Update 1/24
Still shutdown today? Have they made money in the last two years?
It would be so cool for the plant to trip today and LOOP? Would this be the last shutdown in the life Pilgrim plant. :)
NUCLEAR SAFETY
Pilgrim prepared for storm, operators say
The protocol has been tightened in the year since a blizzard-induced shutdown at the plant, a Nuclear Regulatory Commission spokesman says.
PLYMOUTH — Operators at Pilgrim Nuclear Power Station say they are ready for whatever the fast-traveling snowstorm heading up the East Coast this weekend, with accompanying 60 mph winds, brings their way.“We are monitoring the storm closely and have begun preparations under our coastal storm protocol,” Entergy Corp., the plant’s owner-operator, said Friday in a statement provided by spokesman Patrick O’Brien.One provision in the newly beefed-up storm plan calls for a pre-emptive shutdown based on the severity of the storm. “It has to do with wind speeds and the rate of snowfall,” Neil Sheehan, spokesman for the Nuclear Regulatory Commission, wrote in an email Friday.Entergy is holding off on that decision for now. “The currently projected storm path and weather conditions do not meet the criteria for a pre-emptive shutdown of the station,” the company statement said. “We will continue to monitor the storm closely and have appropriate staff and other resources available should conditions change.”The Pilgrim plant's 220-foot primary meteorological tower is still out of service, awaiting a part expected to be installed in February, according to Sheehan. The smaller backup tower will provide plant operators with vital information on wind velocity and direction.That second tower had been inoperable for several years and was just recently replaced. The plant must rely on the National Weather Service in Taunton whenever a single tower goes down and lacks backup.Representatives of the Plymouth Fire Department were at the nuclear plant earlier this week to review storm preparations, according to the town’s emergency management director, Aaron Wallace.It has been just about a year since a blizzard tore through the Northeast, knocking out power at Pilgrim. Problems began with electrical arcing in the switchyard, where power is brought to the plant and sent from the plant to the grid. Such switchyard problems date back as long as 30 years.Operators shut down the reactor during that January storm, but problems persisted, with the failure of a diesel-driven air compressor, a leaking safety valve used to depressurize the reactor, failure of a manually operated safety relief valve and failure of the high-pressure coolant injection system, which then leaked an inch of water onto the floor.Sump pumps could not clear it, since all nonvital functions at the plant had been shut down.The series of malfunctions during that storm prompted a week of federal inspections and contributed to the downgrade of the Pilgrim plant by NRC officials in September to among the three worst performers in the country.Entergy announced in October its plan to permanently shut down the Pilgrim reactor sometime before June 2019.Although some plant watchdogs warn there is no longer any impetus for Entergy to stay on top of plant maintenance, the Nuclear Regulatory Commission spokesman said Friday that procedures for addressing storms have been tightened since last year.“We have a resident inspector at Pilgrim who is continuing to closely track storm preparations,” Sheehan wrote. “For instance, site walkdowns were conducted yesterday to check for any loose debris that could be tossed by strong winds and impact the switchyard or plant infrastructure.“Also, a change put in place since last winter’s storms is the installation of heat lamps in the switchyard to prevent the kinds of electrical arcing events that have occurred in the past,” Sheehan continued. “We will be paying attention to the heat lamps’ effectiveness should they be needed during this storm.”David Lochbaum, director of the Nuclear Safety Project for the Union of Concerned Scientists, said the switchyard is always vulnerable to winds and icing. “The backup generators are the real safety net,” he said. “If they work, they effectively cool the reactor. Because of the problems in the past, (Pilgrim operators) may be more prepared and have a longer list of backups.”
The Weather Service recorded a wind gust of 70 miles per hour at the municipal airport in Marshfield.So far it looks like Pilgrim stayed up at power. Course Plymouth got only grazed by storm Jonas. But...
Update, 6 p.m.
PLYMOUTH MA — Eversource crews on Saturday night restored power to all but about 100 customers after a snowstorm knocked out power to over 1,000.
Winter Storm Jonas brought blizzard conditions that knocked out power for more than 1,000 in Plymouth Saturday afternoon.
"Boston can expect the snowflakes to start falling between noon and 2 p.m. Temperatures will hit a high of about 30 degrees and a low of about 20 at night, said Frank Nocera, a National Weather Service meteorologist.
Nocera said the highest snow totals from the storm would be in the southeastern part of the state, where 8 to 12 inches of snow can be expected. The storm will also feature high winds that may bring down power lines and the possibility of coastal flooding, forecasters said."
Accuweather says Plymouth is going to get more than two hours of heavy snowfall this afternoon.The red outlined area is the National Weather Service's "Winter Storm Warning". Storm Jonas has intensified much more than anticipated in the models. South Shore Massachusett just a few hours ago wasn't supposed to get any snow at all.
