IR 05000272/1997004
| ML18102A992 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 04/18/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102A991 | List: |
| References | |
| 50-272-97-04, 50-272-97-4, 50-311-97-04, 50-311-97-4, NUDOCS 9704230336 | |
| Download: ML18102A992 (19) | |
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Docket Nos:
License Nos:
Report Nos:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272, 50-311 DPR-70, DPR-75 50-272/97-04, 50-311 /97-04 Public Service Electric and Gas Company Salem Nuclear Generating Station, Units 1 and 2 Hancocks Bridge, January 21, 1997 - February 28, 1997 Roy L. Fuhrmeister, Sr. Reactor Engineer, DRS, EEB Raymond K. Lorson, Resident Inspector Robert G. Quirk, NRC Contract Engineer William H. Ruland, Chief, Electrical Engineering Branch Division nf Reactor Safety 9704230336 970418 PDR ADOCK 05000272 G
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SUMMARY Salem Inspection Reports 50~272&311 /97-04 January 21, 1997 - February 28, 1997 This inspection included aspects of licensee engineering and oper~tions. The report covers a 6-week period of inspection related to the Integrated Test Program proposed for the startup of Salem Unit Operations
Excellent performance by the operating crews was observed during the Component Cooling Water Pump Performance Test and the preparations.for the Service Water Pressure Decay Time Tes Engineering
The use of ASME Code Case N-416-1 with ANSI 831. 1 piping to justify inservice leak testing in lieu of hydrostatic testing was evaluated and found to be acceptabl *
There were some problems in post-modification test procedure development. These
. include deficiencies in recently issued feedwater control system test procedures, and the improper post-weld test procedure specification for several modification Since the system being tested, feedwater, is nonsafety-related, enforcement is not appropriate for these deficiencies. These procedures were developed and issued after you implemented corrective actions for similar deficiencies we identified in December 1996. Since these deficiencies were also identified. by your Test Review Board and Nuclear Safety Review Board, still conclude that the test program can demonstrate that the unit operates in conformance with its desig iii
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0 Report Details I. Operations Conduct of Operations Component Cooling Water (CCWl Pump Performance Test Scope of Inspection (70312)
The inspectors observed the preparations for, and conduct of, the CCW pump performance.test which was conducted to address an issue which was raised by the NRC Safety System Functional Inspection (SSFI) team which reviewed the CCW system. The inspectors also. evaluated the adequacy of the test procedure, TS1.SE-SU.CC-0003(0), Rev. 1, "Component Cooling Pump Performance with 11CC16 and/or 12CC16 Throttled." Observations and Findings During the period December 1996 through January 1997, the NRC conducted an
.SSFI of the Unit 2 CCW system. The results of that inspection are documented in NRC Inspection Report 50-311 /96-81. An issue raised in the SSFI report relates that the CCW pumps do not get automatic start signals after an accident. The SSFI team identified a scenario in which a single CCW pump and heat. exchanger could
. supply the cooling loads of two trains of emergency core.cooling system (ECCS)
components for up to 1 5 or 20 minutes. The concern was that this could result in the pump running out on the pump curve *and being damaged by cavitation, resulting in a complete loss of cooling to the ECCS equipmen In response to this concern, PSE&G conducted two special tests. One test was conducted at the manufacturer's facility where a similar pump was run on the factory test loop to determine the maximum flow capability of the pump, and the pump capability with the suction throttled to simulate the elevated return temperature under accident conditions. A second test was conducted at Salem to determine what flow would be achieved with one pump flowing through a single *
heat exchanger feeding two trains of ECCS equipmen The test procedure utilizing installed equipment at the station was written to use the 11 CCW pump and heat exchanger. Temporary instrumentation was installed to monitor pump suction and discharge pressures, pump and motor bearing vibration, system flow; motor amperage and power consumption. Permanent instrumentation was utilized to monitor motor amps and motor winding and bearing temperature Test termination criteria were established in the event of vibration, winding or
. bearing temperartures, or mo'f:or amperage reaching excessive levels.
