ML20059F515
| ML20059F515 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 01/06/1994 |
| From: | Burski R ENTERGY OPERATIONS, INC. |
| To: | NRC OFFICE OF ENFORCEMENT (OE), NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| W3F1-93-0375, W3F1-93-375, NUDOCS 9401140050 | |
| Download: ML20059F515 (16) | |
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4 { 0:T* !13 W3F1-93-0375 A4.05 PR January 6, 1994 Director, Office of Enforcement U.S. Nuclear Regulatory Commission ATIN:
Document Control Desk Washington, D.C. 20555
Subject:
Waterford 3 SES Docket No. 50-382 License No. NPF-38 NRC Inspection Report 93-33 Reply to Notice of Violation Gentlemen:
In accordance with 10 CFR 2.201, Entergy Operations, Inc. hereby submits in. the response to the violations identified in the Notice of Violation and Proposed Imposition of Civil Penalty of the subject inspection Report.
in addition to the information provided in Sections 2 and 3 of NOV 9333-01, Entergy Operations, Inc. submits Attachment 2, as requested in Inspection Report 50-382/93-32.
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NRC Inspection Report 93-33 Reply to Notic~e of Violation W3F1-93-0375 Page 2-January 6, 1994 If you have any questions concerning this response, please contact' W. Pendergrass at (504) 739-6254.
Very truly yours, uc R.F. Burski Director Nuclear Safety RFB/WHP/ssf Attachment cc:
J.L. Milhoan, NRC Region IV.
D.L. Wigginton,.NRC-NRR R.B.~McGehee N.S. Reynolds NRC Resident Inspectors Office q
1 UNITED STATES OF AMERICA l
NUCLEAR REGULATORY COMMISSION q
i sj In the matter of
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Entergy Operations, Incorporated
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Docket No. 50-382 Waterford 3 Steam Electric Station
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R.F. Burski, being duly sworn, hereby deposes and says that he is Director, Nuclear Safety - Waterford 3 of Entergy Operations, Incorporated; that he is duly authorized to sign and file with the Nuclear Regulatory Commission the attached Reply to Notice of Violation and Proposed Imposition of Civil Penalty; that he is familiar with the content thereof; and that the. matters set.forth therein are true and correct to the best of his knowledge, information and belief.
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n6/ r R.F. Bur' ski I
Director, Nuclear Safety - Waterford 3 STATE OF LOUISIANA
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i Subscribed and sworn to before me, a Notary Public in and'for the Parish and i
State above named this
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., 1994.
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Notary Public My Commission expires LS r w u.rc, u
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AttachmentilLto;
- j W3F1-93-0375-1 Page -1 of 11 j
ATTACHMENT 1 ENTERGY OPERATIONS. INC. RESPONSE TO THE VIOLATIONS IDENTIFIED IN I!HE NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY OF INSPECTION REPORT 93-33
'l VIOLATION NO. 9333-01 During an NRC inspection conducted September 14 through October 7, 1993, violations of NRC requirements were identified.
In accordance with the
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" General Statement' of Policy and Procedure for NRC Enforcement Actions,"
10 CFR Part 2, Appendix.C, the Nuclear Regulatory Commission proposes to impose a civil penalty pursuant to Section 234. of the Atomic Energy Act of j
1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular violations and associated civil penalty are set forth below:
A.
Technical Specification 3.6.2.1 requires, in part, that with the '
plant in Modes 1, 2, and 3, two independent containment spray systems j
be operable with each spray system capable of taking suction from the Refueling Water Storage Pool on a containment spray' actuation signal, With one containment spray system inoperable, T~S. 3.6.2.1 requires:
j that the inoperable containment spray system-be restored to' operable-i status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or that the plant be in at.least hot standby (Mode 3) within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; that the inoperable spray system be restored to operable status within the next 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or that the plant be in cold shutdown (Mode 5) within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Contrary to the above, from February 1 to September 30, 1993, with.
j the plant in Modes 1, 2, and 3 at various times, one of the two independent containment spray systems (Train A) was inoperable and i
the actions described above were not taken.
Specifically,. Train A of i
the containment spray system was inoperable because valve CS-125A, a normally closed containment spray header isolation valve, would not N
have opened under all conditions that would have required a j
containment spray system actuation.
B.
