuclear Power Plant Personnel," l and Regulatory Guide 1.8, " Qualification and Training of_ Personnel for Nuclear ~ Power Plants." The inspector reviewed the current staffing and resumes and training records of various personnel to verify that those positions were occupied by individuals with the appropriate training and qualifications.
The inspectors also noted that the operations shift crew rotation was recently - changed from a six-shift rotation to five-shift rotation. Each crew was
staffed above the required technical specification minimum, and changing to a - j five-shift rotation was not expected to have any negative impact on the r operations department ability to safely operate a dual unit facility.
4.2 Conclusions ! The inspectors determined that the current organization was different from that specified in the proposed Technical Specifications and the FSAR, but that all responsibilities were still assigned. The licensee documented its ! ! . i .
. _ l
.- ! i
, ! -17- - , ! I organizational changes in docketed correspondence dated January 22, 1993, and i confirmed its compliance with the Technical Specifications. The
organizational changes were reflected in an FSAR update docketed February 26,
1993. , i Additionally, the inspectors determined that all reviewed positions were filled by qualified personnel and that sufficient operations staffing was
, available to support dual unit operation. - 5 OTHER INSPECTION ACTIVITIES (92701)
! 5.1 SAFETEAM Program Review During the periods October 7-9 and December 7-11, 1992, a four-person team of Headquarters and Region IV personnel conducted a review of the licensee's ! SAFETEAM program. This effort was an extension of the review conducted i February - April 1988 and documented in NRC Inspect 0n Report 50-445/88-23- ! I 50-446/88-20. The purpose of this review was to assess the SAFETEAM program implementation and to evaluate the issues raised to determine if there were . any safety issues identified that were not properly handled that might have an ! impact on licensing of Unit 2. l 5.1.1 Establishment of Program The inspectors reviewed the TU Electric corporate policy statement dated ! March 6, 1992, which established programs such as SAFETEAM "to encourage the , reporting of quality concerns and the timely investigation and resolution of
those concerns." The inspectors also reviewed Nuclear Engineering and Operations Policy Statement 201, " Employee Concerns and Employee Protection," , ' and Station Procedure STA-114, " Employee Concerns and Employee Protection." These procedures replaced Procedure 2.15, " Nuclear Complaints and Concerns," l which was the basis for the 1988 inspection. Station Procedure STA-ll4 establishes a method for employees "to register - nuclear complaints or concerns" and describes the protection that will be
afforded to employees that pursue these complaints or concerns. The procedure ' describes the various methods available at any time to the employee if a concern is not resolved by supervision. These methods include: (1) levels of management up to the President, TU Electric - Generating Division; (2) the NRC; (3) the hotline program; and (4) SAFETEAM. The inspectors concluded that the SAFETEAM program was appropriately established and its functions l adequately described in Station Procedure STA-ll4. 5.1.2 Program implementation l t The inspectors reviewed the implementation of the SAFETEAM program and i verified that it was being conducted in accordance with the SAFETEAM Program i Manual and latest revision of the letter that identifies the CPSES program , differences from the program manual. The inspectors observed a number of ' SAFETEAM entrance orientations and verified that everyone was shown the video
I , w
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-18- i f I and received the explanatory material. In addition to this orientation, the i inspectors confirmed, through attendance at a lecture and review of lesson ! material, that everyone going through site orientation at the personnel
processing center is provided information on the SAFETEAM program. l ) The inspectors reviewed the interview process and found it to be thorough and - comprehensive. It was noted that the interview process did not always- determine the reason or background for someone coming to SAFETEAM, but the licensee indicated that, once a person came to SAFETEAM with a problem, the highest priority was to document the concern and initiate the process. With regard to confidentiality, the inspectors concluded that a process was in place to protect the identity of personnel concerned, but noted that separation of the interview / investigative processes was only one means of , maintaining confidentiality. The licensee indicated that confidentiality was i emphasized throughout the SAFETEAM process. Six records were reviewed that ' ' spacifically identified confidentiality as an issue, and none of the examples-
sl.awad a breakdown of the process. The inspectors also noted that'only one of these records was less than 2 years old.
Forty-two SAFETEAM files were randomly selected and reviewed by the inspectors, and all were found to be complete, well organized, and to have the appropriate closecut indicated. The inspectors confirmed that the files were ! appropriately classified in accordance with the guidance in the SAFETEAM i Program Manual. The inspectors noted that the decision process for referring
an issue to corporate . security was followed and, in many cases, the threshold was considered conservative. i The inspectors reviewed the statistical information maintained by the SAFETEAM organization and noted from the distribution that the highest levels of 7 management were cognizant of this data. According to licensee data, ! 34,560 exit interviews have been conducted since the SAFETEAM was instituted. l For the last four months, SAFETEAM has received an average of 19 concerns a ,' month, with November 1992 being the highest with 32 concerns received. During the months of October and November 1992, a total of 48 concerns were received ' , of which 7 were classified as plant-safety issues. The manager of SAFETEAM ! indicated that he met regularly with the nuclear engineering and operations j , group vice president to discuss SAFETEAM issues, and the inspectors confirmed. ' with the group vice president that this was occurring on a. biweekly basis. Few trending reports were regularly issued, but were available on request. , ,
The inspectors determined that no formal followup of corrective actions is l required by the program. However, the inspectors learned that any item i ' related to safety or plant issues did not get closed by SAFETEAM until it was entered onto the plant open items tracking list to ensure proper followup by i the plant staff. In addition, the licensee indicated that the SAFETEAM ! investigators performed random followup on selected items of interest or .j concern.
! l Several exit interviews were observed and the inspectors confirmed that, for
' everyone that came to the SAFETEAM offices, he/she watched the exit video, was i ! ! ! ! _ _ _ _ , - _ _ _ _ - - . - - - - - - - Y
m . .. .. ._ ! . ,
! - -19- l , ! given the appropriate followup material, and was provided the~ opportunity to
privately discuss any concerns with the interviewers. For those personnel '[ that did not exit through the SAFETEAM facility, the inspectors confirmed'that ' the same followup material was sent to them by mail. The. inspectors reviewed j the handout package and determined that it contained an exit letter from ( TU Electric with Station Procedure STA-Il4 attached, a copy of the TU Electric i . policy on employee concerns, and a blank concern report form with a prestamped , envelope. Information regarding the former employee's rights under the Energy ! Reorganization Act of 1974 and the' time restrictions were contained in the l exit letter. The inspectors did a sample survey of a group of packages that j ' ' were mailed out and determined that they had been received by the addressees. 5.1.3 Investigations (Corporate Security) I i The inspector reviewed 10 investigations that were completed by TU Electric Corporate Security regarding SAFETEAM allegations of wrongdoing. This sample included all har.ssment and intimidation cases and record falsification issues. investigated in 1991. The investigations appeared to be thorough, timely, and
well documented. The inspectors interviewed the investigators and confirmed ' that they were sensitive to the need for maintaining the employee's confidentiality and to not let the identity of the. concerned individual be
compromised during the conduct of the investigation.
f The inspector reviewed the qualifications of the investigators assigned to 4 corporate security and determined that they were well qualified, with extensive law enforcement background. In addition, the inspector noted that ,
the investigators were all licensed by the Texas State Board of Private investigators and Security Agents. . ! The manager of corporate security indicated that no formal procedure for , conducting investigations was in place, but that a draft was completed and ! being reviewed. The inspectors reviewed a copy of the draft and concluded { that it contained the appropriate guidance. During the interim, the l inspectors felt that the criteria established by the state licensing board i provided assurance that investigations would be conducted properly The ! licensee indicated that the procedure would be issued in the near future.
5.1.4 Audits and Evaluations ! ! The inspectors reviewed the June 2, 1992, audit of the SAFETEAM program i conducted by Utility Technical Services, which provides the program to ! TU Electric. This audit is performed annually to provide assurance that the l program is being implemented by TU Electric in accordance with the contractual-
agreement. The inspectors found the audit report to be comprehensive. Three ! recommendations were made for licensee action. The inspectors reviewed ! TO Electric's response to the audit dated July 24, 1992, which described the j actions taken, and found it acceptable. l The inspectors reviewed the evaluation of the Employee Concerns Program f performed August 24 through September 4, 1992, at TU Electric management's l i ! !
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-. ! ' n .- + -20- , , request by the assistant to manager of QA. The evaluation included a review ! of documents and procedures, interviews with personnel, and a tour of site facilities. The evaluation concluded that the programs in place were working , to properly handle employee concerns. The inspectors also met with the ' individual who performed the evaluation, discussed specific report items with him, and concurred with the conclusions made. . 5.1.5 Survey of Workers During the period October 7-9, 1992, the inspectors randomly interviewed i 36 personnel working at the site with regard to their understanding of the- - SAFETEAM program and how to use it and their willingness to contact SAFETEAM
if concerns were not being handled through normal channels. These interviews included engineers, clerical people, and craftsmen, with onsite time ranging from 4 months to 12 years. Overall, personnel demonstrated an understanding _ ' of the program and a willingness to use it. A few expressed concern that the
program was involved too much with personnel issues but understood that TV Electric had purposely expanded the scope of SAFETEAM to include more than
just plant safety issues. The inspectors noted that, in general, personnel i expressed a willingness to resolve issues directly through their supervision prior to going to SAFETEAM, knew how to contact SAFETEAM, and felt that , confidentiality would be maintained. The inspectors determined that some'of the people interviewed had gone to SAFETEAM and were satisfied with the ' resolution of their concern. l 5.1.6 Training and Qualifications ! The inspectors reviewed the resumes of the SAFETEAM interviewers and noted that a conscious decision was made not to use technically trained individuals to interview concernees. All of the interviewers have college training and-
two, including the supervisor, have undergraduate degrees. All interviewers , have received training in interview techniques, with some courses emphasizing , effective listening and report-writing skills. In addition to initial training, interviewers also receive periodic retraining. The. inspectors concluded that the qualifications and training of the interviewers were i acceptable. , I The inspectors reviewed the qualifications of the SAFETEAM. investigat' ors and found them acceptable for the tasks that they are assigned. The investigators exhibited a good understanding of the SAFETEAM program and a sensitivity to maintaining confidentiality of concerned employees.
As part of the SAFETEAM followup process, the inspectors noted that the program refers most concerns to the appropriate site organization for review . and response. These contacts within the site organizations are referred to as 3 ad hoc members and are generally management level individuals. In effect,- ! these individuals are adjunct members of the SAFETEAM organization and are I responsible for the investigation and resolution of concerns. The inspectors ) determined that no written guidance was provided to control these activities and that no structured training program existed to assure that these ad hoc i
O.
. ! t 4 + -21- ! , I members performed their activities in accordance with the overall objectives !' of the SAFETEAM program. The licensee concurred with this observation and indicated that more formal guidance would be provided to ad hoc members. t 5.1.7 Contractor Programs , The inspector reviewed the employee concerns programs of Bechtel Corporation? and Brown & Root, Inc. to determine how these programs supplement the SAFETEAM- program. Neither of these contractor programs are categorized as employee. , concerns programs but, rather, an "open door" process available to anyone._ In
' discussions with the Bechtel Corporation project manager and the Brown & Root- personnel manager, the inspector determined that all employees are informed of
the company's open door policy and encouraged to use the _ normal chain of .
command to resolve any concerns. Employees are also reminded of the SAFETEAM
' program which they had been trained on prior to attending the contractor's orientation.
i The inspector met with the Brown & Root training manager and reviewed the f supervisory training that has been conducted since the restart of Unit 2. The ! inspector obtained copies of the lesson plans and confirmed that communications and interpersonal skills were emphasized. . It appeared that
this training had the equivalent scope and depth of that described in "j Section 3.c of NRC Inspection Report 50-445/88-23; 50-446/88-20. i 5.1.8 Conclusion , The inspectors met with the licensee representatives identified in Attachment I to discuss the results of this review of the SAFETEAM program. l The inspectors concluded that: (1) the SAFETEAM program is generally i implemented in accordance with published procedures; (2) the program provides F a means for employees to bring concerns to management, have'them addressed, r and receive a response; and (3) the program provides management with a- l mechanism for the early identification of issues that could impact the safety 1 of the plant. In addition, the inspectors did not identify any safety issue - that might have an impact on licensing that was not properly handled by the l licensee. j $ 5.2 Environmental Qualification (EO) of Electrical Eauipment important to Safety (10 CFR Part 50.49) During August 1989, the NRC conducted an inspection of the CPSES EQ program. That inspection was documented in NRC Inspection Report 50-445/89-60;
50-446/89-60. At the time of that inspection, Unit 2 construction was on l hold, therefore, only the programmatic aspects of the EQ program were evaluated for Unit 2. During this inspection, the inspectors looked at a i samphng of components from the licensee's " Unit 2 Equipment Qualification { Master List" and verified that the components were installed and maintained in i accordance with the requirements of the licensee's EQ program.
l i .
. . t . , , 1 i .- , -22- .3 1 ! ' The inspectors selected 24 transmitters, two high-range radiation detectors, eight limit switches, and four motor-operated valves for review. This review ' consisted of inspecting electrical conduit seal assemblies, electrical connection insulations (taped and heat shrinkable insulators), mounting orientations, gaskets, and cables. The inspectors were not able to get close enough to any of the resistance temperature detectors'to verify proper ) installation; therefore, the inspectors reviewed the installation
documentation. The inspectors also reviewed the work request to replace 0-ring seals on applicable equipment to establish a qualification start date and to ensure the 0-rings had been replaced after the last opening of the transmitter housing. The inspectors noted several minor instances of maintenance practices that were not in agreement with the established standards of the licensee. These- items included dust accumulation in the grease relief for three of the four motor-operated valves, wires bent at right angles putting stress on the- - conductors, and small grease leaks from the limit switch gear housings. The licensee promptly initiated work requests to address these items. The inspectors concluded that the licensee had installed and was maintaining . equipment in accordance with its EQ program and 10 CFR 50.49. , 5.3 Valve Lineup Verifications As a result of several valves being found out of the_ir expected positions by ' plant personnel, in addition to those addressed in Section 2.3, the licensee committed to perform a verification of all_ safety-related valve lineups prior- to Mode 6 entry. Additionally, other corrective actions related to administrative control of system status were initiated. . As a followup to this commitment, on January 30, 1993, the inspectors performed a walkdown of the RHR system and portions of the CVCS and safety
injection systems to verify that the actual valve positions corresponded to , the information contained in the system status file for the three systems. l The procedures used during the walkdowns were System Operating Procedures 50P-102B, " Residual Heat Removal _ System," Revision 0; SOP-103B, " Chemical and _ Volume Control System," Revision 0; and 50P-201B, " Safety , injection System," Revision 0. Attachment 1 from each procedure was utilized, , ' which is the valve lineup for the associated system. l No valves were found out of position during any of the three-system walkdowns, although several discrepancies were identified. The identified discrepancies - included incorrect component locations in the procedure, the noun names on the , name tags for the RHR inlet and outlet vent valves on RHR heat exchanger 2-02 were reversed, hoses were found connected to two drain valves in the emergency core cooling system valve rooms that were not identified on the valve lineup
sheets in the system status file, Valve 2RH-8735A did not have one of the ~ enhanced name tags, and two RHR recirculation header vent valves inside !