Findings
Introduction. The inspectors reviewed a Green self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, “Instructions, Procedures, & Drawings,” for failure to follow the instructions in the chemical volume control system charging pump pulsation dampener bladder charging procedure. Specifically, the licensee used a gas cylinder containing argon, carbon dioxide, and oxygen rather than a pure nitrogen cylinder to charge the dampener. The gas leaked into the reactor coolant system and was subsequently activated by neutrons. Reactor coolant system activity significantly increased, which elevated dose rates in the auxiliary building.
It's the absence of a fix it quickly philosophy. The longer you got a mechanical defect in a system with degraded safety culture the greater the chances of a bigger problem popping up.Description. The Unit 2 chemical volume control system charging pumps have suction and discharge dampeners to reduce pressure pulsations caused by these positive displacement pumps. These dampeners are an accumulator tank with a nitrogen filled bladder. Nitrogen leakage through the bladder can result in the nitrogen entrainment in the water, which is pumped into the reactor coolant system. The licensee had been aware
of leakage from the dampeners and had implemented quarterly preventative maintenance tasks to check the pressure and fill the dampeners with nitrogen, if necessary.
On July 31, 2015, a reactor coolant sample indicated a rising trend in argon-41. argon-41 is a radioactive isotope of argon that is created when argon-40 in reactor coolant passes through the reactor and becomes irradiated. It undergoes decay, giving off a high-energy beta particle, increasing dose rates in the plant. A failure mode analysis team investigated the possible causes and identified the most likely cause to be a leaking charging pump dampener bladder filled with the incorrect gas.
On September 3, 2015, the licensee performed gas chromatograph sampling on the 2P-36C charging pump suction and discharge dampeners. Although the test equipment cannot test for percent argon content, the test determined that the suction dampener only had a 14.4 percent nitrogen content. The discharge dampener only had a 15.4 percent nitrogen content. If the dampeners were charged with nitrogen as expected, the content would be expected to be over 90 percent nitrogen. The licensee recharged the pulsation dampener with pure nitrogen, and dose rates in the plant returned to normal.
The addition and subsequent activation of argon caused the reactor coolant activity to increase by a factor of three over a period of two months. This increased the dose rates in the vicinity of piping associated with the chemical and volume control system, increasing dose to operators and radwaste personnel.
The licensee performed a cause analysis and determined that a human performance error caused the wrong gas to be used. Plant maintenance mechanics had performed pulsation dampener preventative maintenance on July 28, 2015. The mechanics retrieved a pressure gauge from the hot machine shop and went to the compressed gas cylinder storage rack. The mechanics measured pressure in the cylinders and chose the first cylinder that contained sufficient gas. The mechanics then proceeded to 2P-36C charging pump dampener fill connection, connected the cylinder to the charging header, and recharged the pulsation dampeners.
All of the gas cylinders in this storage location were the same color, and the labelling appeared similar unless read carefully. The mechanics failed to check the label on the gas cylinder to ensure that they chose a nitrogen bottle, and they incorrectly chose the single cylinder that contained a mixture of carbon dioxide, oxygen, and argon.
The licensee revised the procedure to require independent verification of the gas prior to charging pulsation dampeners.
Chemistry samples confirmed there was no change in oxygen content in the reactor coolant.
Analysis. The failure to follow the pulsation dampener charging procedure, which resulted in increased reactor coolant system activity and elevated dose rates in the auxiliary building, was a performance deficiency. The performance deficiency is more than minor because it was associated with the plant facilities/equipment attribute of the Occupational Radiation Safety Cornerstone and adversely affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, charging argon into a pulsation dampener with a known bladder leak resulted in an increase in reactor coolant activity, causing elevated dose rates in several plant areas. Using NRC Inspection Manual Chapter 0609 Appendix, C, “Occupational Radiation Safety Significance Determination Process,” issued August 19, 2008, the inspectors determined that the finding was of very low safety significance (Green) because it did not involve ALARA planning or work controls, did not involve an overexposure, did not have a substantial potential to be an overexposure, and the ability to assess dose was not compromised. The inspectors determined this finding had a cross-cutting aspect in the human performance area, Avoid Complacency, because the plant maintenance mechanics failed to implement appropriate error reduction tools such as self-checking and peer-checking. [H.12]
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, “Instruction, Procedures, & Drawings,” states that “Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.” Contrary to the above, on July 28, 2015, the licensee failed to accomplish an activity affecting quality in accordance with the procedure. Specifically, the licensee failed to charge a charging pump pulsation dampener, an activity affecting quality, with nitrogen as required by quality Procedure OP-2411.066, “Charging Pump Dampener Bladder 2M-115A, B, C and 2M-116A, B, C Charging, Checking and Depressurization,” Revision 5, Attachment 3, Supplement 1. Step 1.3 of this procedure required that nitrogen be connected to the charging pump pulsation dampener supply valve during the charging process, but a bottle with a mix of gases including argon was used instead. The error resulted in a significant increase in reactor coolant activity, with a resulting increase in dose rates in various areas of the plant. As corrective action, the licensee recharged the dampener with pure nitrogen and degassed the reactor coolant system to reduce dose rates in the plant. This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy because it was of very low safety significance (Green) and it was entered into the licensee’s corrective action program as Condition Report ANO-2-CR-2015-02576: NCV 05000368/2015003-01, “Failure to Follow Procedure Results in Increased Reactor Coolant Activity.”
