IR 05000315/1999015
| ML17326A085 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 08/13/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17326A084 | List: |
| References | |
| 50-315-99-15, 50-316-99-15, NUDOCS 9908200040 | |
| Download: ML17326A085 (33) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
License Nos:
50-315; 50-316 DPR-58; DPR-74 Report No:
50-315/99015(DRP); 50-316/99015(DRP)
Licensee:
Indiana and Michigan Power 500 Circle Drive Buchanan, Ml 49107-1395 Facility:
Donald C. Cook Nuclear Generating Plant Location:
1 Cook Place Bridgman, Ml 49106 Dates:
Inspectors:
May 28, through July 16, 1999 B. L. Bartlett, Senior Resident Inspector B. J. Fuller, Resident Inspector J. D. Maynen, Resident Inspector Approved by:
A. Vegel, Chief Reactor Projects Branch 6 Division of Reactor Projects 99Q82QQQ40 99QSiS PDR ADOCK 05QQ03i5
EXECUTIVESUMMARY D. C. Cook Units 1 and 2 NRC Inspection Report 50-315/99015(DRP); 50-316/99015(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant support.
The report covers a 7-week period of resident inspection activities and includes follow-up to issues identified during previous inspection reports.
~Oeratione During this inspection period, the licensee restored all four (two per unit) diesel generators (D/Gs) to an operable status for Modes 5 and 6 (Cold Shutdown and Refueling). This marked the first time since January 11, 1999, that all four D/Gs were operable at the same time.
In addition, the operability issues with boration control were addressed and corrected.
The operability of the D/Gs and boration control resulted in the restoration of the plant's full capabilities in reactivity control, reactor coolant system inventory control, and AC power sources.
The recent actions by the licensee to restore the safety-related equipment to an operable status demonstrated an appropriate safety focus.
(Section 01.1)
The inspectors identified that the licensee was operating some systems in a cross-train configuration.
For example, the "A"Train residual heat removal pump was providing cooling to the reactor coolant system through the "B"Train residual heat removal heat exchanger.
The operating crews did not consider the potential implications of cross-train operation.
(Section 01.2)
The inspectors observed that in preparation for defueling, the licensee's conduct of the Unit 2 drain down of the reactor coolant system (RCS) was methodical and thorough.
When the licensee identified a discrepancy between the indicated RCS water level and the calculated RCS water level, the drain down was stopped until the discrepancy could be resolved.
(Section 01.3)
The inspectors identified that the licensee had removed the Unit 1 East Essential Service Water (ESW) pump from service even though the Unit 1 West ESW pump recently failed an In-Service Test. The inspectors concluded that operations staff lacked rigor in the assessment of the results of the test. Additionally, the inspectors noted insufficient involvement of engineering personnel in a decision by operations personnel to proceed with the planned removal from service of the Unit 1 East ESW pump.
(Section 01.4)
a The inspectors observed a crew in a simulator assessment and concluded that the use of an extra reactor operator (RO) was not consistent with normal plant operations.
The licensee had already identified questions regarding the consistent use of the extra RO and was in the process of revising the use of the extra RO during simulator evaluations.
(Section 05.1)
The licensee's efforts to increase the use of the corrective action program through the initiation of more condition reports (CRs) had resulted in a tower threshold for initiating CRs.
However, the inspectors identified three instances where CRs should have been written and CRs had not been initiated. (Section 07.1)
Operations. management noted a declining trend in configuration control and attention to detail. The inspectors concluded that the use of the functional area and programmatic assessment findings to identify the declining trend was effective.
In addition, the inspectors concluded that management expectations about configuration control were presented to the. plant staff in a timely manner, before an anticipated increase in plant workload. (Section 7.2)
Maintenance The inspectors identified that there was minimal contractor control for the safety-related work being performed on the Unit 1 West Component Cooling Water (CCW) heat exchanger.
The inspectors also determined that there was a programmatic deficiency in the licensee's understanding of quality assurance (QA) requirements.
Most licensee personnel questioned incorrectly assumed that ifa vendor had an approved QA program that the vendor was not required to followthe licensee's approved QA program.
{Section M1.2)
A non-cited violation was issued for the licensee's failure to have a department head review and approve the vendor's procedure for pulling tubes from the Unit 1 West CCW heat exchanger.