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The test was originally scheduled to be run on February 3, 1997. Due to problems with the temporary instrumentation, operations personnel decided to suspend the test to permit the test personnel to correct the problems. The test was resumed on February 5, and another pre-test briefing was conducted due to a different operating crew being on shift~ During the subsequent conduct of the test, while throttling the 11 heat exchanger outlet valve and flowing through the 12 CCW header, the 12 header low pressure alarm was received. The operators did not immediately understand the cause of the header low pressure alarm, and the test personnel could not produce a ready explanation. The operating crew susoended the test to evaluate whether adequate CCW flow to the 12 header existed, and whether plant conditions were safe and stable..The operating crew and the test personnel reviewed system drawings and setpoints, and. determined that the alarm should have been expected for the conditions (heat exchanger outlet v1lve throttled)., In addition, the operating crew requested a review of the data from the pump test at the factory to determine if the alarm should be expected to come in later in the tes During the evaluation of the 12 CCW header low pressure alarm, the operating crew reviewed the test procedure, and held discussions with the test engineer to determine the correct procedural directions for restoring the system in the event the**
test were to be terminate Once the conditions causing the 12 CCW header low pressure alarm were understood, the test was resumed, and carried through to completio Conclusions The performance of the operating crews, with regard to control of plant equipment, procedure use, and response to unexpected test results was found to be excellen.2 Service Water Header Pressure Decay Time Test Scope of Inspection (70312)
The inspectors observed the preparations for the performance of the service water header pressure decay time test on February 21, 1997. The inspectors also reviewed test procedure TS2.SE-SU.SW-0002(0), Rev. 0, "SW Pump Pressure Decay Time Test." Observations and Findings PSE&G has identified some accident scenarios during which the service water (SW)
pumps could lose power for periods of up to 30 seconds. This could result in loss of pressure and voiding in the service water piping, and resultant water hammer when the pumps restart. PSE&G had previously evaluated the magnitude of the water hammer and determined that the integrity of the piping pressure barrier was not challenged. The evaluation did not assess the effects on the pipe supports or the containment fan coil unit (CFCU) cooling coil tubin.*
A modification is bt:ing developed to mitigate the potential water hammer which could result from a loss of power to the service water pumps. Special test TS2.SE-SU;SW-0002(Q), "SW Pump Pressure Decay Time Test," was written and conducted in order to determine how long it takes for the header pressure to decay after the SW pumps trip. The data obtained during this test will be used in the selection process for water hammer mitigation equipmen The test procedure needed to be revised to accomodate equipment which was out *
of service at the time the procedure was to be conducted. In addition, while reviewing the procedure for the pre-test briefing, the Senior Reactor Operator identified additional minor changes which were needed. The operating crew, after discussions with the test director, opted to complete the revisions prior to conducting the pre-test briefin The procedure splits the 21 and 22 service water headers and places all the heat loads on the 21 header for the duration of the test. 'In additon, the pumps which supply the 22 header are placed in manual. This lineup eliminates some of the redundancy of the service water system. As a result, the control room operating crew hesitated to establish the initial conditions and leave the facility with a reduced safety margin for long periods. The control room operating crew therefore, delayed the start of the testing until procedure revisions and safety reviews under 10 CFR 50.59 were complete Conclusions The evaluation by the control room operating crew of the impact of the test conditions on the plant safety margin was indicative of ~ good questioning attitude and an excellent safety perspective. The inspector concluded that the actions of
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the control room crew in delaying the test until paperwork was completed was sound, and was appropriately based on plant safety consideration Ill. Engineering E 1 Conduct of Engineering E1.1 Pressure Testing of Modified Piping Scope of Inspection (72400)
The inspector reviewed Design Change Packages (DCPs) issued for modifications to piping systems. The packages were reviewed to determine what examinations and tests were specified for the welds and piping. The testing called for in the DCPs was compared to that required by the various codes and standards referenced in the DCP Specific DCPs, codes, and standards reviewed for this effort are listed at the end of this repor * *
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Observations and Findings Background The American National Standards Institute (ANSI) Power Piping code is called ANSI B31. 1. This code prescribes material specifications, fabrication processes, design criteria, and post-work testing to be used for power piping systems. This code is currently used for the design of nonsafety-related piping, and was used for the design of safety-related piping systems prior to the issuance of the codes and standards specifically addressing nuc.lear power plant component The American Society of Mechanical Engineers :ASME) Boiler and Pressure Vessel Code, Section Ill (ASME Ill), was developed during the late 1960s and provides specific guidance for,the design and fabrication of nuclear power plant component It prescribes material specifications, fabrication processes, non-destructive examination (NOE) processes, design criteria, and post-work testing to be use The feedwater and condensate system!:1 at Salem are nonsafety-related and are designed in accordance with ANSI B31. 1 criteria. The service water system at Salem is safety-related. Portions of the service water system are designed to the requirements of ANSI B31.1, and other portions are designed to the requirements of ASME Ill. Modifications and additions to the piping systems are designed to the requirements of the original design code for that portion of the piping system.