***"On August 18, 2015, the licensee identified an adverse trend in unsecured doors, as documented in Condition Report CR-ANO-C-2015-03229. Specifically, the condition report documented that 15 condition reports had been written since May 1, 2015, for fire or high energy line break doors found open and unattended. The licensee addressed this trend by conducting a personal interface campaign at the plant entry area. As persons entered the station, managers stopped them, discussed the importance of barriers, and handed them a one page document with further information on why barriers are important to safety. In addition, departmental managers were given an action to develop a plan to verify or improve employee behaviors. Following these actions, two more condition reports identified doors that had been left open. Station management held a stand down on September 28, 2015, with all station employees to ensure that they understood the importance of door design and configuration.'
The inspectors found that the station had appropriately identified the adverse trend in regards to station behaviors, but had failed to document an adverse trend in the number of documented door deficiencies. In the past year, 31 condition reports documented deficient conditions on doors required for security, fire, high energy line break or flooding. Although the licensee failed to identify the trend, the inspectors determined that the licensee was addressing the conditions appropriately in the work management system. The licensee documented the observation in Condition Reports CR-ANO-C-2015-03972 and CR-ANO-C-2015-03973.This whole thing is frightening as hell below. Basically defective breakers and buses interacting with a roof leak....plus the issue gets lost in the bureaucratic document system. Instead of bureaucracies and documentation systems shining a light on problems early, it digs a big hole and buries the problems. Roof leaks are prime evidence of a severe safety culture problem. How long was the roof leak and why didn't the NRC step in before it damaged the bus and breaker?
***Introduction. The inspectors reviewed a self-revealing violation of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” for the failure to promptly identify and correct conditions adverse to quality. Specifically, the licensee failed to promptly replace short bus stabs with longer bus stabs in six safety-related motor control centers (MCCs) following a 2007 motor control center fault.
Description.
On April 21, 2015, non-safety MCC 2B-35 experienced a fault which melted bus bars and caused the feeder breaker to the MCC to open to isolate the fault, de-energizing multiple non-vital loads in the turbine building. Subsequent inspection and analysis determined that the fault was caused by a high resistance connection between the breaker for turbine building recirculation fan and the associated bus bars. Contributing to this condition, the licensee observed indications that water had dripped onto the bus bars from above from turbine building roof leaks. This event led the licensee to review a previous similar event and to assess the corrective actions for that event.
In October 2007, a fault had occurred in a Unit 2 motor control center when starting a charging pump, which tripped the motor control center feeder breaker and secured power to all the loads supplied by that motor control center. The licensee documented in Condition Report CR-ANO-2-2007-01512 that the cause of the fault was “limited physical stab engagement on bus”. The limited contact area between the breaker stabs and the bus bars was determined to be marginal for the current needed to run the charging
Good job Seabrook with getting back to 100% yesterday. The NEISO is at around $39 per megawatt hour. The price is shockingly low for such a cold spell. When is the businesses and ratepayer going to get a break?
Wholesale electricity prices and demand in New England
Friday, January 30, 2015 at 1:54PM
Year-over-year natural gas and wholesale power prices dropped in December on milder weather, lower demand
December’s average natural gas and wholesale power prices in New England were about half as much as the average monthly prices recorded during December 2013, due largely to milder weather that dampened demand. During December 2013, colder weather increased consumers’ use of natural gas for heating, resulting in natural pipeline constraints that drove natural gas prices higher. Those high fuel prices, in turn, pushed up wholesale power prices.
This past December, the average real-time price of wholesale power, at $42.47 per megawatt-hour (MWh)*, fell about 57% from the December 2013 average of $98.53/MWh. It was down by about 5% from November’s price of $44.86/MWh...
