IR 05000312/1988026
| ML20154N857 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 09/09/1988 |
| From: | Bevan R, Bosted C, Crews J, Andrea Johnson, Kosloff D, Miller L, Qualls P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20154N854 | List: |
| References | |
| 50-312-88-26, NUDOCS 8809300023 | |
| Download: ML20154N857 (14) | |
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U. S. NUCLEAR REGULATORY COM4ISSION
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REGION V
Report No:
50-312/88-26 Docket No:
50-312
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Licensee:
Sacramento Municipal Utility District P.O. Box 15830 Sacramento, California 95813 Facility Name: Rancho Seco Unit 1
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Inspection at: Hera, California (Rancho Seco Site)
Inspection Condu d:
st 1-9, 1988 Inspectors:
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k L'. Qew( ' Sept r Reactor Engineer Date Signed
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a ta LeWer
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fY A. JQ Johns.
,nzirc/pentOfficer,RegionV Date' Signed 7/ff6 cfn 7/7GV (G'. g 8,osted, $/.
e%dentInspector,WNP-2 Date Signed
/R'h M
7l'//1Y NM.fua}1s,(
iden Ip pector, Rancho Seco Date Signed s
W&
h 7 t3/11 D. t. y6sloff, Rekiden)bnspector, Davis-Bessie 7/7/u Date Signed
- 19MA,J R. (8. Bevan, ProSct Manager, NRR Date Signed Accompanyirg Personnel:
B. F. Gore, Consultant Batte.le Paciff or est La oratories Approved by:
M it#)
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Lbf. Miller,C@f,ReactorProjectsSectionII Date Signed Summary:
Inspection on August,J 9, 1988 (Report 50-312/88-26)
Areas Inspected:
1his was a special Enhanced Operational Inspectior, Phase II, during power ascension testing at the 80% power plateau.
The inspection was conducted by a team of NRC Regional and Resident Inspec+. ors from Region V and Region III, a Project Manager from NRC Headquarters, anu a consultant from
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8009300023 880912 PDR ADOCK 05000312 G
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the Battelle-Pacific Northwest Laboratories; and included the areas of plant operation and operational support activities.
During the inspection, i
Inspection Procedure 71715 was used.
Results:
No violations with NRC requirements were identified within the areas examined.
Strengths were observed in the overall knowledge and performance of plant operators; a generally strorg discipline in adherence to written
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procedures by essentially all operations, maintenance and testing personnel;
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the effectiveness of coordination and communications (particularly pre-test and pre-job preparations and briefings) between operations, maintenance, QC, and plant performance personnel during the conduct of plant testing and maintenance activities.
A weakness was observed in the clarity of written procedural instruction to plant operations personnel regarding anticipatory actions following plant trip or transient conditions.
A potential generic
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weakness was also observed in the licensee's conduct and documentation of
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safety analyses associated with proposed special tests.
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DETAILS
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1.
Persons Contacted
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F. Fir 11t, Chief Executive Officer, Nuclear B. E. Croley, Assistant General Manager, Technical Services
- D. R. Keuter, Assistant General Manager Nuclear Power Production
- D. E. Brock, Manager, Nuclear Maintenance
- W. E. Kemper, Manager, Nuclear Operations
- S. L. Crunk, Manager, Nuclear Licensing G. V. Cranston, Manager, Nuclear Engineering
- P. E. Turner, Manager, Plant Performance T. E. Redican, Manager, Material Control S. J. Redeker, Assistant Operations Manager
- G. J. Legner, Licensing Engineer
- J. V. Vinquist, Director, Quality Assurance Other licensee and licensee contractor employees were contacted including plant operators, technicians, engineers and supervisory personnel.
- - Attended the exit meeting on August 9, 1988.
+ - Met with the inspection team prior to exit meeting on August 9, 1988.
2.
Scope and Purpose of Inspection
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This inspection was a part of Phase II of the NRC's Enhanced Operational
'nspection (E0I) to evaluate the overall performance of the plant operating crews and those organizations which support plant operations.
Phase I of NRC's E0I involved 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage by an NRC inspection team for a period of approximately three weeks commencing prior to plant startup, through low power testing and the start of the power ascension program to the 25% power level plateau.
(Sec Inspection Report 59-312/88-10) An initial Phase II inspection involved approximately five days by an NRC inspection team, including three days of 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage at the 40% power level plateau.