(Section M1.2)
A non-cited violation was issued for an inadequate procedure which was utilized to pull tubes from the Unit 1 West CCW heat exchanger, in that the procedure did n'ot provide guidance for removing more than one tube.
(Section M1.2)
Plant maintenance personnel have not always been effective at identifying and correcting the root cause of an equipment failure, and repetitive failures of safety-related component have occurred.
Within the maintenance organization, the quality of
,troubleshooting has varied. The licensee recognized this problem and issued guidance on how to perform troubleshooting activities. The troubleshooting guidance appeared to be effective; however, only a small number of troubleshooting activities have been performed since the troubleshooting guidance was issued.
Also, the licensee had not yet developed clear expectations for when the use of the troubleshooting guidance was required.
(Section M1.3)
~En ineerin
~
The inspectors observed that engineering personnel involved in the maintenance activities on the Unit 1 West CCW heat exchanger did not provide oversight to the contractors performing the work. In addition, once the inspectors identified the failure of the contractor to followprocedure, the engineering personnel did not initiate a CR.
(Section E1.1)
Re ort Details Summa of Plant Status The licensee maintained both Units 1 and 2 in Mode 5, Cold Shutdown, throughout. most of the inspection period.
On July 13, 1999, at 7:20 p.m., Unit 2 entered Mode 6, Refueling. The licensee had previously announced plans to temporarily remove all fuel from both reactors in order to safely and more expeditiously perform in plant work activities. During this inspection period, the licensee continued the Expanded System Readiness Reviews and completed the Level 1 system reviews.
Level 2 system reviews were commenced along with increased in plant maintenance and modification activities.
I. 0 erations
Conduct of Operations 01.1 General Comments The inspectors conducted frequent observations of control room activities and in-plant operation of equipment during the extended outage of both reactor units. Overall, plant operations were performed using approved operating procedures and reflected good operating practices.
Specific events and noteworthy observations are detailed in the sections below.
Restoration of "Green Path" The licensee had spent considerable effort in restoring safety-related equipment important for shutdown risk to an operable status over many months.
The licensee used a risk assessment process for removing equipment while in an outage.
Ifboth trains of equipment were operable, then the unit would be in a "green path." The removal of equipment from service could result in dropping down to increasingly risk significant yellow, orange or red paths.
Due to operability issues on the diesel generators (D/G)
and boration control, the licensee had been in an orange path on reactivity control since mid-January.
The licensee complied with Technical Specification requirements, but the equipment remained inoperable for an extended period of time.
During this inspection period, the licensee completed restoration of all four (two per unit)
D/Gs to an operable status.
This marked the first time since January 11, 1999, that all four D/Gs were operable at the same time. The licensee spent considerable effort in addressing the various technical issues which had caused the D/Gs to be declared inoperable.
The issues were discussed in Licensee Event Reports (LERs) 50-315/98016, 50-315/99001, and 50-315/99011.
There was also additional discussion in Inspection Reports 50-315/316-99001 and 50-315/316-99004.
The D/Gs were restored to full operability to meet Mode 5 and 6 operability requirements.
In addition, the operability issues with boration control were also addressed resulting in a restoration to a green path. The effort exerted recently by the licensee in restoring the safety-related equipment to an operable status demonstrated an appropriate safety focu Cross-T in of Safet -Related E ui ment Ins ection Sco e 71707 On July 12, 1999, at 1:53 a.m., the licensee commenced a drain down of the Unit 2, Reactor Coolant System (RCS). This drain down is discussed in additional detail in Section 01.3 below.
During a routine control room tour immediately prior to the drain down, the inspectors observed that the Unit 1 East ("A"Train) residual heat removal (RHR) pump was in operation, but discharging through the Unit 1 West ("8" Train) RHR heat exchanger.
In addition, the Unit 1 West Component Cooling Water (CCW) pump was operating to cool both the "A"Train and "8" Train Unit 1 components.
The inspectors interviewed licensee personnel and reviewed applicable procedures related to operation of systems in a cross-train configuration.
Observations and Findin s The inspectors questioned the control room staff about the purpose for running RHR in a cross-train configuration. The unit supervisor (US) stated that he was unsure of the precise reason why the "A"Train RHR pump was in operation. The US stated that because the "A"Train pump was the last pump run for surveillance testing, the "A"train pump was left running to avoid an unnecessary start of the "8" Train pump.
