IR 05000498/1998019

Insp Repts 50-498/98-19 & 50-499/98-19 on 990125-0317. Violations Noted.Major Areas Inspected:Operations & Engineering

ML20205D750
Person / Time
Site:	South Texas
Issue date:	03/26/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20205D745	List: IR 05000498/1998019 ML20205D738
References
50-498-98-19, 50-499-98-19, NUDOCS 9904020294
Download: ML20205D750 (41)

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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket Nos.: 50-498;50-499 License Nos.: NPF-76; NPF-80 Report No.: 50-498/98-19;50-499/98-19 Licensee: STP Nuclear Operating Company .

Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: FM 521 - 8 miles west of Wadsworth Wadsworth; Texas Dates: January 25 through February 26,1999 Team Leader: C. J. Paulk, Senior Reactor Inspector j Engineering and Maintenance Branch ]

Inspectors: D. G, Acker, Resident inspector, Diablo Canyon Nuclear Power Plant C. A. Clark, Reactor Inspector, Engineering and Maintenance Branch P. A. Goldberg, Reactor inspector, Engineering and Maintenance Branch ,

Accompanied by: R. G. Quirk, Consultant, Beckman & Associates, In M. Shlyamberg, Consultant, NuEnergy, In Approved By: Dr. Dale A. Powers, Chief. Engineering and Maintenance Branch I

ATTACHMENT: SupplementalInformation l

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" I 9904020294 990326 '

PDR ADOCK 05000498 O PDR i

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EXECUTIVE SUMMARY -

South Texas Project Electric Generating Station, Units 1 and 2 NRC Inspection Report No. 50-498/98-19; 50-499/98-19 The purpose of this inspection was to evaluate the engineering performance at the South Texas Project. The system of focus was the residual heat removal system. The team performed a

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vertical slice review of the residual heat removal system and found that the system was capable of performing its design basis functions. While there were severalidentified examples of poor

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human performance, none were signif; cant, either individually or collectively. They were, however, overallindicative of declining performanc l Ooerations t

• From the human factors viewpo'nt, the origina! control room design, with respect to the

' main control board section for the residual heat removal system, provided the operators with information needed to effectively operate the system. Operators were proficient in operating the computerized qualified safety parameter display system (Section E2.3).

Enaineerina

= The performance, as related to the residual heat removal system, of the engineering organizations at the South Texas Project was sufficient to support safe plant operation (Section E1).

• The engineers had not performed a thorough comparison review of the Updated Final ;

Safety Analysis Report with the technical specification basis. This was demonstrated by the failure to include the use of the residual heat removal system pumps for core heat removalin the safety analysis report. This oversight was a concern because it could mislead personnel in the review of changes associated with 10 CFR 50.59," Changes,

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Tests and Experiments"(Section E2.1).

• . Design engineering failed to properly consider random and non-random uncertainties in the performance of residual heat removal system flow calculations, in general. This was not a significant concern for the steam generator tube rupture accident scenario (which was reviewed); however, improper consideration of both types of uncertainties could have a more significant effect on other instrument loops that were not reviewed -

- (Section E2.2).

= Instrumentation essential to residual heat removal system operation during normal and accident conditions was adequate (Section E2.3).

• The identification of a problem involving the possible loss of all three residual heat removal system trains demonstrated a good integrated system operational knowledge by the system engineer (Section E2.4). n ,

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• The response by licensee management to the team's identification of a potential for a

- beyond design basis accident involving the loss of low pressure safety injection flow was

appropriate given the assessed significance of the event (Section E2.5);

• - On the' basis of a brief review, the program to address the concerns associated with the effects on computer programs which could occur upon the change of date at the end of

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the year 1999 appeared to be adequate (Section E2.6).

x L*- The evaluation bf the effect of plant configuration changes with respect to satisfying the I

design basis was lacking in instances where modifications were performed on the

residual heat removal and component cooling water system pumps without consideration of the effects on system performance o' f the improved performance of the modified pumps (Section E2.7).

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• ~ - No problems were identified in the program for performing safety evaluations -

(Section E3.1).

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The procedures for preparing and verifying calculations were adequate (Section E3.2).

• Safety evaluations were performed in accordance with licensee procedures, and they' l met regulatory requirements. The quality of engineering input, in one instance involving I the lifting' of an essential cooling water gantry crane, was lacking, in that the weight information supplied to cupport the evaluation was incorrect (Section E4.1).

-*' The engineers' pursuit and resolution of potential bearing degradation in the component ,

cooling water pumps was not aggressive, in that it did not prevent repetitive problems

- with degraded bearing oil (Section E4.2).  ?

• The licensee's' training program for revswers of safety evaluations was effective, as supported by the lack of significant issues identified in the team's review of completed I I

safety evaluations (Section ES).

• A nonsignificant' error the team identified in a technical specification for the time l

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constants associated with the compensated steam line pressure-low allowable value -

setpoint indicated a lack of attention to detail by engineering and licensing personnel

.when preparing and reviewing the technical specifications (Section E7.1).

• ' In general, the reviewed calculations (approximately 30 electrical, instrumentation, and mechanical) were adequate; however, a number of minor errors and a lack of rigor to ensure quality were identified (Section E7.2).

• The failure to perform the required service tests for the Unit 2 Class 1E batteries,~ I

Trains B and D, in 1995 and 1997, was identified as a violation of Technical

Specification 4.8.2.1_d. The corrective actions taken, and proposed, in the event report

- adequately addressed the cause of this technical specification violation. This Severity

' Level IV violation is being treated as a Non Cited Violation, consistent with Appendix C 1of the NRC Enforcement Policy (Section E8.8).

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-4-Report Details 111. Engineering E1 Conduct of Engineering

' . Insoection Scooe (93809)

The purpose of this inspection was'to evaluate the engineering performance at the South Texas Project.1.The system of focus was the residual heat removal system. The team reviewed design basis documents, the safety analysis report, technical-

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specifications, system operating procedures, surveillance test procedures,' calculations, design change packages, condition records, safety evaluations, and engineering actions associated with previously identified issues (as discussed in the sections below). This review was performed in accordance with NRC Inspection Procedures 93809, " Safety System Engineering Inspection (SSEI)"; 37001,"10 CFR 50.59 Safety Evaluation Program"; and 92903, " Followup - Engineering." Observations and Findinas The team found that the overall performance of engineering personnel was adequat This finding was based, in part, on the good past performance, as demonstrated by the monitoring data from the Maintenance Rule Program, of the residual heat removal system and other safety-related cooling water system The team found some nonsupervisory engineers who did not exhibit a good questioning attitude, and some who did not have a good knowledge of system interactions. The

- team found that supervisory engineers were knowledgeable of the specific topics fo which they provided information lo the tea Conclusions On the basis of the observations and findings documented in the remainder of this report,-the performance, as related to the residual heat removal system, of the

- engineering organizations at the South Texas Project was sufficient to support safe plant operatio E2- Engineering Support of Facilities and Equipment

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. E Residual Heat Removal - Electrical and Instrumentation and Controls System Descriotion

< 'Insoection Scope (93809)

The team reviewed the electrical and instrumentation and controls aspects of the residual heat removal system to ensure the design would meet the functional requirements specified in the Updated Final Safety Analysis Report, technical

. specifications, and system design basis documents during normal, accident, and abnormal condition Pg

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ib.' Qhagreations and Fir n j

The team noted some inconsistencies between the technical specifications and Updated - )

Final Safety Analysis Report sections concoming the use of the residual heat removal )

system pumps. Technical Specification Bases 3/4.5.6," Residual Heat Removal _

l System," stated that the residual heat removal system ensured adequate heat removal for long term cooling by use of its pumps for a small break loss-of-coolant accident, an

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isolable loss-of-coolant accident,~ or a secondary system piping break in Modes 1,2, and 3.-

However, Section 5.4.7 of the Updated Final Safety Analysis Report, " Residual Heat

' Removal System," addressed only the normal shutdown cooling mode of the syste Neither Section 6.3, " Emergency Core Cooling System," nor Chapter 15 of the Updated -

Final Safety Analysis Report addressed the use of the residual heat removal system '

pumps for loss-of-coolant accident or secondary system failure The team was informed by a licensee representative that the use of the residual heat removal system pumps for accident conditions was addressed in the question and answer portion of the Final Safety Analysis Report, and was being incorporated into the text sections as part of an Updated Final Safety Analysis Report revision. Additionally, after acknowledging the team's finding, licensee personnel initiated Condition Record 99-01328 to address discrepancies contained in the design basis document related to the requirement for the use of the residual heat removal pumps to mitigate small break I loss-of-coolant-accidents with break sizes less than 3.81 cm [1.5 in). Conclusions

The engineers had not performed a thorough comparison revicw of the Updated Final {

Safety Analysis Report with the technical specification bases. The lack of a thorough 1 review was demonstrated by the failure to include the use of the residual heat removal system pumps for core heat removal in the safety analysis report. This oversight was a 1 concern because it could result in plant personnel reaching erroneous conclusions l regarding proposed changes associated with 10 CFR 50.59, " Changes, Tests and )

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Experiments."- 1 E Instrument Setooints j . Inspection Scooe (93809)

The team reviewed residual heat removal system-related setpoint information including the technical specifications, the Updated Final Safety Analysis Report, plant surveillance j procedures, and supporting calculations. Several documents reviewed were required by 1 Regulatory Guide 1.105, " Instrument Setpoints for Safety Related Systems," Revision l Other setpoint calculations reviewed were not required by Regulatory Guide 1.105, but were used for technical specification compliance or normal plant operatio l

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-6- Obse'rvations and Findinas ..