10 CFR Part 50, Appendix B, Criterion XVI requires, in part, that measures be established to assure that conditions adverse to quality, such as failures and malfunctions, be promptly identified and corrected.
In the case of significant conditions _ adverse to quality, the measures shall assure that the cause of-the condition is i
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' Attachment 1 to W3F1-93-0375 Page 2 of 11~
determined and corrective action taken to preclude repetition.
The identification of the significant condition adverse to' quality, the cause of the condition, and the corrective action taken shall be documented and repo'rted to appropriate levels of management.
1.
Contrary to the above, on February 1,1993, valve CS-125A in Train A of the containment spray system failed to open on demand, a significant condition adverse to quality, and the measures established by the licensee did not assure that the l
cause of the condition was determined and corrective action taken to preclude repetition.
Specifically, valve CS-125A failed to open.due to high differential pressure across the valve, no action was taken to correct this condition or prevent I
a repetition, and valve CS-125A failed under similar conditions on September 13, 1993.
2.
Contrary to the above, on September 13, 1993, valve CS-125A in Train A of the containment spray system failed to open on demand, and the measures established by the licensee did not assure that the condition was promptly identified and corrected.
Specifically, valve CS-125A was declared operable prior to taking any action to address the conditions that caused the failure of the valve to open, i.e., the'~
circumstances that were causing a high differential pressure to y
exist across the valve. The fact that the valve would not operate under certain conditions was not identified until September 24, 1993.
These violations represent a Severity Level III problem (Supplement 1).
Civil Penalty- $25,000.
BESPONSE (1)
Reason for the Violation A.
Entergy Operations Inc. admits tMs violation and believes that. the root cause for valve CS-125A inoperability is due to a system daign.
that did not allow for adequate system venting which allowed a condition to exist whereby higher than expected differential pressure across CS-125A could develop on pump start.
The differential pressure in some instances created a condition whereby CS-125A has failed to stroke on occasion; specifically, on February 1,1993 and September 13, 1993.
-to W3F1-93-0375 Page 3 of 11, A historical review of maintenance and. operational data pertaining to-CS-125A was conducted to determine whether or not the conditions made apparent in the September 13th failure existed previous to_that event.
Parameters and documentation researched in records included spray system component maintenance involving opening the system, recorder traces of "A" Shutdown Cooling header pressure, trended valve stroke time performance data, maintenance logs, spray riser phenomena notations, special test data, surveillance-data, quality-deficiency documents, and log entries.
In addition, special testing was performed to measure starting surge pressures under simulated accident actuation conditions.
(For a detailed-discussion of this event and subsequent system testing, refer to LER 93-004-001).
Based on the initial information gath3 red.via the special test, air was discovered to exist in the containment spray piping.
The presence of this air in the piping contributed to a pressure surge l
phenomena which was produced upon start of the containment spray pump.
The piping configuration and check valve arrangement of the train A containment spray piping just upstream of CS-125A facilitated capturing this pressure surge in the piping thus allowing a high differential pressure to be developed across the valve CS-125A.
It-is believed that the differential pressure across the valve, created a condition whereby the valve would rot operate consistently.
B.
Entergy Operations Inc. admits this violation in that after ' careful review of historical operational and maintenance records it was revealed that on February 1,1993, there was a documented failure of-valve CS-125A to stroke under conditions similar to those conditions observed during the September 13. 1993 event.
1.
Review of historical maintenance records-have shown that on February 1,1993, CS pump A was started for performance of ESFAS relay surveillance, OP-903-094.
Peak pressure.noted on the Shutdown Heat Exchanger inlet was 325 psig.
Subsequent.to the pump run an attempt was made to open CS-125A.
Nuclear Auxiliary Operator (NAO) logs indicate that the " valve failed to stroke" and had to be mechanically' agitated, after which, the valve successfully stroked with a 7.2 second stroke time.
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The maximum time allowed by the 'IST plan.is 10_ seconds.
Interviews with operations supervisors and maintenance personnel could not confirm that the valve completely failed to stroke but that the valve stroke was " jerky" in' movement, or the valve only " partially" opened, i
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- to W3F1-93-0375 Page 4 of 11 A Condition Identification (CI), 284418, was written to enter the failure in the corrective maintenance program. The C1-documented that the valve " failed to stroke smoothly".
On March'10, 1993 C1 284418 was assigned for work and the valve CS-125A actuator was lubricated.