The design pressure of the condensate system piping at Salem has,been changed, to allow installing higher setpoint relief valves. The higher setpoint relief valves will reduce the problems with relief valve seat leakage which have been experienced over the years. The original design pressure of the piping was 650 psig, while the design pressure of the pressure vessels in the system was 700 psig. The design pressure of the piping has been increased to 700 psig, which will require pressure testing of the piping. In addition, modifications have been made to the feedwater piping, which will require pressure testin The containment fan coil units (CFCUs) at Salem provide for the removal of heat from the containment during normal operation and postulated accident condition The CFCUs transfer the heat froni the containment atmosphere to the service water system, which then disperses the heat to the environment. A condition ~ad been postulated where, in certain accident sequences, the CFCU fans could be running with the se.vice water side isolated. This could cause the expansion of trapped water, and result in an overpressure condition for the CFCU tubes and connected piping. To resolve this issue, PSE&G is installing relief valves on the CFCU return lines. This relief valve will vent the expanding water from the return line into the downstream discharge header. The piping on the inlet side of the new relief valve is designed to ANSI B31. 1 criteria, while that on the outlet side of the relief valve is desigr;ed to ASME Ill, Class 3 criteri Code Required Testing Both the ASME Ill and B31.1 codes require hydrostatic testing of piping which has been modified or repaired by welding. Hydrostatic testing is conducted at a pressure higher than the design pressure of the piping. ANSI B31.1 requires visual examination of welds on piping operating at temperatures less than 350° F and pressures less than 1025 psig, and visual examination of welds in piping operating at temperatures between 350° and 750° F which have a wall thickness less than 3/4". The 1992 edition of ASME Ill, Subsection ND, requires radiographic (RT),
magnetic particle (MT), or dye penetrant (PT) examination of welds on 2 inch nominal pipe size.(NPS) or larger piping. No NOE is required for pipe sizes less than 2" NP Code Case N-416-1 authorizes the use of inservice leak testing (ISL T) in lieu of hydrostatic pressure testing for ASME Section Ill and XI testing. lnservice leak tests are performed at normal operating pressure and temperature of the syste PSE&G received approval from NRC to use Code Case N-41 6-1 at the Salem and Hope Creek stations. The Safety Evaluation Report (SER) which approves tne use '
of the code case was issued January 20, 1995, and specifies that non-destructive examination (NOE) of welds is to be performed in accordance with the 1992 edition of the ASME Code. The SER further requires that for ASME Ill, Class 3 systems, additional NDE is to be performed on the root pass of butt and socket welds when surface examination methods (MT or PT) are used for weld NO For OCP 2EC-3590-1, PSE&G has specified ISLT for the pressure tests of both the ASME Ill, Class 3, and B31.1 portions of the piping. PSE&G used Code Case N-416-1 to justify these ISLT pressure tests. In addition, the 2"NPS and larger welds receive PT of the root pass and the completed weld, whil.e the connections smaller than 2"NPS receive PT of the completed weld. The inspector questioned the use of an ASME code case with ANSI 831. 1, since it was written against ASME XI. PSE&G engineers provided a sound technical basis for the decisio After consulting with technical specialists in NRR, and Region I management, the inspector found the use of the ASME code case with B31.1 piping to be acceptabl Conclusions The use of ASME Code Case N-416-1 has. been previously approved by NRC for ASME Section Ill piping and systems at Salem and Hope Creek. That approval was silent with regard to safety-related piping designed to the requirements of ANSI B31. 1. The inspector determined that the technical justification for the code case was reasonably applied to the B31.1 piping. The inspector also determined that PSE&G was performing weld NOE in excess of the requirements of the B31.1 cod Based on these facts, and after consult~tion with technical specialists in NRR, technical specialists in Region I, and Region I management, the use of ASME Code Case N-416-1 on safety-related piping designed in accordance with ANSI B31. 1 was found to be acceptabl.- '
E3 Engineering Procedures and Documentation E Service Water testing Required for Restart Scope of Inspection The inspector reviewed the Description of Change, Testing Summary, and Test Instruction sections of DCPs for emergent work on the Service Water Syste The following DCPs were reviewed for the inspection:
DCP 2EC-3590-1, Rev. 2, Addition of Thermal Overpressure Device on CFCU Return Piping