(See Inspection Report 50-312/88-19)
The current (Phase II) inspection involved appror.imately nine days by an NRC inspection team, including five days of 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage at the 80%
power level plateau.
During this period, transient testing-including main feedwater pump trip, reactor trip, and emergency feedwater initiation and control - was witnessed by the NRC inspectors.
3.
Performance of the Operating Crews During the period August 1-5, the NRC inspection team witnessed plant operations on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> basis.
Observations were conducted related to the performance of licensed operators in the control room and non-licensed operators in areas outside the control room.
This inspection provided an opportunity for the NRC inspection team to observe and evaluate operating crew performance during the conduct of j
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planned power ascension testing at the 80% power level plateau.
Two such
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tests - trip of a main feedwater pump (Test STP-1023) and Reactor Trip (STP-10828) - involved transient plant conditions and associated malfunctions of plant systems which were unanticipated; thus, presenting challenges to the control room operators to take appropriate actions promptly to assure that important plant parameters were maintained within post-trip / transient limits of a previously determined acceptable
"responre window."
A particular challenge to the plant operators occurred during the conduct of special test procedure STP-1023.
The test was initiated by the planned trip of one of two main feedwater pumps (Pump A).
The expected response of the plant systems was such that reactor power would be automatically reduced (run back) to approximately 65% power while the operating main feedwater pump (Pump B) would automatically pick up flow j
lost by the trip of Pump A, thus maintaining the mismatch between heat generation (by the reactor) and heat removal (by steam generators) within j
limits which would preclude excessive undercooling or overcooling of the
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Excessive overcooling or undercooling of
the RCS could result in RCS temperature and pressure conditions which would challenge the plant's automatic reactor protection and/or engineered safety features systems.
During conduct of the test main feedwater pump B, after initially
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responding to a demand to increase flow, unexpectedly (within approximately one minute) experienced a relatively rapid and sustained reduction in flow, contrary to an automatic demand by the plant's integrated control system (ICS) to increase flow.
The plant control room operators were prompt in recognizing symptoms of a malfunction of the plant's automatic feedwater control or ICS systems.
(Subsequent
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investigation revealed that a module failure had occurred within the main
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i feedwater Lovejoy control syctem)
In response to these symptoms, the control room operators transferred main feedwater control from
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"automatic" to "manual", thus permitting them to have direct control of
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the B main feadwater pump.
The pump responded to an increased flow demand by the control room operators, who maintained manual control of the 8 pump until plant parameters had stabilized, thus preventfng an RCS I
undercooling condition which would have most likely resulted in automatic reactor trip due to high RCS presture.
The plant operators had also
manually initiated (by opening the backup spray valve) pressurizer spray i
i flow as an additional action to prevent excessive rise in RCS pressure.
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The actions by the control room ope ators described above were judged by the NRC inspection team to reflect favorably upon their alertnsss as well as the skills and knowledge they had gained through operator training i
programs.
Another significant factor contributing to the unusually prompt and effective response by the control room operators in this instance was what was observed to be a comprehensive and detailed
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briefing and "walk-through" of the test procedure with the plant i
operators prior to conduct of the test.
This briefing and walk-through j
was conducted by representatives of the plant performance and operations departments, and was followed by an extensive question and answer session with active participation by the plant operators.
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Similar performance of the operating crew (a different crew was observed
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during conduct of special test procedure STP-10828 (Reactor Trip).
In this instance the premature lifting and blowdown of a code safety valve in the plant's main steam system presented the potential for overcooling of the RCS and resultant loss of pressurizer level indication.
Control room operators responded to indication of a relatively rapid decrease in pressurizer level (greater than 100 inches / min.) by the starting of the
"B" high pressure injection (HPI) pump and subsequent manual clignment of HPI injection valves to all four RCS loops, thus providing supplemental RCS makeup.
These actions by the operating crew were judged by the NRC inspection team to once again reflect favorably upon operator alertness as well as a high level of skill anc4 knowledge of overall plant transient behavior, system performance, and abnormal operating procedures.
Specifically, the actions by the plant operators were a significant factor in terminating the rapid decrease in pressurizer level at approximately 30 inches.
A corresponding rapid reduction in RCS pressure was also terminated at approximately 1775 psig, 175 psig above the low pressure safety features (High Pressure Injection) actuation level.