The valve stroked smoothly after lubrication.
At that time, the failure of CS-125A was believed to be related to inadequate lubrication of the valve actuator. The actuator was lubricated and the valve was satisfactorily stroked. There were no indications apparent to the operations and maintenance personnel that any other problems associated with CS-125A existed. The IST valve stroke times were consistent with previous times and other indications appeared to be consistent with what was historically observed.
1 The work authorization was subsequently closed with the completion of actuator lubrication.
Plant personnel were not aware of the pressure surge phenomena that the A train was experiencing and corrected what was thought to be a sticky valve.
It was not until the September 13 event and subsequent system testing, that site personnel recognized the pressure surge and the affects of Train design on the pressure surge.
Subsequent to the February 1, 1993 event, and prior to September 13, CS-125A was stroked on six different occasions.
Each occasion the valve stroked successfully, with times consistent with previous times, and on three of the six occasions the valve stroked with a differential pressure across the valve.
2.
On September 13, 1993, containment spray train A was declared inoperable when it was discovered that the containment spray header isoiation valve, CS-125A, would not open with a high j
differential pressure across the valve.
The differential pressure developed during the performance of an ESFAS relay surveillance which started and ran the associated containment spray pump on its miaimum recirculation flow path. A high differential pressure remained across CS-125A after the pump was secured. The header was subsequently depressurized, the valve stroked satisfactorily and the Technical' Specification action statement was exited.
Operability of the valve at that time was based on evidence that the valve had successfully stroked, and that the stroke time was consistent with historical IST stroke times. Also, the only parameter that had changed was the high differential
Attachment ~1-to W3F1-_93-0375 Page.5 of 11 pressure across the valve.
It was believed that CS-125A would' perform its safety function when required and that the observed high differential pressure would not exist during receipt of a valid Containment Spray actuation signal (i.e., the high differential pressure was related to testing)..It'was believed that the spray valve would open before the' spray pump started therefore the differential pressure would not exist.
The valve's failure was documented by initiation of a Condition Identification (CI). The CI was assigned to engineering for problem evaluation.
After careful consideration and discussion with the vendor, engineering issued recommendations for interim actions to be implemented by the Operations' department.
In addition, a Condition Report (CR) and a NRC Event Notification were initiated on September 17, 1993. The notification was i
based on the conservative assumption that there was a potential for a condition to exist that could affect both trains of containment spray, thus preventing a safety function. The Event Notification was made pursuant to 10 CFR 50.72 (b)(2)(iii)(D). Operations department issued special-standing instructions to implement the engineering recommendations.
The standing instructions specifically stated the following: -1)
Prior to running either containment spray pump, declare the associated containment spray train out of service and comply with the applicable T.S.,
(2) When the containment spray pump is secured, verify the containment spray header pressure is bled down to reduce any differential. pressure across CS-125A(B), and (3) The recommended vent path is to be through the Shutdown Cocling Heat Exchanger Outlet to the RWSP valve, CS-ll8A(B), then declare the containment spray train operable.
The initial valve operability determination assumed that the worst case design basis accident was'a LOCA coincident with a j
loss of offsite power. Under this design basis accident, the 1
sequence of events would be such that CS-125A would receive an j
open signal prior to a spray pump start.
However, additional evaluation revealed that the worst case scenario was a Main Steam Line Break inside containment while maintaining offsite power.
In this case the spray pump and valve.would get an actuation signal at essentially the same time and analyzed peak containment pressure would be at its highest level.
It was, therefore, incontlusive as to whether CS-125A would come off 1
its seat just prior to the spray pump coming up to speed and i
l to-W3F1-93-0375-Page 6 of 11-relieving the pressure surge. With this additional information, on September 24, 1993, Site Directive W4.101, Nonconformance/ Indeterminate Analysis Process, was entered.
A special test procedure was developed for the gathering of system data and approved by the Plant Operational Review-Committee (PORC) on September 25, 1993.
Upon initiation of the-special test, containment spray. train ' A' was declared inoperable on September 25, 1993, at 1505.
Data gathered during performance of the special test revealed that CS-125A would not come off its seat prior to developing the differential pressure and was indicative of air entrained in the containment spray piping. The air in the piping created an excessive pressure surge upon pump start that was locked into' the piping at valve CS-125A by the upstream stop check valves, CS-111A and CS-117A.