.[ , . ~
' -23- ,- , v q . l containment (Valves 2RH-0031 and -0032) were identified in the field by the - inspectors and 'were not on the system operating-procedure valve lineup. l , All of the identified deficiencies were brought to the licensee's attention ~i and corrective actions were initiated. - These corrective actions included modifying the procedures to correct the locations and valve names, the j addition of the two vent valves to the valve lineup in Procedure S0P-102B, and
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a comparison of the associated system operating procedure valve lineups to the- ' flow diagrams for the RHR, CVCS, safety injection, reactor coolant, station _i service water, containment spray, and auxiliary feedwater_(AFW) systems to
i determine if any other valves were not included in the associated valve lineups. . 1 Additionally, the licensee reviewed the valve lineups performed during hot ! , functional testing to determine if the two vent valves had ever been , documented as being identified. According to the licensee, the two vent l valves had been identified on the valve lineup performed during hot functional ! testing and noted.as not being on the system operating procedure valve lineup,- but the system operating procedure valve lineup was never revised to incorporate the valves. Further reviews by the licensee determined that four j vent valves in the CVCS.were similarly identified during hot functional -j testing but were not incorporated into the system operating procedure valve
lineup. The failure to properly translate identified deficiencies into the
procedure is identified as a violation of Appendix 0 of 10 CFR 50, Criterion V -! (446/9260-02). j ! Operations Department Administrative Procedure ODA-410, " System Status , Control," was also modified to provide specific guidance on the documentation required when an evolution is suspended or terminated prior to completion of the evolution. The inspectors reviewed the procedure change notice and found l that it satisfactorily addressed the control of system status following the j suspension of an evolution.
5.4 Abnormal Operating Procedure (ABN) Field Verifications As a result of deficiencies identified by the inspectors in ABNs during the ! inspection documented in NRC Inspection Report 50-445/92-49; 50-446/92-49, the
licensee conducted field verifications of selected ABNs and initiated ' procedure changes to incorporate the findings. During the Operational i Readiness Assessment Team (ORAT) inspection in January 1993, the inspectors identified additional deficiencies in the same procedure, ABN-803B, " Response , ! to a Fire in the Control Room or Cable Spreading Room," subsequent to the licensee's revisions. The inspectors determined that additional deficiencies
existed in other ABNs and that-only portions of the selected procedures had
been field verified by the licensee. The licensee subsequently committed to ! t perform a field verification of all Unit 2 and common ABNs and to complete this activity on a schedule based on operating mode. The NRC concurred with
the approach proposed by the licensee, and the review of this activity'is
identified as an inspection followup item (446/9260-04). l ! i ! ! !
i ~ . -,.
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, . - , -24- , ! Subsequent to and/or concurrent with the licensee's field verifications, the f inspectors performed walkdowns of-3 sample of ABNs required for Mode 6 to 1 verify that the field verifications parformed by the licensee were effective J in identifying and correcting procedural deficiencies. The procedure steps reviewed were also evaluated for clarity of intent, accuracy of locations and equipment identification, and the capability for being performed as described.
5.4.1 Procedure ABN-104, " Residual Heat Removal System Malfunction" The inspectors performed a walkdown of Procedure ABN-104, " Residual Heat i Removal System Malfunction," Revision 5. Several examples were identified by l the inspector where valve and breaker locations were correct for Unit I but j incorrect for Unit 2, and the noun names on several valve labels did not match
the text in the ABN. Attachment 15 to this procedure directed the operator to
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' relocate two fuses from their holders into different holders to energize a 120Vac receptacle .The fuses wera found already installed in the fuse holders ' to energize the receptacle. Attachment 7, Steps 1.0.c.l.d) and 1.0.c.2.d)
contained incorrect locations for several Unit 2 valves. Additionally, the valve numbers stated in the procedure were correct for Unit 1, but the .j corresponding valves in Unit 2 had different numbers. Consequently, the l procedure could not be performed es written due to the erroneous valve numbers ! referenced in the procedure. This failure to provide adequate. corrective .! ' action following the previous identification of ABN procedural deficiencies is- identified as a violation of Appendix B of 10 CFR 50, Criterion XVI ! (446/9260-03). j ' Several procedural enhancement items in addition to the deficiencies were identified during the walkdown and communicated to the licensee. Corrective i actions were initiated to correct the dericiencies and the enhancements were i being reviewed by the licensee for incorporation into the procedure if i desired. ~ j In summary, the inspectors determined that the procedure was generally ' ' acceptable, with the exception of the erroneous valve numbers and component locations. ' ! 5.4.2 Procedure ABN-107, " Emergency Boration" l l Abnormal Procedure ABN-107, Emergency Boration," Revision 2, was reviewed by the inspectors Field walkdowns determined that the procedure was well written, the intent and direction contained in each step was clear, and all components referenced in the procedure were accurately identified regarding
location and labeling. No deficiencies were identified. ! ! 5.4.3 Procedure ABN-502, " Station Service Water Malfunction" l The inspectors reviewed Revision 3 of Procedure ABN-503 and no deficiencies
were identified regarding component identification, location, labeling, or .! procedural clarity. One observation noted was that Valves ISW-0002 l and 25W-0002, which were located in the overhead, required the use of.a i ! ! l
, .. . - - - . . . . ? ! . ' 1 -25- ,. t t I 25-foot extension ladder which was not' available. The procedure did, however, identify the valve location and the need for the ladder. 5.4.4 Procedure ABN-602, " Response to a 6900/480V System Malfunction"
The body of Procedure ABN-602, Revision 2, was reviewed by the inspectors. .
The majority of actions required by the body of the procedure were located in - i the control room and no deficiencies were identified. 5.4.5 Procedure ABN-603, " Loss of Protection or Instrument Bus"
Procedure ABN-603, Revision 2, was reviewed by the inspectors. In general, j the procedure was clear as to intent, and the labeling and locations were ' accurate. One observation noted by the inspectors was -that Step 3.3 2.a : i directed the operator to " place the affected inverter TRANSFER SWITCH to
TRANSFER." The switch position was actually labeled " BYPASS" instead of- ' " TRANSFER." A procedure change form was promptly iritiated by the licensee to correct the deficiency. [
5.4.6 Procedure ABN-8038, " Response to a Fire in the Control Room or Cable q Spreading Room" ' The inspector performed a walkdown of Procedure ABN-803B, " Response to a Fire
in the Control Room or Cable Spreading Room," Unit 2, Revision 0. The . . walkdown was restricted to'. verifying those actions taking. place outside the . control room, which' included the bulk of the procedure. ! ' Two examples were identified where .the component labeling did not match the procedural reference. In Attachment 2, paragraph 8, the component designators. for the Diesel Generator 1 fuel oil pressure and Diesel Generator 1. jacket . water pressure instruments were given as 2-PI-3409-3A and 2-PI-3415-1A, ! respectively, but were labeled as 2-PI-3409-3 and 2-PI-3415-1 in the field. i In Attachment 2, paragraph 16, the component designated 2EB3-2/lG/BKR was i labeled 2EB3-2/16/BKR-1 in the field. The inspector did not-consider that t either of these errors would have precluded the proper execution of the l procedure. The licensee' initiated actions to make the necessary corrections. l i During the walkdown, the accompanying auxiliary operator was unable to open + the lock to enter the remote shutdown panel enclosure. The licensee stated j that the lock would be reworked or replaced. The inspector noted that access
to the remote shutdown panel could be gained by climbing over the fenced , enclosure, if necessary. l Several procedural enhancement items were identified during the walkdown and l communicated to the licensee. These included component descriptions that did l not include tag numbers, lack of clarity in the task description, lack of a ! warning of an alarmed electrical panel, an incorrect door number given for access assistance, and incorrect descriptions of component locations. None of
these problems would have prevented the operator from taking the required - action, though some actions may have been delayed by initial confusion. j ! .-
. _ _ _. . . , l - a ! .- t -26- i .- i i In summary, the inspector determined that the procedure was sufficient as .i found to direct successful execution of~ the listed sequence of actions. T he .- i licensea stated that problems identified with the procedure would be ! corrected. , 5.4.7 Procedures ABN-908, " Fuel Handling Accident," ABN-909, " Spent Fuel .} Pool / Refueling Cavity Malfunction," and ABN-108, " Shutdown' Loss of . Coolant" " ! Procedures ABN-908, " Fuel Handling Accident," Revision 2, and ABN-909, " Spent , Fuel Pool / Refueling Cavity Malfunction," Revision 2 were walked down by the t inspectors. Several typographical errors were noted regarding the nomenclature associated with several radiation monitors referenced in ' Procedure ABN-908. In Procedure ABN-909, Step 6 references the use of a nitrogen bsttle to provide a backup source of gas pressure to the SFP gate seals. A nitrogen bottle could not be located by the inspector in the
ittediate area of the required connection. Step 24 of the same procedure t required the operator to manipulate switches on two instrument cards in the process instrument cabinets. The cabinet labels contained more than twice the
number of alpha-numeric characters than are identified in the procedure. The ! deficiencies identified in Procedures ABNs-908 and -909 were minor and would-
not have prevented successful completion of the procedure. ~The inspector also reviewed the notes and comments made by a licensee employee who had performed a similar walkdown of the same procedures. The walkdown appeared to be very I thorough, with no' deficiencies identified by the inspector that were not- identified by the licensee reviewer. Additionally, none of the identified , deficiencies should have prevented a trained operator from performing the procedure as written.
The inspectors also observed a licensee employee performing portions of a , walkdown of Procedure ABN-108, " Shutdown loss of Coolant," . Revision 1. The- ! individual was thorough in his identification and documentation of potential
discrepancies and was ensuring the accuracy of the procedure with regard to .; equipment locations and description. , l 5.4.8 Conclusion i Following the licensee's commitment to perform field verifications of all ABNs, the inspectors determined that the individuals performing the verifications were thorough and that the comments generated'from the reviews j performed in the field should result in more accurate procedures. The
- procedures were generally adequate to perform their intended function, ' although a number of minor deficiencies regarding-labeling, nomenclature, and , locations were identified. . However, the deficiencies identified by the , inspectors in Procedure ABN-104, " Residual Heat Removal System Malfunction," following the licensee's initial review are considered to be the result of l inadequate corrective actions taken following the previous identification of procedural deficiencies and constitute a violation. j , i l
.. . 5 -27- 3 > , 5.5 Valve 2FW-0088 Postwork Testing , The ORAT had identified a deficiency in' that postwork testing requirements were not specified in Work Order 1-93-034476-00 following reassembly of , Valve 2FW-0088. The inspectors verified that a postwork test report was: - initiated to identify the appropriate testing. The test report was verified to include a visual' inspection of the valve under operating pressure conditions, a forward flow test, and a reverse flow leakage test. As of the end of this inspection period, the testing had not been performed. 56 Inadequate Training of Auxiliary Operators l t The ORAT had identified seven contractor auxiliary operators that were allowed to perform operator activities without having previously been trained in accordance with the FSAR. Following the identification of the inadequate _ training, all of .the contractor auxiliary operators, including the original seven, were relieved of all duties requiring a qualified auxiliary operator. These activities included manipulation of plant components, performance of system -lineups, placing or - removing clearance tags, performing as standby clearances, and the , ' installation of operator aids. Subsequently, following reviews and management approval, the contractor - operators were authorized to verify labels, install operator aids, and install pipe caps. According to the licensee, approximately 600 clearances had been-processed since December 21, 1992, the designated date at which all systems and activities were controlled by Nuclear Operations' programs. These clearances were reviewed by the licensee and, those which were on safety-related systems and contained contractor auxiliary operator signatures as active participants, were verified to be accurate by a qualified auxiliary operator. ' The immediate corrective actions taken by the licensee were adequate to address the concern, and the contractors' qualifications and training requirements continued to be evaluated by licensee management. 5.7 Review of Provisions for loss of Decay Heat Removal Events The inspectors reviewed the recommendations contained in Generic letter 88-17, and the licensee's actions taken to prevent and respond to a loss of decay
heat removal event'for Unit 1, which were documented in NRC Inspection Reports 50-445/89-90; 50-446/89-90 and 50-445/90-61; 50-446/90-61. During the week of January 25, 1993, the Unit 2 reactor vessel water level was , maintained below the reactor vessel flange. The inspectors verified that the , licensee had installed and was utilizing diverse methods of monitoring vessel q water level. The diverse means of level indication included wide and narrow
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. -d , -28- , range main control board indicators and an alternate-Tygon hose indication. The Tygon hose was verified to be appropriately installed. The licensee had implemented Integrated Plant Operating Procedure IPO-010B, " Reactor Coolant System Reduced Inventory Operations," for draining, controlling, and refilling reactor vessel water level during reduced inventory conditions. Procedure ABN-104B, " Residual Heat Removal System Malfunctions," , addressed the required response to a loss of decay heat removal event. The inspectors reviewed the licensee's actions taken with regard _to Generic Letter 88-17 program enhancements for Unit 1 and determined that-they had been implemented on both units. The inspector's observation identified in the referenced NRC inspection reports had been appropriately addressed in l Procedures ABN-104B and IP0-010B. . In conclusion, the inspectors determined that the licensee had installed plant
instrumentation, implemented appropriate procedures, and provided sufficient - operator training to prevent and respond to, if necessary, a loss of decay ! heat removal event consistent with those implemented on Unit 1. 5.8 10 CFR 21 Implementation
An assessment of the licensee's implementation of the requirements of i 10 CFR 21 was performed in order to verify the adequacy of evaluations, reportability determinations, and corrective _ actions. Specifically, the inspectors reviewed a selected sample of 20 of the total population of- approximately 8310 CFR 21 notifications which had been received or generated by TU Electric subsequent to the licensing of Unit 1 in April 1990. A listing of the 10 CFR 21s which were reviewed is provided in Attachment 2 of this inspection report. Within this area, the inspectors reviewed the licensee's process for evaluating and reporting of defects required by 10 CFR 21.21(a). These activities were administratively controlled by Procedure TNL-2.01, Revision 0, " Identification, Evaluation and Reporting of Defects and Honcompliance j Under 10CFR21," for Unit I and Procedure 2PP-9.01, Revision 2, " Evaluating and Reporting of Adverse Conditions Under 10CFR50.55(e) and 10CFR21," for Unit 2. ! Based on the results of these reviews, it was determined that the licensee's.
process for the evaluation and reporting of defects which constituted a substantial safety hazard was generally acceptable. All of the reportable deficiencies, which were properly reviewed, reflected an impact evaluation, including the justification for nonapplicability of specific items. The corrective actions associated with these issues were typically comprehensive in nature. However, two weaknesses were identified with respect to the implementation of this program. The first weakness involved the licensee's programmatic controls associated with the reporting requirements of 10 CFR 21.21(a) which were defined in Procedure TNL-2.01. As determined by the inspectors, this 1 ? I
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-29- ., i procedure had not been revised to reflect the current 10 CFR 21 requirements- \\ ' with respect to the time limitations ' associated with the evaluation and reporting of defects and failures. The inspectors concluded that the_
reporting requirements delineated in' Procedure 2PP-9.01 appropriately. ' implemented the subject reporting requirements and no examples were identified where the licensee had failed to properly address reportable deficiencies. Additionally, as stated by the licensee, a revision to Procedure TNL 2.01 was ! in the review process.and was scheduled to be issued in February 1993 to l ' reflect the new Part 21 information. ! ,' The second weakness involved inaccuracies in the Indus'try Operating Experience Reports (10ERs) associated with two 10 CFR 21 evaluations. The first' issue ! involved IDER IN 91-45 (reference P21-WEST-01/20/1992), which addressed
potential malfunctions of Westinghouse ARD, BFD, and NBFD relays and , A 200 DC/DPC250 magnetic contactors. This 10ER concluded, in part, that CPSES , did not have any ARD relays installed in safety-related systems. As ! ' determined by the inspectors, this conclusion was not in agreement with the technical disposition of DNE Form FX 91-779 which identified eight Class IE. ARD relays, which performed safety-related functions. Although this , discrepancy did not affect the licensee's technical resolution of this issue,
the failure of the Events Analysis Group to identify and correct this l conclusion is indicative of a potential weakness in the independent safety assessment function of this organization. '
Additionally, the inspectors identified a discrepancy in the licensee's i evaluation of a potential setpoint drift anomaly associated with ITT-Barton ! differential pressure switches (reference P-21-CPE-10/23/1990) in that the i 10ER response did not provide a definitive justification for the conclusion - 4 that no action was required. The subject 10ER response stated, in part, that although ITT-Barton pressure switches X-PIS-3633 and X-PIS-3634 were , identified on the master equipment list as Class IE safety-related components, they were not affected by the postulated seismic event setpoint drift anomaly because the transmitters were powered from associated Class IE electrical circuits. Based on the review of this justification, it could not be
determined that the 10 CFR 21 safety hazards associated with this issue had been appropriately addressed. ! Subsequent inspection followup revealed that the subject pressure switches i provided an alarm function only and that the potential setpoint drift did not - represent a safety concern for these components. Although the IDER response
to this issue was ultimately determined to be acceptable, the lack of ! specificity in the events assessment conclusion is identified as a second , example of a weakness relative to the lack of attention to detail during the l evaluation documentation of 10 CFR 21 deficiencies and failures. j 5.8.2 Conclusion Within the areas inspected, no deficiencies were identified, and it was determined that the licensee's process for evaluating and reporting of defects ! under the provisions of 10 CFR 21 was generally acceptable. However, two !