The performance of non-licensed operators was also observed by the NRC inspection team, with particular attention to tasks involving equipment clearance and independent verification of equipment status.
These tasks were observed to be conducted competently and in adherence to written procedures.
4.
Wo d Planning / Work Control Work planning in terms of the accuracy and completeness of maintenance work packages was examined by the NRC inspection team during the current inspection, as had been the case during previous Phase I and Phase II Enhanced Operational Inspections.
A work task examined closely during the current inspection involved the replacement of a bearing on the "B" Decay Heat Pump.
The work package was observed to include supplemental information relating to steps in the work instructions not specifically
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covered in the pump vendor's manual.
This supplemental information, such as special precaution in the removal of a gasket for subsequent replacement, was judged by the NRC inspection team as an enhancement to the work package instructionc over some work packages examined during prior inspections by the Enhanced Operational Inspection Team.
During discussions with maintenance department supervision prior to commencement of work on the replacement of the bearing in the "B" Decay Heat Pump, a member of the NRC inspection team was informed that start of the job had been delayed pending resolution of a discrepancy identified by a QC inspector.
The discrepancy related to the absence of a Commercial Grade Item Dedication (CGID) evaluation form associated with the replacement bearing.
Further discussion with representatives of thi QA/QC and material control organizations revealea that the replacement bearing had been issued by a site warehouse attendent in error, in that
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the attendant had failed to verify that a CGID had been properly processed prior to the issuance of the replacement bearing, which had been appropriately marked (tagged) and identified as a commercially purchased item.
As discussed abova, a QC inspector, during routine
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veview of documentation associated with the job, had identified the discrepancy.
Further review by the NRC inspection team revealed that disciplinary action had been taken against the warehouse attendant (storekeeper)
involved for failure to adhere to written procedures covering the issuance of commercially purchased parts.
The facility records also included a memorandum to all Material Control Department personnel, dated August'4, 1988.
The memorandum addressed the subject of "Adherence to Procedures", and included strongly worded expectations regarding adherence to procedures -- including the statement that repetitive violations can result in termination.
The memorandum further directed that department supervision implement a "program of refamiliarity with procedures..." governing individual employee's scope of work.
This training is to be t.ocumented by signature of each employee attesting to having read and understood "the contents and requirements" of procedures applicable to their scope of work.
An NRC inspector verified that a CGIO form was properly processed prior to use of the replacement bearing during the course of the current
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inspection.
Members of the NRC inspection team attended a pre-outage briefing of licensee management on August 1 (the first day of the inspection).
The briefing included a discussion of principal maintenance tasks to be included in a nominal 10 day maintenance outage scheduled to commence on August 6.
One of the principal jobs discussed involved repairs (by the l
use of furmanite) to reduce observed gasket leakage on reactor coolant pump "C".
The job also included the conduct of dimensional measurements of selected stud bolts on the pump.
The briefing included the selection and training of contract personnel for conduct of the leak repair
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activities.
Preparation for the job included the use of a mock-up model of the pump to facilitate the training of primary and backup teams involved in the job, including maintenance, engineering, radiation protection, and QC personnel.
The mock-up training included simulated
steps of establishing boundary conditions, staging of tools, drilling of
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injection holes, the installation of injection nozzles, and furmanite injection.
Members of the NRC inspection team were favorably impressed by what appeared to reflect thorough job planning, preparation, and i
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trGining associated with the tasks involved.
The NRC team focused particular attention on the overall work planning associated with this
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Job since it involved the utilization of contract work forces, a task not routinely performed, and a task performed under unusual work conditions of high temperature and humidity as well as radiological t.onditions j
requiring special work planning to minimize radiation exposures to personnel.
The overall assessment of the team was that work planning has continued to show improvement during the course of Phase !! of the NRC's Enhanced Operational Inspection.
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Procedure Adequacy and Adherence Discussions between members of the NRC's inspection team and control room operators prior to the conduct of STP-1023 revealed that the operators were of the opinion that it would be desirable and appropriate to manually open the backup pressurizer spray valve promptly following initiation of the test in anticipation of,a rapid increase in RCS pressure.
This anticipatory action by the plant operators would allow
the use of supplemental pressurizer spray not available after the main (or lead) spray valve had opened in response to an. automatic demand on
rising RCS pressure, due to interlock circuitry between the main and
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backup spray valves.