. The team noted that the licensee's engineers relied on WCAP-11273, " Westinghouse

- Setpoint Methodology For Protection Systems South Texas Projects Units 1 and 2,"

, February .1993, and WCAP-14262, " Bases Document for Westinghouse Setpoint Methodology For Protection Systems South Texas Projects Units 1 and 2," December 1994, for the establishment of reactor protection system and engineered safety feature setpoints and tolerances. The team verified that the safety injection setpoints from the '

WCAPs, the technical specifications, and surveillance test procedures were censistent,

' with the. exception addressed in Section E The team identified a minor inconsistency between the setpoints and the eccident analysis for a' steam generator tube rupture. The nominal %tpoint for the low

_ pressurizer pressure safety injection actuation was 12,803.6 kPa [1,857 psig). However, the accident analysis assumed 12,297.7 kPa (12,755.3 kPa nominal + 172.4 kPa uncertainty) [1,875 psig (1,850 psig nominal + 25 psi uncertainty)]. The licensee's

. accident analysis engineer stated the discrepancy between the assumed nominal setpoint and actual nominal setpoint was insignificant because injection would not begin until pressure dropped below the high head safety injection pump discharge pressure of approximately 11,721.1 kPa [1,700 psig]. A' licensee engineer stated that this deviation from the NRC-approved steam generator tube rupture analysis approach was not formally documented. The team found this lack of accident analysis documentation to be of minor conce Calculation ZC-7034, " Loop Uncertainty Calculation for RHR Pump Discharge Flow Monitoring Instrumentation," Revision 0, included an inconsistent use of sensor

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temperature effects for residual heat removal system flow Tran'smitters RH-FT-867,

-868, and -869 (Tobar Model 32DP1) under accident conditions. The licensee's engineers used a Westinghouse-determined environmental allowance value as a positive non-random (bias) vwfue, but failed to include the random temperature effect, which Westinghouse also used in WCAP.-11273. As a result, the instrumeat uncertainty associated with accident condition temperatures was a fraction of a ' percent less than what would be expected if both random and non-random (bias) values were used. A licensee representative initiated Condition Record 99-2066 to address this issue, which marginally affected'the use of this instrument loop for indication of inadequate pump flow during shutdown cooling operation and for post-accident monitoring flow indicatio ' Conclusions Design engineering failed to properly consider random cnd non-random biases in the

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, performance of residual heat removal system flow calculations. This was not a significant concern for the steam generator tube rupture accident scenario; however,

' improper consideration of both types of biases could have a more significant effect on certain instrument loop analyses that were not reviewed. With this exception, the engineenng staffs provided adequate support for maintaining instrument setpoint o w

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M E2.3, Plant Walkdowns

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The team completed walkdowns of the Unit 1 main control room, the auxiliary shutdown - <

panel, and electrical equipment rooms in the electrical auxiliary building. The primary

. purpose of the.walkdowns was to determine if the residual heat removal system controls

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and indications were adequat3 from a human-factors standpoin Observations ard Findinos -

The team observed that the residual heat removal system and interfacing systems', such as the component cooling water system and related power supply controls and indications in the main control room, were easily identified.- The team noted that

' controls and indicators were grouped by functional trains, and abnormal plant configurations were identified with nearby lights to comply with Regulatory Guide 1.47,

" Bypassed and inoperable Status indication for Nuclear Power Plant Safety Systems."

Post-accident instrument monitoring was provided on the Class 1 E qualified safety -

L parameter display system.L The team observed that the control room staff was capable of rapidly displaying requested plant parameter The team'noted there were few items in the areas inspected that had deficiency tags,-

and very few annunciators were illuminated on the main control board. The team

observed that the few illuminated status lights were associated with the train outage work week. The team found this to be a positive indication with respect to the maintenance of plant equipment and indicators for day-to-day operations, as well as for accident mitigatio .

The team noted that two of the three residual heat removal system heat exchanger temperature recorders had been replaced with Westronic Model 1600-series devices, but the third recorder, a Westinghouse Hagan recorder, had not. A licensee representative stated that all three were to be have been replaced with the Westronic recorders, b'ut the control room personnel and maintenance staff were not satisfied with the operation of the Westronic mode ' A licensee instrumentation and controls design engineer stated the design change

. package for the recorder replacement was generated at a time when no formal human-factors review process was in place. The team noted that Condition Record 38-57,

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while not specifically associated with the recorder replacement, did addre ,s the lack of

review of changes affecting the control room. The team observed that the corrective actions included re-institution of a team to perform such reviews, as well as procedural changes and training. In the_ case c the residual heat removal system recorder l replacement, the new human-factora evaluation addressed use of potential replacement

recorders in the' plant simulator. ' Based on feedback from the operations staff and application of human-factors rewews, the licensee had decided to replace all three residual heat removal system heat exchanger recorders with a different mode Jl

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- The team noted that some control room indicators had green, yellow, and red zones annotated to signify normal, marginal, and abnormal readings. An operator reported these color bands were initially established prior to the initial plant startup based on best .

estimate values. After startup, some zones were determined to be inadequat j Changes were initiated with a work order after being reviewed by several members of i

~ the operations staff. However, prior to development of the work request process, I changes were not reviewed under a formalized multi-discipline process, sueli as described in NUREG-0700, " Human-System Interface Design Review Guideline -

f Process and Guidelines: Final Report." Licensee personnelinitiated Condition Record 99-01349 to evaluate the' current program against NUREG-0700 criteria and determine if the zone coding should be included in the formal operator aid progra The team noted that the switchgear, battery charger, and battery rooms were clean with few dehelency tags hung. Train separation was aided by the use of different rooms for i each train. The team observed that there was adequate room between panels for j maintenanc ]

' The' team ' identified two deficiency tags on 125Vdc switchboard Cubicles 4B and 4C -

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which were over 18 months old. A licensee representative determined that the tags I were for missing or broken power cable connection barrier covers, but were not included

- in the automated condition reporting process. Therefore, these deficiencies were not being tracked for correction. A licensee representative initiated Condition Records 99-01305 and 99-01308 to repair the deficiencies. The licensee representative indicated the deficiencies would probably be completed during the up":oming Unit 1 refueling outag The licensee representative stated the previous material deficiency resolution process permitted only a select group of personnel to enter problems into the related computer database. Tags were manually generated and it was the responsibility of the supervisor

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to ensure deficiencios were entered into the computer. This process had been changed so that now individuals finding the discrepancies would enter the conditions into the 4 compute The residual heat removal system engineer stated that routine inspection of associated

. spaces was performed to identify long-standing, uncorrected conditions. Items such as inis should have been identified sooner. However, repair of these deficiencies was most likely missed because the repair required a board outage, and the board had not been de-energized since the tags were hung (after the last refueling outage).

The team found that the implementation of the revised process for identification of deficiencies requiring work did not assure that all relatively old deficiencies were included.

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r Conclusions The engineering staff provided adequate support for maintaining the main control boar From a human-factors view point, the original control room design, with respect to the

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main control board section for the. residual heat removal system, provided the operators -

with information needed to effectively operate the system. Operators were proficient in operating the computerized qualified safety parameter display system,

' E2.4 L Modifications /Temoorary Modifications - l

.j a Inanaction Scooe (93809) -

The team reviewed several design change packages (see Attachment) issued for the residual heat removal system and associated systems (e.g., essential cooling water), to determine if the selected design changes and modifications had been prepared and processed in an appropriate manner.' In addition to the documentation for the particular design change ~or modification being reviewed, other documentation contained, or referenced, in the design change' packages was reviewed. The team reviewed the safety evaluations included in nine of the reviewed design change package ' b.' ' Observations and Findinas in general,'the team found that the contents of the safety evaluations and design packages were of good quality and the design changes and modifications had been i adequately prepared and processe '

Dealloying of aluminum bronze piping components in the essential cooling water system, and the resulting occasional leaks, have resulted in several design change packages for both units at this facility On June 13,1998, a corrosion product buildup, indicative of dealloying, was discovered on the underside of the discharge flange for essential cooling water screen wash booster Pump 2C,~at the mechanical seal flushing '

tube fitting: This. example of dealloying of aluminum bronze material was noted during a special monthly essential cooling water system walkdown inspection performed by the licensee's quality control inspectors, and documented in Condition Record 98-1084 Design Change Package 98-10849-5 was issued to implement corrective actions for the

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The team reviewed the corrective actions implemented per Condition Record 98-10849 and Design Change. Package 98-10849-5 with the cognizant engineer and noted the

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• ~ The essential cooling water system piping was fabricated from aluminum bronze. Some of the plant's welds that utilized backing rings have shown a susceptibility to cracking. The potential effects of cracking in the above-gre ed and below-

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ground essential cooling water system piping have been evaluated with respect to the potential for cracking, flooding, spraying, and undetected failure. Based on the ability to detect cracking before a critical size is reached, the licensee's -

" engineers concluded that the essential cooling water system maintains the capability to mitigate the effects of an acciden ,

• Safety-related equipment sensitive to spray from the essential cooling water-system has been protected, and flooding is not a concer * Any known essential cooling water system leak has been treated as a temporary non-code condition in accordance with Generic Letter 90-05, ." Guidance for -

Performing Temporary Non-Code Repair of ASME Code Class 1,2, and 3 Piping." In the interim, the system's operability has been evaluated in accordance with analytical methods consistent with ASME Code,Section XI, and the location has been monitore * Dealloying of aluminum bronze piping components in the essential cooling water system was evaluated in Engineering Report 91-201-12, "ECW System Failures -

and Their Analysis," Revision 0, dated January 11,199 The team reviewed Engineering Report 91-201-12, and Appendix 9A of the South Texas Project Updated Final Safety Analysis Report. The team found the engineers' current method of addressing the dealloying of aluminum bronw piping components in the essential cooling water system to be reasonabl The team noted that Design Change Notice 9603614 corrected a beyond design basis problem which could have occurred during shutdown conditions. This identification occurred during the review of Design Change Package 95-12071-14,"SSPS Upgrade and Enhancement." The solid state' protection system technical support system engineer identified a problem where,-if the Train A inverter was out of service and power was lost to the Train B inverter (the alternate power supply to the related solid state

. protection system Tre i R), all three residual heat removal system pumps could be los The Train A and C pumps would be lost due to loss of power to the residual heat removal system low flow logic circuit actuation relays, and the Train B pump would trip due to loss of powe If the inverter was lost in Modes 1,2, or 3, the plant would enter a short term limiting

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condition for operation which, if not exited, would require the plant to be shutdown. This limiting condition for operation did not apply to the shutdown modes, but the engineer

realized the importance of maintaining the residual heat removal system pumps for shutdown cooling. The team noted that the engineer's resolution of the concem appropriately corrected the design flaw by providing a separate source of power for the Train C pump. The team found the engineer's performance to have been proactive and indicative of a good questioning attitude. Management made the necessary changes which reduced the risk of losing all three trains while in the shutdown cooling mod p, J