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.. - .. - . , .. ! , , , -30- l , l ~ ' weaknesses were identified relative to the licensee's implenantation of the evaluation and reporting of defects and noncompliance. The first weakness . t ' involved the icensee's programmatic controls defined in Procedure TNL 1.01, which had not. oeen revised to reflect current 10 CFR '21 reporting time-frame requirements. The second weakness concerned two examples where the licensee's ! Events Assessment organization failed to provide comprehensive documentation-
of the justification for their conclusions regarding nonreportability.. 5.9 Solid State Protection System Technical Evaluation < During this reporting period, the inspectors reviewed the licensee's technical , resolution of ONE Form 92-1350, which identified multiple failures of TERMI- POINT connectors in the Train B solid state protection system. Specifically, the inspectors examined the supporting technical evaluation, TE 92-002691, 1 which concluded that the resultant forces due to a safe-shutdown earthquake ! i were so small that there was no operability concern for the solid state protection system. Based on the review of this technical evaluation, it could not be confinned that the licensee's plant engineering organization had
i employed a conservative analytical basis for their operability evaluation of the solid state protection system. This lack of conservatism was exemplified , ' by the licensee's utilization of a nominal wire length in the calculation ' versus the worst case wire length, which resulted in a significantly higher calculated force. This calculation also failed to identify the minimum-TERMI- POINT connection force required to maintain seismic qualification of the solid l state protection system. Subsequent to the inspectors identification of these inadequacies, the . licensee performed a more rigorous evaluation of the reported deficiencies, ! which was documented in TV Electric Calculation CS-CA-0000-3290. Baseu un the -l review of this refined calculation, it was determined that the maximum i reaction / pull force was negligible. The potentially nonconservative approach i used by the licensee to address the operability of the solid state protection l system in TE 92-002691 is identified as a weakness. 6 REVIEW 0F TI 2500/019: " Reactor Vessel Pressure Transient Protection for j Pressurized Water Reactors (PWRs)" (2500/019) l t The purpose of this inspection was to verify that the licensee had an ! ! effective mitigation system for low temperature overpressure transient conditions. 6.1 Discussion j The inspectors reviewed the licensee's actions pertaining to their commitments relating to Unresolved Safety Issue A-26 concerning reactor vessel pressure
transient protection for pressurized water reactors. The licensee maintains documentation which justifies that the cold overpressure mitigation , system (COMS) has been designed to prevent the RCS from exceeding the , applicable Technical Specifications and 10 CFR 50, Appendix G, limits.. . i
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, 1 ' The inspectors reviewed the setpoint determination documentation for the CPSES l COMS. A previous concern was that the'COMS setpoints had not accounted for - pressure instrument errors. The licensee reviewed this concern.and identified-
the fact that the power-operated relief valve (PORV) pressure setpoints have ! been lowered to prevent exceeding the Technical Specification limits due to , instrument error. Also, the PORV pressure setpoints are staggered. Tne j result is a lower PORV pressure setpoint of 425 psig and an upper PORV j pressure setpoint at 500 psig when the RCS temperature.is less than approximately 240 F. This is substantially less than the upper limit of
560 psig for this temperature range specified in Figure 3.4-4 of the Technical- ' Specification. The inspectors reviewed documentation which verified that the COMS has been , designed to protect the reactor vessel given a single failure in addition to a j failure that initiated the pressure transient. In May 1988, the licensee had- , been notified that the Westinghouse Safety Review Committee had identified a , po entially unanalyzed condition where the COMS could actuate during a main ' steamline break (MSLB) or a steam generator tube rupture event given a single failure in the COMS circuitry. In July 1988, the licensee submitted SDAR CP-88-30 to the NRC as required by 10 CFR 50.55(e). ! The FSAR analyses of the MSLB and steam generator tube rupture events . considered single failures in the systems required for accident mitigation in ' accordance with the requirements of 10 CFR 50, Appendix A. Regarding the postulated random failure of a wide range temperature channel during an MSLB - or steam generator tube rupture event, which results in COMS actuation, this , particular failure does not occur in a system required to mitigate the , initiating event and was neither a consequence of the initiating event nor an- undetectable f ailure. Should such a failure occur, this evaluation verified that there was sufficient instrumentation and indication to alert the - operators to a COMS failure. There were also mitigation techniques readi.y available to the operator should a COMS failure lead to the opening of a PORV. - Furthermore, the operators have been trained in an inadvertent PORV actuation- type event which provides additional assurance of the ability to detect ar.d , mitigate the consequences of a COMS failure.
NUREG-0797, Supplement 25, Safety Evaluation Report reviews the concerns identified and concluded that SDAR CP-88-30 was closed. ' The inspectors reviewed the operating procedures to determine if the time in a water-solid condition was minimized. Integrated Plant Operating Procedure IP0-005B, " Plant Cool-down from Hot Standby to Cold Shutdown," Revision 0, dated May 5, 1992, indicated that, if the RCS was to be opened or , solid conditions were desired, then the RCS should be placed in a solid ' condition. The procedure stated that time in solid-plant conditions should be minimized. ' The inspectors reviewed the licensee's controls for minimizing the temperature differentials between the steam generators and the reactor vessel while in a water-solid condition to reduce the pressure transient caused by the mixing of ..
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different temperature water. The licensee's procedures minimized this pressure transient by different methods. The procedures did not allow
starting reactor coolant pumps (RCPs) in a water-solid condition unless the- RCS is in the process of being filled and vented. The Technical Specifications and procedures did not allow starting an RCP in Modes-4 or 5
unless the steam generator secondary water temperature is less than 50 F greater than each of the RCS cold leg temperatures. Additionally, -if all RCPs had been stopped for more than 5 minutes during a heatup and the reactor coolant temperature is greater than the charging and seal injection water temperature, RCP restart would not be attempted until. a steam bubble.is established in the pressurizer. If all RCPs were stopped and the RCS was being cooled down by the RHR heat exchangers', RCP restart would not be attempted until a steam bubble is formed in the pressurizer. The procedures also required at least one RCP to be in service until the reactor coolant temperature was reduced to 160 F. The heater breakers are to be tagged in the
open position to prevent a pressure transient caused by inadvertent ' pressurizer heater operation. The procedures and Technical Specifications required all safety injection , pumps and one charging pump' to be inoperable when the reactor coolant is less than 350oF. This limit ensures that any pressure transient can be terminated by the operation of one PORV. ' To alert operators to the automatic operation of the COMS, a high pressure alarm is activated in the control room at a pressure below the PORV setpoints. Once alerted to a pressure transient, the operator would have the opportunity to correct the cause. The inspectors confirmed that the licensee's training program encompassed specific training pertaining to low-temperature overpressure events. i The licensee's surveillance program and Technical Specifications required the performance of an analog channel operational test on the PORV actuation channel within 31 days prior to entering a condition in which the PORV is required to be operable and at least once every 31 days when the PORV is , required to be operable. In addition, a channel calibration on the PORV actuation channel is required at least every 18 months. 6.2 Conclusion The inspectors determined that the licensee had complied with their [ commitments for the installation of the COMS. The satisfactory review of the ' licensee's COMS fulfills the inspection requirements delineated in TI 2500/19, , " Reactor Vessel Pressure Transient Protection." ! i 7 REVIEW 0F TI 2515/065: "TMI ACTION PLAN REQUIREMENT FOLLOWUP" (2515/065) , i This TI provided inspection guidance for the items identified in the TMI Action Plan that required inspection followup. .
. -33- , 7.1 (Closed) TMI Action Items I.C.l.1, l.C.I.2.B. 1.C.l.3.B: "Small-Break LOCA," " Inadequate Core Cooling," and " Transients and Accidents" Short Term Accident and Procedure Review These items were reviewed and closed for Unit 1 in NRC Inspection Reports 50-445/90-02; 50-446/90-02 and 50-445/91-32; 50-446/91-32. The inspectors verified that the source documents utilized for the development of the Unit 2 emergency response guidelines were the same as those used for Unit 1, that the operator training programs were the same for both units, and that the function and task analysis performed were applicable to both units. Based on the development of the Unit 2 emergency response guidelines using the above documents, the inspectors concluded that the subject issues were appropriately addressed. Additionally, the Unit 2 abnormal condition procedures, alarm response procedures, and emergency response procedures were determined to be adequate to support Unit 2 operation as addressed 4, NRC Inspection Report 50-445/92-57; 50-446/92-57. 7.2 (Closed) TMI Action Item 1.D.2.2: " Plant Safety Parameter Display Console Installed" This item involved the installation and implementation of the Safety Parameter Display System (SPDS). NRC Inspection Report 50-445/91-21; 50-446/91-21 previously addressed this action item, and only the NRC review of the Unit 2 SPDS preoperational test results remained open. The SPDS, a subset of the emergency response facility computer system, did not have a specific preoperational test; however, during other preoperational tests, SPDS inputs associated with the tested systems were recorded to verify the ability of the computer system to receive, process, and display the pertinent information. Main steam isolation valve Preoperational Test Procedure 2CP-PT-34-01 and AFW Preoperational Test Procedures 2CP-PT-37-01 and -03 were reviewed and the components were found to function in accordance with design basis documents (DBDs), as detailed in NRC Inspection Report 50-445/93-02; 50-446/93-02. These systems supplied inputs to the SPDS and the points were recorded in the preoperational tests, thus demonstrating SPDS functionality. Additionally, the inspectors reviewed Procedure XCP-EE-28, Revision 3, " Plant Computer / Emergency Response f acilities Computer Field input Verification," which tested field inputs into the system. All SPDS input points have been satisfactorily tested. 7.3 (0 pen) TMI Action item 1.D.2.3: " Plant Safety Parameter Display Console fully implemented" The licensee's preoperational tests were not designed to demonstrate that the SPDS could perform during all plant conditions given that these signals could not be simulated under test conditions. Contractor Report RDA-PCS-0005, " Plant Computer PCS00 Verification and Validation Report," dated November 9, 1992, indicated that the system had not been tested in a fully loaded $
. - '! s. - , -34- L , , ' condition and could not be completely tested until the plant begins power operation. The contractor noted that the system was functionally tested at a -l minimum input level, whereas it should be tested during maximum information
processing to identify potential system deficiencies and that. a potential - existed for failures of SPDS to occur during plant startup. However, as !' documented in TU Letter TXX-92525 dated November 2, 1992,.the licensee committed to perfonn a 30-day availability test of SPDS during low-power startup operations in response to Generic Letter 89-06, " Task Action Plant , Item I.D.2 Safety Parameter Display System."
! Based on the inspectors' review of documentation and the licensee's commitment to perform the availability test of SPDS, the inspectors determined that the' i licensee had taken the appropriate actions to address the TMI action item but will leave this item open pending review of the 30-day availability test l results. j '4 (Closed) TMI Action Item II.B.I.2: " Installation of Reactor Coolant . System Vents" ' The closure for Unit 1 of TMI Action Item II.B.1.2 was documented in NRC Inspection Report 50-445/90-07; 50-446/90-07. This item had remained open'for Unit 2 pending the review of the. applicable portions of the RCS preoperational- test results. During this inspection, the inspectors reviewed Test Procedure 2CP-PT-55-04, " Pressurizer Relief Tank," Revision 1, dated i' November 17, 1992. Based on this review, it was determined that the requirements of-this action item were appropriately addressed in the ' preoperational test results. 7.5 (Closed) TMI Action Item II.B.I.3: " Procedures for Use of Reactor . ' Coolant Vents" NRC Inspection Report 50-445/89-09; 50-446/89-09 documented the closure of TMI Action item II.B.1.3 for Unit 1. This item had remained open for Unit 2 pending the development of the procedures to address the use of RCS vents.
During this inspection, the inspectors reviewed Procedure FRC.0.1B, " Response to Inadequate Core Cooling," dated January 11, 1993. The review indicated that the licensee had adequately addressed the use of reactor coolant vents in , the above procedures. The inspectors determined that the 'above reviews- provided reasonable assurance that the procedures for use of reactor coolant vents met the requirements of TI 2515/065. 4 7.6 (Closed) TMI Action Item II.B.3.4: "Postaccident Samplina System , Modifications" This item was reviewed and closed for Unit 1 in NRC Inspection Report 50-445/90-07; 50-446/90-07. For Unit 2, this item was reviewed in NRC - Inspection Report- 50-445/91-21; 50-446/91-21. The inspection activity performed for Unit 2 was completed with the exception of the licensee's > demonstration of the capability of using the Unit 2 postaccident sample system- to complete and analyze samples within the required 3-hour time limit. !
