05000266/LER-2007-003, Regarding ESFAS Instrumentation, Lead/Lag Time Constants for Steam Line Pressure Outside Technical Specification Values
| ML071570538 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  (DPR-024, DPR-027) |
| Issue date: | 06/06/2007 |
| From: | Koehl D Nuclear Management Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NRC 2007-0043 LER 07-003-00 | |
| Download: ML071570538 (5) | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| 2662007003R00 - NRC Website | |
text
N Point Beach Nuclear Plant Committed to Aluclear Operated by Nuclear Management Company, LLC June 6,2007 NRC 2007-0043 10 CFR 50.73 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Point Beach Nuclear Plant, Units 1 and 2 Dockets 50-266 and 50-301 Renewed License Nos. DPR-24 and DPR-27 Licensee Event Report 266130 1 -2007-003-00 ESFAS Instrumentation, LeadlLaa Time Constants for Steam Line Pressure Outside Technical Specification Values Enclosed is Licensee Event Report 2661301 -2007-003-00 for the Point Beach Nuclear Plant Units 1 and 2. This LER discusses the discovery of steam line pressure instrumentation having lead/lag time constants outside Technical Specification values. This event is reportable in accordance with10 CFR 50.73(a)(Z)(i)(B) for, "Operation or Condition Prohibited by Technical Specifications" and 10 CFR 50.73(a)(2)(v)(D) for, "Event or Condition That Could Have Prevented Fulfillment of a Safety Function."
This m t a i n s no new commitments and no revisions to existing commitments.
' Site ~icd-president, ~ o i b t Beach Nuclear Plant Nuclear Management Company, LLC Enclosure cc:
Administrator, Region Ill, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC PSCW 661 0 Nuclear Road Two Rivers, Wisconsin 54241 -951 6 Telephone: 920.755.2321
LICENSEE EVENT REPORT (LER)
(See reverse for required number of digitstcharacters for each block)
FAS Instrumentation, LeadILag Time Constants for Steam Line Pressure Outside Technical Specification A
ESFAS n a n a na 9ia9:
SUPPLEMENTAL REPORT EXPECTED (14)
EXPECTED MONTH DAY YEAR YES (If yes, complete EXPECTED SUBMISSION DATE).
X NO SUBMISSION DATE (1 5)
ABSTRACT On April 7, 2007, procedure 1 ICP 04.001 El Reactor Protection and Safeguards Analog Racks Steam Pressure Refueling Calibration was completed to satisfy Technical Specification (TS) 3.3.2 Table 3.3.2-1 Function I el surveillance requirement (SR) 3.3.2.8. Five of the six steam pressure compensator modules were found to have lag time constants greater than 2.0 seconds (TS requirement =1<2). The sixth module was found to have a lead time constant less than 12.0 seconds (TS requirement >/=12). An engineering review of waveform graphs used during the calibration procedures identified a non-ideal curve and subsequent determination that a resistor was not appropriately bypassed resulting in the lead function not at zero during graph generation. On May 21, 2007, the calibration of Unit 2 steam pressure compensator modules was checked using procedure 2 ICP 04.001 E. All six steam pressure compensator modules were found to have lag time constants greater than 2.0 seconds; two had lead time constants less than 12.0 seconds. The corrective actions, a new methodology for curve generation combined with increased electronic noise filtering, is applicable to both Unit 1 and Unit 2, and has been in place since each unit's last refueling outage. A review of historical data shows the condition may have existed since initial plant operation. The safety analysis results demonstrated the minimal deviation from TS limits is of very low safety significance. U.S. NUCLEAR REGULATORY COMMISSION (1-2001)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION PAGE (3) 2 of 4 TEXT (If more space is requ~red, use addftional copies of NRC Form 366A) (17)
Event Description
Between April 4 and April 7, 2007, refueling outage calibrations were completed on six Unit 1 steam pressure instrument channels. The as-found values for all six pressure compensation modules identified time constants which were slightly outside the Technical Specification (TS) limits, and thus were inoperable.