DCP 2EC-35'90-2, Rev. 0, Modifications to CFCU Service Water Valves SW57 and SW223
DCP 2EC-3600-1, Rev. 0, Service Water (SW) Media Size Change Observations and Findings DCP 2EC-3590-1 is discussed in detail in section E1.1 abov DCP 2EC-3600-1 replaced the service water strainer elements with new elements having a larger hole size. The purpose of this modification was to improve the performance of the strainers with regard to flow capacity and backwash operatio Backwash operation has been problematic, with the backwash motors tripping on overload before the strainers completed the backwash cycle. The retesting for the modification included differential pressure measurements, strainer drive motor testing, and verification of proper backwash cycle completio DCP 2EC-3590-2 upgraded the actuatl)rs for the CFCU inlet and outlet control valves. These valves are pnuematically actuated to close and open by spring forc The modifications included installing larger springs to improve the differential pressure capability of the valves, and the addition of a volume booster on the air supply to reduce the stroke time of the valves. Post-modification testing included stroke time testing of the valves and flow measurements. This is intended to ensure that the valves will open, and close, in acceptable times in the presence of dynamic (flow-induced) effect Conclusions The inspector concluded that the post-modification testing planned for the service water system will properly demonstrate that the modified components function in acordance with their current desig E4 Engineering Staff Knowledge and Performance E Feedwater Test Procedure Development Inspection Scope The inspectors reviewed multiple feedwater Design Change Packages (DCP) to determine if the proposed post-modification testing would adequately demonstrate that components modified were included in post-work test procedures, that the testing was appropriate, and the procedures conformed to site standard A listing of the documentation reviewed during th9 inspection is included in this repor Observations and Findings 2EC-3285 Condensate Pressure Re-Rate and fielief Valve Replacement The condensate pumps were upgraded in the 1980's to prevent feed pump trips on low suction pressure. This resulted in system relief valves weeping during low flow conditions. PSE&G determined it would be necessary to upgrade the condensate system design pressure from 610 psig to 725 psig to eliminate the weepag PSE&G determined it would also be necessary to replace and* relocate several feedwater heater relief valves, increase the setpoints for relief valves in thermal isolation zones, and decrease the setpoints for feedwater relief valve The design package issued in September 1996 resolved these issues and included a 150% design pressure hydrostatic test to re-rate various ASME pressure vessel feedwater heaters, condensate polisher demineralizers, and resin traps from 700 to 725 psig. In December 1996, Engineering re-evaluated the change and determined there was a more cost effective means to resolve the problem and eliminate the I
1088 psig hydrostatic test. iThe solution was to lower the condensate design pressure to 700 psig. Although relief valve weepage may occasionally occur with this system design pressure, the 150% design pressure test was eliminated. The revised design change package was approved in January 199 The hydrostatic test was changed to an inservice leak test at normal operating pressure (NOP). This was consistent with the extension of Code Case N-416-1 to the 831.1 designed systems as addressed in section E1.1. Ti1e test procedure for leak testing was identified as SC.MD-GP.zz.::0192(0), "Post Maintenance Leakage Testing." The purpose of SC.MD-GP.ZZ-0192(0) is for post-maintenance testing non-code job packages, and is comparable to the inservice leak test in SC.MD-GP.ZZ-0033(0) except that it permits leak tests with insulation installed. The use of this post-maintenance test procedure for piping modified by welding is reasonabl *'
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Miscellaneous Feedwater Piping Modifications Most of the other modifications to the feedwater system piping were minor in scope. However, there was an inconsistency in selecting the test procedure for inservice leak tests. These change packages reviewed are identified in the attached table. The PSE&G ASME Code specialist stated the 831.1 design basis feedwater system should use SC.MD-GP.ZZ-0033(0) for code job packages (CJPs); the non-CJPs should use SC.MD-GP.ZZ-0192(0). As can be noted in the table on page 15, this has not been consistently followed. Since post-modification testing of nonsafety-related balance of plant systems is not covered by either Regulatory Guide 1.33 nor Technical Specifications, no enforcement action is being considered for this matte Conclusions The engineering thougnt process to revise the condensate design pressure from 610 to 700 psig was a good application of engineering judgment. The apparent misuse of SC.MD-GP.ZZ-0192(0) for CJPs and SC.MD-GP.ZZ-0033(0) for non-CJPs is an