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, ' During this inspection period, the inspectors reviewed the results of. Preoperational Test Procedure -2CP-PT-59-01, Revision 0, " Post Accident ' Sampling System," which documented the capability to obtain RHR and RCS water- samples. Additionally, the inspectors reviewed Work. Order 4-93-033905-0,
which documented the ability to obtain a containment atmosphere sample as
required. The inspectors concluded that the licensee had demonstrated the capability to satisfy the requirements of the TMI Action Plan regarding the postaccident - sampling system. , 7.7 (Closed) TMI Action Item II.D.3.1: " Direct Indication of Relief and l Safety Valve Position" ' This item involved the direct indication of the relief and safety valve position which was closed in NRC Inspection Report 50-445/89-72; 50-446/89-72 for Unit I and romained open pending review of the Unit 2 preoperational testing of the pressurizer safety and relief valves position indication circuits. This item required the RCS relief and safety valves to be provided . with a positive position indication in the control room. .This indication must { be derived from a reliable valve position detection device or from a reliable 7 indication of flow in the discharge pipe. This item had remained open pending the inspectors' review of preoperational test results for Unit 2 to determine if the. indicating system had been adequately tested and calibrated. . During this inspection', the inspectors reviewed the preoperational test results obtained during the conduct of Test 2CP-PT-55-08, Revision 0, " Pressurizer Pressure' Control System," dated December 8, 1992. Based on the results of this review, it was determined that the iequirements for this action' item were appropriately addressed in the preoperational test , results, and the inspection requirements of TI-2515/065 had been satisfied. 7.8 (closed) TMI Action Items II.E.1.2 and II.E.1.3: " Auxiliary Feedwater System (AFWS) Reliability Evaluation" These item concerned a reevaluation of the AFWS. Specifically, the NRC
required the licensee to do the following: (1)'use event-tree and fault-tree ' logic techniques to determine the potential for AFWS failure under various
loss of main feedwater conditions, (2) reevaluate system flow rate design , ' bases and criteria, and (3) conduct a deterministic review of the AFWS using acceptance criteria of Standard Review Plan 10.4.9 and Branch Technical Position ASB 10-1 As previously documented in NRC Inspection Reports 50-445/90-07; 50-446/90-07 and 50-445/90-09; 50-446/90-09, this item ' was previously reviewed and closed for Unit I based on the inspectors review of responses to commitments' made by the licensee. ~ . In response to the first requirement to determine the potential for AFWS failure under various loss of main feedwater conditions,'the licensee evaluated the effects of the loss of main feedwater with offsite power, loss i
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r of main feedwater and loss of offsite power, and loss of feedwater and loss of all AC power. The principle deficiency identified was_the failure of both - , trains due to the closure of the manual valves in the two supply lines from . _ the condensate storage tank. In response, these valves are locked open as recuired by Procedure 50P-3048, Revision 1, " Auxiliary Feedwater System." In response to the second requirement involving a reevaluation.of system flow , rate design bases and criteria, the licensee identified and evaluated each plant transient and accident condition considered in establishing AFW flow requirements and summarized the criteria which were the general design bases' for each event. For each plant transient, the analysis concluded that thi i AFWS is capable of removing the stored and residual heat, thus preventing overpressurization of the RCS. This approach was previously utilized and accepted for Unit 1. In response to the final requirement involving conducting _a deterministic review of the Standard Review Plan Section 10.4.9 and Branch Technical t Position ASB 10-1, the licensee concluded that the AFWS's safety evaluation outlined in Section 10.4.9.3 of the FSAR was sufficient in meeting the intent - of this requirement. This approach was previously utilized and accepted for Unit 1. Based on the above evaluations and the fact that the licensee's actions had previously been accepted for-Unit 1, the inspectors concluded the licensee had appropriately addressed the issues of this portion of the action item for Unit 2. Additionally, this item involved inspector review of the. staff's short- and long-term recommendations and the licensee's commitments stated in NUREG-0797 " Safety Evaluation Report," dated July 1981. A total of 17 recommendations were addressed in the NUREG. Eight of the seventeen are addressed below, and- the remaining recommendations were either previously reviewed and closed, or were determined to not be applicable to CPSES.
Recommendation GS-1: "The licensee should propose modifications to the Technical Specification to limit the time that one AFWS pump and its associated flow train and essential instrumentation can be inoperable. The outage time limit and subsequent action time should be required in current Technical Specification; i.e., 72 hours and 12 hours, respectively." The inspectors verified that the final draft version of combined Technical i Specification, Section 3.7.1.2, met the above recommendation. Recommendation GS-4: Emergency procedures for transferring to alternate sources of AFW supply should be available to the plant operators. These procedures should include criteria to inform the operator when, and in what order, the transfer to alternate water sources should take place. The following cases should be covered by the procedures: l e
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-37- , r ! "(1) The case in which the primary water supply.is not initially ! available. The procedures for this case should include any ' . operator actions required to protect the AFWS pumps against self damage before water flow is initiated. [ "(2) The case in which the primary water supply is being depleted. The procedures for this case should provide for transfer to the alternate water sources prior to draining of the primary water supply."
Both of these cases were addressed in Procedure ABN-305, " Auxiliary Feedwater- System Malfunction." The inspector reviewed this procedure and concluded that the procedures provided adequate guidance to operators while transferring between primary and alternate water sources. > ' Recommendation GS-6: The licensee should confirm flow path availability on an AFWS flow train that has been out of service to perform periodic testing or t maintenance as follows: "(1) Procedures should be implemented to require an operator to ! determine that the AFWS valves are properly aligned and a second operator to independently verify that the valves are properly aligned. "(2) The licensee should propose Technical Specifications to assure that prior to plant startup following an extended cold shutdown, a flow test would be performed to verify the normal flow path from the primary AFWS water source to the steam generator: The flow test should be conducted with AFWS valves in their normal alignment." For Item 1 of this recommendation, the inspector reviewed Procedure 0PT-206B, "AFW System." This procedure provided steps to initially align the AFWS and to independently verify valve position. For Item 2 of this recommendation, the staff concluded that the AFW flow path > from the condensate storage tank to the steam generator is automatically , verified during use of the AFWS during normal plant startup.
NUREG-0979, Chapter 22, Section ll.E.1.1, also addressed additional short-term recommendations that did not have numbers. The inspectors reviewed the licensee's response to these short-term recommendations as follows: , Recommendation: "The licensee should provide redundant level indication and low level alarms in the control room for the AFWS primary water supply, to allow the operator to anticipate the need to make up water or transfer to an alternate water supply and prevent a low pump suction pressure condition-from - r occurring. The low level alarm setpoint should allow at least 20 minutes for operator action, assuming that the largest capacity AFW pump is operating."
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_ _ . , . . __. . , ' . i . -38- - , The CPSES. condensate storage. tank has a usable volume of 28,780'gallo' ns of I water at the to-tow level alarm. Assuming that the largest. capacity AFW pump is operating, this volume would allow operators at least 20 minutes to- , transfer to an alternate water supply. .This is'a common design feature for i both Units 1 and.2. Since this method was accepted for Unit 1, the inspectors. l consider this recommendation closed for Unit 2. Additionally, the inspectors verified that redundant level indications were displayed in the control room. j , i Recommendation: "The licensee should perform a 48-hour endurance test on all t engineered safety feature system pumps, if such a test or continuous period of operation has not been accomplished to date. Following the 48-hour-pump run, the pumps should be shut down and cooled down, and then restarted and run for ! I hour. Test acceptance criteria include demonstrating that the pumps remain j within design limits and that pump room ambient conditions (temperature, l humidity) do not exceed EQ limits for safety-related equipment in the room." l In addition to the above recommendation, the licensee, in a letter dated
June 24, 1981, committed to make available test results including: (1) a brief description of the test method and instrumentation used, (2) a plot of bearing and bearing oil-temperature versus time for each pump demonstrating that the temperature design limits were not exceeded, (3) a plot of pump room ambient temperature'and humidity versus time to demonstrate that the pump room ambient conditions do not exceed EQ limits for safety-related equipment in the' , ' room, and (4) a statement confirming that the pump vibration limits were not exceeded. j In response to this recommendation and commitment, the inspectors reviewed
! test summaries of AFW preoperational testing. Reviewed were Procedure 2CP-PT-37-01, Revision 0, " Auxiliary Feedwater System"; and Procedure 2CP-PT-37-03, Revision 0, " Auxiliary Feedwater Turbine Driven Pump."
Based on this review, the inspectors concluded that the AFW pumps were successfully tested and the results were within the acceptance' criteria. - , , Recommendation: "The licensee should implement the'following requirements as specified by Item 2.1.7.b on page A-32 of NUREG-0578: ! Safety-grade indication of AFW flow to each steam generator shall ' be provided in the control room. The AFW flow instrument channels ! shall be powered from the emergency buses consistent with ' satisfying the emergency power diversity requirements for the AFWS set forth in Auxiliary Systems Branch Technical Position 10-1 of
the Standard Review Plan, Section 10.4.9." i ' The inspectors verified that safety-grade indications of AFW flow to each steam generator were provided in the control room and that the AFW instruments were powered by emergency power. This was supported by the AFW safety , evaluation outlined in Section 10.4.9.3 of the FSAR. l
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NUREG-0797, Chapter 22, Section II.E.1.1, also addressed long-term , recommendations. The inspectors reviewed the licensec response to these .long- , term recommendations as follows t Recommendation GL-3: "At least one AFWS system pump and its associated ~ flow ^ path and essential instrumentation should automatically initiate AFW flow and be capable of being operated independently of any ac source for at_least two , hours. Conversion of dc power to ac power is acceptable." 1 This item remained open pending the review of preoperational test data . 'I demonstrating that the turbine-driven pump can nperate for over 2 hours without additional cooling. The inspectors reviewed the test review report ' for Test Procedure 2CP-PT-34-03, Revision 0, " Auxiliary Feedwater Turbine Driven Pump," dated October 24, 1992. The test review report indicated that. - ' th'! turbine-driven AFW pump operated vor over 2 hours without any forced > ventilation at recorded flow ranging from 870-880 gpm, operating speed 4034-4076 rpm, and steam supply pressure ranging from 960-1070 psig, all of which met the design basis. ' Recommendation GS-5: "The licensee should upgrade the AFWS automatic- ~ initiation signals and circuits to meet safety-grade requirements."
NRC Inspection Report 50-445/89-09; 50-446/89-09 stated that this item will be reviewed in conjunction with TMI Action Item II.E.1.2.1.8, " Safety-grade Initiation for AFWS," during a future inspection. In-NUREG-0797, the staff documented that this circuitry is part of the engineered safety feature actuation system and, therefore, the design conforms to the' recommendations. Since no modifications were required, the inspection requirements of Tl 2515/65 for this item were considered completed for Units 1 and 2. i ' Based on the inspectors' review of the above recommendations, the determination was made that the licensee had appropriately addressed the , requirements for the TMI Action Item. 7.9 IClosed) TMI Action item II.E.1.2.2.C: " Auxiliary feedwater flow Rate Indication - Safety Grade" This item concerned the AFW flowrate indication system. Specifically, this l item required that AFW flowrate indication be provided in the control room, , that the indication be safety grade, and that the flowrate channels be powered , from emergency buses. As previously documented in NRC Inspection ~! Report 50-445/89-17; 50-446/89-17, this item was reviewed and closed for Unit 1. The Unit 2 AFW design was determined to be essentially identical to the Unit I design and was documented in NRC Inspection Report 50-445/91-23; 50-446/91-23. The item remained open for Unit 2 pending review of the AFW , ! preoperational test data. The inspectors reviewed the preoperational test data associated with these . flow indicators in Test Procedure 2CP-PT-37-01, Revision 0, " Auxiliary '! I .:
, . - . ._ [ s- ! . l 1 -40- t , l ! Feedwater System," and verified that the flow indicators performed acceptably. ! Based on the inspectors' review of this test data, this item has been i adequately addressed for Unit 2. ! 7.10 (Closed) TMI Action item II E.3.1.1: Emergency Power-Supply for " , Pressurizer Heaters" 3 ' This action item involved the confirmation that sufficient pressurizer heater - , capacity is av-diable to maintain natural circulation conditions with a loss ! of offsite rower. This item was closed in NRC Inspection Report 50-445/90-07;
50-446/90-07 for Unit I and remained open for Unit 2 pending review of _the preoperational testing of the pressurizer heaters. This review also concluded that the pressurizer heaters were not required to maintain natural circulation but to ensure that RCS pressure was maintained greater than saturation
pressure.
During this inspection period, the inspectors reviewed the preoperational test
results obtained during the conJuct of Test 2CP-PT-55-06, Revision 0,
" Pressurizer Spray and Heaters." Based on the results of this review, it was determined that the requirements of this action item were appropriately ' addressed in the preoperational test results which demonstrated that there was ! sufficient pressurizer heater capacity to maintain RCS pressure with a loss of'
offsite power.
7.11 (Closed) TMI Action Item II.F.1.2.A: " Noble Gas Monitor /Long Term" i 1 This item essentially required that the licensee provide continuous monitoring !' of high-level, postaccident releases of radioactive noble gases from the plant. NRC Inspection Report-50-445 us-67; 50-445/89-67 documented the / closure of this item for Unit 1. This item.had remained open pending the review of the Unit 2 preoperational testing 'of the noble gas monitors. During this' inspection, the. inspectors-reviewed the preoperational test results obtained from Test 2CP-DP-70-01, Revision 0, " Radiation Monitoring System," dated December 28, 1992. Based on the results of this-review, the inspectors concluded that all inspection requirements of TI-2515/065 for this item had been satisfied. 7.12 (Closed) TM1 Action Items ll.F.1.2.C, II.F.1.2.0, and 11.F.1.2.E: " Containment High Range Radiation Monitor." " Pressure Monitor." and " Water Level Monitor" < These three items were previously addressed in NRC Inspection Report 50-445/91-29; 50-446/91-29 as II.F.1.3, II.F.I.4, and II.F.1.5, , respectively, and were left open pending review of the applicable Unit 2 , preoperational test results. , ! ' Instead of performing preoperational tests, the licensee developed calibration data packages for the containment high range radiation and pressure monitors. The acceptability of the data packages was based on the performance of instrument calibrations that were previously required for the original
q . .
- . i ~
i
, -41- , .; i i preoperational tests and satisfied the requirements of the FSAR. The licensee _l tested the water level monitor in accordance with Preoperational .' Test CP-PT-065-01, " Containment Atmosphere and Hydrogen Monitoring." , The inspectors verified that the instruments were properly calibrated over the correct range, were within the design tolerances, and that preoperational testing demonstrated conformance with the design performance requirements. j i Based on the above review, it was determined that the licensee had implemented l the appropriate actions to address the subject TMI action items. 7.13 (Closed) TMI Action Item II.F.1.2.F: " Containment H_ydrogen Monitors" ] This item involved the provision for indication of continuous hydrogen -{ concentration in the containment atmosphere to be provided in the control ! room. Additionally, measurement capability shall be provided over the range
of 0-10 percent hydrogen concentration. This item was closed for Unit 1 in , NRC Inspection Report 50-445/89-67; 50-446/89-67. 'l . i Revision 4 of DBD-EE-004, " Design Basis Document _ Accident Monitoring ' Instrumentation," was previously reviewed and the inspectors concluded that the design basis for the Unit 2 hydrogen monitor was essentially-identical to
Unit 1. This review was documented in NRC Inspection Report 50-445/91-29; ! j 50-446/91-29. The item remained open for Unit 2 pending a review of the , Unit 2 preoperational test data. j i The inspectors reviewed Revision 0 of Procedure PPT-TP-92-27, " Containment , Hydrogen Analyzer Preoperational Test Trains A & B," dated January 11, 1993,
and the applicable test summcry. Based on this review, the inspectors concluded that the requirements of this . item were successfully addressed during preoperational testing. ! 7.14 (Closed) TMI Action items II.F.2.2 and II.F.2.4: " Instrumentation for Detection of inadequate Core Cooling" and " Install Level Instruments" , i , ! These items essentially required the licensee to install instrumentation to monitor core water level and to develop the procedures necessary to- implement 3 the use of the instruments. NRC Inspection Report 50-445/89-72; 50-446/89-72 i documented the closure of this item for Unit 1. This item had remained open ' pending a review of the preoperational testing results and the implementation > of procedures for the Unit 2 instrumentation which is used to detect inadequate core cooling. During this inspection, the' inspectors reviewed the results of Preoperational Test 2CP-PT-74-03, Revision 1, dated November 24, 1992, " Heated Junction Thermocouple System," and verified that the licensee
! had developed and implemented Procedure FRC-0.18, " Response To Inadequate ~ Core ' Cooling," Revision 0, dated January 11, 1993. !' Based on the results of this review, the inspectors concluded that all inspection requirements of TI-2515/065 for these items had been satisfied. ! . .) . - - - - t
. ! .. . i .; -42-
.7.15 (Closed) TMI Action Item II.G.1.1: " Emergency Power for Pressurizer E uipment" ' J NRC Inspection Report 50-445/91-21; 50-446/91-21 previously documented the
! review of this item for Unit 2. All requirements of NUREG-0737, _ . 't " Clarification of TMI Action item Requirements," were satisfied at that time with the exception of the review of preoperational tests for the emergency- , power supplies for the PORVs and associated block valves motive and control components and the pressurizer level indication circuits. ' The inspectors' review consisted of verifying that Class lE emergency power supplies for the 125Vdc,118Vac, and 480Vac systems satisfied the acceptance criteria of the associated preoperational tests. The completed tests reviewed were: 2CP-PT-02-01A, -01B, -01C, and -01D; "118 VAC RPS Channel I, II, III.