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-11 - Conclusions The design change packages for the reviewed design changes and modifications had

been prepared and processed in accordance with licensee and regulatory requirement No areas of concern were identifie '

The identification of the problem involving the possible loss of all three residual heat removal system trains demonstrated a good integrated system operational knowledge by the system' enginee E2.5 Residual Heat Removal System Heat Exchanaer Discharae Valve Operation a.- - Insoection Scooe (93809)

The team reviewed the ability of the residual heat removal system heat exchanger flow control Vaives RH-HCV-864, -865, and -866 to operate under normal and accident condition Observations and Findinas The team noted that the residual heat removal system heat exchanger flow control valves, which are included in the low head safety injection flow path, were normally open and failed open on loss of control air. The valves did not receive safety injection signals to ensure they were properly positioned when the low pressure safety injection pumps starte ~

Flow Control Valves RH-HCV-864, -865, and -866 were ASME Section Ill, Class 2 Seismic Category 1, Fisher 8-in, Type 7613,300 psi, butterfly valves with pneumatic operators. The related solenoid-operated Valves RH-FY-3860A, -3861 A, and -3862A were environmentally-qualified Class 1 E devices, but the flow control valves had non-safety grade pneumatic positioners. The solenoid-operated valves vent the flow control valve pneumatic operators to the containment atmosphere resulting in the flow control valves fully opening. The team observed that the solenoids were normally energized dJring plant operation, thus keeping the flow control valves closed. A failure of the non-safety grade positioners could cause the residual heat removal system heat exchanger

. flow control valves to close and inhibit all three trains of low pressure safety injection flow.-

- Licensee engineers stated that the air supply to the valves would be isolated by a containment isolation signal, and valve spring pressure would shut the valves if there L was a " smart" failure that resulted in the positioners failing in an unsafe directio < However, the licensee's engineers did not have any analysis to show how fast the air header inside containment would bleed down, thus permitting the valves to reposition to their safe open condition. The team found that, without such analysis, the licensee was not able to demonstrate that the assumptions in the accident analysis would be met and that adequate' flow would be established. The licensee's engineers also stated they did not recall a modification to the solid state protection system that would have removed a

• safety injection signal from the solenoid valve .

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The following is presented in order to permit a better understanding of the scenario for

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loss of low pressure' safety injection flo I There must first be an accident that would result in a safety 1

injection signal and require low pressure safety injection flo Then, there must be a single failure of one train of the low

. pressure safety injection system. The solenoid-operated valves for the residual heat removal system heat exchanger bypass flow -  !

properly position (even though they utilize the same type of

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nonsafety-related positioners as the residual heat removal system .

' heat exchanger outlet valves). And, finally, the two positioners for the _ residual heat removal system heat exchanger outlet valves must fail in a manner that would keep the valves close The team found this scenario to be beyond design basis because it involved more than the single-failure of a safety-related component, and the failures of the nonsafety-related 4 components was not the result of a comm'on-mode problem. The team also considered the scenario to have a low probability of occurrence. However, the consequences of such a scenario could be significant. Therefore, the team pursued this issue bece .se of 4 the potentially involved ris As a result of the team's questions, licensee personnel initiated Condition

- Record 99-02042 to address this issue. The team was informed on February 16,1999, that licensee management h'ad determined that, while the scenario for failure was of -

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l very low probability, modification of the control of the flow control valves in Modes 1,2, and 3 was prudent. As such, the power was removed from the solenoid-operated valves causing the flow control valves to remain in their intended safety position. The team was also informed that additional review would be performed to determine if further j_

modification would be warrante The team found the response by the engineers and licensee management to have been

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- indicative of an organization intent on ensuring that the plant remained in a safe condition while an assessment of the plant configuration was performed. This was based on the fact that licensee management directed that the power for the residual heat removal system heat exchanger outlet and bypass valves be removed, causing the valves to be in the position required for accident mitigation. The team also found that the configuration of the controls for the residual heat removal system heat exchanger

.' outlet and bypass flow control valves was in accordance with the original plant desig During team discussions with system and design engineers, the team observed that some engineers did not exhibit a strong understanding of system interrelations, a strong

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questioning attitude, or a strong ' understanding of the design basis. The team noted j that engineers relied heavily on the original plant design, especially the unique three- I train configuration, without giving thorough consideration to the maintenance of the

design basis.' The team noted that engineering supervisors were the persons who  !

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eventually provided the information to addiess the_ questions raised by the team. The

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. team was informed by_a licensee management representative that the plant's cooling

~ water systems _ perform well and that the engineers may have not had to review the

'. design basis for a significant amount of time; therefore, this lack of involvement may have been responsible for the perceived performanc '

, Conclusions ,

The response by licensee management to the team's identification of a potentiini for a; beyond design basis accident involving the loss of low pressure safety injection flow was

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appropriate given the assessed significance of the event.-

The nonsupervisory engineers' understanding of the plant's cooling water system -

interrelations and design bases was lackin ' E2.6 L Readiness of Computer Systems a. = Insoection Scooe (9380M The team reviewed the status of the licensee's preparations to address the potential .

computer problems associated with the year 2000.'

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' Observations and Findinos The team noted that the licensee had an active site-wide program associated with

- Generic Letter 98-01," Year 2000 Readiness of Computer Systems at Nuclear Power Plants." The program is described in the " Year 2000 Readiness Program Plan," dated November 23,1998. The team observed that the program organization began in October 1997, and engineering reviews started January 1998 with an initial inventory of potentially susceptible computer systems and components. The licensee projected that computer readiness for the year 2000 will be achieved by July 1,199 The licensee's staff stated that they maintained close communicatl . with other uti!ities and vendors regarding potential computer issues. Licensee enginima evaluated potentially impacted systems, including those that vendors had certified as being able to

transition at the change of the year. The team noted that the licensee's engineers had performed some testing on the qualified safety parameter display system. The testing was completed satisfactorily during the Unit 2 refueling outage in October 199 Most problems identified by the engineers to date were minor and could be resolved by

' simple." work-around" tasks. ' The team found the licensee's management was proactive, as demonstrated by the planning to upgrade chips in some devices such as Westronic recorders to reduce the number of work-around tasks. The System Engineering

- Department Manager, who was also the Year 2000 Embedded System Area Director, stated that the most significant problem to date under his cognizance was chemistry data management. Hardware and software changes were being implemented to resolve this issu ,

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' On the ba s of a brief review, the licensee appeared to have an adequate program to address the concems associated with the effects on computer programs which could occur upon the change of date at the end of the year 199 E2.7.; Translation'of the Desian Basis into the Plant Ooeratina. Surveillance. and Maintenance Procedures

, . Insoection Scope (9380G1 The ' team reviewed the inservice test procedures and calculations for the residual heat removal, component cooling water, essential cooling water, auxiliary feedwater, low .

head safety injection, and high head _ safety injection systems. This review compared

, the required action acceptance criteria (high and low) limits with the certified pump curve ' Observations and Findinos The team noted that the low action limit acceptance criteria for the low and high pressure safety injection pumps were conservative with respec6 to the technical specification limits. The team found that the low limit was conservative with respect to design basi The team noted that both the low and high action limit acceptance criteria for the j auxiliary feedwater pumps were very close to the pump certified curve values. The team found that both limits were acceptable with respect to the design basis.-

The team asked the licensee's engineers if the low and high action limit acceptance critsria for the component cooling water, essential cooling water, and residual heat j removal pumps were bounded by design basis analyses. The discussions with the l I

licensee's engineers revealed that the action required limit acceptance criteria for these pumps were based only on the ASME OM6 limits (*10 percent) and did not reflect that

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the allowable pump degradation used in the design basis calculations, which was typically approximately -4 percent,~ +0 percen ' The licensee's engineers stated that additional controls in translation of the minimum and maximum design required flows were provided by the normal plant operating procedures. The licensee's engineers illustrated this linkage by showing the minimum and maximum flow table for the component cooling water system operating procedur The team's limited review did not identify any specific cases where the actual pump conditions were outside of the values used in the design calculations. Nevertheless, the ;

team was concerned with the lack of design control to preclude a condition where pump degradation could lead to a pump performance below the values used in design and

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licensing bases. Similarly, maintenance activities, such as like-for-like replacement,

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could result in conditions where a pump's performance could be in excess of the analyzed va!aes. Although the minimum system performance could benefit from this,

' the effect on the net positive suction head available, maximum system pressure, etc.,-

. could be negative (e.g., the pump could be oversized for the design). )

t The team noticed that Procedure OPOP03-ZG-0009,,"Mid-Loop Operations,"

Revision 10, contained a graph of residual heat removal system heat exchanger flow versus water level in the reactor coolant system piping during mid-loop operation. This I raised the question as to the use of the curve and its validity. During the review of Calculation MC 6138, " Residual Heat Removal Pump at Midloop in the Event of a Loss of Offsite Power," Revision 0, the team observed that the calculation was prepared to address the ability of the residual heat removal system to function in mid-loop operation with a failure'of the flow controller for the residual heat removal system heat exchanger outlet valve. The failure of the flow controller could result in a flow of as high as 14,006 Lpm [3,700 gpm]. The team noted that the caiculation concluded that the residual heat removal system was capable of performing its intended function under such circumstances. The team's review of Calculation MC 6138 identified the following concern *- The team noted that the results of this calculation predicted available net positive suction head to be 6.37 m [20.91 ft) at 12,681.1 Lpm [3,350 gpm] for fluid at 100*C [212'F]. This value was substantially higher than the value calculated in -

Calculation PCC-N4SD-TGX-48, which, according to the residual heat removal design basis document, is the design calculation of record for the residual heat removal system available net positive suction head. The available net positive suction head established in Calculation PDC-N4SD-TGX-48 was 4.34 m

[14.24 ft) at 12,870.4 Lpm (3,400 gpm] for fluid at 65.6*C [150*F]. The team identified that the differences were the result of licensee engineers using nonconservative assumptions for pipe diameters and lengths in Calculation MC 6138. When values more representative of the actual plant configuration were used by the engineers, the team noted an acceptable correlation to the calculation of recor * The team also noted that this calculation established the required level of water in the pipe for given flows by extrapolating data beyond the 11,356.2 Lpm [3,000

- gpm] provided in the reference document (WCAP-11916, " Loss of RHRS Cooling While the RCS is Partially Filled"). The team did not identify any information on either the technique used by the engineers for this extrapolation or the acceptability of the extrapolation (i.e., will the empirical relationship established in WCAP-11916 hold true beyond 11,356.2 Lpm [3,000 gpm]).