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indication that problems with procedural compliance continued to exist. Although the inservice leak testing in the two procedures is similar, this is another indication that plant procedures are not always followed verbatim. Enforcement is not appropriate since the feedwater system is a nonsafety-related balance of plant syste E4.2. Digital Feedwater Control System Test Procedure Review Inspection Scope (70348)
DCP 2EC-3306 added a main turbine runback on a SGFP trip and also replaced the analog SGFP speed controllers with digital controllers. Special Test Procedures (STP) 2EC-3306 STP-001 and 2EC-3306 STP-002 were revised in January 199 The inspector reviewed the test procedures to ensure the new SGFP digital governors and SGFP trip/turbine runback circuitry testing was technically adequate and consistent with site procedure Observations and Findings 2EC-3306 STP-001 tunes (adjusts the controller gain and reset values) the Steam Generator Feed Pump (SGFP) digital governors and 2EC-3306 STP-002 verifies the new main turbine runback circuitry. The STPs had testing voids, as well as technical and administrative problems. These deficiencies are similar to control room ventilation procedure problems identified in Violation 50-311196-21-01. These problems demonstrated continued inattention to detail during the test preparation, review, and approval process. Examples of these problems are described belo *
Neither test had detailed precautions in the step-by-step instruction portion telling plant operators what should be done if the equipment does not perform as expected during the tes :.-~..
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- Some modified equipment features were not tested; one example is not performing an actual end-to-end check of the electrical overspeed limite *
The 2EC-3306 STP-001 cover page incorrectly indicated the changes to the procedure were minor in nature, and were primarily a reformatting. The changes were actually extensive, but based on the incorrect cover page, the DCP Responsible Engineer incorporated the revised procedure in the DCP without a detailed revie *
2EC-3306 STP-001 called for initial SGFP speeds of 11000 and 1 2000 RPM; the PSE&G Test Engineer confirmed the values should have been 1100 RP *
Data sheets in 2EC-3306 STP-002 referred to a non-existent acceptance criterio *
The prerequisite sections of the procedures were weak. 2EC-3306 STP-002 required performing applicable sections of the three procedures to prepare the feedwater system for testing, but the sections identified were incorrect. '
Additionally, two of these procedures have been on administrative hold since before the STPs were written; the STPs did not have a requirement to review changes to these procedures before implementing the tes *
2EC-3306 STP-002 prerequisites included Technical Specification action statements that would be entered near the completion of the test and therefore were not actually prerequisite *
2EC-3306 STP-002 correctly had a place for the test engineer to sign after each prerequisite "line," but 2EC-3306 STP-001 had only one signature for the 12 prerequisite *
Both 2EC-3306 STP-001 and 2EC-3306 STP-002 "Initial Conditions" include the statement "Test conditions will be from cold shutdown to power operations, as applicable." 2EC-3306 STP-001 section 2.0 states testing will be in mode 2 and mode 1. 2EC-3306 STP-002 starts testing at 90%
power. These more limiting descriptions would have been the correct initial condition *
Neither of the STPs included sign-offs for accomplishing the initial condition Independent of the NRC inspection, similar findings were recognized by PSE&G, including the multidisciplinary Test Review Board (TRB) and Nuclear Safety Revie Board (NSRB). As a result, weekly meetings were established to resolve these problems before the tests are executed. PSE&G msnagement directed the revision of the existing tests as well as creation of new special test procedures to more thoroughly test the syste '; __ *
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10 Conclusions Test procedures 2EC-3306 STP-001 and 2EC...:3306 STP-002 have deficiencie However, the plant equipment tested by these STPs is non-safety relate Therefore the integrity of the RCS boundaries is not challenged, the ability to shutdown and maintain the reactor in a safe shutdown condition is not challenged, and the public health and safety is not placed at risk by a failure of these system These modification test procedures were reviewed by NRC because they were so extensive, and these could be an indicator of the general PSE&G ability to properly define, plan, and execute test procedures. It is apparent that some problems exist in this area, but based on the PSE&G internal TRB and NSRB actions, no further NRC action is planned on this matte E SGFP Vibration and Shaft Position lnstrumention Upgrade Test Procedure Review_ Inspection Scope (70300)