"Or the fix could be as simple as cycling each SRV open and close once every month to disrupt the oxidize bonding"
Right, Hope Creek this testing period had a 71% failure rate and Cooper has a 63% failure rate...kind of in the ball park, you think each?The drastic increase in failures compared to the last four outages should should raise the hairs on the back of your head. Any ethical engineering report like this should openly question this drastic increase and vow to immediately fix it. Why didn't they mention this in the report...what else is Cooper habitually not confronting and fixing at the plant? How come in Mrs Bower's letter to me on Hope Creeks SRV problems he didn't discuss the increase in setpoint accuracy problems? I just saying he is not discussing the painful truth... It is like he is a advertising executive and not a federal regulator. How many SRVs would have failed testing if the limits were +/- 1% or didn't have a stellite coating the on seat and valve? The +/- 3% and Stellite coating is accommodating these defectively designed valves. It is just giving a illusion they fix the problem. It is destructive "Normalization of Deviance" on steroids. It is a common organizational mental illness.
On the second SRV going INOP Cooper needs to be shutdown in 24 hours.You get it, a ethical organization(s) would never preform an experiment on nuclear power plant safety equipment. They would put the stellite coated internals and valve on a test stand and exactly model the environment and length of duty as in the nuclear plant. They would put the valve in a much more harsh environment than the plant, so the problems would be exaggerated. Then they would test the valves just like they do when it comes out of the nuclear plant. They'd never put that stellite into a nuclear plant without being 1000% sure how the stellite would perform. It would fix the lift setpoint accuracy problems. I am telling you something stinks rotten here.
LER 2015-001-01: 5 failed TS safety testing
LER 2011-005-00: 1 failed TS safety testing
LER 2010-001-00: 2 failed TS safety testing
LER 2008-002-00: 1 failed TS safety testing
LER 2008-002-00: 1 failed TS safety testing
***Read what this below sentence in the LER. This is Coopers title of the document. The NRC wants me to make believe these below 16 words don't matter. Ask Cooper what they are required to do in this case if they find this specific "condition prohibited by technical specification while at power". They are required to emediately shutdown. This is all "Catch 22" crazy circular logic. Right, "a loss of safety function.
Valve Test Failures Result in a Condition Prohibited by Technical Specifications and a Loss of Safety FunctionPLANT STATUSCooper Nuclear Station (CNS) was in Mode 1, Power Operation, at 100 percent power, when the event was discovered; i.e., January 26, 2015.BACKGROUNDThe pressure relief system includes three American Society of Mechanical Engineers code safety valves (SV) [EllS: SB] and eight safety relief valves (SRV) [EllS: RV], all of which are located on the main steam lines [EIlS: SB] within the drywell [EllS: NH], between the reactor vessel [EllS: RPV] and the first main steam isolation valve [EllS: ISV]. The SVs provide protection against over pressurization of the nuclear system and discharge directly into the interior space of the drywell. The SRVs discharge to the suppression pool and provide three main functions: overpressure relief operation to limit the pressure rise and prevent safety valve opening, overpressure safety operation to prevent nuclear system over pressurization, and depressurization operation (opened automatically or manually) as part of the emergency core cooling system [EllS: B J, BM, BO].Technical Specification (TS) Limiting Condition for Operation 3.4.3 requires the safety function of seven SRVs and three SVs to be operable. The nominal set pressure and tolerances for these valves are established in CNS TS Surveillance Requirements (SR) 3.4.3.1.The SRVs installed at CNS are Target Rock Model 7567F, two-stage, pilot-actuated valves with pilot assemblies comprised of Stellite 21 pilot discs and Stellite 6B pilot body seats. The pilot assemblies had been in continuous service since installation in Refueling Outage (RE) 27.Corrosion bonding occurs when the protective oxide layers of the seat and disc break down and allow a crevice corrosion process to develop between the seat and disc. The seat is machined and then lapped with the disc to create a tight fit with one another. During the material removal process (machining) on both the seat and disc, the protective oxide layer that provides corrosion protection is removed. Because the SRV pilot valves are then assembled, the oxide layer is not given sufficient time to reestablish itself naturally, and no external process, such as pickling, is done to ensure that the oxide layer is reestablished to its full extent without any breaks or discontinuities. When the SRV pilot valves are assembled, the seat and disc are jammed together and air cannot reach the surfaces, therefore the full benefits of the oxide layer of the anti-corrosion material is diminished.EVENT DESCRIPTIONOn January 26 and February 11, 2015, three complete SRVs and five SRV pilot assemblies, removed during RE28 in the Fall of 2014, were as-found tested at National Technical Systems Laboratories, formerly Wyle Laboratories.The pressure setpoint for SRV pilot assembly serial number 385 is 1090 psig. The TS SR 3.4.3.1 as-found limit of acceptance is 1090 +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1124 psig, 3.119% above the pressure setpoint. For informational purposes, the technicians performed a second and third lift. The results were 1087 psig and 1087 psig, both within 3% of the pressure setpoint.The pressure setpoint for SRV pilot assembly serial number 386 is 1100 psig. The TS SR 3.4.3.1 as-found limit of acceptance is 1100 +/- 3%. The first actual lift pressure of SRV number 386 was 1192 psig, 8.36% above the pressure setpoint. A second and third lift was performed and the results were 1108 psig and 1112 psig, both