= The team found that the licensee could not identify what was the technique used for the extrapolation. The team determined that the licensee, in an attempt to justify the curve in the calculation, performed a curve fit using a parabolic

• j

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l-16-equation in the form of y = a + bx +cx2 , where: y represented reactor coolant system level relative to the reactor coolant system pipe centerline, and x j represented residual heat removal system intake flow in gpm. This curve fit generated y values lower than those plotted on the curve, thus numerically the plot appeared to be conservativ * On the issue of the acceptability of the extrapolation, the team was informed that !

the engineers were not aware of any restrictions. At a later time, however, they informed the team that there were limitations imposed in WCAP-11916 on the extrapolation. The engineers stated that the extrapolated flow of 14,006 Lpm

[3700 gpm) (and extrapolated level of 7.62 cm [3 in) above pipe centerline)

corresponded to a Froude Number of 2.8. Therefore, the extrapolation was consistent with the limits of test results which formed the basis of Figurs 2-14 in WCAP-1191 I

• The licensee's engineers also informed the team that Procedure OPOP03-ZG-0009 was being revised. The team learned that the revision will annotate on the graph, provided as an operator aid, an area of prohibited operation in excess of 11,356.2 Lpm [3,000 gpm]. The team noted that such prohibition had been included in the body of the operating procedure since 1996, when a safety evaluation associated with Procedure OPOP03-ZG-0009 concluded that operation above 11,356.2 Lpm [3000 gpm) was unacceptable. The team found that the failure to revise the graph of flow versus level to be indicative of poor attention to detail on the part of engineering personne ]

During the initial discussions with the licensee's engineers, the team noted that the ;

engineers did not exhibit a good understanding of why there was a need to have formal i tools to translate changes in the configuration of the plant into the design changes. The team ild not identify any such controls in the existing procedures at the South Texas '

Project. In particular, residual heat removal and component cooling water pumps have been reworked, and a new base line was established. However, the licensee's )

engineers did not provide empirical data to demonstrate that the effect of this rework l resulted in the pump performance being bounded by the design basi I c. Conclusions The evaluation of the effect of plant configuration changes with respect to satisfying the design basis was lacking in two instances where modifications were performed on the residual ht removal and component cooling water system pumps without i considew. ,n of the effsets on system performance as a result of the improved I performance of the modified pump l

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-17-E3 Engineering Procedures and Documentation

. E Safety Evaluations Insoection ScoDe (37001)

The team reviewod Procedure OPGP05-ZA-0002,"10 CFR 50.59 Evaluations,"

Revision 9, which governed the process for conducting safety evaluation ObservationpJad Findinos The team noted that Procedure OPGP05-ZA-0002 did not apply to technical specification changes, emergency plan changes, security plan changes, or changes that were governed by 10 CFR 50.55a," Codes and Standards," and the ASME Code The team noted that the preparer of a safety evaluation was not required to take qualification training. However, every screening and safety evaluation required a review by a qualified reviewer. The procedure defined a qualified reviewer as an individual whc comp!eted the licensee's training course for safety evaluations, or was in current possession of a senior reactor operator license, . Conclusions No problems were identified in the program for performing safety evaluation E3.2 Calculation Preparation and Verification Insoection Scope (93809)

The team reviewed Procedures OPGPO4-ZA 0307," Preparation of Calculations,"

Revision 1, and OPDP01-ZE-0001, " Design Verification Process," Revision 1, for completeness and consistency with regu!atory requirement Observations and Findinos The team found that the procedures were concise and generally consistent with regulatory requirements and practices. The team noted the following instances in which procedural guidance was weak: Procedure OPGPO4-ZA-0307, Section 3.4.2, requires personnel to update the calculations if revisions to referenced materialimpacted the calculations. This implicitly requires personnel to verify information obtained from all calculational references. Additionally, Procedure OPGP04-ZA-0307 does not require personnel to verify design input information included in a calculation as an attachment but not listed as a referenc i

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' . The procedures did not clearly address management expectations for the level

of calculational review and approval when calculations were revised. A licensee

, engineering manager stated that, when calculations were revised to incorporate accumulated small changes previously issued as design changes, the expectations were that the preparer and verifier should be generally

- knowledgeable about the calculation. However, as detailed in the procedure, the preparer and reviewer were primarily responsible for ensuring the changes in the change documents were properly incorporated. The manager stated that credit

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was taken for the engineering reviews completed when the design change ~

package was prepared and verifie .

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l Procedure OPGPO4-ZA-0307, Section 3.2, " Calculation Review and Approval,"

Subsection 3.2.2, stated the verifier "SHALL develop a comprehensive .

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s understanding of the calculation methodology and content and be able to -

respond to any questions about the calculation." However, the' procedure defers )

to Procedure OPDP01-ZE-0001 for conducting the verification. Implicit in the procedure is expectation that the verifier should check all information in the calculation and not pedorm just a high level review; however, this expectation is

- not clearly state . . Procedure OPDP01-ZE-0001 permits significant latitude in the depth of the varification effort. Procedure OPDP01 ZE-0001, Section 5.5, requires the design verifier to clearly document the verification method used, what was reviewed, -

and the results of the review. This is normally accomplished through the use of Form-1 of the procedure. In the case of the recent Revision 11 to -

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Procedure EC-5008, " Class 1E Battery, Battery Charger and inverter Sizing,"

Form-1 was not used, and the calculation cover sheet stated for verification

' method:'" Review of the open amendments against the calculation."

. Conclusions L The procedures for preparing and verifying calculations were adequate; however, some

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guidance pertaining to the review and verification of calculations lacked specificit E4 : Engineering Staff Knowledge and Performance E4.1 ' Safetv Evaluations Insoection Scope (93809 and 37001)

The team selected safety evaluations for review (see Attachment) from the licensee's

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December 10,1998, transmittal to the NRC, which was submitted pursuant to the requirements of 10 CFR 50.59. The team reviewed Procedure OPGP05-ZA-0002,

"10 CFR 50.59 Evaluations," Revision 9, which governed the process for conducting safety evaluations. The team also interviewed licensee personnel from both system and design engineering organization i r '-

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Observations and Findinas The team reviewed Unreviewed Safety Question Evaluation 97-0023, Revisions 0 & 1, which contained the evaluation for the one time deviation for lifting the essential cooling water gantry crane and removing it from the emergency cooling water intake structur The team noted that licensee engineers determined that Revision 0 of the unreviewed safety question evaluation did not incorporate accurate de:a since tne crane weight was >

assumed to be less than the actual weight of the cran )

The licensee's engineers did not know that the weight estimate in the safety evaluation was too low until an attempt was made to lift the crane. The lift was terminated when ;

l the mobile lift crane's load cell indicated that the load had reached the administrative limit established near the safe operating limit of the mobile lift crane for the operating radius and boom length. Licensee maintenance personnel had removed the seismic track restraints prior to the attempt to lift the crane, and this removal put the crane into ,

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an unanalyzed condition for approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> while the crane was moved into its parked position and tied dow The team noted that Unreviewed Safety Question Evaluation 97-0023, Revision 1, included load drops using a conservative weight for the crane. in addition, calculations were revised to include the conservative crane weight. Boom failures of the 77.1-t (85-ton],453.6-t (500-ton], and 589.7-t (650-ton] cranes were also addressed in the revised analysis. The licensee's engineers concluded that the essential cooling water piping would remain operable during the crane removal and any postulated load drops that could occur. The next attempt to remove the crane was successfu . Cpnclusions Safety evaluations were performed in accordance with licensee procedures, and they met regulatory requirements. The quality of engineering input, in one instance involving ;

the lifting of an essential cooling water gantry crane, was lacking, in that the weight information supplied to support the evaluation was incorrec E4.2 Condition Records a. - Insoaction Scope The team reviewed Procedure OPGP03-ZX-0002," Condition Reporting Process,"

Revision 17. In addition, the team reviewed condition records associated with the residual heat removal system and the component cooling water system (see Attachment). The team discussed the condition record process and some of the condition records with appropriate licensee personne ,

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b. ~ ~ Observations and Findinas By reviewing and discussing the condition record procedure with appropriate licensee -

personnel, the team determined that the condition record process provided a single process for documenting evaluations and resolving problems, concerns, activities, and '

, conditions that could adversely affect, or have tha potential to adversely affect, the safe operation of the plant.-

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The team noted, during'the review of Condition Record 98-3449, dated February 27, t 1998, that the licensee determined there was a need to change the oil in the component cooling water pump bearings since the oil appeared to be " broken down" and was black in color. The team observed that the vendor's manual contained a recommendation that the oil be replaced on a 3-month frequency. The team noted, however, that th . licensee's engineers had established a frequency of every 78 week ~

The team noted that,'in 1997, the pump bearing oil was analyzed and found to have a j

very high iron content. _ When the oil was changed in 1997, the oil also appeared to be j

" broken down." The team noted that the bearing oil was " broken down" the last two '

times the oil had been sample , During the review of the maintenance history of the six component cooling water pumps j for the last 5 years, the team identified numerous instances when the bearing oil of {

' Pump 3R201NPA101 A was changed due to problems _with the oil. For example, in April

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1996,' metal shavings were found in the in-board bearing housing and the out-board

- bearing housing oil was discolored. In October 1996, grey sediment was found in the oil. In June 1997, the' oil looked dirty and black. In December 1997, the outer bearing

housing oil showed signs of slinger ring wear material. In May 1998, dirty oil was found

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in the bearing housing. After each of these discoveries, the bearing oil was drained and

~ replace In May 1998, licensee maintenance personnel disassernbled the bearings of the pump and found sediment in the lower portions. The licensee maintenance personnel cleaned ,

_ the bearings to remove the sediment, reassembled the bearings, and filled them with j new oil. The licensee's engineers determined that this residue was the cause of the I many instances where the oil was observed to be " broken down." Since the bearing l cleaning, the oilin the bearings has been clea The team found that the licensee's engineers were not aggressive in addressing the potentially significant issue of bearing wear (and possible pump failure) in the ,

component cooling water pump )

l Conclusions The engineers' pursuit and resolution of potential bearing degradation in the component cooling water pumps was not aggressive, in that it did not prevent repetitive problems with degraded bearing oi .