Engineering personnel then revised the special test procedure to accomplish enhanced system venting of air from the system.-
The A train piping was inspected on September 25, 1993, and a portion of high point piping was discovered that did not have a vent valve. A vent valve was subsequently installed on September 26, 1993, and the piping vented. Other sections of piping were vented through the existing vents by sweeping the system with the containment spray pump.
Engineering continued to inspect the
'A' train piping for presence of air by'using ultrasonic testing methods.
A Nonconformance Condition Identification (NCl) was generated to evaluate the high i
pressure events that had occurred on the A train piping.
The i
evaluation concluded that no damage had occurred due to these events and system integrity had been maintained.
Containment spray train B piping was evaluated for similarities to train A.
The areas evaluated were piping physical layout, piping length, vent valve locations, piping slopes, previous surveillance tests, maintenance, and operational data.
Based on significant differences between A and B train and due.to the fact that none of the B train supporting systems were affected, the B train was considered to be operable.
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' Attachment 1 to
'l W3 F1 0375.
Page 7 of 11 On September 27, 1993, engineering personnel at Waterford 3-consulted hydraulic experts with Ebasco Engineering, in New
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York, and confirmed that the data collected supported that the pressure surge. phenomena observed was due to the presence of air in the piping.
After numerous sweeping and venting efforts, considerable: amounts of air were removed from the system. As quantities of air were removed from the system, the l
pressure increase observed at valve CS-125A was reduced.
Ultrasonic inspection of the piping on September 28, 1993, revealed that a section of piping had an air pocket remaining.
On September 28, 1993, a T.S. enforcement discretion was granted to extend the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement, for LC0 3.6.2.1, an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to install another vent valve to remove this air from the system. The new vent valve was installed on September 29, 1993, and venting operations continued.
In addition, a modification was completed to add additional venting capacity to the CS-125A valve actuator to decrease valve opening time.
Venting operations, CS-125A stroking, and ultrasonic testing of piping continued on the 29th.
A pressure test pump and "Flowscanner"-instrumentation was used to determine at what differential pressure CS-125A would stroke. The differential pressure stroke testing performed on.the 29th revealed that CS-125A continued'to-respond inconsistently when operated at pressures where it may be required to operate. The valve stroked at approximately 220 psid. This was below the design value of 300 psid.
It should be noted that throughout the testing, CS-125A, would stroke at-times and not stroke at others, depending on the pressure at the time of stroke and elapsed time between strokes.
On September 30, 1993, a test was performed to check for air intrusion at the containment spray pump. An insignificant j
amount of air was vented during this test.
The need for an emergency T.S. amendment became apparent on September 30, 1993, following the unsuccessful differential j
pressure tests of CS-125A.
T.S. amendment 86.was requested and granted on October 1, 1993.
Containment spray valve CS-125A was opened and the A train of containment spray was declared i
operable at 1630 on October 1,1993.
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I Attachment l to-U
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5-f W3F1-93-0375 Ji Page 8 of 11 j
In October 1993, Waterford 3 issued'a. Licensee Event Report (LER) pursuant to 10 CFR 50.73 (a)(2)(v) as an " event or condition that. alone could have prevented the fulfillment of the safety function of structures or systems that.are needed to mitigate the consequences of an accident".
However, after careful consideration and analysis it was determined that a l
more appropriate reporting requirement would be 10 CFR 50.73-(a)(2)(i)(B), "as operation or condition prohibited by Technical Specifications", in that only one of the two required redundant containment spray systems was inoperable for greater than the allowed outage time (See revised LER-93-004-01 dated December 30,1993). Waterford 3 will issue a revision to the LER to provide additional information which was not available in time for issuance of the original LER or its Revision 1.
2)
Corrective Steps That Have Been Taken and the Results Achieved l
Upon identification of the design deficiency, an emergency change to the Technical Specifications was requested, and granted,' allowing -
1 Waterford 3 to operate with CS-125A in the open position. This will l
prevent any future pressure surges in the A train of containment spray.
In addition, on November 3, 1993, a Condition. Review Board,.
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consisting of senior management personnel, was established to review condition reports and condition identifications to ensure proper priority and dedication of resources. The Precursor Trending Program-was also upgraded to review the input cards daily, ensuring that appropriate attention is given to any adverse conditions identified
.by this program.