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The NRC inspection team expressed a concern to facility management that the anticipatory action contemplated by the control room operators in this instance was not covered by the plant operating procedures.
In response to the concern expressad by the NRC inspection team, a Procedure t
Temporary Change Notice was approved prior to conduct of STP-1023.
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temporary change to operating procedure A.3, Pressurizer and Pressurizer i
Relief Tank System, permitted the anticipatory action which the control i
room operators felt to be necessary.
Notwithstanding the action taken by licensee management in response to the NRC inspection team's expressed concern, the matter of procedural
adequacy was pursued by the NRC inspection team as a potentially generic management issue.
The generic concern by the NRC inspection team was i
I that there is an apparent continuing need for licensee management to emphasize the responsibility of all plant staff, including management and j
supervisicn, to strengthen and maintain a work environment which fosters a continuing sensitivity by all plant personnel to insure that written procedural guidance is complete and clearly reflects acceptable actions on the part of plant operators and others.
During t.he course of the inspection the NRC inspection team did observe
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actions by facility management which appeared to be responsive to the
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I team's expressed concern'regarding the adequacy of plant operating
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i procedures.
One such action was the issuance on August 8, 1988 of a
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momorandum to all plant operations personnel citing two recently
identified instances where operating procadures were in need of revision to reflect operating practices or a preferreo wie of operating plant i
i systems not specifically covered by existing operatic,g procedures.
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such instance cited was the opening of the backup pressurizer spray valve t
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discussed above.
The other instance was the starting of a high pressure j
injection (HPI) pump in anticipation of the need for additional makeup to l
the RCS following reactor trip.
The memorandum requested that plant operators think of other areas in plant operations where actions are taken by them which are different from that required by procedural requirements or where there is no procedural requirement covering the action.
Such instances are to be documented on Problem Feedback Reports
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for evaluation and incorporation into procedures as appropriate.
The l
l memorandum requested that the information be provided prior to September
q 16, 1988.
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Another action by facility management was the issuance on August 9, 1988
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of an Operations Special Order (No. 88-37), wherein clarification was provided regarding operation of the HPI system following reactor trip.
The special order stated that the starting of an HPI pump lined up to the borated water storage tank in anticipation of the need for additional makeup to the RCS following reactor trip is acceptable. The special order also addressed the subsequent injection of makeup water via HPI
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injection into the RCS cold legs in accordance with emergency operating procedure E.02.
The special order stated that foi trips which do not involve LOCA or overcooling transients' in.iection via the HPI syste'n through the "A" RCS Loop (normal makeup nozzle) will provide adequate makeup to maintain pressurizer level on scale, i.e., greater than 10 inches.
The undesirability of HPI injection into RCS loops B, C and 0 (with resultant thermal cycling of their associated injection nozzles),
except where "absolutely necessary" to prevent pressurizer level from decreasing below 10 inches, was also discussed.
Licensee representatives stated that clarifications provided to plant operators in Operations Special Order 88-37 do not cor.flict with the intent or content of existing operating procedures.
They did state, however, that existing proceduras would be evaluated and revisions made to incorporate the clarifications provided in the special order, as appropriate.
At the time of the Exit Meeting the subject of the completeness of cperating procedures was discussed in the context of a significant management issue to be examined further during future inspections.
The actions initiated by licensee management in response to the inspection team's concerns were also acknowledged, particularly the request made of plant operations personnel to provide feedback regarding the adequacy of current operating procedures.
6.
Control of Plant Instrumentation Calibrations In response to deficiencies identified during the previous Phase II Enhanced Operational Inspection, licensee management committed to the development of an Action Plan to evaluate and implement needed improvements in the control of plant instrument calibrations.
During the current inspection a member of the inspection team examined steps initiated by licensee management to address the deficiencies identified.
Discussions with Licensee representatives revealed that a comprehensive action plan, entitled Maintenance Department Calibration Proaram Action Plan and dated July 19, 1988, had been approved and issued for implementation.
The action plan addresses not only the specific deficiencies identified during the previous NRC inspection, but several additional actual or potential program deficiencies and needed program enhancements.
The action plan addresses needed improvements in the preventive maintenance program for plant instrumentation as well.
The action plan identified and established due dates for 23 separate actions to be completed over the next approximately 5 months, through December 1988.
The actions include numerous tasks aimed at standardizing methods of control and implementation of the instrument calibration
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program.