In addition, he stated that there was some small benefit to discharging through the "8" Train RHR heat exchanger for RCS letdown flow control.
The inspectors were concerned that operating safety-related components in a cross-train configuration could result in the licensee exceeding the design or licensing basis.
In addition, cross-train configurations could complicate system performance and recovery following partial loss of power events or other postulated accidents.
The inspectors questioned the manager of operations, shift manager, shift technical advisor, and the reactor operators about their understanding of the advantages, disadvantages, and potential safety issues involved with cross-train alignments.
Although the manager of operations appeared to understand the potential consequences of cross-train alignment, the operating crew had not considered that this method of operating plant equipment could result in unexpected system inter-dependencies.
The crew realigned the equipment by stopping the East RHR pump and starting the West RHR pump.
In addition, after inspector questioning condition report (CR) 99-18735 was written to document and correct the lack of an integrated operating philosophy. The CR stated that "... the operating crews tend to view plant operation in a functional group methodology rather than a integrated process.
That is, systems are viewed and operated individually rather than considering the interdependence of these systems.
This results in a fragmented rather than integrated operating philosophy."
The licensee's and inspector's review of the cross-tying of the RHR trains did not identify any safety-significant risk. In addition, the licensee did not cross-tie the RHR trains while Mode 1, Power Operation Conclusions The inspectors identified that the licensee was operating some systems in a cross-train configuration.
For example, the "A"Train RHR pump was providing cooling to the reactor coolant system through the "B"Train RHR heat exchanger.
The operating crews did not consider the potential implications of cross-train operation.
(Section 01.2)
Observations of Reactor Coolant S stem Drain Down Unit 2 Ins ection Sco e 71707 In preparation for performing a core off-load for Unit 2, the licensee performed a drain down of the reactor coolant system (RCS) to unbolt and remove the reactor vessel head.
The inspectors reviewed selected licensee condition reports, operability determinations, observed the pre-job briefing, and the drain down evolution.
Observations and Findin s As documented in previous inspection reports, the licensee had been in the process of performing Expanded System Readiness Reviews (ESRR) for most plant systems.
The ESRR process resulted in a large number of CRs and Operability Determinations (OD)
existing on plant systems necessary for core off-load. The licensee expended considerable resources in the review ofthe CR data base and the ODs to determine those applicable for core off-load.
Licensee personnel reviewed approximately 7,500 CRs and about 200 open ODs for applicability for the transition from Mode 5, Cold Shutdown to Mode 6, Refueling. Of these, approximately 200 items were determined to be applicable to the mode change and received a more detailed review. The purpose of the review was to identify those outstanding items that were required to be corrected prior to the mode change; the licensee scheduled and completed those items. The inspectors reviewed selected CRs and ODs as part of their assessment of the licensee's mode change review. The inspectors did not identify any CRs or ODs which had not also been identified by the licensee as being required for Mode 6. In addition, the inspectors did not identify any items remaining open that adversely affected Mode 6.
In addition to the individual reviews ofthe ODs noted above, the licensee performed an assessment of the aggregate impact of the ODs. This aggregate assessment, documented in CR 99-17871, determined there were no substantial adverse synergistic effects. The inspectors reviewed the completed CR prior to the licensee's initiation of the drain down and had no additional questions.
The inspectors observed the licensee's pre-job briefing and determined that it was thorough and in a'ccordance with plant procedures.
Substantive questions were asked by the participants including a representative of Performance Assurance.
Allquestions were answered prior to the start of the drain down. An inspector question regarding the lineup of RHR equipment was discussed previously in Section 01.2 above.
The licensee was methodical and thorough during the performance of the drain down.
The drain down was commenced at 1:53 a.m. using Procedure 02-OHP [Operations Head Procedure] 4021.002.005, Revision 13A, "RCS Draining." In accordance with the
procedure, the operators monitored the reactor vessel level indicators to ensure they were in close agreement with each other and monitored the tank to which the RCS was being drained.
In addition, the shift technical advisor (STA) monitored the drain down and performed independent calculations to account for the water being drained and the draining rate.