within 3% of the pressure setpoint.The pressure setpoint for SRV pilot assembly serial number 1242 is 1090 psig. The TS SR 3.4.3.1 as found limit of acceptance is 1090 +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1267.7 psig, 16.24% above the pressure setpoint. The results of a second and third lift were 1091 psig and 1090 psig, both meeting the pressure setpoint.After this failure, testing was halted in order to verify testing accuracy. Testing was found to be the same as used in years past, and testing resumed on February 10 and February 11 for the remaining five SRVs.The TS SR 3.4.3.1 as-found limit of acceptance for SRV pilot assembly serial number 1243 is 1100 psig +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1139 psig, 3.545% above the pressure point. For informational purposes, a second and third lift was performed. The results were 1112psig and 1105 psig, both meeting the pressure setpoint.SRV pilot assembly serial number 1241 was tested. The TS SR 3.4.3.1 as-found limit of acceptance is 1090 psig +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1138 psig, 4.404% above the pressure point. A second and third lift was performed. The results were 1106 and 1092 psig, both meeting the pressure setpoint.BASIS FOR REPORTCNS is reporting this event as an operation or condition prohibited by plant TS per 10 CFR50.73(a)(2)(i)(B), and also as a condition that could have prevented the fulfillment of the safety function of structures or systems as defined under 10 CFR 50.73(a)(2)(v).An existing engineering analysis demonstrated that the reactor vessel would not be challenged during an overpressure event. In addition, a new analysis determined that the existing Minimum Critical Power Ratio (MCPR) operating limit would have protected the MCPR safety limit in the event of an anticipated operational occurrence. As such, this event will not be counted as a Safety System Functional Failure for the Nuclear Regulatory Commission performance indicator since no loss of safety function occurred.SAFETY SIGNIFICANCEAlthough the TS related to the set point lift pressures of the SRV pilot valve assemblies were exceeded, an analysis of this event indicates that the design basis pressures to ensure safety of the reactor vessel and its pressure related appurtenances would not be challenged. Public safety was not at risk. Safety to plant personnel and plant equipment were not at risk.CAUSEThe direct cause of five of eight SRV pilot valves failing their lift tests is corrosion bonding.CORRECTIVE ACTIONSThe following corrective actions have been entered into CNS' corrective action program:1. CNS shall inspect the SRVs during disassembly to ensure there are no indications of binding, vibration, or other mechanical problems that might cause effects similar to that of corrosion bonding.2. Laboratory work, under the direction of CNS, shall be undertaken to confirm or deny corrosion bonding of the disc and seats as needed. A comparison with previous laboratory findings about SRV pilot valves will be performed to determine, if possible, the role time in-service played in the failures.3. Based on the results of the inspection and laboratory work, specific findings and corrective action recommendations in the form of a revised root cause investigation report will be completed.4. If no evidence to refute corrosion bonding is identified, ensure after machining and lapping processes have been completed, that the oxide, passive layer on the seat and disc are fully restored by pickling or an equivalent process.5. Presuming that no technical reason is discovered to prevent the following, submit to the Nuclear Regulatory Commission a Technical Specification change that requests setpoint changes as noted in EE 10-053; NEDC-33 543P, Revision 0, Class Ill, DRF 0000-0103-4647, dated February 2010; GE-H NEDC-3362OP, Revision 0, May 2011; and GE-H, report 002N5242-R0, entitled, Cooper Cycle 28 SRV Set Point Study.PREVIOUS EVENTSLicensee Event Report (LER) 2011-005-00 - On June 22, 2011, one of eight Target Rock SRV pilot valve assemblies failed to lift within TS lift setpoint requirements. Wyle Laboratories performed this testing. The pressure setpoint of the failed pilot assembly was 1090 +/- 32.7 psig; it lifted at 1199 psig. Two subsequent informational lifts were performed for the SRV pilot assembly and were within the TS pressure setpoint tolerances. The mechanistic cause was the same as reported in previous LERs, pilot disc-to-seat corrosion bonding.LER 2010-001-00 - On January 12, 2010, two of eight Target Rock SRV pilot valve assemblies failed to lift within TS lift setpoint requirements. Wyle Laboratories performed this testing. The pressure setpoint for the first pilot assembly is 1100 +1- 33.0 psig; the SRV pilot assembly lifted at 1166 psig. The pressure setpoint for the second pilot assembly is 1090 +1- 32.7 psig; it lifted at 1139 psig. Two subsequent informational lifts were performed for both SRV pilot assemblies and were within the TS pressure setpoint tolerances. The mechanistic cause was the same as reported in previous LERs, pilot disc-to-seat corrosion bounding.LER 2008-002-00 - On July 7 through July 9, 2008, the results of Target Rock SRV test data performed at Wyle Laboratories identified that one of eight SRV pilot assemblies failed as-found pressure setpoint testing. The SRV pilot assembly lifted at 1165 psig, outside its TS setpoint tolerance of 1100 +/- 33.0 psig. The mechanistic cause was pilot disc-to-seat corrosion bounding between the Stellite 21 pilot disc and Stellite 6B pilot body seat to cause the SRV pilot assembly to lift outside its TS setpoint tolerance.LER 2007-002-00 - On February 28 through March 2, 2007, the results of Target Rock SRV tests performed at Wyle Laboratories identified that one of eight SRV pilot valve assemblies failed to lift within its TS lift setpoint of 1090 +/- 32.7 psig. The failure was a result of sufficient corrosion bonding between the SRV pilot valve assembly Stellite 21 disc and the pilot valve Stellite 6B body seat to cause the SRV pilot valve to lift outside its TS setpoint tolerance.