The procedures used in calibration of these modules have historically included the development of graphical traces. The graphs were developed using a method called "Step Input." A different method, called "Ramp and Hold," combined with additional electronic noise filtering in test equipment, was used for the first time for Unit 1 calibrations during April 2007 to develop the graphical traces. Upon recognition of the Unit 1 time constants being outside of TS limits also having possible applicability to Unit 2, additional calibrations were planned. On May 24, 2007, calibrations were completed on all six Unit 2 steam pressure instrument channels in a sequential manner. The as-found values for all six pressure compensation module time constants were slightly outside the TS limits so these channels were declared inoperable. Each Unit 2 channel was sequentially calibrated with adjustments to time constants made such that the channel was returned to operable status during the calibration process. The first Unit 2 use of the "Ramp and Hold" methodology was during the 2006 refueling outage.
Event Analysis and Safety Significance:
The TS requirement for lag is =/<2 seconds. Five Unit 1 and six Unit 2 modules exceeded the TS lag value; the largest being at 2.2 seconds. The TS requirement for lead is =/>I2 seconds. One Unit 1 and two Unit 2 modules exceeded the TS lead value; the lowest being at 11.7 seconds.
A review of the safety analyses was conducted to determine whether the low steam line pressure safety injection setpoint (more particularly, the leadllag characteristics of the setpoint) had been credited in mitigating the effects of analyzed transients and accidents. Three analyses were identified that potentially credited the setpoint.
Rupture of a Steam Line (MSLB) - Core Response. This analysis evaluated the Peak Clad Temperature (PCT) and the margin to Departure from Nuclear Boiling (DNB) resulting from a postulated limiting main steam line break (MSLB). While this analysis credited the low steam line pressure safety injection as the primary trip, the assumed analytical setpoint was 350 psig and included a 1.5 second delay for sensing. The anticipatory leadllag functions were not credited. Based on this, the deviations in the leadllag module settings would not have had an adverse impact on the safety function credited with mitigating the analyzed transient.
Rupture of a Steam Line (MSLB) - Containment Pressure Response. This analysis evaluated the containment pressure and temperature responses to a postulated MSLB using computerized numerical methods. While the input "deck" for the computer runs included a Safety Injection (SI) system actuation setpoint of 51 5 psia for steam generator pressure, it was specifically noted in the description of input parameters that this setpoint was not a factor in the outcome of the analyses. Rather, the analyses concluded that the containment hi-hi pressure SI was received before the low steam pressure SI setpoint could be reached, specifically because the leadllag settings prevented processing the low steam pressure SI signal more rapidly. As a result, the low steam pressure SI was not credited with mitigating the containment pressure transient. LER NUMBER 6 NUMBER NUMBER FACILITY NAME (1)
Point Beach Nuclear Plant DOCKET NUMBER (2 05000266 U.S. NUCLEAR REGULATORY COMMISSION (1-2001)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME (1)
Point Beach Nuclear Plant DOCKET NUMBER 2 F q F l TEXT (If more space IS required, use addltlonal copies of NRC Form 366A) (17)
Rupture of a Steam Line (MSLB) - Mass & Energy Releases for MSLBs Outside of Containment.. This analysis developed the limiting mass and energy releases caused by a postulated High Energy Line Break (HELB) located outside of containment. The output of the analysis is used to determine the severity of potential harsh environments resulting from a HELB. As such, the first order considerations are the mass flow rate of steam emanating from a postulated break and the duration of the break flow before it is isolated.
Because safety injection alone does not precipitate main steam isolation, and the main steam isolation signal is independent of the steam line low pressure signal, minimal variations in the leadllag module settings would not have had a significant impact on the duration and mass flow rates of postulated steam line breaks evaluated by this analysis. Additionally, the HELB-related EQ parameters in the primary auxiliary building and the turbine building do not protect plant safety limits related to a fission product barrier.
Summary: In each of the three steam line break analyses that cited the low steam line pressure safety injection, the variations in the settings of the leadllag functions in the signal would not have been consequential should an actual event have occurred.