For instance, an ongoing evaluation by the licensee had
revealed an inconsistency among various calibration procedures regarding affixing calibration stickers to instruments following calibrations, with some procedures requirina such stickers and others not.
Another finding of the licensee's evaluation was that no grace period (or schedule tolerance) had been established regarding the time interval between scheduled calibration dates.
A grace period of 25% was subsequently established.
This grace period, according to licensee representatives, is not be be utilized in the actual scheduling of calibration dates.
Rather it has been established in recognition of the fact that groups of instruments are covered by a particular maintenance work request, and the calibration of the group of instruments may require several days to complets.
The grace period will also accommodate instances where work planning or other circumstances may delay the actual performance of scheduled work.
This item is closed for purposes of the NRC's Enhanced Operational Inspection.
It is anticipated that the implementation of selected action plan items will be examined during future inspections by Region V.
7.
Housekeeping and Plant Material Conditions Frequent tours of the plant by the NRC inspection team revealed no significant concerns with regard to housekeeping or plant material conditions.
Observations and/or questions which arose during tours of the plant were either answered on-the-spot or responded to satisfactorily during the course of the inspection.
Discussions were held with licensee representatives regarding two observations of plant material conditions which remained open at the conclusion of t'.e previous Enhanced Operation Inspection.
(See items 8.
J) and K) of Iospection Report 50-312/88-19).
These discussions revealed that additional evaluation and inspections by licensee representatives are required to resolve these items (which concerned minor steam and water Icakage through and in the vicinity of the auxiliary feedwater pump P-318).
The items remain open.
8.
Observations of Power Ascension Tests The conduct of the following power ascension tests at the 80% pewer level plateau were witnessed by members of the inspection team during the current inspection.
Test Procedure Number Title of Test STP-1023 Loss of Single Main feed Pump Test STP-10828 Reactor Trip Test, 80% Power STP-668 EFIC High/ Medium Docay Heat Test As discussed in paragraph 3. of this report, the performance of the plant operating crews during conduct of the tests was judged to be good, and reflected favorably upon the alertness of the licensed operators in the control room as well as their skills and knowledge of plant behavior and system operating procedures.
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Equipment malfunction was experienced during the conduct of each test.
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These malfunctions and actions taken or initiated by the licensee with regard to each are discussed below.
STP-1023 During the conduct of the test, the B Main feedwater pump (MFP-B), after initially responding to a demand to increase flow following the trip of MFP-A, experienced a relatively rapid decrease in flow.
The decrease in r' imp flow was contrary to the demand of the plant's integrated control system (ICS) which was to increase flow from approximately 40% to 65%.
Control room operators, recognizing symptoms of a malfunction of the plant's ICS or main feedwater control system, transferred control of MFP-8 from automatic to manual and were able to increase feedwater and stabilize plant conditions at a power level of approximately 65%.
Automatic reactor powee runback occurred in response to ICS demand, as designed.
Subsequent invectigation/ analysis by licensee maintenance and plant performance personnel revealed that the malfunction of MFP-B in automatic control had resulted form a component failure in the pump's Lovejoy controller.
The failed component, a Demand Setpoint Converter (module M-9), was replaced, and following post-maintenance testing the pump was successfully returned to automatic control.
An analysis of ICS performance, based upon system parameters monitored (and recorded) during the test, showed that this portion of feedwater control system functioned properly.
Following conduct of the test plant operacors were unable to restart MFP-A, which had been tripped to initiate the test.
Trouble shooting and investigation revealed the failure of a Ramp Rate Generator module (M-18)
in the Lovejoy feedwater controller to be the cause of pump malfunction in this instance.
The M-18 module was replaced, and the pump was returned to satisfactory operation.
Discussions with licensee representativr.s revealed a prior history of module failures in the plant's Lovejoy feedwater controllers.
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five module failures have occurred since plant operations were resumed in March 1988.
Overall reliability of the plant main feedwater system was discussed with licensee management, with particular emphasis on the frequency of module failures within the Lovejoy controllers.
Licensee management stated that funds have been budgeted to replace the current Lovejoy controllers with i
more reliable "state-of-the-art" controllers.
They stated that, although l
not yet firm, the current target date for replacement of the controllers is at the time of the next plant refueling outage.