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ES- Engineering Staff Training and Qualification i Inspection Scope (93809 and 37001)

The team reviewed training outlincs and material for the initial and recertification programs for personnel responsible for the preparation and approval of safety evaluations in accordance with the requirements of 10 CFR 50.59. This review utilized the guidance of NRC Inspection Procedure 37001," Safety Evaluations." - Observations and Findinas The team determined that the licensee had no requirement for recertification training of personnel who reviewed safety evaluations. In addition, the team noted that preparers of safety evaluations were not required to be certifie In 1990, licensee management required mandatory refresher training for all of the certified reviewers. Any certified reviewer who did not successfully complete the training lost certification for the performance of safety evaluation reviews. After the refresher training, a licensee representative stated that the number of certified reviewers was 399

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employees. The team noted that 61 persons had lost their certification. Approximately 200 of the 399 certified employees were in the engineering organization. In addition, the licensee representative stated that, in the engineering organization, approximately 80 percent of the preparers were also certified reviewers. The licensee representativo stated that every 2 years the need for additional recertification training would be evaluate c. ' Conclusions The licensee's training program for reviewers of safety evaluations was effective, as supported by the lack of significant issues identified in the team's review of completed safety evaluation E7 Quality Assurance in Engineering Activities E Technical Specification Adeauacy Inspection Scoco (93809)

The team reviewed the sections of the technical specifications associated with the residual heat removal system to ensure they were consistent with setpoint calculation Observations and Findinas The team noted in Technical Specification Table 3.3-4," Engineered Safety Features Actuation System Instrumentation Trip Setpoints," that entries for safety injection and steam line isolation initiation setpoints used a notation on the " Compensated Steam Line Pressure-Low" allowable value setpoint of 2709 psig that could not be met. Specifically,

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-22 the notation called for the steam line pressure low lead-lag controller setpoints of "t, 250 -

seconds and t, s 5 seconds." The team determined that the table entry should have been % 250 seconds and ta s 5 seconds." A licensee representative initiated Condition Record 99-01710 and Technical Specification Change 242 to correct this erro j

Conclustons LAn error the team identified in a technical specification was not significant from an ,

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engineering standpoint, but was indicative of a lack of attention to detail by engineering and licensing personnel when preparing and reviewing the technical specification .

E7.2 : ' Quality of Calculations

. insoection Scope (93809)

The team reviewed the calculations listed in'the Attachment to this repor Observations and Findinos The team found that the calculations, in general, were adequate. The team identified numerous minor problems in recent revisions to old calculations. Examples of the problems encountered varied from the very simple (e.g., not correcting page references when the calculation was reformatted and pages were renumbered) to the more complex (e.g., the use of incorrect room tamperature when calculating instrument

- uncertaint:ss associated with the effect of temperature, the failure to account for all

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potential electrical loads on Class 1E battery sizing calculations, and the use of.non-conservative values for starting currents).

The team noted that many old calculations (from the initial design development stage)

used data from informal communications (e.g., telephone conversations). The team identified that there was no formal vendor approval of data on the telephone -

conversation sheets. The team selected several items and requested the licensee's engineers to provide _ data verification using more current information such as controlled vendor manuals. The licensee's engineers were able to verify most values; no cases were found where the information in the telephone conversation sheets was wron However, the' team found that the use of informal telephone conversation sheets in recently revised calculations, when controlled data was available, was indicative of a less than rigorous assurance of quality.'

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c.- Conclusions In general, the revie'wed calculations (approximately 30 electrical, instrumentation, and rnechanical) were adequate; however, a number of minor errors and a lack'of rigor to ensure quality were identifie x w

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E8 Miscellaneous Engineering issues

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E oed) Unresolved item 50-498: 499/9716-01: Errors in instrument uncertaint csGculation Inspecten Scope (92902)

. In 1997, NRC inspectors identified a number of errors and omissions in setpoint uncertainty calculations. During the 1997 inspection, licensee engineers performed preliminary calculations which indicated that the associated instruments * loops were still operable and that existing setpoints were adequate to support the technical specifications and related design base During this inspection, the team reviewed the completed calculational changes and supporting documentatio ' Observations and Findinas

' Volume Control' Tank Level

To ensure that suction to the charging pumps was not lost, upon loss of inventory in the volume control tank, there is an alarm and automatic swap-over of the supply to the charging pumps from the volume control tank to the refueling water storage tank. This swap-over occurs when reaching 3 percent level in the volume control te.nk. This swap-over protects the charging pumps against loss of net positive suction hea In 1997, NRC inspectors observed errors in the setpoint uncertainty calculation that was used to support the assumption that the swap-over at 3 percent level would occur before

the tank was empty. . These errors indicated that instrument uncertainty was greater

.than'the assumed 3 percent, which would not ensure that the alarm and swap-over would occur with sufficient time to maintain the net positive suction head and prevent pump cavitation. During the 1997 inspection, licensee engineers provided a preliminary

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calculation that supported the 3 percent swap-ove The team reviewed the new Calculation ZC-7025, " Loop Uncertainty Calculation for VCT Level Monitoring instrumentation," Revision 0, and observed that the licensee's engineers determined that the instrument uncertainty was 2.2 percent. The team observed that the calculation was in accordance with the licensee's and the instrument Society of America's standards, except for uncertainty associated with instrument tap locations.' The team found that the licensee's engineers had correctly included construction uncertainties (tap locations) in the calculation. However, the licensee's engineers had treated this uncertainty as a random uncertainty which the team did not )

consider to be in accordance with the licensee's and the Instrument Society of America's

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standard . .,. '

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24-Random uncertainties are those uncertainties which can' vary with time. Process -

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uncertainties, which do not change, such as instrument and tap locations, are usually -

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, ; treated in calculations as biases, which are calculated differently in uncertainty

calculations. The team considered the treatment of the tap location as a random

- uncertainty.was incorrect and not conservative. The licensee's engineers agreed and issued Condition Record 99-1339 to address the deficiency in the calculatio ' The licensee's engineers determined that ths 3 percent setpoint was adequate. Based

. on a review of the licensee's revised calculation, the team found the evaluation to be '

acceptable.~

Refuelina Water Storaos Tank Usable Volume and Level Instrument Setooints L-In 1997, NRC inspectors determined that the refueling water storage' tank level setpoint calculation was invalid. The licensee's engineers performed preliminary calculations that supported a number of setpoints associated with refueling water storage tank level and volume requirement The team reviewed the new refueling water storage tank level setpoint Calculation ZC-7024, " Loop Uncertainty Calculation for RWST Level Monitoring instrumentation," Revision 0, and determined that the licensee's engineers had supported the existing setpoints. The teem determined that the licensee's engineers had actual measurements for tap locations for Unit 2, but not Unit 1. The licensee's engineers assumed that the worst case Unit 2 locations bounded Unit 1. The team

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considered this assumption invalid. The licensee's representative acknowledged the team's comments and provided a calculation that indicated that the existing setpoints were still acceptable, even with the use of additional uncertainty for Unit 1 tap location The team considered the calculation, with the additional uncertainty, to be acceptable to demonstrate adequate setpoints related to refueling water storage tank level and

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required volume Auxiliarv Feed Water Storaae Tank Usable Volume and Level Instrument Setooints in 1997, NRC inspectors identified errors in instrument uncertainty which reduced the design volume to a margin'of 19,927 L [5000 gallons]. The inspectors also observed that the licensee's engineers may not have conservatively tr-deled the flow, with regard to vortexing, from the auxiliary feedwater storage tan '

, 1Th( modeling of the tank with respect to vortexing was reviewed and closed in

' Inspection Report 50-498; -499/9810. That report concluded that the analysis was adequat {4 During the current inspection, the team reviewed the auxiliary feedwater storage tank level uncertainty Calculation ZC-7023, " Loop Uncertainty Calculation for AFWST Level i Monitoring instrumentation," Revision 0, and considered it to be acceptable to

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demonstrate r.dequate setpoints related to auxiliary feedwater storage tank level and required volume '

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Degraded Grid Voltage Relav Setooint

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L in 1997, NRC inspectors identified that the licensee's calculation to determine the

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fdegraded grid voltage relay setpoint may be inadequate because it did not include any .

uncertainty for calibration accuracy, nor did it follow any setpoint guidelines. The'

licensee's engineers performed a preliminary calculation that demonstrated that the :

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setpoint was adequate. '

L During this inspecten, the team reviewed Calculation EC-5098, " Degraded and -

Undervoltage Protection instrument Uncertainties," Revision O. The team found it to be adequate to support the existing setpoint."