"The corrective actions were to weld repair the affected piping followed by replacing piping with very corrosion resistant material(AL6XN)."They had to shutdown units two's fire water for two hours. They discovered the beginning or the leak in 2008 and it got lost in their terrible work document system until a huge pipe blew out. At one point, they brought a crew into the plant to replace the weaken section of pipe with the small pin hole leak in it. They botched the replacement job, they neglected (screw-up) to replace the leaking section of pipe...it was scheduled to be replace and they replaced the wrong section of expensive pipe.
NRC INTEGRATED INSPECTION REPORT 05000247/2015001 AND 05000286/2015001
(pg 27)The inspectors reviewed corrective action documents and WOs for identified degradation of the fire protection piping and conducted a walkdown to assess the material condition. In 2010, Entergy generated CR-IP2-2010-5187 due to the discovery of a through-wall leak in the fire protection piping downstream of valve FP-2. This leak was discovered during a UT conducted as extent of condition for a nearby through-wall leak documented in 2008 (CR-IP2-2008-0044). Entergy created WO 135106 to replace the corroded and corroding piping section. In November 2012, the WO was in a ready status and scheduled to be worked. Due to problems obtaining effective isolation for protective tagging due to valve leak-by, the repair was postponed and the work was not done. Entergy had planned a major maintenance outage for the fire protection system for May 2014 to repair leaking valves and sections of corroded piping. Despite being within the isolation boundary and ready to work, the section of piping containing the 2010 leak was not included in the scope of this work. WO 135106 was instead scheduled following Unit 3 3R18 RFO. The inspectors noted that Entergy did not consider the remaining service life of the degraded piping section when delaying the repair from 2012 to 2015. This issue was entered into Entergy’s CAP as CR-IP2-2014-6668.
December 21, 2015Vice President, OperationsEntergy Nuclear Operations, Inc.Indian Point Energy Center450 Broadway, GSBP.O. Box 249Buchanan, NY 10511-0249SUBJECT: PLAN FOR THE REGULATORY AUDIT OF THE SERVICE WATER INTEGRITY AND FIRE WATER SYSTEM AGING MANAGEMENT PROGRAMS PERTAINING TO THE INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION (CAC NOS. MD5407 AND MD5408)Dear Sir or Madam:By letter dated April 23, 2007, as supplemented by letters dated May 3, 2007, and June 21, 2007, Entergy Nuclear Operations, Inc. (Entergy), submitted an application pursuant to Title 10 of the Code of Federal Regulations Part 54, to the U.S. Nuclear Regulatory Commission(NRC) for renewal of the operating licenses for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3). The NRC staff documented its findings in the Safety Evaluation Report (SER) related to the license renewal of IP2 and IP3, which was issued August 11, 2009 and supplemented August 30, 2011 (SER Supplement 1), and November 6, 2014 (SER Supplement 2). Subsequent the issuance of SER Supplement 1, the NRC staff identified additional operating experience at several nuclear power plants regarding recurring internal corrosion, corrosion occurring under insulation, and managing aging effects for fire water system components. To address this operating experience, on November 22, 2013, the NRC staff issued interim staff guidance document LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” In accordance with the enclosed audit plan, the NRC staff plans to conduct an onsite audit of the service water integrity and fire water system aging management programs during the week of February 22, 2016. If you have any questions, please contact me by telephone at 301-415- 6459, or by e-mail at michael.wentzel@nrc.gov.Sincerely,/RA/Michael J. Wentzel, Project ManagerProjects Branch 2Division of License RenewalOffice of Nuclear Reactor Regulation