- and IV" 2CP-PT-30-01A and -018, " Diesel Generator Train A and B," documented in '
NRC Inspection Report 50-445/93-02; 50-446/93-02
2CP-PT-01-01A and -01B, "125 VDC System-Safety Related Class IE Trains A >
and B"; and 2CP-PT--01-03A and -03B, "125 VDC System-Safety Related ' Class IE," documented in NRC Inspection Report 50-445/92-48; , 50-446/92-48. The test results evaluations were complete and all acceptance criteria were met or appropriately evaluated and resolved. , ! Based upon the above reviews, the inspectors concluded that the' licensee had taken the necessary actions to address the TMI action item. 8 REVIEW OF TI 2515/066: INSPECTION REQUIREMENTS FOR IE BULLETIN 84-03, . " REFUELING CAVITY WATER SEALS" (2515/066) ! In response to the operational failure of the refueling cavity water seal at s the Haddem Neck facility, IE Bulletin 84-03 was issued on August 24, 1984. This bulletin directed specific actions to be taken by plants prior to j initiating refueling operations. As previously documented in NRC Inspection Report 50-445/88-39; 50-446/88-33, the licensee's response to this bulletin was reviewed and closed for Units 1 and 2 based on the implementation of revised alarm and refueling procedures. Subsequent guidance for performing additional near-term inspection followup to the license's response to i IE Bulletin 84-03 was provided in TI 2515/066. 8.1 Discussion
During this reporting period, the inspectors evaluated the licensee's response i to the potential failure of refueling cavity water seals for both Units 1 ..
'- -s=- - b- 2 , m, . n !
, \\ * r -43-
, > ! .i and 2, which was delineated in. TU Electric's Letter TXX-88399 dated April 22, 1988. As stated in this correspondence, the refueling cavity seal design at - , CPSES differs from the pneumatic seal assembly, which was identified lin . Bulletin 84-03, in that.the installed configuration consists of two
' permanently welded assemblies. 3 Based on the difference in the. design features for this system, the licensee
determined that the refueling cavity seal-design was not expected.to be- .! susceptible to gross failure-and that the seal was expected to leak before any i
significant degradation. This approach, which was based on the licensee's evaluation of industry operating experience, resulted in the development.of . measures to provide for the early detection and mitigation of a failure of the l refueling cavity water seal. As determined by the inspectors, these measures l included the implementation of remote monitoring capability for. the reactor l cavity sump level and reactor cavity sump pump.run time instrumentation. A
reactor cavity . sump high level alarm was also provided 'in the control room, j Additionally. CPSES Technical Specifications, Sections 3.9.9.1, 3.9.9.2, . and 3.9.10 require that the refueling cavity level be verified within.2 hours l prior to the start, and-every 24 hours thereafter, during fuel movement of l fuel assemblies within the containment. This process . includes a refueling
cavity low-level alarm at the SFP panel and a refueling cavity system trouble l' alarm in the control room. ! In order to verify the implementation of these actions, the inspectors ~ reviewed the following procedures, which provided specific instructions . i relative to the identification of potential refueling cavity seal-leakage and j! the mitigating actions associated with this event. i Procedure ABN-909, Revision 2, " Spent Fuel Pool / Refueling Cavity ~ e Malfunction" , , Procedure RFO-102, Revision 6, " Refueling Operation" !
Procedure ALM-0062A, Revision 3, " Alarm Procedure 1-ALM-6B" ! =
Procedure ALM-0021A, Revision 6, " Alarm Procedure 1-ALM-2A" r
.! Procedure ALM-0701, Revision 2, " Alarm Procedure Spent Fuel Pool Panel"
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e. Procedure ALM-0062B, Revision 0, " Alarm Procedure 2-ALB-6B" Procedure ALM-00218, Revision 0, " Alarm Procedure 2-ALB-2A" l
8.2 Conclusion i Based on the review of the licensee's actions in response to a potential ' failure of the refueling cavity water seal, it was determined that appropriate
procedural controls and alarm features had been implemented to detect and
mitigate the consequences of this postulated event for both Units 1 and 2. .
,
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i -44- l , l . 9 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
! - 9.1 (Closed) Violation 445/91202-01: 446/91201-01: Failure to Implement Adeauate Design Control Measures l This violation pertained to several examples of a failure to implement i adequate design control measures. The violation was of_ concern because the , number of examples indicated a lack of rigorous control of the design control !" process. This violation was comprised of seven examples of failure to implement adequate design control measures. 1 In response to the violation, the licensee issued Letter TXX-92202 dated
April 30, 1992. As stated in the licensee's response to resolve the l violation, the approach included addressing each finding for cause, extent of condition, significance, corrective actions, and actions to preclude _; recurrence. Additionally, the individual parts of the violation were reviewed
collectively by the licensee to determine underlying causes to develop - preventive actions. l The licensee found that, in most cases, the findings would not have occurred [ had the preparers been more careful in developing the calculations and had the i reviewer or design verifiers been more thorough in their review of the
calculations and the applicable design inputs. , The licensee instituted a training program which discussed the design verification provisions in ANSI N45.2.ll. This training focused on the i purpose, methods, and importance of complete and thorough verification of the
' design using actual examples to reinforce design concepts. The inspectors reviewed the licensee's training package and attendance sheets. j The training program included calculation responsibilities, design verification, and preparation, review, and control of calculations.
Attendance sheets documented the attendance of site engineers involved in ! calculation review, verification, and approval. In addition to training, a number of reviews and procedure changes were
completed for the individual parts of this violation. These actions and the inspectors reviews are individually discussed below. 9.1.1 Incorrect Temperatures and Pressures used in Class 1 Piping Analysis Incorrect design temperature and pressure values were used in Westinghouse supplied Class 1 piping analysis for the emergency core cooling system. The Westinghouse supplied Calculation 2-015Z used design temperature and pressure ! values that differed from the correct values listed in TU Electric's Unit 2 " ACCESS" database and revised by Westinghouse in Letter WPT-12394, dated ! January 24, 1990. In addition, Westinghouse had failed to reconcile the latest available design temperature and pressure in some~ of the Unit 1 design calculations since the revised values were also applicable to the equivalent l i I t
_. . . _ - .- . . t .. ~ . .h -45- , t i ! Unit I systems. Westinghouse subsequently identified an additional 14 Unit 1 ) piping calculations which had used incorrect design temperature and pressure i values.
! For the Unit I corrective actions, the inspectors reviewed Westinghouse i Letter WPT-14326 dated January 24, 1992, which documented that the 14 Unit 1 ! piping calculations had been revised to reflect the correct design conditions. l t Additionally, Westinghouse performed a review of all fluid system ' correspondence written subsequent to Letter WPT-12394 to determine if there
were any other changes to design pressure and temperature which would effect l system qualification. Inconsistencies were identified but assessed to have no a - effect on system qualification. Westinghouse also documented in the letter i that the correct Unit 1 design conditions were incorporated into the CPSES l Line List CPES-M-1017, Revision 4. Additional corrective actions and root ' cause for the Unit 1 finding were reviewed by the inspectors in Westinghouse ! ! Letter SE&PT-WSL-748 dated February 27, 1992. The letter stated that Westinghouse Unit 1 internal procedures, WCPS-5, Revision 2; and Change Notice WPCN 3 and WCPS-7, Revision 3, with Change Notice 1, had been revised , to specify that the Line List CPES-M-1017, Revision 4, with DCAs, was the
appropriate source for Unit 1 design pressures and temperatures. The t inspectors reviewed these procedures and determined that they were acceptable. ! t The Unit 2 corrective actions were specified in Westinghouse i Letter SE&PT-WSL-748 and were reviewed by the inspectors. This letter
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documented the Westinghouse review of other related specifications and documents to ensure that other errors related to DCAs were not made. The ! inspectors reviewed the results of the Westinghouse reviews and found them to ! be appropriate. Westinghouse also stated in this letter that the Comanche Peak ACCESS program would be the source for Unit 2 design pressures and
temperatures. In addition, training has been provided to the Westinghouse personnel onsite to ensure that the equipment qualification group is provided with DCAs and TUE forms that affect any Westinghouse supplied equipment. The 3 inspectors reviewed a sample of the training records and determined that the ' licensee had completed the corrective actions. [ , 9.1.2 Incorrect Class lE 125Vdc Short Circuit Calculation This finding involved Class IE 125Vdc short circuit calculation i (Calculation 2-EE-0016, Revision 1), which failed to consider the full . contribution of the battery charger by incorrectly assuming a limiting i amperage during the initial fault current surge. The licensee revised DBD-EE-044, "DC Systen," to incorporate the criteria for calculating the de short circuit _ current from batteries based on 125Vdc
' potential, the manufacturer's supplied potential, the manufacturer's supplied , internal resistance, and ANSI Standard C37.14-1979 for battery charger fault current contribution. The inspectors reviewed DCN 4737, Revision 0, which revised DBD-EE-044,
Revision 4, to incorporate criteria for calculating dc short circuit currents l , , , _ _ _
- - - - . .- ~ _ ..
1 . o
-46- 3 i ! and Calculation 2-EE-0016, Revision 2, "Short Circuit Study for Class IE DC Systems," and determined that the licensee had completed the appropriate- ! - corrective actions. j ' 9.1.3 Lack of Coordination in Class lE 125Vdc Protection Device Coordination Study '
This finding involved Class IE 125Vdc protective device coordination study (Document EE-CA-0008-182, Revision 2), which showed a lack of coordination 4 because of a failure to properly account for the battery charger and battery short circuit contributions. In conjunction with the corrective actions above, the licensee revised Calculation EE-CA-0008-182. The inspectors reviewed ' Calculation EE-CA-0008-182, Revision 3, in conjunction with those documents.
During this review, the inspectors identified a discrepancy between Calculations 2-EE-0016 and EE-CA-0008-182 (200A fused switches versus 100A fused switches). The lionsee acknowledged the discrepancy and subsequently reserved Calculation Change Notices 001 for 2-EE-0016 and 002
for EE-CA-0008-182 through the calculation processing group to be issued to
correct the discrepancy. The inspectors determined that the licensee had completed the corrective actions. 9.1.4 Unanalyzed Voltage Drop to Critical Components This finding involved analyses having not been performed to determine the voltage drop to critical components required to mitigate a main steam line break outside the containment in accordance with the requirements of
DBD-EE-31, " Environmental Qualificat a of Safety-Related Electrical , Equipment," and DBD-EE-52, " Cable Philosophy and Sizing Criteria." The licensee revised Calculations 2-EE-0006, " Voltage Drop on Class lE 125 VDC i 4 Control Circuits"; 2-EE-0007, " Class IE 480VAC Motor Control Center Starter , Coil Pickup Analysis"; and 2-EE-0012, " Voltage Drop on Class IE Miscellaneous .! 125VAC Control Circuits," for Class IE control and instrumentation circuits to } address the affect of the higher ambient temperature of 334 F.
The inspectors reviewed the applicable calculation change notices for Calculations 2-EE-0006, 2-EE-0007, and 2-EE-0012 and determined that the
licensee had completed the appropriate corrective actions. , 9.1.5 Incorrect Service Water Temperature used in RHR Cooldown Analysis ' This finding involved the RHR cooldown analysis, Calculation FRSS-TBX-1076, " Comanche Peak 1&2 Train Cooldown Times," which incorrectly assumed a constant service water temperature of 102 F over the 24 to 30 hours of the cooldown. ' This assumption was incorrect in that the heat sink temperature would increase during the accident due to heat rejection. The licensee performed
Calculation FSE/SS-TBX-1678, Revision 0, which determined that the two-train ! cooldown of the nonaccident unit could be achieved after experiencing a design -! , _
_ _ . . . -_ . . .; . Y -47-
, , , , loss-of-coolant accident on the other unit. This ' calculation was reviewed , during the Configuration Management Team inspection, NRC Inspection-
Report 50-445/91-202; 50-446/91-201, and found to be acceptable. ' t ' The licensee prepared Calculation ME-CA-0000-3294, " Safe Shutdown impoundment Hydrothermal Analysis," Revision 0, which determined the safe shutdown
' impoundment temperature as a function of time while assuming a dual unit I normal cooldown which maximized the heat rejected. The calculation determined , a safe shutdown impoundment temperature profile different from that assumed in
the Westinghouse RHR.cooldown analysis. The inspectors reviewed the licensee's calculation and found it acceptable. Using the results of this calculation, Westinghouse prepared Calculation FSE/SS-TBX-1846, "RHR.Cooldown Calculations," Revision 0, which determined the cooldown capabilities of the ' RHR system. The inspectors reviewed DCN 4896, Revision 0, which revised DBD-ME-260, ,
Revision 1, " Residual Heat Removal System." Thir DCN incorporated changes required by the revised safe shutdown impoundment temperature profile. In . ~ addition, the inspectors reviewed Amendment 87 dated December 18, 1992, to !' Section 9.2.5.3 of the FSAR dealing with the safe shutdown impoundment. The inspectors found the revisions acceptable. _ The licensee had committed to review other calculations that might have been affected by the constant. .l temperature assumption. The inspectors reviewed Unit 2 TUE Form 91-3303, ' Revision 0, which documented the review and revision of Unit 2 calculations which were affected by the temperature. In addition, the inspectors reviewed both Units 1 and 2 calculations that had been revised. The inspectors , reviewed the minutes of the May 26, 1992, quality accountability meeting where -the licensee emphasized that assumptions could not be made regarding critical parameters. The inspectors detennined that the licensee had completed all off the required corrective actions. 9.1.6 Incorrect Backup Relay Calculation This finding involved the backup protective relay (Device 51V) calculation (TNE-EE-CA-0008-267, Revision 1), which incorrectly used a 2000 kVA transformer per unit impedance instead of the EDG impedance .! The licensee currected the 6.9kV bus voltage computation, and the correct characteristic curve for Relay 51V was utilized in Calculations TNE-EE-CA-0008-267 and -157. ! The inspectors reviewed the calculation change notices for TNE-EE-CA-0008-157 and -267 and determined that the licensee had completed the corrective actions. l 9.1.7 Seismic Support Calculation Used an Incorrect Weight for the Battery . Room Heaters This finding involved a seismic support calculation for the battery room ! explosion proof heater which used an incorrect weight for the heater assembly. , i s
F l . , d . -48- , In Ebasco Calculation Volume-IV, Book 52, a weight Se pounds was used for the seismic support of the heater assembly instead of the 1160 pound weight which was indicated on the vendor drawing. The licensee generated ONE- Form FX-91-1661 to address the issue for both units and to correct the calculation. There was sufficient margin in the calculation to allow.for the increase in weight of the heater assembly. The licensee determined that, during the copying process of the calculation, a ' second book in the calculation package was inadvertently omitted. This was determined when the calculation was requested for revision and two books were , supplied instead of one. It was found that the second book of the calculation package had used the correct weight of the heater assembly, therefore, a deficient condition in the calculation did not exist. The inspectors reviewed the ' calculation, Volume. IV, Book 52, Revision _0, and determined that the second book of the calculation contained the correct weight of the heater assembly. The second book contained the latest amputer runs and hand calculations. In addition, the inspectors reviewed Change Notice I to the calculation dated January 20, 1992, which revised- the table of contents to specify which section contained the calculation with the revised equipment weight. The inspectors determined that appropricte corrective action had been implemented. 9.1.8 Conclusion Based on the above documentation reviews and inspection results, it was determined that the licensee had implemented appropriate corrective actions to address the identified violation. 9.2 (Closed) Violation 445/9208-02: 446/9208-02: Inattention to Detail , Resulted in Failure to Follow Established Procedures, and the ! Performance of Maintenance on the Wrong Component This violation concerned two examples of inattention to detail by construction ~ i personnel, which resulted in a failure to properly implement and follow procedures. The first example involved the removal, disassembly, repair, and
reassembly of Valve 2HV-4515, a Unit 2 to Unit 1 CCW cross connect valve, that ! ~ was not performed in accordance with procedures. The second example involved the repair of a Unit 1 valve rather than the counterpart Unit 2 valve,
2CS-7048A, which was specified on the work order.