The calculations were in close agreement until approximately 5:22 a.m. at which time the drain down was stopped.
The STA calculated that the RCS level indicators should read approximately elevation 622'ue to the 7,300 gallons drained.
The operators reported that the level indicators (2-NLI-132 and 2-NLI-142) read 624'. The 2-foot level difference equated to approximately 1800 gallons. The drain down was stopped until the cause of the discrepancy could be identified and corrected.
The licensee subsequently determined that the cause was a calculational assumption that pressure in the RCS would remain constant at about 1.3 psig and in fact the pressure had dropped during the drain down to about 0.5 psig. The lower pressure had allowed more fluid to drain from the steam generator U-tubes resulting in an additional 2,000 gallons of fluid needing to be drained.
The calculations were revised and showed that the indicated level of 624'as.correct.
Conclusions The inspectors observed that in preparation for defueling, the licensee's conduct of the Unit 2 drain down of the reactor coolant system (RCS) was methodical and thorough.
When the licensee identified a discrepancy between the indicated RCS water level and the calculated RCS water level, the drain down was stopped until the discrepancy could be resolved.
Removal of the East Essential Service Water ES Pum from Service Unit1 Ins ection Sco e 71707 During a routine control room tour the inspectors observed that the licensee had removed the Unit 1 East Essential Service Water (ESW) pump from service for maintenance.
The removal from service occurred even though several hours previously the Unit 1 West ESW pump had failed an In-Service Test (IST) due to low developed differential pressure.
The inspectors reviewed procedures, reviewed completed surveillance tests, and interviewed personnel to understand the basis for the licensee's decision to remove a safety-related component from service when its opposite train counterpart was degraded and inoperable.
Observations and Findin s On July 2, 1999, at 4:00 a.m., the licensee removed the Unit 1 East ("A"Train) ESW discharge strainer and pump from service for maintenance.
Several hours earlier at 1:20 a.m., the Unit 1 West ("B"Train) had failed an IST. The pump failed the surveillance test due to low differential pressure.
The pump was required to develop approximately 64 psig differential pressure at 9,200 gpm, but test instruments showed that only 58 psig was reached.
The operating crew discussed the test failure with management.
Operations management determined that the flowwas sufficient to supply all required cooling for
"7
the present mode. The Unit 1 West ESW pump was declared inoperable as a result of the test failure but the pump was considered available for use.
The Unit 1 West ESW pump was already inoperable due to an inability to complete post-maintenance testing from previous maintenance.
This maintenance had included a replacement of the pump motor.
After operations personnel determined that the Unit 1 West ESW pump was inoperable but available, the operating crew removed the Unit 1 East ESW pump from service.
With the Unit 1 East ESW pump out of service, Unit 1 was left with only one available ESW pump and that pump was degraded.
To document the Unit 1 West ESW pump low differential pressure, operations personnel wrote CR 99-.17678.
The inspectors were concerned that the control room operators removed one safety-related component from service without fullyevaluating a degraded condition on the opposite train component.
The inspectors questioned the operators, operations department supervision and engineering supervision about engineering's involvement prior to deciding that the Unit 1 West ESW pump was available but inoperable.
The inspectors determined that engineering was not consulted and that operations department personnel had decided that engineering involvement was not necessary..
Afterthe decision, operations management stated that engineering personnel should have been involved in the decision making process.
The inspectors discussed the organization's decision to proceed with the planned removal from service of the Unit 1 East ESW pump with the operations manager and the plant manager.
Both managers agreed that additional evaluations should have been performed prior to removing the Unit 1 East ESW pump from service. The inspectors observed that operations staff demonstrated a lack of rigor in the assessment of the low differential pressure and a lack of sensitivity to the IST program. The managers agreed with the inspectors'omments.
Conclusions The inspectors identified that the licensee had removed the Unit 1 East ESW pump from service even though the Unit 1 West ESW pump recently failed an IST. The inspectors concluded that operations staffs lacked of rigor in the assessment of the results of the test. Additionally, the inspectors noted insufficient involvement of engineering personnel in a decision by operations personnel to proceed with the planned removal from service of the Unit 1 East ESW pump.