I A special root cause investigative team was assembled to look at all 1
facets of this event.
It is Waterford 3's intent to continue j
investigation into the root cause(s) of this event and publish our findings in a future revision to LER-93-004-01 following Refuel 6.
j in addition, two self-assessment teams were assembled to review 1
events related to this issue. One corporate team and one in-house team.
Based on information received from these teams, several generic and specific corrective actions, discussed in section 3, will i
be implemented.
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. Attachment I to lI W3F1-93-0375
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Page 9 of 11.
(3)
Corrective Steos Which Will Be Taken to Avoid Further Violations q
The self assessment teams assembled to review the sequence of_ events y
associated'with CS-125A concluded that some causal factors existed j
with respect to the current Corrective Action Program. A summary.of_
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findings identified by the special root cause and self-assessment teams noted that the threshold for entering the Corrective Action Program did not appear to be commonly understood by site personnel, and a clarification of definitions appears to be warranted.
In addition several generic and specific corrective actions will be implemented.
1 Generic corrective actions include:
- 1) Conduct training sessions by i
department to accomplish the following goals:
a) emphasize corrective action program goals, b) define individual responsibilities, c) clarify entry requirements for the corrective action process, and d) discuss management expectations;
- 2) A-j Condition Review Board was initiated on 11/3/93, to review condition reports and condition identifications on the front end to ensure proper priority and dedication of resources; and 3) Daily Precursor Trending Program review.
Specific corrective actions include:
- 1) Evaluate procedures and design and implement changes as necessary to minimize pressure surges;
- 2) Inspect / repair / replace CS-125A and inspect CS-125B, with Vendor assistance during Refuel 6; 3) Based on Inspection a) review maintenance practices with respect to valve assembly / disassembly and-b) review and upgrade planned maintenance requirements;
- 4) Complete evaluation of potential for other systems to experience a similar problem; and 5) Upgrade piping design pressure prior to Refuel 6.
In addition the following procedures and Directives will be revised to further clarify definitions, responsibilities and actions: Site Directive W2.501, Corrective Action, Station procedures UNT-005-002, Condition Identification, and UNT-006-011, Condition Report.
As a good practice and part of Entergy's Total Q' ality' Improvement-u program, Waterford 3 has been participating as a Key Process Team member in the Key Process Analysis for Corrective Action / Root Cause Analysis. This Key Process Team was formed and has been active for the past year.
The mission of this team is to provide a structured corrective action process for Entergy Operations to realize the j
-benefits of early condition identification and timely,- effective and appropriate resolutions to conditions affecting Entergy facilities.
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A'ttachment 1 to
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Page 10'of 11-The team's short term goal is to address current program weaknesses-and share process strengths. The short term enhancements include I
various process adjustments, but more importantly, the changes include the development of common terminology, threshold criteria and measurement plans to ensure that the team is capable of measuring, trending and comparing performance at each of Entergy's facilities.
These enhancements are scheduled to be complete prior to the end of J
1994.
The team's long term goal is to converge the various processes q
towards a "best" process prior to the end of 1995. The team has developed a plan for continued analysis at the various facilities and j
has identified other companies for benchmarking to continue the process improvement cycle. As an element of Entergy's Total Quality Improvement program the Key Process Team will continue to monitor and i
adjust the corrective action / root cause analysis process as necessary for any future improvements.
(4)
Date When Full Compliance Will Be Achieved l
Compliance with Generic corrective actions will be achieved as follows:
- 1) Training sessions by department are in progress and will be completed by January 12, 1994.
- 2) The Condition Review Board was established on November 3, 1993, and continues to function reviewing Condition Reports (CR's).and Condition Identifications (CI's).for proper priority and dedication of resources.
- 3) The Precursor Trending Program upgrade to provide for daily review will be completed by January 12, 1994.
Compliance with Specific corrective actions will be achieved as follows:
- 1) Procedure and design evaluation for minimization of pressure surges will be completed by June 1,1994,
- 2) Inspection and work associated with CS-125A and B, with Vendor-assistance, will be accomplished during Refuel 6 which is scheduled to begin March 4, 1994.
- 3) Review of maintenance practices with respect to valve assembly / disassembly and reviv and upgrade of planned maintenance 1
requirements will be accomplished by August 1, 1994.
- 4) Evaluation of potential for other systems to experience similar problems will be completed by January 12, 1994.