Lt A task force was comprised to perform a root cause analysis and develop - l corrective actimes to prevent recurrence of wrong unit components activities
and to address the failure of personnel performing activities to impl_ement- ! procedures. The task force was composed of representatives of the Units 1 , and 2 QA organiu tions, Unit 1 maintenance, radiation protection, plant . analysis, Unit 2 project management, construction, operations, and licensing,- ? and was to review all aspects of these issues and the' groups involved. The i task force' concluded that, in each case, training was adequate to prevent 1 human error by well-trained, experienced staff. However, it was concluded , ! ! . . . - . - . _. .
-. _. _ - ~
' , 4 . i -49- , ii I that additional emphasis of the positive component verification process was i ! needed to enforce the licensee expectations to prevent wrong component activities and to encourage step-by-step adherence to procedures. To complete i the corrective actions, several additional activities were specified and completed. A plant wide program was developed to reemphasize the positive verification process with display signs _ throughout the plant. The positive
, verification process and expectations were incorporated into initial and ! requalification of general employee training. The training was also I . incorporated into each involved group's cyclic training. The training i included the unit color identification component designator labels, including the component designator numbers, train and power. supply designator, and color
scheme. In addition, a site-wide training bulletin was issued incorporating -
the same training information.
6 The inspector reviewed the root cause analysis, corrective action report, TUE i Form 92-4498, and training records and verified the results of the training !" and program by questioning licensee personnel. The inspector concluded that the root cause analysis examined all aspects of the issues, determined the i root cause, and appropriately specified the corrective actions. The
corrective actions were specified with reasonable completion dates and were ! completed in a timely manner. The inspector concluded that the licensee ' 3 - devoted the appropriate resources to these violations and performed an - excellent root cause and corrective action evaluation. i 9.3 (Closed) Violation 446/9225-01: Improper System Status Control l This violation resulted from the inclusion of incomplete instrument air valve. -l lineup documentation with unresolved discrepancies into the system status file j prior to hot functional-testing. Procedure ODA-410, " System Status Control," -i Revision 0, required that valve lineups be complete with all discrepancies i resolved, reviewed, and approved prior to. placing the lineups in the system i status file. The licensee reviewed the NRC's finding and concluded in . -l TU Electric Letter TXX-92440' dated September 25, 1992, that the violation was
~ the result of lack of attention to detail and the lack of familiarity with 'l maintaining the startup operating instructions. j In response to the identification of this issue, the licensee performed an [ additional instrument air valve lineup and no examples of mispositioned valves 'l were identified. Additionally, during the conduct of' hot functional testing, ! 29 valve lineups on systems required to support hot functional. testing were { reviewed prior to exceeding the 200of plateau, and again prior to exceeding
the 350 F plateau, with no examples of mispositioned components identified. i The licensee also issued Operations Standing Order 92-0035 to provide
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additional guidance and examples of valve lineup deficiencies and deficiency resolutions.
! The inspectors reviewed the standing order and found the guidance to.be ! , appropriate. Additionally, the inspectors reviewed the following valve ' lineups contained in the system status file: 1 - .- . . .
, -. _ . . ' .
. & -50- , t S0P 3038, Revision 1, " Condensate System," Attachment 1
' S0P 1018, Revision 0, " Reactor Coolant System," Attachment 1
S0P 204B, Revision 0, " Containment Spray System," Attachment 1
S0P 103B, Revision 0, " Chemical and Volume Control System," Attachment 3 . This review indicated that the system lineup documentation was completed in accordance with Procedure ODA-410 and the identified deficiencies were properly noted and dispositioned. Based on these reviews, the inspectors ! concluded that the licensee's corrective actions were complete and appropriate to prevent recurrence. 9.4 (Closed) Violation 446/9233-01: Loose electrical conduit seal assembly > fittinos , This violation involved the licensee's failure to identify, in TUE ' Form 92-5633, Revision 1, the multiple loose instrument fittings as a condition that would require evaluations beyond that required +or individual
nonconformances or deficiencies. Additionally, the licensee failed to identify a condition that had potential impact to Unit 1. ,
' The licensee issued TUE form 92-6300 to upgrade the conditions of TUE Form 92-5633 to programmatic / repetitive. TUE' Form 92-6292 was initiated to ' document the lack of a technical evaluation to inform Unit 1 of the loose fitting issue. As a result of this TUE, Technical Evaluation 92-1944 was [ issued to address Unit 1. Additionally, Memorandum CPSES-9230734 was issued
to identify enhancements to the Unit 2 quality accountability process. The inspectors reviewed the above documents and the licensee's corrective actions. As a result of the licensee's evaluations, DCA-95216, Revision 3,
was issued to require inclusion of a locknut on all electric conduit seal ' assemblies on Rosemont transmitters with street elbows. The inspector . conducted a walkdown of several Rosemont transmitters with street elbows and - f found no discrepancies.
Based on the above documentation reviews and inspection results, it was ! determined that the licensee had implemented appropriate corrective actions to ! address the identified violation. , t 9.5 (Closed) Violation 446/9234-01: Blank Flange in Diesel Generator Lube , Oil and Incorrectly Positinned RHR Valve ! ! This violation involved examples of an inadequate procedure and a failure to follow procedures. The first example concerned the identification of a blank-- flange which was inadvertently left installed in a lubricating supply line in ! Diesel Generator 2-02. The second example involved the discovery of RHR
Valve 2-87248 being found closed by the licensee contrary to the system status j file position. No documentation or justification for'the valve being out of
position could be determined. t !
j -= - --.- - . t
__ _ _ j . ! ! . . i -51-
. . 1 The installation of the blank flange was identified as a construction
deficiency (SDAR CP-92-014) for which the repair and corrective actions were
reviewed and closed in Section 11 of this inspection report. With regard to ' the'other system status control issue, the inspectors found the near-term
corrective actions to be acceptable. Any long-term corrective. actions . proposed by the licensee will be evaluated as part of their response to the ! subsequent violation identified in Section 2.3 of this report. Therefore, j this' item is closed, i 10 FOLLOWUP (92701) r 10.1 (Closed) Inspection Followup Item 446/9204-02: Weld Configurations .i This item involved the configuration of Welds TCX-4103-1, -2, and -3, and l whether the physical arrangement of the welds leaded themselves to full circumferential inspection as required. i !' The licensee concluded that Weld TCX-3 was configured such that a complete inspection was possible. The two remaining welds could not be completely ! inspected, and the licensee requested relief from the full circumferential 1 inspection requirement. This relief request was contained in TUE letter l TXX-92632, dated December 21, 1992. This request was reviewed and approved by ! ! NRC, and is documented in NUREG 0797, Supplement 26, Appendix S, Section 3.J. ! Based on the approval of the relief request, no further inspection activity is required and this item is closed.
i 10.2 (Closed) Inspection Followup Item 446/9221-01: Remote Shutdown Panel ! Communications ! ! This item involved the availability of reliable communications equipment , associated with the Unit 2 remote shutdown panel. Specifically, during the
evaluation of startup Test Procedure 150-223B, " Remote Shutdown Capability i Test," the inspectors determined that the licensee had not established dedicated communications capabilities between the remote shutdown panel and the emergency operations facility. . During this reporting period, the inspectors confirmed that a dedicated l telephone had been installed in the remote shutdown panel and that j communications capability to and from the emergency operations facility was i effectively demonstrated.
} 10.3 (Closed) Inspection followup Item 446/9251-02: Reactor Vessel Stud Hole ! Deficiency l l This item involved the lack of concentricity on the reactor _ vessel flange stud -{ holes. Specifically, during the licensee's review of the stud hole-inspection i results, the threads in the reactor vessel flange were determined to be . nonconcentric with the holes in varying degrees around the entire circumference of the vessel flange. During the review of TUE Form 92-6712, which documented the subject deficiency, the inspectors questioned the l l i i l -.
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-52- , , i I acceptability of the methodoingy used to evaluate.the effective loss of thread , ! engagement due to the reported eccentricity. 1 As determined by the inspectors, the licensee's justification for the -j resolution of TUE Form 92-6712 was based on Westinghouse Letter WPT-15027
dated November 4,1992, which referenced Calculation PCE-92-0131. Subsequent J 4 followup identified that this calculation had not been completed or filed. , However, Westinghouse had provided a supplemental letter,. WPT-15047 dated November 25, 1992, which documented their basis for the acceptability of a'll
reactor vessel stud holes with no effective loss in thread engagement. The-
inspectors reviewed this letter and conferred with Westinghouse technical
representatives in order to verify the basis for the revised assessment of ] reactor. vessel stud hole eccentricity. The inspectors also reviewed the ' technical dispositions of Westinghouse's Field Deviation Report- TCXM-10215 and Combustion Engineering Deviation Notice 16120, which addressed the lack of i concentricity. The licensee initiated TUE Form 92-7063 to address the use of the incomplete , ' calcalation as adequate technical justification for the use-as-is disposition of TUE form 92-0712. The inspectors reviewed the disposition of.TUE Form 92-7063. According to Westinghouse Letter WPT-15107 dated December 22, ! 1992, the calculation had been completed, but not formally verified, when a
more appropriate technical justification was utilized. Additionally, .; Westinghouse letter WPT-15139 dated January 14, 1993, documented the review of i 50 randomly selected letters for reference validation. All 50 of the 1 referenced documents were verified to be valid by Westinghouse. j As a result of these reviews and an examination of the stud hole inspection ! results, it was determined that the technical justification for the eas-is l' disposition provided on TUE Form 92-6712 was acceptable in that the thread form was confirmed by the use of a go/no-go gauge check performed on all l 54 reactor vessel flange stud holes. j 10.4 (Closed) NRC Bulletin 89-03: " Potential Loss of Required' Shutdown Margin During Refuelinq Operations"
I This NRC bulletin was issued on November 21, 1989. It pointed out the
potential for loss of the required minimum shutdown margin during fuel , handling operations and requested that licensees perform several actions to .
ensure that adequate shutdown margins are maintained. TU Electric responded .i to.this bulletin in Letter TXX-89873 dated January 5, 1990.
1 The inspector verified that Station Refueling Procedure RF0-106, Revision 6, ] " Development and Implementation of the Reload Shuffle Sequence Plans," l contained the guidelines of vendor Letter W-89TB-G-0037 dated July 24, 1989, ) in Appendix 8.B, which specifically addressed actions to ensure that core .l reactivity is maintained within the core design analysis.
! The ' inspector also reviewed the training material and attendance documentation -) -associated with the training administered to the senior reactor operators, the l .
i -t ! f . _ _ . - _ _ _- _ ,
e - - - . . -53- , . reactor engineers, and the performance and test engineers that had been assigned core load responsibilities. ~The inspector concluded that the licensee had taken the appropriate actions to address the actions requested in the bulletin. 11 FOLLOWUP ON LICENSEE ACTION ON 10 CFR PART 50.55(e) DEFICIENCIES (92700) , , 11.1 (Closed) Construction Deficiency SDAR CP-85-029: " Design of Architectural Features" This issue involved the identification of nonseismic to seismic interactions which were not properly considered during the initial desig, of architectural features. Specifically, in response to regulatory initiatives, the licensee determined that the integrity of nonseismic metal floor plates, handrails, gratings, and masonry installations could not.be assured during a postulated safe shutdown seismic event. As previously documented in NRC Inspection Report 50-445/89-85; 50-446/89-85, the licensee's corrective actions associated with this issue were evaluated and closed for Unit 1. . With respect to Unit 2, the inspectors reviewed the licensee's corresponding corrective actions, which were delineated in TV Electric's letter, TXX-91283, dated September 24, 1991. These actions included the validation of existing designs for gratings, deck plates, ladders, hand rails, and anchorages for miscellaneous structural items in accordance with established commodity inspection procedures. In order to determine the adequacy of the licensee's engineering methodologies and programmatic controls which were developed to + address the requirements of Regulatory Guide 1.29, " Seismic Design Classification," the inspectors reviewed the following project procedures: , NQA 3.23-0.01, Revision 2, " Quality Control Monitoring
Program (Unit 2)," Attachment 8E , i DBD-ME-005, Revision 1, " Seismic /Nonseismic System Interaction Program"
Specification CPES-A-2026, Revision 0, " Rolling Steel Doors" l
l Specification CPES-A-2022, Revision 0, " Hollow Metal Doors And Frames"
Specification CPES-S-2006, Revision 1, " Structural Steel"
Procedure 21M-5.01, Revision 4, " Project Instruction For The Civil / [
Structural Group" i Calculation 0218-05-0280, Revision 0, " Verification of Checkered Plate ' e In Reactor And Safeguards Building" Procedure EQE Document 52060-P-001, Revision 2, " Project Plan - Seismic j
Adequacy Evaluation of Unit 2 Non-Seismic Commodities" !