DCP 2EE-0119 replaced the SGFP vibration and shaft position instrumentation with a state-of-the-art data collections and analysis system. The inspector reviewed the post-modification test procedures to determine if they adequately tested the system function Observations and Findings The design change was initiated as a minor modification and completed using the PSE&G Workbook 6 process. The scope increased but the abbreviated Workbook 6 process was still used and the change package was approved on May 16, 199 The test procedures were at a. very high level and information required to conduct the test was not provided. For example, high vibration alarm setpoints were all blank. The Design Engineer indicated this was acceptable because correct setpoint values were not known when the DCP was issued, but would be known prior to returnin9 the system to servic This data void was deemed not acceptable by the startup test organization. As a result, the DCP was modified using site procedures; detailed installation and test steps were added, and the package size grew. The Design Engineer stated the similar modification for Salem Unit 1 will be completed using the more robust Workbook 1 proces Conclusions The initially issued test procedures were inadequate, but problems were corrected using site procedures for resolving problems identified during installation and testing. As in the case of the digital feedwater control system modifications, the SGFP vibration and shaft position instrumentation is not safety-relate PSE&G's decision to approve the modification package with known voids demonstrates *a less than adequate post-modification test procedure review proces....
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ES Miscellaneous Engi;;aering Issues E (Closed) Inspector Followup Item 50-311196-21-02: Review Special Test Procedure EC-3306 STP-002, SGFP Trip/Turbine Runback Operational Test after it had been issue *
Based on the discussion in E4.2, this issue is close E (Closed) Unresolved Item 50-311196-21-03: Controls for development and testing of SGr-P digital governor and ADFCS softwar PSE&G stated procedures NC.NA-AP.ZZ-0064(0), Revision 0, "Software Quality Assurance," approved in 1990 and ND.DE~AP.ZZ-0054(0), Revision 0, "Process Computer Maintenance and Modification Control Program," approved in 1992 are the applicable procedures for the SGFP digital governor and ADFCS computer software development and testing. Both of these procedures have been upgraded
- to revision 1, and two lower tier documents, ND.DE-TS.ZZ-5503(0), "Software Requirements for Critical Digital Systems Utilizing Mature Software," *and ND.DE-TS.ZZ-5506(0), "Digital System Life Cycle," have been issued over the last few years. However, the revision 0 procedures which were in effect when the DCPs were in their early stages have been followe There are inadequacies in NC.NA-AP.ZZ-0064(0), Revision 0, particularly on how commercial off the shelf software (COTSS) and other mature software should be handled, and how changes to software should be controlled between the time the software effort begins but before it becomes fully operationa,.
The first problem was recognized by the licensee in 1992, and has been resolved to a large extent by the revision to the parent as well as development of the lower tier procedures. The SGFP digital governor and ADFCS software programs were implemented in parallel with the development of the upgraded procedures. To a large extent, PSE&G used the improved methodology in the newer procedures, but documentation is not always in strict compliance with the The issue with change!? to software while it is still in development arose several times during the course of the ADFCS software development effort. The changes identified prior to the shipment from Westinghouse were included in revisions to various software documents. Changes to the software after it arrived at Salem were handled t.:sing the standard design change process, and documented with Modifications, Concerns, and Resolutions (MCR) forms. For example, PSE&G added a new digital output to the turbine runback logic circuitry before the ADFCS was shipped to the site. This feature was included in the System Requirements Document (SRO), "Advanced Digital Feedwater Control System Technical Requirements," revision 5, dated October 25, 1994. PSE&G later decided to replace the Bailey SGFP 2000 RPM governor latch bistable signal with one developed by the ADFCS. This function was not in~luded in the SRO but was addressed in an MCR. PSE&G stated this change will be rolled into the SRO prior to the completion of the projec ~.: '--.