. c.- Conclusions

, The team concluded that the licensee had ' demonstrated that the errors observed during a 1997 NRC inspection did 'not result in any setpoints being outside the design analysi ' Therefore, no violation of regulatory requirements had occurred. The licensee's

engineers had made improvements in the area of instrument uncertainties used in j caiculation >

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E8.2 - (Closed) Volation 50-498/03014: Failure to translate measuring and test equipment calculation accuracy assumptions into calibration procedures. The team verified the

- corrective actions described in the licensee's response letter, dated January 21,' 1998, to

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be reasonable and complete. No similar problems were identifie q

= E8.3 ~ (Closed) Violation 50-498/04014: Excessive amendments led to calculations with

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erroneous information. The team verified the corrective actions described in the o

, licensee's response letter, dated January 21,1998, to be reasonable and complete. No *

Tsimilar problems were identifie m ,

E (Closed) Violation 50-498/05014

Lack of procedural requirements to evaluate the effect of changes in calculations on other documents, specifically the Final Safety

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,, Analysis Report. The team verified the corrective actions described in the licensee's .

response letter, dated January 21,1998, to be reasonable and complete. No similar

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. problems were identifie :

c E8.5 - (Closed) Violation 50-498/01014: Failure to promptly identify and correct setpoint errors in calculations.;The team verified the corrective actions described in the licensee's response letter, dated January 21,1998, to be reasonable and complete. No similar problems were identifie E8.6 - (Closed) Violation 50-498/02014: Failure to void a calculation related to instrument uncertainty where two calculations indicated different results for the same paramete '

.-The team verified the corrective actions described in the licensee's response letter, dated January 21,1998, to be reasonable and complete. ' No similar problems were i'

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- E8.7: (Closed) Licensee Event Report 50-499/97-001: Five Unit 2 main steam safety valve

' setpoints above required toleranc Closed) Licensee Event Reoort 50-498:499/97-005:..Two Unit 1 and two Unit 2 main steam safety. valve setpoints found above required toleranc (Closed) Licensee Event Report 50-498:499/97-009: Unit 1 and 2 main steam safety :

valve as-found setpoints out of tolerance hig = (Closed) Unresolved item 50-498/9805-01:. Two Unit 1 main steam eafety valve

'setpoints above required toleranc 'The issue of the as-found setpoints of main steam safety valves being out-of-tolerance high is an industry issue that is being reviewed by the Main Steam Safety Valve Owners Group.- While the engineers at the South Texas Project took actions to address this-problem, they realized, from industr, experience, that this was not a plant-specific -

concern. As such, the engineers and management at the South Texas Project were instrumental in the formation of the industry owners' grou The team noted that the licensee had determined that the out-of-tolerance conditions were bounded by the design bases and were not representative of unanalyzed condition Each of tl.ese previously identified issues is being closed, pending resolution of the as-found out-of-tolerance setpoints by the owners' group and subsequent NRC revie This issue will be tracked by the NRC as a single inspection followup item for each unit

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(50-498;-499/9819-01).

'E (Closed) Licensee Event Report 50-499/99-001: Failure to fully meet the requirements of Technical Specification Surveillance 4.8.2.1d for batterie On J9nuary.12,1999, licensee personnel identified a failure to implement the technical .

specification surveillance of the Unit 2 Trains B and D Class 1E batteries. The licensee

- reported that Surveillance 4.8.2.1d (a service test) was not performed because " credit was erroneously taken for the service test in accordance with the surveillance

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procedure."

The team identified that the surveillance test program engineers had incorrectly interpreted Surveillance 4.8.2.10, which states that credit for the service test required by Surveillance 4.8.2.1d could be taken once every 60 months by the completion of the performance test specified in Surveillance 4.8.2.1e. The surveillance test program engineers stated that they believed that the performance test (Surveillance 4.8.2.1e)

could be credited for the service test (Surveillance 4.8.2.1d) at any time.

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-27-Tlie team identified that, in reality, both a service test and a performance test were required to have been performed every 18 months since 1995 for the Unit 2 l Trains B and D Class 1E batteriesJ The team noted that Surveillance 4.8.2.1f required a performance test every 18 months once the battery reached 85 percent of its service life. (This test was to be in addition to the service test required by 1 Surveillance 4.8. 2.1d.) The team determined that the Unit 2 Trains B and D Class 1E

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batteries had been placed in service in 1979 and had a_20-year service life. The batteries, therefore, reached 85 percent of their service life in 1995,17' years after being

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The Unit 2 Trains B and D Class 1 E batteries were replaced in October 199 '

Therefore, there is no safety concern at this time.-

The team identified the failure to perform the required service tests, in 1995 and 1997, as a. violation of Technical Specification 4.8.2.1d (50-499/9819-02). The team found the corrective' actions taken, and proposed, in the event report to adequately address the

cause of this technical specification violation. This Severity Level IV violation is being -

treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Licensee Event

- Report 50-499/99-00 V. Menacement Meetinos X1 Exit Meeting Summary The team leader presented the inspection results to members of licensee management on March 17,1999. .The licensee representatives acknowledged the findings presente The team leader asked the licensee representatives whether any materials exam!ned during the-inspection should be considered proprietary. The licensee representatives stated that scme material was considered proprietary. All proprietary information was returned to their possession. No proprietary information was included in this repor .

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, ATTACHMENT-SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED

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- Licensee-T. Cloninger, Vice-President, Nuclear Engineering and Technical Support J. Cook, Nuclear Steam Supply System Section Supervisor, Systems Engineering J. Cottam, Engineering Supervisor, Design Engineering

~ J. Johnson, Manager, Engineering Qualit T. Jordan, Manager, Systems Engineering W. Mookhoek, Licensing Engineer

-, S. Thomas, Manager, Design Engineering -

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G. Guerra, Resident inspector C. O'Keefe,' Senior Resident inspector

-- W. Sifre, Resident inspector INSPECTION PROCEDURES USED -

- IP 37001 - 10 CFR 50.59 Safety Evaluation Program IP 92903 - Followup - Engineering

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lP 93809'- Safety System Engineering inspection (SSEI)

ITEMS OPENED AND CLOSED Opened

' 50-498/9819-01- IFl main steam safety valve setpoints outside of allowable tolerances (Section E8.7) '

~ 50-499/9819-01 IFl main steam safety valve setpoints outside of allowable tolerances (Section E8.7) -

,. 50-499/9819-02- NCV failure to perform Technical Specification required tests on the Unit 2 Trains B and D Class 1E batteries (Section E8.8) '

Closed 50-499/97-001 . LER five Unit 2 main steam safety valve setpoints above required '

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tolerance (Section E8.7)-

50-498/97-005 LERL two Unit 1 and two Unit 2 main steam safety valve setpoints found above required tolerance (Section E8.7)

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• /97-005 LER two Unit 1 and two Unit 2 main steam safety valve setpoints found above required tolerance (Section E8.7)

i 50-498/97-009 LER Unit 1 and 2 main steam safety valve as-found setpoints out of tolerance high (Section E8.7)

50-499/97-009 LER Unit 1 and 2 main steam safety valve as-found setpoints out of tolerance high (Section E8.7)

50-498/9716-01 URI _ - errors in instrument uncertainty' calculations (Section E8.1)

50-499/9716-01 URI - errors in instrument uncertair'ty calculations (Section E8.1)

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50-498/01014 VIO failure to promptly identify and correct setpoint errors in )

calculations (Section E8.5) ]

50-498/02014- VIO failure to void a calculation related to instrument uncertainty where two calculations indicated different results for the same parameter (Section E8.6) 1 t

50-498/03014 VIO failure to translate measuring and test equipment calculation I accuracy assumptions into calibration procedures (Section E8.2) I 50-498/04014 VIO excessive amendments led to calculations with erroneous information (Section E8.3)  !

50-498/05014 VIO lack of procedural requirements to evaluate the effect of changes in calculations on other documents, specifically the Final Safety Analysis Report (Section E8.4) )

h 50-498/9805-01 URI two Unit 1 main steam safety valve setpoints above required ]

tolerance (Section E8.7) J l

50-499/9819-02 NCV failure to perform Technical Specification required tests on the

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Unit 2 Trains B and D Class 1E batteries (Section E8.8)  !

50-499/99-001 LER failure to fully meet the requirements of Technical Specification Surveillance 4.8.2.1d for batteries (Section E8.8)  ;

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LIST OF DOCUMENTS REVIEWED Procedures l PROCEDURE TITLE REVISION l NUMBER

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OPDP01-ZE-0001 Design Verification Process 1 l

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Pi CEDURE TITLE REVISION NUMBER l r - OPGP03-ZE-0022 Inservice Testing Program for Pump l OPGP03-ZE-0033 RCS pressure Boundary Inspection for Boric Acid 7 Leaks i

' OPGP03-ZF-0001 ' Fire Protection Program 9 OPGP03-ZF-0018 Fire Protection System Operability Requirements 8 OPGP03-ZX-0002 Condition Report Process 17 i

OPGPO4 ZA-0002 Condition Report Engineering Evaluation 2 Program OPGPO4-ZA-0307 ' Preparation of Calculations 1 OPGP04-ZA-0328 Design Document Control Program 5 .

i 01 GPO4-ZE-0309 Design Change Package 5 OPGPO4-ZE-0310 Plant Modifications 3 OPGPO4-ZE-0311 Design Change Function Test identification 1 OPGP04-ZE-0312 Design Change implementation 5 OPGP05-ZA-0002 10 CFR 50.59 Evaluations 9 OPMPO4-ZG-0004 Bench Testing of Relief and Safety Relief Valves 13 OPMP05-DJ-0010 1E Battery Equalizing Charge 7 OPOP02-CC-0001 Component Cooling Water 13 OPOP03 ZG-0009 , Mid-Loop Operations 10 OPOP04-AE-0001 Loss of Any 13.8 kV or 4.16 kV Bus 13

- OPSP03-AF-0001 Auxiliary Feedwater Pump 11 (21) inservice Test 4 OPSP03-CC-0001 Component Cooling Water Pump 1C(2C) 5 Inservice Test OPSP03-EW-0011 Essential Cooling Water Pump 1B(2B) Reference 1 Value Measurement OPSP03-EW-0018 . Essential Cooling Water System Train B Testing 18 OPSP03-RH-0001 Residual Heat Removal Pump 1 A(2A) Inservice 1 Test

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PROCEDURE TITLE ' ~

REVISION

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h OPSP03-RH-0002; Residual Heat Removal Pump 1B(2B) Inservice . Test OPSP03-RH-0003 Residual Heat Removal Pump 1C(2C) Inservice >

Test e

OPSP03-SI-00011 Low Head Safety injection Pump 1 A(2A) 3 Inservice Test -

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OPSP03-SI-0010 -- High Head Safety injection Pump 1 A(2A) 2L Reference Value Measurement

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. OPSP05-HC-0934L Containment Pressure Loop Calibration 1 OPSP05-HC-0934T.; ' Containment Pressure Transmitter Calibration 0

- OPSP05-MS-54L . Main Steam Line Pressure Loop Calibration 2 OPSP05-MS-54T Main. Steam Line Pressure Transmitter . Calibration OPSP05-RC-0455L Pressurizer Pressure Loop Calibration 4 OPSP05-R'C-0455T . ' Pressurizer Pressure Transmitter Calibration 3 4E019NO1009 L Interdiscipline/ Generic Equipment Qualification 10

. LP.NO. ESP 700.03 Engineering Support Continuing Training - 50.59 0 Refresher LP.NO.NTD40.03.LP .10 CFR 50.59 Unreviewed Safety Question 3 Evaluations

' LP.NTD040.02.LP 10 CFR 50.59 Safety Screenings ' 3 NDEP Visual Examination for Leakage VT-2 Condition Records

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RECORD SUBJECT DATEISSUED NUMBER 97-00057 ' No Condition Record Deficiency Report Team Exists 01/02/97 97-00704- Obtain New Relief Valve from Warehouse and Bench Test 01/16/97 i and Replace 9; 00931 ' CDTP for Relief Valve incorrect in the South Texas Project 01/20/97 Pressure Safety Valve Setpoint index  ;

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RECORD SUBJECT DATEISSUED

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97-01274- When Removing Residual Heat Removal Relief Valve to 01/21/97 Bench Test, Found There Was No Way to isolate the Valve Discharge-97-01685 Residual Heat Removal Pump Did Not Start When the Hand 01/31/97 Switch Was Taken to Start :

97-02365- Need to Test and Rework Valve to Be Used as a Spare 02/10/9 .