A review of TS Tables 3.3.1-1 and 3.3.2-1, RPS and ESFAS respectively revealed no other occurrences of specific leadllag time constant limits. TRM 2.1, the Core Operating Limit Report (COLR) for Unit 1 and TRM 2.1 for Unit 2, and TRM 2.2, Pressure Temperature Limits Report for Units 1 and 2 were reviewed. No occurrences of specific instrumentation leadllag time constant applicability was found in the TRMs.
Cause
The cause of the event was human error. The first occurrence was during the development of the calibration procedures prior to plant initial operation. The individual(s) developing the procedures failed to identify the difference between actual and ideal graphical displays of circuit output. Current engineering evaluations identified the inappropriate graphical display curves. The curves were not ideal because a resistor in the circuit is wired such that it can not be removed from the circuit during graph production. The resistor prevents establishing the lead function at zero. A lead function not at zero causes a slight difference in the graphical output that is not easily distinguished from an ideal exponential function. The test procedure does not require a comparison of the developed actual curve output versus ideal curve output. Rather, the actual curve is used to determine mathematical values subsequently used in doing calibrations. Circuit simulators were used to develop ideal graphs during the engineering evaluations done to determine the cause for exceeding the TS requirements. It was only under these close examinations, performed to explain the out-of-tolerance values, that the difference in graphs was discovered. Calibration procedure results back into the 1970s were reviewed. The reviews indicated the presence of the resistor in the circuit. It was therefore concluded the condition has existed since initial operation of both units.
Human error also prevented the identification of the problem in 2006 during the Unit 2 refueling calibrations.
Electronic noise is present in the circuit and is subsequently present in the graphical displays produced during testing. Technicians did not accurately select the mid-point of the electronic noise band during performance of the calibrations. Point selection techniques are addressed during technician training and are considered as "skill of the craft," and are not proceduralized. The levels of electronic noise were recognized after the Unit 2 calibrations were completed and were addressed by the use of additional filtering, implemented via test equipment software programming. Improved filter constants were employed during the U.S. NUCLEAR REGULATORY COMMISSION (1-2001)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME (1)
Point Beach Nuclear Plant DOCKET NUMBER 2 OIOL)02.6qF TEXT (If more space is required, use addrtlonal coples of NRC Form 366A) (17)
Unit 1 calibrations performed during April 2007. The resultant improved accuracy facilitated problem identification and understanding of the Unit 1 results.
Corrective Action
Previous calibrations had used a "Step Input" Method to generate graphical curves. A "Ramp and Hold" method was used for the first time during each unit's last refueling outage. The "Ramp and Hold" method effectively removes the effect of the R-12 resistor in the circuit, thus producing correct curves. The "Ramp and Hold" method has been incorporated into each unit's testing procedure for use in steam pressure channel calibrations. In addition test equipment software programming changes have been made. The reprogramming of Maintenance Test Equipment (MTE) was done in the time between the Unit 2 and Unit 1 refueling outages. The reprogramming is internal to the MTE, improving the electronic noise filtering which improves the accuracy and usability of graphical display outputs. Coaching and feedback discussions on point-selection techniques and "Ramp and Hold" methodology have taken place between Instrumentation and Control (I&C) technicians and supervisors.
System and Component Description:
The system that was affected is the Engineered Safety Features Actuation System (ESFAS)
Instrumentation; and specifically, the main steam line pressure (low) instrument loop to generate a safety injection signal. The ESFAS system monitors plant conditions that require Engineered Safety Features (ESF) equipment actuation and automatically initiates ESF equipment to mitigate plant accidents. The Safety Injection - Steam Line Pressure - Low function consists of three channels on each steam line. The three channels satisfy protective requirements with a two-out-of-three logic. The function is anticipatory in nature and includes a lead-lag ratio.
Previous Occurrences
A review of recent LERs (past three years) was performed. No events or conditions involving the same underlying concern or reason as this event were identified.
Failed Components Identified: None.
Additional Information
None.