- . ! .- t t - i ! -54- 1 , i ! Procedure EQE Document 52060-P-002, Revision 1, "Walkdown Criteria -
, ' Seismic Adequacy Evaluation of Unit 2 Non-Seismic Commodities" Procedure EQE Document 52060-P-003, Revision 2, "Walkdown Procedure -
Seismic Adequacy Review of Unit 2 Non-Seismic Commodities (CPSES Document EQE-5.01-21M)"
Procedure EQE Document 52060-P-004, Revision 1, " Evaluation Criteria - -
' Seismic Adequacy Review of Unit 2 Non-Seismic Commodities" t ' Procedure EQE Document 52060-P-005, Revision 0, "Walkthrough Procedure -
Seismic Adequacy Review of Unit 2 Non-Seismic Commodities (CPSES Document EQE-5.02-2IM)" , t Procedure EQE Document 52060-P-006, Revision 0, "Walkdown Procedure - i '
Seismic Adequacy Review of Common Area Non-Seismic Commodities (CPSES ' Document EQE-5.03-2IM)"
Based on the inspectors' review of the referenced material, no discrepancies were identified.and it was generally concluded that the licensee's process for . evaluating seismic Category I/II interactions, including the identification 1 and resolution of nonseismic commodities with potential interaction i consequences during safe-shutdown earthquake conditions, was properly ! addressed. + 11.2 (Closed) Construction Deficiencies SDARs CP-85-035 and CP-86-045:
" Cable Tray Hanger Design" and " Seismic Category 11 Systems and Components" The f.irst deficiency (SDAR CP-85-035) was concerned with the identification of ' numerous installation discrepancies involving differences between the design requirements for cable tray supports and as-built configurations. The second ' i deficiency (SDAR CP-86-045) involved inadequate design controls _ associated with the installation of Seismic Category II components. Specifically, the design requirements of the FSAR (Section 3.2 and 3.78.28) were not properly l implemented in that some seismic Category II equipment located in Seismic - Category I buildings had been qualified only at the anchor points and not at '; other locations on the principal structure. i i As previously documented in NRC Inspection' Report 50-445/90-03; 50-446/90-03, SDARs CP-85-035 and CP-86-045 were reviewed and closed for Unit 1 based on the , implementation system design validation activities and hardware modifications _
which were conducted under the auspices of the licensee's Corrective Action Program. , ! During this reporting period, the inspectors reviewed the methodologies and corrective actions associated with the resolution of these issues for Unit 2, 'j which were documented in TU Electric's letter, TXX-92022, dated January 8, - 1992. As described in this correspondence, Unit 2 project management j j l l .
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initiated the following' program to validate the seismic integrity.of existing I non-Category I installations located in Seismic Category I buildings. l t
Area engineering walkdowns were performed within Seismic Category I
structures to identify potential source candidates for further . evaluation. Engineering walkdowns were performed in accordance with ! project procedures which defined the screening criteria for source ! , connodities based on earthquake experience data. Candidates identified during area walkdowns were either evaluated . $
' specifically or qualified by bounding analysis _for structural integrity. ' Where structural integrity could not be adequately demonstrated using
t specific evaluation or bounding analysis techniques, commodities were either modified or justified as acceptable using source-target . evaluation methods similar to those used in Unit 1. !
Additionally, for new non-Category I commodities installed in Unit 2 and ! common areas, requirements were instituted to maintain structural integrity. i ? for safe-shutdown earthquake loading. Similarly, for current generation Seismic Category I systems, components, and structures installed in Unit 2 and ' common areas, the licensee implemented a program to confirm that they were not
adversely affected by the existing sources. l, . The inspectors reviewed the following project documents in order to verify the ! ' implementation of the licensee's seismic evaluation programs- i DBD-ME-005, Revision'1, " Seismic /Non-Seismic Systems Interaction ' e Program" DBD-CS-082, Revision 0, " Cable Tray And Cable Tray Hangers" i
' DBD-CS-086, Revision 2, "HVAC Duct And Duct Supports"
. t ~I DBD-CS-090, Revision 2, " Conduit And Conduit Support Design Train A, B,
And Greater Than Two Inch Diameter Train C Conduits" ! , DBD-CS-093, Revision 1, " Seismic Adequacy of Train C Conduits (Two Inch
Diameter And Less)" T Specification CPES-E-2004, Revision 1, " Electrical Installation"
Specification CPES-S-2005, Revision 2, " Electrical Raceway Installation"'
Specification CPES-H-2019, Revision 0, " Installation, Fabrication, And !
' Inspection Requirements for HVAC Systems, Supports, And Accessories" Procedure 21M-5.02, Revision 2, " Conduit And Conduit Supports Design"
i 1 I ~ ' . - _ -
+ l 1 f -56- , i 4 Procedure 21M-5.03-CTH, Revision 1. " Cable Tray And Cable Tray Hanger
Design" . Procedure 21M-5.ll-HVAC, Revision 1, " Seismic Design of Category I t
And II Air Handling Units, Plenums And Equipment Supports" Procedure 21M-5.19-HVAC, Revision 1, " Seismic Design Criteria For
Seismic Category II And Non-Seismic Non-Safety Related (NNS) HVAC Ducts -l And Duct Supports"
, Procedure 52060-P-003, Revision 2, " Seismic Adequacy Review of Unit 2 a Non-Seismic Adequacy Review of Unit 2 Non-Seismic Commodities" The following calculations were also reviewed in order to verify the proper i translation of seismic design criterion for installed Seismic Category II structures. Calculation 0218-CS-0280, Revision 0, " Verification Of Checkered Plate
In Reactor And Safeguards Building Unit 2" Calculation 0218-CS-0119, Revision 0, " Verification of Unit 2 Typical
Grating and Fastening Details" , Calculation 0218-CS-2323, Revision 0, " Verification of Checkered Plate i
^ In Diesel Generator Room" t Calculation 16345/6-CS(S)-147, Revision 0, " Seismic Qualification Of
. Missile Restraining Doors"
Calculation 16345/6-CS(S)-149, Revision 2, " Rolling Steel Doors Subject
to Seismic Loads" , . The inspectors also evaluated the translation of Unit I reverification ! requirements to Unit 2, as committed to in the CPSES Corrective Action Program. As a result of these inspection activities, which were documented in l NRC Inspection Report 50-445/92-13; 50-446/92-13, it was generally concluded
that;the Unit 1 Post-Construction Hardware Validation Program results, including the corrective actions for Seismic Category II systems and , components, were properly _ incorporated into Unit 2 construction completion ( programs and design validation processes. Based on the results of these extensive reviews,-no deficiencies were
identified and it was determined that the licensee had implemented appropriate
corrective actions to address-the identified pro,cammatic deficiencies. ) ,
, . (Closed) Construction Deficiency Significant Deficiency Analysis { 11., Report (SDAR) CP-86-41: "Small LOCA Mode 4 Operations" .i This potential deficiency involved the evaluation of the effect of a small i break loss of coolant accident during Mode 4 operation The NRC staff was 1 .
. . . . -57- , reviewing the Westinghouse Owners Group topical report, WCAP-12476, " Evaluation of LOCA during Mode:3 and Mode 4 Operation for_ Westinghouse NSSS," , and reviewed the licensee's final letter, TXX-92472, regarding_ this issue with regard to CPSES. The acceptance of the licensee's position is documented in I Section 15.3.8 of Supplement 26 to NUREG-0797, " Safety Evaluation Report related to the operation of Comanche Peak Steam Electric Station, Units 1 and 2." , 11.4 (Closed) Construction Deficiency SDAR CP-86-082: " Cable Tray Hanaer Welds Used to Splice Channel Sections" i During the as-built review of Unit I cable tray hangers, the licensee found
that certain welds used to splice channel sections end to end to form posts
were not the required full penetration welds. Radiographic examination of a_ '; sample of welds that 'could not be visually inspected because of the presence of insulation material also found welds that were not full penetration welds. I As previousiv documented in NRC Inspection Report 50-445/89-27; 50-446/89-27, l this construction deficiency was reviewed and closed for Unit 1 based on a ! review of construction records, a field walkdown, and ultrasonic testing on inaccessible welds. 1 Regarding Unit 2, the inspectors found that the insulation had not been installed at the time of deficiency identification and the welds were visually j inspected. The corrective actions were to identify any welds without full i penetration during the design verification program and replace these welds
with full penetration welds. In addition, the construction procedure was i revised to provide more specific direction. l The inspectors found that the licensee had inspected all installed cable tray
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hangers (approximately 2800) for this deficiency. The inspection followed , Procedure CPE-EB-FVM-CS-003, " Field Verification Method,' Unit 2 Cable Tray 'i Hanger As-Built and Design Adequacy Verification Program," during the
' Corrective Action Program from 1984 through 1987. The documentation of the inspection was the issuance of an "as-built" drawing that detailed the welds l as full or partial penetration welds. Partial penetration welds were then i replaced with full penetration welds by issue of a DCA.
Specification CPES-E-2005, " Electrical Raceway Installation," was changed by
' DCA 93583 on November 20,-1990. As a result, Procedure CQP-EL-225, " Cable Tray and Supports," was changed to address these same inspection requirements ' for cable trays and supports that had not been installed at the time of the above inspection required by Procedure CPE-EB-FVM-CS-003. 'As a result of , these inspections, 20 hangers were identified to have incomplete welds and , those were replaced'with a splice plate and full penetration welds. The , inspectors reviewed the DCAs and the construction work documents which implemented the repairs and verified completion of the repairs. ) ! Based on the above reviews, the inspectors determined that appropriate corrective actions had been implemented.
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, I , . 11.5 (Closed) Construction Deficiency SDAR CP-87-023: " Conduit Unions" h This deficiency involved the identification of discrepancies on electrical I, conduit unions subsequent to their inspection and acceptance by the licensee's '! i quality control organization. Specifically, during the conduct of system validation inspections, the licensee identified loose conduit connections'on i both Class IE and non-lE electrical systems. As stated in TU Electric's j Letter TXX-6565 dated July 27, 1987, this condition v:as attributed to ' inadequate installation and -inspection procedures associated with tightening of conduit unions. As previously documented in NRC Inspection. - i Report 50-445/89-47; 50-446/89-47, this item was reviewed and closed for - Unit 1 based on the licensee's corrective actions, which included extensive
reinspection of installed conduit unions and the revision of the governing. l installation and inspection procedures to address tightening of unions. .: With respect to Unit 2, the inspectors reviewed the following project- documents in order to verify that the corrective actions associated with > conduit unions had been properly implemented: l DBD-ME-005, Revision 1, " Seismic /Non-Seismic Systems Interaction j
Program" j Specification CPES-lE-2004, Revision 1, " Electrical Installation" = ' Specification CPES-S-2005, Revision 2, " Electrical Raceway Installation"
Project Letter CPSES-9130633 dated December 4,1991, " Quality Control (
Backfit Inspection, Conduit System, PCHVP-CPM-002, Attribute No. 244" . Project Letter CPSES-9029171 dated December 17, 1990, "Backfit !
! Inspections for Conduits" ! Procedure CQP-EL-222, Revision 1, " Installation And Fabrication Of
Conduit Raceway Systems" i Procedure EQE Document 52060-P-002, Revision 1, "Walkdown Criteria - 1 e Seismic Adequacy Evaluation of Unit 2 Non-Seismic Commodities" [ Procedure EQE Document 52060-P-003, Revision 2, Walkdown Procedure - (
Seismic Adequacy Review of Unit 2 Non-Seismic Commodities (CPSES } Document EQE-5.01.21M)" l I Based on the referenced documentation reviews, no discrepancies were identified and it was determined that the licensee had implemented appropriate l corrective actions to address the identified deficiency. ! ly
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, 11.6 (Closed) Construction Deficiency SDAR CP-87-068: "Hilti Bolt - Jnadequacies"
Tnis construction deficiency involved the incorrect utilization of concrete l " expansion anchors (Hilti bolts) to secure rotating equipment and the improper - torquing of installed Hilti bolts. This issue was previously reviewed and + closed for Unit 1 in NRC Inspection Report 50-445/90-03; 50-446/90-03 based on , the licensee's reinspection and evaluations of as-built configura'tions and the [ ~ revision of the applicable installation specification.
During this reporting period, the inspectors reviewed the licensee's corrective actions relative to Hilti bolt inadequacies, which were documented ! in TU Electric's Letter TXX-88174 dated February 5,1988. As stated in this correspondence, the cause of the subject deficiencies was attributed to inadequate engineering criteria. In order to verify the technical adequacy of. ~ the procedural controls for the installation of_ concrete expansion anchors, i the inspectors reviewed the governing Construction Specification CPES-S-2001, ' Revision 2, " Structural Embedments." The inspectors also reviewed the . 4 following project documents which defined the walkdown inspection criteria-for installed configurations in Unit 2 and common areas as well as' the results of , these reinspection activities. l Procedure EQE Document 52060-P-002, Revision 2, "Walkdown Criteria
Seismic Adequacy Evaluation Of Unit-2 Non-Seismic Commodities, CPSES" , Procedure EQE Document 52060-P-003, Revision 2, "Walkdown Procedure
Seismic Adequacy Review Of Unit 2 Non-Seismic Commodities CPSES (CPSES , Document EQE-5.01-llM)" j EQE Document 52060-R-001, Revision 0, " Program Summary And Results Of
The Seismic Adequacy Review of CPSES Unit 2 Non-Seismic Commoditie's" l > EQE Document 52060-R-002, Revision 0, " Program Summary And Results Of .i
The Seismic Adequacy Review Of CPSES Common Area Non-Seismic { Commodities"
a - in addition to the above listed programmatic reviews, the inspectors conducted l extensive field verification walkdowns of installed concrete expansion anchors
to evaluate the adequacy of Hilti bolt configuration control processes. The l results of these evaluations, which were previously documented in NRC I r
Inspection Reports 50-445/91-21; 50-446/91-21 and 50-445/91-29; 50-446/91-29, i generally concluded that the licensee had developed a strong program for the installation of concrete expansion anchors, including the establishment of- j appropriate QA plans, instructions, and procedures for the implementation of l installation requirements.
' Based on these reviews and the results of documented inspection findings, no discrepancies were identified and it was determined that the licensee had
implemented appropriate corrective and preventive measures to address the identified deficiency, t , haa e,-. . ~ ,,-. , . ,-_ . . _ . - - , -
. . . . _ - . _. _ _ ? . ! ~ ! -60- i P 11.7 (Closed) Construction Deficiency SDAR CP-87-071: " Missing Welds and l Undersized Members" t Third-party reinspections identified deficiencies regarding undersized members, undersized welds, missing welds, and missing inspection records of completed structural steel assemblies. As previously documented in NRC Inspection Reports 50-445/90-03; 50-446/90-03 and.50-445/89-74; 50-446/89-74, this construction deficiency was reviewed and closed for Unit I based on the , ' Post-Construction Hardware Validation Program. . Regarding Unit 2, the inspectors found that Corrective Action Request 87-012, , Revision 2, which documented this deficiency, was closed based on: -(1) the'
confirmation that inspection records were found for all Unit 2 assemblies;_ ' (2) the issuance of Specification CPES-S-2006, " Structural Steel Specification," which included specific attributes to. preclude -recurrence of- the deficiencies; (3) the training of personnel on the specification requirements; and (4) the issuance of engineering, construction and inspection procedures to assure adequate design control, installation, and-inspection. - The root cause for the undersized members and missing welds was determined to be inadequate construction supervision and inspection procedures. The root- " cause for undersized welds was determined to be inadequate workmanship and inspection. The issuance of the specification and procedures was the- preventive action taken to preclude deficiencies for any new installations. r Field verification was not required for Unit 2 because records were found for , all installations. However, "backfit" type inspections were performed on .' Unit 2 Seismic Category I and II type structures because of the specification change. Seismic Category I type structures were inspected 100 pcrc .t . Seismic Category II type structures were given a 100 percent inspection by - ! construction, engineering and a 10 percent sample reinspection by quality control as addressed in Procedure 2-EAP-033, " Verification of Seismic . . Category II Structural 'and Miscellaneous Steel." The inspectors reviewed the-
checklists that documented the "backfit" inspections identified above for all ' Category I type structures. The inspectors reviewed the close-out memorandum on the Category 11 type structures. - Based on the-above reviews, the inspectors determined that appropriate ! corrective actions had been implemented, i 11.8 (Closed) Construction Deficiency SDAR CP-87-135: " Control' Room Air.