On September 28, 2015, at 20:46, with the Hope Creek reactor operating at 100% power, a human error during surveillance testing resulted in the actuation of the Redundant Reactivity Control System (RRCS), and subsequently, an automatic reactor scram on a valid low water level signal. At the time of the transient, a surveillance test of division 1 of the RRCS system was in progress. The test simulates a high reactor pressure signal. Plant data show the signal was entered in both channels of division 1 of the RRCS system. The resulting system actuation caused a trip of both Reactor Recirculation Pumps, and the actuation of the Alternate Rod Insertion (ARI) function of the RRCS system. As a result of these two actuations, reactor power lowered, causing reactor water level to lower to the Reactor Protection System (RPS) trip set point of +12.5 inches. The RPS initiated an automatic reactor scram. Reactor operators recovered water level to within the desired band using the feedwater system. Reactor pressure was maintained using turbine bypass valves discharging to the main condenser.CAUSE OF EVENT
The cause of this event is that the technician made an error in the performance of the surveillance test. The error was most likely caused by pressing the incorrect key on the common keyboard for the panel (placing the wrong channel in test). Based on a review of plant data (alarms and indications) and surveillance test simulation on the RRCS training simulator, it was concluded that the technician most likely recognized the unexpected conditions and attempted to correct his error. The technician did not understand that the pressure test signal had sealed in on the incorrect channel. When faced with an unexpected condition, the technician did not stop and seek supervisory guidance .. When the test signal was subsequently entered into the correct channel, the RRCS system actuation resulted. When the cause analysis determined that the cause was associated with a human error, and also determined the most probable error sequence, technician response to further questions could not be obtained, because the technician who was involved had resigned.
This excerpt is from a recent letter to me by the NRC's Mr Bower concerning Hope Creek. Is he trying to minimized the extent of the problems with Hope Creeks SRV problems or scrupulously telling us the complete story. Anyone nuclear whether nuclear employees or the NRC should be "sticklers for the details". Why was Mr Bowers Chief, Projects Branch 3, so inaccurate to me? I bet you he went to a spectacular college? Hope Creek over the years have habitually violated their "mechanical stresses on the torus and torus attached piping" (MAPI value).
First posting belowNRC official Mr. Bower: "In addition, the increase in mechanical stresses on the torus and torus attached piping due to the higher lift setpoints remained within code acceptable limits."For some some reason Hope Creek only put a few years worth of "mechanical stresses on the torus and torus attached piping" limits in their LERS. So the red highlighted data below is the times Hope Creek's violated or challenged the "MAPI values"(mechanical stresses on the torus and torus attached piping). Does not disclosing the MAPA values constitutes a cover-up.
*F 3.1% Ion-implanted discLER 2001-007-00
K 7.8% Disc not implanted
(psig) (psig) (psig)LER 2003-003-00
F013P 1216 1120 1087 -1153 8.6
F013H 1169 1108 1075 - 1141 5.5
F013D 1182 1130 1096 - 1163 4.6
(Again erratic testing documentation. There is no more "notes" on seat leakage?)
(psig) (psig) (psig)
*F013A* 1190 1130 1096 -1163 +5.3
F013D** 1196 1130 1096 -1163 +5.8
F013E** 1187 1130 1096 -1163 +5
*F013G** 1204 1120 1086 -1154 +7.5
F013J** 1165 1120 1086 -1154 +4
F013K** 1142 1108 1075 -1141 +3.1
F013L** 1191 1120 1086 -1154 +6.3
F013M* 1150 1108 1075 -1141 +3.8
* These valves failed due to seat leakageLER 2004-009-00
** These valves failed due to corrosion bonding/sticking of the pilot disc
(psig) (psig) (psig)
*F013A 1192 1130 1096 -1163 5.5%
F013B 1171 1130 1096 -1163 3.6%LER 2006-03-00
F013C 1207 1130 1096-1163 6.8%
F013D 1184 1130 1096 -1163 4.8%
*F013F 1156 1108 1075-1141 4.3%
(psig) (psig) (psig)
*F013A 1166 1130 1096-1163 3.2%
F013C 1166 1130 1096-1163 3.2%
F013K 1144 1108 1075-1141 3.2%***This LER below is when they began publishing a value(MAPI value) on the SRV piping stresses (LIMIT). The accident is SRV pipe break between the vessel and torus. It is a very dangerous kind or LOCA or pipe break. They could very quickly heat up primarily containment threating electrical cables and vessel level instrumentations.