- 5) Piping design pressure upgrade-will be accomplished prior to Refuel 6, scheduled to begin March 4, 1994.
, to W3F1-93-0375 Page 11 of ll
-Revisions of Procedures and Directives necessary to facilitate implementation of the appropriate Corrective Action Program changes are scheduled to be completed by March 31, 1994.
Procedures-and directives scheduled to be changed are:
Site directive W2.501, i
Corrective Action, Station procedures UNT-005-002,. Condition Identification, and UNT-006-Oll, Condition Report.
A supplemental report to the LER-93-004-01 will be submitted by August 31, 1994 outlining the findings. and actions related to this event.
At this time Waterf ord 3 will be in full. compliance.
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.,I W3F1-93-0375 Page 1 of 2 ATTACHMENT 2 ENTERGY OPERATIONS. INC. RESPONSE TO INSPECTION REPORT 93-32 (SECTION 2.2) frent Descriotion On October 11,1993 Operations was performing OP-903-094, ESFAS Subgroup Relay Test, Operating when MS-120B, Main Steam Line 2 Normal Drain Valve, failed to close, as required, after receiving an ESFAS test signal.
The valve failed to stroke close because the valve motor. overloads tripped when a close signal was sent to the valve. The Shift Supervisor did not declare the valve inoperable and enter the appropriate Technical Specification Action Statement, nor was the occurrence documented by the Station Log, a Condition Identification or a Condition Report.
An operator was dispatched to reset the overloads and to manually stroke the valve in an apparent attempt to move the valve off its backseat. The valve was subsequently retested and stroked closed in accordance with its surveillance procedure.
The valve was stroked three times successfully within one hour.
The control room staff did not initiate a CI immediately because they felt that MS-120B no longer had a hardware problem, however a Precursor Trending Program (PTP) card was filled out to record the event.
This was based on the fact that the valve had been successfully stroked manually-and had successfully passed its surveillance test and the overloads had remained reset during successive retests.
On October 13, 1993, after review of the previous events by Operations and STA management, the control room staff conservatively declared the valve inoperable, wrote a CI and a CR. Maintenance personnel subsequently examined the valve operator using the Valve Operation Test and Evaluation System (VOTES) and found that the valve parameters were within acceptable limits even though there was a slight increase in the closing torque value.
No other problems were found. On October 15, 1993 the valve was again returned to its operable status.
Entergy Operations Inc. believes that Control Room personnel failed to
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immediately declare the valve MS-120B inoperable and enter the appropriate Technical Specification Action Statement on October 11, 1993 when the valve failed to stroke in response to an ESFAS test signal, and that the event was not appropriately documented until October 13, 1993, when a Condition Identification (CI) and a Condition Report (CR) was initiated.
. to W3F1-93-0375.
Page 2 of 2 The Root Cause of the valve's failure to stroke is not known conclusively at this time. MS-120B did not stroke close initially with an ESFAS signal applied, however, it has successfully stroked on all subsequent attempts.
Testing and examination have not revealed any parameters outside the normal l
bands, except for.a slight increase. in.the closing torque value. A review i
of maintenance history was performed, and no maintenance has been performed since MS-1208.was last tested satisfactorily per OP-903-094.
Further evaluation will be performed for root cause determination.
Actions to orevent recurrence In addition to those Corrective Actions delineated in Attachment 1, Condition Report 93-186 prescribes several corrective actions to prevent recurrence.
Actions specifically related to this event are as follows:
- 1) Operations personnel were debriefed in accordance with~ the Improving Human Performance (IHP) procedure,
- 2) The Operations Superintendent has conducted interviews with all Operations Department Supervisors concerning.
equipment operability and the.use of the corrective action process,
- 3) Operations Personnel will review this event via the Priority 2 Required Reading, and 4) Valve MS-120B.will be evaluated further to attempt to determine exact root cause(s) of valve's initial failure to stroke.
The schedule for completion of corrective actions is as follows:
- 1) The IHP debriefings were completed, October, 1993,
- 2) Operations Superintendent interviews were completed November 2,1993,.3) The priority 2 required reading will be completed by March 18 -1994, and
- 4) MS-120B will be inspected during Refuel 6, scheduled to begin March 4, 1994, for further root cause evaluation (Cl 287718). At this time Waterford 3 will be in full compliance with CR 93-186.
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