-97-02451;

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z Contingency Work Order for the Hydrogen Analyzer 02/11/97-97-02964 : During installation of Piping Flanges, the Take out Distance . 02/15/97

' Was incorrect Resulting in a Gap Larger than the Flanges 97-0668h Residual Heat Removal Pump Flange Has inactive Leak 04/05/97 Around Entire' Circumference-97-08042 Significant Boric Acid Leakage of Residual Heat Removal 05/01/97 Valve

97-08138 Residual Heat Removal Valve Has a Serious Boron Buildup' 05/02/9 ,

and Body to Bonnet Leak 97-10575 Component Cooling Water Pump 2A Failed .

06/27/97 .

Procedure OPSP03-CC-0001 Due to High Differential Pressure l

97-11347 Oil Analysis Indicates Abnormal Wear Materials in 07/15/97 l Component Cooling Water Pump inboard / Outboard Bearing

= Oil 97-11793 Question Whether Residual Heat Removal Discharge to . 07/23/97 Letdown to isolation Motor-Operated Valve Could Be Stroked at Power -

97-14198 Observed That Valve Showed Signs of Packing Leak 09/14/97 97-1422 Component Cooling Water Pump inboard Bearing Needs Oil 09/14/97 97-14594 Heavy Boron Buildup Upstream of Residual Heat Removal 09/18/97 Pump Vent Valve i 97-17575 Calibration Tolerance for Component Cooling Water 10/30/97 Pump 2C Suction Pressure increased Contrary to ASME l Section XI l L

97-18891 Boron Buildup Around Component Cooling Water Valve 11/24/97 1

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RECORD' . SUBJECT DATEISSUED

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97-20070 E1d11 Battery Charger Voltage Climbed to Approximately 12/22/9 V When Placed in Service -

98-00446 After Rur.aing Two Component Cooling Water Pumps ! 01/08/98 Simultaneously, Average Reactor Coolant Temperature and -

Power increased ~ -

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98-01698 - Emergency Operating Procedure Setpoint for Steam - 02/02/98-

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Generator Narrow Range Level incorrect 93-03108 -- Replace the Soleno'd Valve Operator Which Was Subjected ^ '02/23/98

. to a High Voltage Ercursion 93-03449 Component Cooling Water Pump Outode Bearing Oil Needs 02/27/98 to Be Changed 98-04244 Both inboard and Cuteoard Temcerature Elements Have Oil 03/11/98 Leaking from Around Th.eade E5tering Motor 98-060C - ' Electrical Auxiliary Building Fans and Component Cooling 04/15/98 Water Pumps Start Then Trip When Switch Moved from Pull-To-Lock to Auto if Safety injection Signalis Present -i 98-08946 ~ Component Cooling Water Pump Inboard Motor Bearing and 06/11/98 Inboard Pump Bearing Using Excessive Amounts of Oil 9"b15552 Snubbers Were Found to Be Broken Which Points to 10/06/98 '

- Occurrence of Water Hammer'

'98 16671' . Reactor Coolant Pump Thermal Barrier Return Failed to ' 10/18/98-Close Within the Allowed Pressure Range 99-01305: Deficiency Tag Not Entered into Corrective Action Program - 01/27/99 ]

Power Cable Connection Barrier Cover Missing l 99-01308 Deficiency Tag Not Entered into Corrective Action Program - 01/27/99

- Power Cable Connection Barrier Broken

~ 99-01328 Use of the Residuai Heat Removal System for Small Break 01/27/99 Loss of Coolant Accident-99-01349T Zone Codings on Main Control Room Meters To Be 01/27/99 Evaluated for inclusion .. Operator Aid Program-99-0171 TSC-242 to Correct Typograptiical Error on Tech Spec 02/11/99 3/4.3.3 Whera Tau Values (Time Constants) Have Commas Instead of Sutt:ripts 1 arH R

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99-01978' Revise Calcuiation EC5098 to Correci emperatures in 02/09/99 Section 5.2.2 and 5.3.2 -

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RECORD' SUBJECT DATEISSUED NUMBER 99-01980 . Tracking Condition Report Against Calculation EC5008 02/09/99 Revision 11 for Minor Ptoblems Found During NRC Inspection of Residual Heat Removal System 99-02001 Revise Condition Report Engineering Evaluation 97-20070 to 02/08/99 incorporate Conclusion Regarding Reactor Coolant Pump Undervoltage and Underfrequency Relays 99-02042 Evaluate Operation of Residual Heat Removal Bypass and 02/11/99 Throttle Valve to include System Lineup and Update / Revise Design Documents as Required 99-02043 Discrepancy Between Component Cooling Water Design 02/10/99 ;

Basis Document and Updated Final Safety Analysis Report {

99-02066 Evaluate Need to include Both Random Normal Temperature 02/11/99 Effects (STE) and Accident Environmental Bias (EA) Effects i in Channel Statistical Allowance Calculations 99-02087 Plant Procedure Uses Component Cooling Water Flow Lower 02/10/99 I Than That Used in the Loss of Coolant Accident Analysis 99-02093 Evaluate Chattering Phenomenon for Oversized Pressure 02/10/99 Relief Valve 99-02366 Void Calculations MC-6140 and MC-6143 02/16/99 Desian Chanae Packaaes PACKAGE SUBJECT NUMBER 95-12071-14 Solid State Protection System Upgrade and Enhanceme ;

97-19849-4 Replacement c4 Reactor Coolant Pumps 1 A, B, C, D Seal Leakoff / injection Flow Recorders i

98-10849-5 Essential Cooling Water Screen Wash Booster Pump 2C Flange Dealloyed TPNS#3R282NPA202C 98-5902-7 Change Safety injection Accumulator Level and Pressure Alarm Setpoints, Supplement 0 98-5902-5 Change Safety injection Accumulator Level and Pressure Alarm Setpoints, ,

Supplement 0 98-5844-7 Revise the Emergency Response Facility Data Acquisition Digital System Alarm Setting of EWTA6883, EWTA68888, EWTA6893, Supplement 0

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'8 PACKAGE SUBJECT NUMBER j 98-5844-5 -l Revise the Emergency Response ::acility Data Acquisition Digital System Alarm Setting of EWTA6883, EWTA68888, EWTA6893, Supplement 0 98-5136-2 Valve CV-0236B Replace Bellows Valve with Gate Valve, Supplement 0 98-0622-2 Standby Diesel Jacket Water and Lube Oil Coolers Tube Plugging, Supplemants 0,1(VOIDED),2

98-0529- . Upgrade Applicable St Miniflow Motor-Operated Valve Spring Packs to 0301-111, Supplements 0,1 97-7950-1 Add New Instrument Valve 9Q111TIA9213 to Isolation Valve FY-7131, Supplements 0,1 (VOIDED)

97-7414-6 Essential Cooling Water System Annubar Flow Element Modification, Supplement 0 97-7306-3 Remove Line 1 A1890 Downstream of Valve 1 A0969, Supplement 0 97-6847-2 Add Higher Tap Setting to Setpoint index for 3V112VPA005, Supplement 0 96-9391-2 Replacement of Residual Heat Removal Heat Exchanger 1B Temperature Recorder N1RH-TR-0875, Supplement 0 96-4167-2 Replacement of Residual Heat Removal System Heat Exchanger 1 A Inlet / Outlet Temperature Recorder N1RH-TR-0874, Supplement 0 96-0870-2 Remove Internal of Essential Cooling Water Check Valve 1-EW-0262, Supplement 0

'95-8107-4 Emergency Core Cooling System Emergency Sump Flange Holder, Supplement 0 95-6558-1- . Change the Letdown Heat Exchanger Flow Range and Re-size FE-0132, Supplement 0 95-6543-3 Mechanical Auxiliary Building and Reactor Containment Building Non-Essential Chillers, Supplement 0 95-6543-1 Add Purge Cycle Counter and Oil Pressure Cut-Out Switch Isolation Valves to Essential Service System Chillers, Supplement 0 95-5754-3 Residual Heat Removal System Standpipe Check Valves and Heat Exchanger not Full Alarm, Supplement 0 95-5701-3 Add Vent PipingNalves-Charging and Volume Control System Charging Line, Supplements 0,1 (VOIDED)

95-5701-2 . Add Vent PipingNalves-Charging and Volume Control System Charging Line, Supplements 0,1 (VOIDED)

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9-i PACKAGE SUBJECT NUMBER 95-3344-29 Provisions for Removal of Reactor Coolant Pump 2A Motor, Supplements 0, 4 1, 2 95 2013-4 Heating Ventilation And Cooling Condensate Drains Recycle - Essential-Cooling Water Sump Pump Piping Reroute, Supplements 0,1 (VOIDED)