(psig) (psig) (psig) Actual Limit*
*F013A 1195 1130 1096-1163 5.80% 3.00%
F013C 1203 1130 1096-1163 6.50% 21.80%
*F013F 1163 1108 1075-1141 5.00% 5.50%
F013G 1156 1120 1087-1153 3.20% 8.70%
F013K 1212 1108 1075-1141 9.40% 22.40%
F013L 1170 1120 1087-1153 4.50% 16.30%Licensee Event Report 2010-002-01
(psig) (psig) (psig) Actual Limit'
*F013A 1177 1130 1096-1163 4.20% 3.00%
F013C 1186 1130 1096-1163 5.00% 21.80%
*F013G 1199 1120 1087-1153 7.10% 8.70%
F013K 1172 1108 1075-1141 5.80% 22.40
%F013L 1192 1120 1087-1153 6.40% 16.30%F013P 1157 1120 1087-1153 3.30% 27.4%Licensee Event Report 2012-004-01
(psig) (psig) (psig) Actual Limit
F013B 1169 1130 1096-1163 3.50% 39.4%
*F013F 1193 1108 1075-1141 7.70% 5.5%
F013H 1157 1108 1075-1141 4.40% 37.7%
F013K 1202 1108 1075-1141 8.50% 22.40%
F013L 1193 1120 1087-1153 6.50% 16.30%
F013P 1185 1120 1087 -1153 5.80% 27.4%
(They are really erratic documenting this testing. So now this MAPI value is discontinued(LIMIT))without explanationLicensee Event Report 2013-007-00
(psig) (psig) (psig) Actual
*** F013A 1170 1130 1096-1163 3.5%
F013D 1192 1130 1096-1163 5.5%
F013F 1178 1108 1075-1141 6.3%
F013K 1149 1108 1075-1141 3.7%
F013L 1175 1120 1087-1153 4.9%Licensee Event Report 2015-004-01
The established "MAPI value" on FO13F in is past LERs (LER 2009-002-01) is 5.0% and in this LER they are in violation on F013F with setpoint accuracy of 11.90%. So they are in violation in this LER on setpoint accuracy and SRV piping stress values on F013F.
(psig) (psig) (psig) Actual
F013C 1216 1130 1096.1 -1163.9 7.61%
***F013F 1240 1108 1074.8 -1141.2 11.90%
*F013G 1208 1120 1086.4 - 1153.6 7.86%F013H 1148 1108 1074.8-1141.2 3.60%
F013J 1161 1120 1086.4 -1153.6 3.66%
F013K 1161 1108 107 4.8 -1141.2 4.80%
F013 L 1165 1120 1086.4 -1153.6 4.00%
F013 M 1207 1108 1074.8 -1141.2 8.90%
F013P 1221 1120 1086.4 -1153.6 9.00%
F013R 1169 1120 1086.4 -1153.6 4.38%
"During the scram, level 8 occurred immediately"So here we go again after a special inspection effectively nothing is fixed. Vessel level is just banging around...reactor vessel goes up and down like a mad man and tripping the feed pumps.
Power Reactor Event Number: 51644 Facility: RIVER BEND
Region: 4 State: LA
Unit: [1] [ ] [ ]
RX Type: [1] GE-6
NRC Notified By: DANIEL PIPKIN
HQ OPS Officer: HOWIE CROUCHNotification Date: 01/09/2016
Notification Time: 07:04 [ET]
Event Date: 01/09/2016
Event Time: 02:37 [CST]
Last Update Date: 01/09/2016Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(2)(iv)(B) - RPS ACTUATION - CRITICAL
50.72(b)(3)(iv)(A) - VALID SPECIF SYS ACTUATIONPerson (Organization):
VIVIAN CAMPBELL (R4DO)
Event Text
Unit SCRAM Code RX CRIT Initial PWR Initial RX Mode Current PWR Current RX Mode 1 A/R Y 100 Power Operation 0 Hot Shutdown
AUTOMATIC REACTOR SCRAM ON MAIN STEAM ISOLATION DUE TO ELECTRICAL FAULT
"On 1/9/16 at 0237 [CST], River Bend Station sustained a reactor scram during a lightning storm. An electrical transient occurred resulting in a full main steam isolation [MSIV] (Group 6) and a Division II Balance of Plant isolation signal. During the scram, level 8 occurred immediately which tripped the feed pumps. A level 3 signal occurred also during the scram. Subsequent level 3 was received three times due to isolated vessel level control. The plant was stabilized and all spurious isolation signals reset, then the MSIVs were restored. The plant is now stable in Mode 3 and plant walkdowns are occurring to assess the transient."
During the scram, all rods inserted into the core. The plant was initially cooled down using safety relief valves. Offsite power is available and the plant is in its normal shutdown electrical lineup.