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All of the referenced. site software control procedures are scheduled for periodic review in the near future; the licensee indicated they will apply lessons learned from the SGFP digital governor and ADFCS software efforts in the next procedure revision E (Open) Inspector Followup Item 50-311196-21-04: ADFCS is not being tested in accordance with system design documentatio The ADFCS design requirement is the system should be able to maintain SG level while rolling the main turbine at 8% power. Current test plans call for not rolling the turbine until the plant is at 1 5 % power. PSE&G stated they experienced plant
_stability problems in the past when adding the turbine load while at low power. As the SGFP digital governor has not been fully tested and adjusted yet, in conjunction with their previous low power control problems, PSE&G has determined it is more prudent to delay initial turbine roll with the new system until the unit is at 1 5 %
rated thermal power. They also stated they will open an Action Request (AR) to review the need to perform an 8% power turbine roll in the future. This item will remain open pending review of PSE&G's corrective actions for the A V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 7, 1997. The licensee acknowledged the findings presente Some of the material reviewed during the inspection was marked as proprietary information. This material was returned to the licensee at the end of the inspectio "
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PARTIAL LIST OF PERSONS CONTACTED Public Service Electric and Gas Company G. Cranston C. Fricker A. Giardino P. Koppel L. Lake D. Lyons M. McGough S. Michigan G. Overbeck M. Rencheck S. Robitzski G. Salamon J. Schubert A. Spivak B Thomas
- E. Villar Manager, Nuclear Electrical Engineering Salem Quality Assurance Salem Projects System Engineer lnservice Test Group Supervisor (Salem/Hope Creek)
Salem lnservice Test Manag~r Director Design Engineering and Projects Technical Assistant to Director Design Engineering Director System Engineering Manager Salem System Engineering Technical Engineer Licensing and Resolution System Engineer Maintenance !:ngineering Supervisor Licensing Engineer Licensing Engineer U.S. Nuclear Regulatory Commission T. Fish R. Fuhrmeister R. Lorson R. Quirk Resident Inspector Senior Reactor Engineer Resident Inspector NRC Contract Engineer LIST OF DOCUMENTS REVIEWED System Pressure Testing DCP 2EC-3590-1, Rev. 2, Addition of Thermal Overpressure Device on CFCU Return Piping DCP 2EC-3285, Rev. 1,Condensate Pressure Re-Rate and REiief Valve Replacement DCP 2EC-3336, Rev. 0, FW Pump Recirculation System Upgrade DCP 2EC-3426, Rev. 0, Replacement of Degraded Pipe and Fittings ASME Boiler and Pressure Vessel Code,Section XI, Rules for inservice inspection of Nuclear Power Plant Components (ASME XI), 1986 edition ASME Boiler and Pressure Vessel Code, Section Ill, Rules for Construction of Nuclear_
Power Plant Components, Division 1, Subsection ND: Class 3 Components (ASME Ill), 1992 edition ASNI Standard B31.1, Power Piping (B31.1)
Code Case N-41 6-1
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. Feedwater Test Procedure Development DCP 2EC-3178 Advanced Digital Feedwater Control System DCP 2EC-3306 Turbine Runback/SGFP Control Circuit Modification DCP 2EC-3329 Condenser Hotwell Level Modifications DCP 2EC-3285 Condensate Pressure Re-Rate and Relief Valve Replacement DCP 2EC-3336 FW Pump Recirculation System Upgrade DCP 2EC-3426 Replacement of Degraded Pipe and Fittings DCP 2EC-3436 Replace Feedwater Thermocouples With RTDs DCP 2EC-3537 CN & FW Heater MMIS for Level Controllers DCP 2EE-0035 Secondary Plant Level Controller Replacements DCP 2EE-0116 Main Feed Reg Bypass Valves Stem Travel Stops DCP 2EE-0117 SGFP Turbine Hydraulic Speed Control Governor Actuator Replacement DCP 2EE-0119 SGFP Vibration