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95-1586-2 DG~13 Jacket _ Water _ Cir Pump (30151MPXO334), Supplement 0 95-1381-9 Splitting of Technical Support Center Chiller 118 into two Independent Plants, Supplement 0 Safety Evaluations EVALUATION DESCRIPTION ' REVISION NUMBER

=96-0004 Mid-Loop Flowrate Increase From 1500 GPM to 3000 GPM 0 Per Residual Heat Removal Train: l 96-0046 ._ Revise Updated Final Safety Analysis Report from Dual 0 Train Protection to Single Train Protection 96-0048 Change the Requirements from Operable to Functional O Charging Pumps in Modes 5b and 6'-

96-0059 ' Procedure Revision to Clarify Safe Load Paths _ 0 97-0001 Potential Two-Phase Flow in Reactor Containment Fan 0 Coolers j 97-0009 Remove Motor-Operated Valve Numbers for Section 0 l 9.2.2.2 of Updated Final Safety Analysis Report l

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97-0011- Remove Internals of Essential Cooling Water Check Valve 0 97-0023- Essential Cooling Water Gantry. Crane Removal 0,1 i

'i 97-0026 Revision of Procedure OPGPO-ZA-0069 )

97-0042.~ . Changes to Updated Final Safety Analysis Report, O

. Sections 8.1'and 8.2 (Offsite Power)

'98-0010 Emergency Operating Procedure Narrow Range Steam .O Generator Setpoint -

98-0013 Changing Fire Detector Test Frequency, Fire Pump Fuel 0

~ Oil Testing and Hose inspections

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. 10 EVALUATION DESCRIPTION REVISION NUMBER 98-0023 Engineering Evaluation of Rigging Plan for Installation of 0 Reverse Osmosis Skid 98-0040 Updated Final Safety Analysis Report Update'- 0 98-0048 Peak Clad Temperature Assessment 0 98-1278: Unreviewed Safety Question Evaluation Associated with 0 Control of Transient Fire Loads and Use of Combustible and Flammable Liquids and Gases Ca!culations CALCULATION DESCRIPTION REVISION NUMBER CWBS-C-091 Residual Heat Removal System Flow Split 1 CWBS-C-150 Residual Heat Removal System Pump Runout Potential 0~

EC-5008 - Class 1E Battery, Battery Charger and invertor Sizing 11 EC-5029 4.16 KV Switchgear Relay Setting 5 EC-5052 _ Degraded and Undervoltage Protection 4 EC-5094 Instrument Uncertainty Mid-Loop Level 0 EC-5098 Degraded and Undervoltage Protection Irstrument - 1 Uncertainties FRSS/CBWS- Residual Heat Removal System Performance with 108*F 0 l C-080 -Componer:t Cooling Water System Temperature  !

' FRSS/CWBS- Residual Heat Removal System Flow with Minimum Flow 0

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C-096 Line Open i

FSA-TGX-3114 Residual Heat Removal System Cooldown Performance 0 ;

i FSD/SS-TGX- Residual Heat Removal System initiating Window 0 I 347 =

MC 5047 Component Cooling Water System Heat Loads 2 MC-5307 Net Positive Suction Head for Component Cooling Water 3 Pumps  ;

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i CALCULATION DESCRIPTION REVISION 1 NUMBE I

- MC-5476 , Component Cooling Water Pump Requirements Verification 0 MC-5517 Pressure Drop Evaluation for the Residual Heat Removal 2 Syciam MC-5991 Component Cooling Water Single Train Shutdown 2 Tomperature (Appendix R);

MC-6019 Component Cooling Water / Emergency Cookng Pond Supply 0 Temperature MC-6036 Residual Heat Removal System Loss of Flow During Reactor 0 Coolant Pump Faal Standpipe Line Break

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MC-6052 Thermal Study of Component Cooling Water Supply to C Reactor Containment Fan Coolers Post-Loss of Coolant Accident

' MC-6090 - Component Cooling Water Heat Exchanger Fouling 0 MC-6100 Evaluate Safety-Related Pump Minimum Flow per NRC 0 Bulletin 88-04

- MC-6138 Residual Heat Removal Pump at Midioop in the Event of a 0 Loss of Offsite Power MC-6143 : , Residual Heat Removal System Heat Exchanger Water 0 Hammer

- MC-6144 Throttling Low Pressure Safety injection Pump Flow 0 N4SD-TGX-16 . Reactor Coolant System Cooldown Profile for Rapid 3 Refueling Operations 1 PDC-N4SD .- Residual Heat Removal System' Available Net Positive 0

- TGX-48 ' Suction Head and Normal Cooldown Flow WCAP-11273 - ' Westinghouse Setpoint Methodology For Protection Systems February South Texas Projects Units 1 and 2_ 1993 WCAP-14262 Bases Document for Westinghouse Setpoint Methodology December !

For Protection Systems South Texas Projects Units 1 and 2 1994 j

- . l ZC-07013 - Residual Heat Removal System Closure Alarm Setpoint - 0 Suction Valves -

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CALCULATION DESCRIPTION REVISION NUMBER

ZC-07030 Loop Uncertainty Calculation for Reactor Coolant System . 1 Wide /Extaded Range Pressure instrumentation & Residual Heat Retooval System Pump Suction Low Pressure Permissive isolation interlock ZC-07034 Loop Uncertainty Calculation for Residual Heat Removal 0

.-System Pump Discharge Flow Monitoring Instrumentation Drawinas DRAWING DESCRIPTION REVISION NUMBER

, SN129F02013 #1 Safety injection System 22 SN129F05013 #2 Safety injection System 22 SN129F05014 #1 Safety injection System 13 SN129F05014 #2 Safety injection System 12 SN129F05015 #1 Safety injection System 14 i

SN129F05015 #2 Safety injection System 14 SN129F05016 #1 Safety injection System 11 5N129F05016 #2 Safety injection System 12 SN129F05017 #1 Component Cooling Water System 18 SN129F05017 #2 Component Cooling Water System 18

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SR-20-9-Z-420421 RCFC CCW Supply and Return Valves - Logic Diagram 7 SR169F20000 #1 Residual Heat Removal System 20 SR169F20000 #2 Residual Heat Removal System 19 1 5R169F20000 #1 Piping and Instrumentation Diagram Residual Heat 20 -

Removal System SR209F05017 #1 P&lD Component Cooling Water System 18 SR209F05018 #1 Component Cooling Water System 16

!- SR209F05018 #2 Component Cooling Water System 18 SR209F05019 #1 Component Cooling Water System 15

~ SR209F05019 #2 Component Cooling Water System 16

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DRAWING DESCRIPTION REVISION NUMBER

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SR209F05020 #1 Component Cooling Water System 16 I SR209F05020 #2 Component Cooling Water System 14

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9-E-CC02-01 #1 Elementary Diagram RCFC Chilled Water Supply MOV _7 0059 9-E-CC03-01 #2 Elementary Diagram RCFC Chilled Water Fleturn MOV 8 0070  !

9-E-CC23-01 #1 Elementary Diagram CCW Supply isolation MOV 0057 11 9-E-CC24-01 #1 Elementary Diagram CCW RCFC Return isolation MOV 12 0069 9-E-CC28-01 #2 Elementary Diagram RCFC Chilled Water Return MOV 9 0148 '

9-E-CC41-01 #2 Elementary Diagram RCFC Chilled Water Return MOV 9 0209 9-E-PLAA-01 #1 Single Line Diagram 480V Class-1E Load Center E1 A 14 (EAB)

9-E-PLAB-01 *1 Single Line Diagram 480V Class-1E Load Center E1B 12 (EAB)

9-E-PLAC-01 #1 Single Line Diagram 480V Class-1E Load Center E1C 15 (EAB)

9-E-PMAA-01 #2 ~ Single Line Diagram 480V Class-1E Motor Control 19 Center E2A1 (EAB)

9-E-PMAD-01 #2 Single Line Diagram 480V Class 1E Motor Control 21 Center E281 (EAB)

9-E-PMAD-01 #1 Single Line Diagram 480 Class 1E Motor Control Center 19 E181 (EAB)

9-E-RH01-01 #2 Elementary Diagram RHR Pump 1 A,1B,1C Mini Flow 12 MOV's 0067A, B, and C J

9-E-RH02-01 #2 Elementary Diagram RHR Inlet isolation MOV's 0061 A, 13 B, and C 9-E-RH03-01 #2 Elementary Diagram RHR inlet Isolation MOV's 0060A, 11 B, and C 9-E-RH04-01 #1 Elementary Diagram RHR CVCS isolation MOV's 0066A 12

& 0066B

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14 DRAWING DESCRIPTION REVISION NUMBER 9-E-RH04-01 #2 Elementary Diagram RHR CVCS Isolation MOV's 13 0066A, & 00668 9-E-RH05-01 #2 Elementary Diagram Residual Heat Removal Pumps 1 A 7

& 1B & 1C (PA101 A, PA101B & PA101C) (PA201 A, 201B,201C}

9-E-RH05-01 #1 - Elementary Diagram Residual Heat Removal Pumps 1 A 8

& 1B & 1C (PA101 A, PA101B & PA101C) (PA201 A, 201B,201C)

9-E-RH05-02 #1 Elementary Diagram Residual Heat Removal Pumps 1 A 0

&1B&1C 9-E-RH05-02 #2 Elementary Diagram Residual Heat Removal Pumps 1 A 0

& 1B & 1C 9EPMAA-01 #1 Single Line Diagram 480V Class-1E Motor Control . 22 Center E1 A1 (EAB)

9EPMAG-01 #1 Single Line Diagram Class-1E Motor Control Center 18 E1C1 (EAB)

9EPMAG#02 1 Single Line Diagram 480V Class-1E Motor Control 18 Center E2C1 (EAB)

9ERH01-01 #1 Elementary Diagram RHR Pu:np 1 A,1B,1C Mini Flow 14 MOV's 0067A, B, and C 9ERH02-01 #1 Elementary Diagram RHR Inlet Isolation MOV's 0061 A, 15 B, and C 9ERH03-01 #1 Elementary Diagram RHR In, Isolation MOV's 0060A, 13 B, and C Desian Basis Documents 5R169MB1021 Residual Heat Removal System, Revision 4 SR209MB1018 Cornponent Cooling Water System, Revision 2