Licensee representatives stated that, in the interim, a program of improved preventive maintenance, including planned periodic replacement of selected modules within the present Lovejoy controllers, is to be given priority consideration in an effort to improve overall system reliability.
I STP-10828 The test was initiated by manual actuation of the reactor J
trip circuit from a nominal power level of 80%.
The reactor protection system functioned as designed following initiation of the test.
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Subsequent to trip of the reactor, main steam safety valves (four
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associated with each steam generator, with specified set points ranging from 1050 to 1070 psig) lifted.
One of the MSSVs apparently failed to reseat properly resulting in a condition of slight overcooling of the
reactor coolant system (RCS), with corresponding decrease in RCS
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temperature and pressuia and pressurizer level.
In response to an indication of rapid decrease in pressurizer level, control room operators manually started the "B" high pressure injection (HPI) pump and subsequently manually aligned HPI injection valves to permit injection into all four RCS loops.
The actions by plant operators were in i
accordance with plant emergency procedure E.02.
During the post-trip
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l transient RCS pressure decreased to approximately 1775 psig, and I
pressurizer level decreaseo approximately 105 inches to a minimum level I
of approximately 30 inches.
RCS parameters (temperature and pressure)
were well within the acceptable posb trip response window.
Although the post-trip review had not been completed by the licensee at the conclusion of the current inspection, preliminary results of j
l investigation by licensee representatives revealed the following.
It had been determined, from a review of plant data, that one of the
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MSSVs (Valve PSV-20544) apparently lifted at approximately 1018 psig.
Reportedly the valve had last been set to lift at approximately 1030
l psig, which is below its specified maximum setpoint of 1050 psig.
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valve experienced a blowdown in pressure to approximately 930 psig before
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reseating.
The extent of blowdown experienced (approximately 11%) was in l
excess of that (4%) described in the Updated Safety Analysis Report
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(USAR).
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Licensee representatives stated that the minimum steam generator pressure of 930 psig experienced during the transient was, according to I
discussions held with the NSSS vendor, within conditions previously analyzed.
Tentative plans were to render MSSV PSV-20544 inoperable by mechanically gagging the valve, prior to resuming plant operation.
This action is allowed by the plant technical specifications which permit one of eighteen installed HS$V's to be inoperable.
With regard to HPI injection into all four RCS Loops during the i
transient, licensee representatives stated that the number of thermal l
cycles (approximately 40) experienced to date on the HPI injection l
nozzles were well within the number (110) allowed by the current piping stress analysis,
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The following additional observations by plant operators had been i
identified for resolution prior to plant restart as part of the licensee's post-trip review.
These items were not pursued by the HRC inspection team, other than by way of a cursory review for safety significance, l
a.
Auxiliary Boiler trip upon increase in steam demand.
(Not a safety-related system)
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b.
Low flow indication on HPI injection to RCS '.oop A.
(The licensee's
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preliminary evaluation was that this observation related to a flow instrumentation anomaly previously evaluated and understood.)
c.
Main turbine overspeed alarm.
(Preliminary evaluation by the licensee was that there was not an actual turbine overspeed condition, and that the alarm was a consequence of the peculiar design of the reactor trip / turbine trip circuitry.)
d.
"B" EH oil pump shutdown.
(Not a safety related pump)
e.
Immediate starting of an HPI pump by plant operators following reactor trip.
(This subject, which relates to procedural adequacy, is discussed in paragraph 5. of this report.)
STP-668 The purpose of this test was to demonstrate that the Emergency Feedwater Initiation and Control (EFIC) system would automatically control steam generator level at a predetermined level upon loss or unavailability of the main feedwater system.
The test was commenced early in the morning of August 6 by manually initiating EFIC l
system actuation, followed by the isolation of main feedwater to the j
The test closely followed termination of the reactor i
l trip test (STP-10828), discussed above.
Therefore, plant conditions included the availability of decay heat from the reactor core during
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conduct of the test.
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Upon manual initiation of EFIC both auxiliary feedwater (AW) pumps (P-318 and P-319) started automatically, valves in the AFW system positioned t
automatically, and feedwater lerels in the steam generators were satisfactorily controlled by the EFIC system at a nominal level (approximately 27.5 inches) in accordance with EFIC system design.
No anomalies were observed in the functioning of the EFIC system.
Approximately ten minutes into the test operators who were stationed at pump P-318 (a tandem, electric / turbine driven pump) reported to control
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l room operators that smoke was observed coming from the vicinity of the pump's outboard shaft packing gland.