Conditioning and Primary Plant Ventilation Systems"
During review of Unit 1 -operating procedures, the licensee . identified that the control room HVAC system could be susceptible to a single failure that could , prevent automatic isolation of. the system under accident conditions. . Additionally, the licensee found that the auxiliary, safeguard, fuel building ventilation supply fans had a non-Class 1E power supply. These same fans were i automatically tripped by nonsafety-related pressure switches. As previously i documented in NRC Inspection Report 59-445/89-73; 50-446/89-73, this ! . , _ - . , . _ , . - m .
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-61- l 1 construction deficiency was reviewed and closed for Unit 1 based on a design
modification that provided safety-related controls which automatically tripped [ these fans and met the single failure criterion. i ~f Regarding Unit 2, the inspectors found that Design Modification 90-415 had .[ been issued to rewire the control room air conditioning system to meet with ~ the single failure criterion. The inspectors reviewed the work orders, . , WO-2-92-023940-00 and WO-2-92-021911-00, which installed this design ! modification. The inspectors verified completion of the design modification
installation. I Based on the above reviews, the inspectors determined that appropriate corrective actions had been implemented. ,
11.9 (Closed) Construction Deficiency SDAR CP-92-014: Blank found in EDG I Lube Oil Supply Line ' This deficiency involved the identification of an improperly. controlled stainless steel blank found in a Diesel Generator 2-02 lube oil supply line , flange. As previously documented in NRC Inspection Report 50-445/92-34; 50-446/92-34, this-issue was identified as an example of an inadequate , procedure in Violation 446/9234-01.
P As documented in TU Electric Letter TXX-92418, the licensee attributed the root cause of this occurrence to the failure of several procedures to adequately control the accountability of temporary blanks. The inspectors ., reviewed Procedure CDP-ME-101, " Installation of RWMS Piping, ANSI B31.1 Piping [ and Associated Components," Revision 0; Procedure CP-SAP-6, " Control of Work
in Station Components After Release from Construction to Startup,"
Revision 26; and Procedure CP-SAP-13, " Temporary System Modifications," Revision 14, which were modified to enhance accountability for blanks.
Training was also provided to personnel regarding the need for thorough documentation on work documents. Additionally, as stated in the licensee's - i response, no additional undocumented blanks were found in other systems. j i The licensee performed a complete inspection of all items supplied by this oil line and numerous components were replaced. The diesel generator was successfully tested during Unit 2 preoperational testing. . . , Based on the review of the documentation, inspectors' verifications of-
corrective maintenance activities, and subsequent postwork testing, it was i determined that appropriate corrective actions were implemented to address the ! SDAR and Example 1 of Violation 446/9234-01. -
11.10 (Closed) Construction Deficiency SDAR CP-92-018: " Steam Leak in a 3" Schedule 80 Lateral"
-! ' During hot functional' testing of Unit 2 on July 29, 1992, a steam leak was discovered in a 3-inch Schedule 80 lateral in the steam generator blowdown ' system. This deficiency was identified on TUE Form 92-5913. It established j . ' , _ _ _ ._. . -
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) -62- , , ! i that the deficiency was caused by internal defects in the forged steel that were present during the manufacturing process of the pipe. The licensee.
determined that the deficiency could not create a substantial safety hazard were it to remain uncorrected and was thus not reportable'. The inspectors found that TUE Fcrm 92-5913 was' closed. The immediate 1 , corrective action was to install a temporary plug into the lateral, Land 1 subsequent corrective actions included replacement of the lateral following l 1 completion of hot functional testing. Additionally, the licensee radiographed: the only other lateral of this same heat that had been installed in Unit 2. . One of the laterals of the same heat was in storage, and the' inspectors
reviewed the construction work documents regarding the. replacement of the-
deficient lateral as well as the radiographs of the lateral in storage. In-addition, the inspectors reviewed the metallurgical analysis report which concluded that the failure occurred because of casting defects at:the foundry. The report stated that debris or nonmetallic material filling the defects did not separate until the hot finctional test, possibly because of the. gradual
cleaning action of extended steam exposure. ' Receiving records indicated there were five forged laterals of this heat ! received on March 24, 1980. Two of these laterals were installed in Unit 1, and Technical Evaluation 92-2453 dated November 24, 1992, was issued to Unit 1 to address the issue. The technical evaluation was a followup to an earlier interoffice correspondence dated August 31, 1992. The interoffice 'l correspondence was written to document an earlier discussion on the same
' subject. Unit I corrective action'for these laterals-had not been established at the conclusion of this inspection period.
The inspectors reviewed and concurred with the analysis which established that- this failure was not a substantial safety hazard were it to remain - uncorrected. Based on the review of above documentation, the inspectors determined that appropriate corrective actions had been implemented. > 11.11 (Closed) Construction Deficiency SDAR CP-92-019: Potential For RHR j Pump Steam Bindinq
Pursuant to 10 CFR Part 50.55(e), the licensee reported a potential
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operability problem concerning the RHR pumps. When in the low head safety injection mode with suction side fluid temperatures greater than _250 F, the RHR pumps could be rendered inoperable by the formation of steam voids in the
suction piping after the pumps start in response to a safety injection signal. 1' This scenario is possible at the time of transitionL from Mode 4 to. Mode 3, when the RHR system is at an elevated temperature following its use in plant -- heatup, Once placed in the standby mode, approximately 10 hours are needed to. cool the RHR system to the point that suction side flashing would not occur during a starting sequence. The licensee's procedural controls ensure that prior to entry into Mode 3l (350 F) the temperature of both RHR loops is less than 250oF, which is..the; j =i f
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, -63- - E . ] cutoff below which the steam binding phenomenon should not occur. . i Additionally, one loop of RHR is removed from the shutdown. cooling mode prior , to reaching 250'F during plant heatup, thus ensuring that -it would-be ! available for service. if needed. Relying on these controls, the licensee j concluded that steam binding of the RHR system could only occur during Mode 4 and that it should affect, at most, only one loop. ~ This enables the licensee . -; to meet the Technical Specification requirements for the RHR system without
., having to rely on the service of an RHR loop at temperatures in excess of i 250oF. The licensee performed a probabilistic risk assessment of the core melt risk from a startup Mode 4 loss-of-coolant accident.with one loop'of RHR
disabled and concluded that this. scenario constituted'a negligible contribution to the overall loss-of-coolant accident risk. Based on these.
considerations, the licensee determined that this def.iciency did not represent j a substantial safety hazard and, therefore, was not reportable under > 10 CFR 50.55(e). The inspector reviewed documents assembled by tne licensee and held' ._ . discussions with several licensee engineers. The inspectors' review supported ! the licensee's conclusion that the concern was not reportable. l
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_ . ' . . ATTACHMENT 1 , , - 1 PERSONS CONTACTED 1.1 TU ELECTRIC , Simon Abuyounes, Lead Discipline Engineer r ' R. Adams, Instrumentation and Controls Engineering Supervisor
- G. R. Ashley, ABB Impell Scope C
+J. Audas, Manager, SAFETEAM
- 0. Bhatty, Licensing Engineer
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- H. J. Brau, Operations Support
- H. D. Bruner, Senior Vice President
J. Burnett, Construction Engineer ' +*W. J. Cahill, Jr., Group Vice President D. Carlsen, EQ Engineer R. Carver, Electrical Maintenance Assistant Manager E. Dalasta, Assistant Lead Mechanical Engineer J. Daranay, Instrument and Control Lead Engineer R. Dern, Startup Test Engineer
- J.
R. Disser, Unit 2
- J. W. Donahue, Manager, Plant Analysis
+T. Gibbs, Investigation Coordinator, SAFETEAM
+F. Green, Interview Coordinator, SAFETEAM
- W. G. Guldemond, Manager, Independent Safety Engineering Group
, N. Hammett, Construction Engineer
- C. Harrington, Mechanical Equipment Engineering Supervisor
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- S. W. Harrison, Unit 2 Project Engitmering Manager
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- T. L. Heatherly, Licensing Engineer
- T. A. Hope, Site Licensing Manager
D. Keating, Technical Programs Supervisor ,
- J. J. Kelley, Jr., Plant Manager
- D. M. McAfee, Manager, QA
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- D. R. Moore, Transition Manager
' J. Murray, Planning / Scheduling T. Narang, EQ Engineer ,
- D. Palmer, Event Analysis Manager
R. Parson, Startup Test Supervisor +9. Pendleton, Manager, Contracts J. Petit, Systems Engineer J. Ragan, level III Radiographer
- C. W. Rau, Unit 2 Project Manager
+J. Rumsey, Manager of Corporate Security R. Skiba, Licensing Engineer
+G. Stewart, President _UTS
- M. W. Sunseri, Manager, Maintenance Engineering
D. Thompson, Construction Engineer T. Trail, Licensing Engineer +R. D. Walker, Manager of Regulatory Affairs for Nuclear Engineering Operations ! I l b f
_ _ _ - _ _ , . -2- , 1.2 NRC Personnel +R. Brady, Special Assistant +R. Wise, Allegations Coordinator + Denotes personnel that attended the December 11, 1992, SAFETEAM meeting.
- Denotes personnel that attended the January 29, 1993, exit meeting,
, in addition to the personnel listed above, the inspectors contacted other l personnel during this inspection period. l 2 EXIT MEETING I . An exit meeting was conducted on January 29, 1993. During this meeting, the ! inspectors reviewed the scope and findings of the report. The licensee did I not identify as proprietary any information provided to, or reviewed by, the inspectors. ] l - _ _ - . ___ __________ __ _______ _______________________________ ______ --_____________________ _-________ . . _
.- .- . . _ _ ' ,. , .. , . ATTACHMENT 2 Procedure No. Revision Title-
- 2CP-PT-23-01
0 Radioactive Vents anc Drains
- 2CP-PT-65-01
0 Containment Atmosphere & Hydrogen Monitoring 2CP-PT-12-02 1 Communications Sound Powered Telephone System , !
- 2CP-PT-45-01
0 Containment Ventilation
- 2CP-PT-36-01
1 Safeguards Building HVAC 2CP-PT-14-03 1 Loss of Instrument Air ' 2CP-PT-02-OlA 1 118 VAC IV 2PCI RPS Channel 1. Test (7.5 KVA Test)- ' 2CP-PT-02-OlB 1 118 VAC IV 2PCI RPS Channel II Test (7.5 KVA Test);
2CP-PT-02-Olc 1 118 VAC IV 2PCI RPS Channel III Test (7.5 KVA Test) 2CP-PT-02-01D 1 118 VAC IV 2PCI RPS Channel IV Test (7.5 KVA Test)
2CP-PT-02-02A 1 118 Volt Class IE Elgar Inverters 2CP-PT-02-02B 1 118 Volt Class IE Elgar Inverters 2CP-PT-02-02C 1 118 Volt Class IE Elgar Inverters 2CP-PT-02-02D 1 118 Volt Class 1E Elgar Inverters '
- 2CP-PT-02-14
0 Plant Electrical Survey Test 2CP-PT-79-01 0 Polar Crane Preoperational Test ' 2CP-PT-40-01 1 Fuel Handling Tools And Fixtures 2CP-PT-40-02 0 Fuel Transfer. System 2CP-PT-40-03 1 Refueling Machine (Manipulator Crane) 2CP-PT-79-02 0 Containment Fuel Handling Bridge Crane l' 2CP-PT-49-01 1 Charging And Letdown 2CP-PT-ll-01 1 Component Cooling Water System Preoperational Test ' i 2CP-PT-06-02 0 Fire Protection System 2CP-PT-06-03 0 Fire Detection System , 2CP-PT-04-01 1 Station Service Water , STA-707 9 "10 CFR 50.59 Reviews" STA-815 4 "Open Item Evaluation and Deferral Process"
STA-802 10 " Acceptance of Station Systems and Equipment" STA-606 18 " Work Requests and Work Orders" ,
- NOTE:
Preoperational test results review were not completed by the licensee.
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, a -2- , 10 CFR Part 21 Reference Number CPSES UNIT TITLE P21-ABB-04/02/1991 1&2 Current Transformer (CT) Cracking P21-C00P-01/15/1992 1&2 Cooper P21 Issue, EDG Power Cylinder Liner P21-C00P-02/24/1992 1&2 Starting Air Valve Assembly ' P21-C00P-04/04/1991 1&2 Defective Brush Holders on EDG _ P21-C00P-04/10/1991 1&2 Failure of Substitute Relay Supplied for CPSES EDG P21-C00P-09/ll/1992 1&2 EDG Jacket Water Pump Shaft P21-CPE-01/09/1991 1&2 Error in Calculation for F1 P21-CPE-10/23/1990 N/A Barton D/P Switches Seismic Qualification P21-CVI-06/05-1991 1&2 Agastat E7022 and E7024 A-L Series Relays P21-ELM /FASCO-03/13/1992 1 & 2 Nutherm Elmwood/Fasco Defect in Contactors P21-FOX-01/03/1991 N/A Improperly Processed Parts, Foxboro Transmitters ' P21-GENE-01/02/1992 1&2 ED&C Frame Molded Case Circuit Breakers P21-NL1-07/08/1992 1&2 GNB Industrial Battery P21-IR-09/19-1991 1&2 Ingersol-Rand, Pump Defuser Failures
P21-LIMI-12/07/1992 1&2 Limitorque MOV Declutch System Anomalv < P21-MCG-10/13/1990 2 Failure / Malfunction of Reactor Trip LKR Cell Switch P21-ROSE-07/30/1992 1&2 Rosemont Transmitter Over-torque Specifications P21-TAYLOR-ll/12/1992 1&2 Taylor Forge Stainless Steel -, Fittings 304/316 P21-WRST-06/28/1991 1&2 Potential Diode Failure in SSPS System 21R-92-002 1&2 Copes Vulcan Valve Bonnet-To-Body Fasteners 4 l l ! i 1 2
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.. ' ATTACHMENT 3 , ACRONYMS ABN abnormal operating AFW auxiliary feedwater AFWS auxiliary feedwater system CCW component cooling water COMS cold overpressure mitigation system
CPSES Comanche Peak Steam Electric Station CVCS chemical and volume control system , DBD Design Basis Document DCA Design Change Authorization DCN Design Change Notice . EDG emergency diesel generator i EQ environmental qualification FSAR Final Safety Analysis Report ! HVAC heating, ventilation, and air conditioning IDER industry operating experience report MSLB main steamline break ONE operation notification and evaluation ORAT Operational Readiness Assessment Team PORV power-operated relief valve PR-ISM Plant Reliability - an Integrated System for Management QA quality assurance RCP reactor coolant pump RCS reactar coolant system
RHR residual heat removal i SDAR Significant Deficiency Analysis Report SFP spent fuel pool SPDS safety parameter display system TI Temporary Instruction TMI Three Mile Island , 4 TUE TV Evaluation .. E i . .{ i r 1 - . }}