and Shaft Position Monitoring DCP 2EE-0135 Protection of Condensate Piping from Overpressurization DCP 2EE-0139 Hotwell Isolation Valve Seal Water Line Flexible Hose DCP 2EE-0196 Condensate and Main Steam System Chemical Injection/Sample Internal Sparger Pipe Removal DCP 2EE-0272 Steam Generator Feedwater Flow Element Flange Compression Stop Rings DCP 2E0-2338 Condenser Vacuum Pressure Transmitter 2PA2396 Replacement DCP 2E0-2341 Steam Generator Feed and Condenser Absolute Pressure Transmitter 2PA2397 Replacement 2EC-3178 Advanced Digital Feedwater Control System 2EC-3306 Turbine Runback/SGFP Control Circuit Modification 2EC-3329 Condenser Hotwell Level Modifications 2EC-3285 Condensate Pressure Re-Rate and Relief Valve Replacement 2EC-3336 FW Pump Recirculation System Upgrade 2EC-3426 Replacement of Degraded Pipe and Fittings 2EC-3436 Replace Feedwater Thermocouples With RTDs 2EC-3537 CN & FW Heater MMIS for Level Controllers 2EE-0035 Secondary Plant Level Controller Replacements 2EE-0116 Main Feed Reg Bypass Valves Stem Travel Stops 2EE-0117 SGFP Turbine Hydraulic Speed Control Governor Actuator Replacement 2EE-0119 SGFP Vibration and Shaft Position Monitoring 2EE-0135 Protection of Condensate Piping from Overpressurization 2EE-0139 Hotwell Isolation Valve Seal Water Line Flexible Hose 2EE-0196 Condensate and Main Steam System Chemical Injection/Sample Internal Sparger Pipe Removal 2EE-0272 Steam Generator Feedwater Flow Element Flange Compression Stop Rings 2E0-2338 Condenser Vacuum Pressure Transmitter 2PA2396 Replacement 2E0-2341 Steam Generator Feed and Condenser Absolute Pressure Transmitter 2PA2397 *
Replacement
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Feedwater Piping lnservice Leak Testing Procedure Selection DCP Code Non-code SC.MD-SC.MD-J 0 b pipin GP.ZZ-GP.ZZ -
Pkg 0033 0192 2EC-3285 x
x rev
was code job and R1 referenced -0033 2EC-3329 x
condenser static water test 2EC-3336 x
x-0033 referenced for all shop and installation FP recirc welds as well as pneumatic tubing; tubing should be tested per l&C installation procedure 2t:.L;-3426 x
x x
generic pipe replacement so it can be code or non-code job pipe 2EE-0035 x
x 2EE-0117 x
per section 1.3 control oil piping installed per 831.1 but no leak testing is called out 2EE-0135 x
x 2EE-0139 x
x 2EE-0196 x
x x
CN piping is non-code; MS is*
code pre-requisite step 1.3.8 calls for liquid penetrant testing on all welds IAW -0192, but -0192 does not addre5.:; this testing 2EE-0272 x
x
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LIST OF ACRONYMS USED ADFCS Advanced Digital Feedwater System ANSI American National Standards Institute AR Action Request ASME American Society of Mechanical Engineers CCHX Component Cooling Heat Exchanger CFCU Containment Fan Coil Unit CFR Code of Federal Regulations CJP Code Job Package COTSS Commercial Off The Shelf Software CR Condition Report DCP Design Change Package ECCS Emergency Core Cooling System l&C Instrumentation and Controls ISi lnservice lnspecLion
!SLT lnservice Leak Testing MCR Modifications Concerns and Resolution MT Magnetic particle Examination N/A Not Applicable NOE Non-destructive examination NPS Nominal Pipe Size NOP Normal Operating Pressure NRC Nuclear Regulatory Commission NSRB Nuclear Safety Review Board OTSC On-The-Spot Change PMT Post-Maintenance Testing PT Dye Penetrant Examination PSE&G Public Service Electric and Gas RCP Reactor Coolant Pump RCS Reactor Coolant System RHR Residual Heat Removal RPM Revolutions per minute RT Radiographic examination SER Safety Evaluation Report SGFP Steam Generator Feedpump SI Safety Injection SNSS Senior Nuclear Shift Supervisor SORC Station Operations Review Committee
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SRO Senior Reactor Operator SSFI Safety System Functional Inspection SW Service Water TRB Test Review Board TRIS Tagging Request Inquiry System TS Ter.hnical Specification