Control room operators immediately shut the pump down.
I AFW pump P-319 continued to provide adequate flow to maintain the required l
steam generator levels, and the test was not interrupted as a consequence
of the removal of pump P-318 from service.
On August 9, 1988 licensee management met with members of the NRC i
l inspection team to discuss the results of short-term efforts to evaluate l
and correct conditions which led to overheating of the shaft packing on l
pump P-318.
It was reported that the packing had been replaced in the outboard shaft packing gland, and the pump was started and run for a period of approximately one hour on August 6.
During the one hour run temperatures of both the inboard and outboard packing glands had appeared normal reaching a stable temperature of approximately 90*F.
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had been started again on the morning of August 9 and run for a period of approximately two hours.
During this two hour run the temperature of l
l the inboard packing gland had increased from 85'F to 104*F, where it had l
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essentially stabilized - rising only two degrees over the last hour of
the test run.
The temperature of the outboard packing gland had
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increased during the two hour period from 81*F to 136'F, and was still increasing (at approximately 20 degrees /hr.) when the test was terminated.
These discussions also revealed that on two previous occasions since mid-March 1988 the pump had experienced overheating of the pump shaft packing similar to that which occurred on August 6 during
,
the conduct of STP-668.
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At the time of the Exit Meeting on August 9. NRC inspection team members expressed concern that overheating of the shaft packing on pump P-318 had been a repetitive problem over the past several months, and that actions by the licensee had not been successful in understanding and correcting
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cnnditions associated with this problem, t.icensee management stated that
,
investigative efforts involving representatives of the pump vendor as well as the packing supplier were currently in progress, and that a root
!
.
'
cause evaluation was to be initiated by the plant staff.
Licensee
management also committed to a meeting with the NRC Region V staff prior to a resumption of power operations to discuss continuing efforts to
,
J understand and resolve problems which have led to overheating of the pump
,
shaft packing gland.
A tentative date of August 11 was proposed for such
<
I a meeting.
Licensee management stated that subjects to be discussed i
during this meeting (on August 11) were to include the following:
i Consideration of longer term redesign, wherein a mechanical seal
...
would replace shaft packing on pemp P-318.
An assessment of the current packing gland design-including critical
...
dimensional considerations for packing rings and the location of a
,
lantern ring within the packing gland / stuffing box.
j A decrease in the interval for surveillance testing of pump P-318.
...
Short term resolution of conditions which have led to overheating of
!
,
...
packing over the past several months.
9.
Licensee Reviews and Evaluations of Proposed Tests
,
The NRC inspection team reviewed the test procedure packages for each of the following special test.s to be performcd during the current
!
inspection:
STP-1023 (Loss of Single Main Feed Pump Test), STP-10828 (Reactor Trip Test, 80% Power), and STP-668 (EFIC High/ Medium Decay Heat l
Test).
The test procedure package for each test included the documentation of the licensee's determination of the applicability of 10 CFR 50.59.
The licensee had documented a determination that 10 CFR 50.59 was not applicable to the tests, since neither test involved a change in the technical specifications or in the design basis for plant systems involved in the tests.
Based upon this determination a written safety
,
j evaluation had not been prepared to specifically address a determination j
as to whether the tests involved an unreviewed safety question.
i
-
-
g
-
s
.
,
.
- In response to discussion between ' %ensee representatives and a member of the NRC inspection team, licens66 representatives prepared a revised written safety evaluation for each test to address considerations of an unreview safety question.
The expanded safety evaluations were provided to the NRC inspection team, and found to be acceptable by a member of NRC's inspection team, prior to the conduct of the proposed tests.
Licensee management committed to reassess and revise as appropriate their current procedures governing safety evaluations, and associated documentation, of proposed special tests or changes to the plant to more specifically address a determination that such tests or changes do not involve an unreviewed safety question, where applicable.
It is
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L anticipated that implementation of this commitment will be reviewed during future inspections by Region V and NRR.
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10.
Exit Meetino The findings of the inspection were discussed with those licensee representatives indicated in paragraph 1. on August 9, 1988.
At this time licensee management reaffirmed plans to meet with the Region V staff to further discuss actions to be taken, particularly with regard to system / equipment malfunctions described in this report, prior to the i
resumption of plant operation.
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