Operator Training and Qualification 05.1 Simulator Observations Ins ection Sco e 71707 The inspectors observed one control room operating crew during a licensee simulator assessment as part of the routine cycle of training. Licensee personnel referred to the assessment as an "as-found" or "out-of-the-box" assessment.
The inspectors observed the performance of the crew, the performance of the training staff, and the feed back given to the crew following the simulator assessmen Observations and Findin s During the performance of the scenario, the crew requested an extra reactor operator (RO). This extra RO was allowed by plant procedures, and the crews had trained with an extra RO as a normal practice.
For this simulator assessment the crew did not have their own extra RO, so the training staff provided the extra RO. The extra RO was a role-playing instructor who had knowledge of the scenario.
In an effort to ensure he did not supply the crew with information that they would not normally have, the role-playing instructor only performed those duties directed by the US or shift manager.
This significantly restricted the flowof information from the extra RO compared to simulator sessions where the extra RO was provided by the crew.
The inspectors discussed the use of the extra RO with licensee management and determined that the use of the extra RO in simulator scenarios was being revisited in an effort to resolve questions such as this. The manager of operations stated that use of the extra RO would be maintained until at least the next set of annual requalification exams had been completed.
He also stated that because the crews had trained with the extra AO, removing that resource with just a few weeks remaining before the exam would not be appropriate.
During the performance of the observed scenario, the US failed to verify containment spray actuation following receipt of a containment spray signal. As a result, the Distributed Ignition System was not placed into service as required by plant procedures.
The training evaluators properly failed the US for the scenario, and the US agreed that failing to verify the containment spray actuation should have resulted in his failure.
However, the inspectors noted that while the evaluators discussed whether this was a failure for the individual or for the whole crew, there was no discussion as to whether the RO who reported the receipt of the containment spray signal should have done more to assist the US in the performance of the step.
The inspectors observed material condition discrepancies between the simulator and the control room. Most material condition issues were of a temporary nature and as such not normally reflected in the simulator, however, there were several issues that were long-standing and as such consideration should have been given to adding them to the simulator. An example would be leakby of the isolation valves to the main condenser start up air ejectors.
The leakby resulted in operator work arounds to manually close isolation valves prior to placing another start up air ejector in service.
After discussions with operations department personnel and various plant operators, the inspectors determined that consideration was normally given to adding issues such as the leaking isolation valves to the simulator.
Because numerous pieces of plant equipment had become inoperable and/or degraded since the plant shutdown in September 1997, the difference in the material condition between the shutdown and the modeled material condition ofthe simulator was significant. The licensee planned to address the material condition issue Conclusions The inspectors observed a crew in a simulator assessment and concluded that the use of an extra RO was not consistent with normal plant operations.
The licensee had already identified.questions regarding the consistent use of the extra RO and was in the process of revising the use of the extra RO during simulator evaluations.
Quality Assurance in Operations 07.1 Case S ecific Checklist Item 2A "Failure to Prom tl Identif and Evaluate Conditions Adverse to ualit "
As a result of NRC and licensee identified problems relating to the adequacy of the corrective action program, the NRC identified this performance area as one that requires oversight during the NRC's assessment of the licensee's restart effort as delineated in letters to the licensee dated July 30, 1998, and updated on October 13, 1998. The inspectors reviewed the following issue as it related to NRC Manual Chapter 0350 Case Specific Checklist Item 2A, "Failure to Promptly Identify and Evaluate Conditions Adverse to Quality."
Ins ection Sco e 71707 During this inspection period, the inspectors noted generally good performance by licensee staff regarding the initiation of CRs. The licensee had determined that the initiation of CRs should be encouraged and as a result the threshold had been lowered.
Previous licensee experience showed that 2,000 to 3,000 CRs would be initiated in an average calendar year.
By the end of June, 1999, over 18,000 CRs had been initiated.
However, the inspectors observed three instances where licensee staff should have initiated CRs but failed to do so. The inspectors performed followup to these failures.
Observations and Findin s Condition Re ort 99-19342 0 erations Review of Maintenance Job Orders Plant Manager's Standing Order (PMSO) - 184, "Senior Reactor Operator Review For Operability," was issued January 8, 1999. The Plant Manager's Standing Order required that "Prior to declaring any safety-related equipment operable, a Senior Reactor Operator (SRO) shall review applicable papenvork to assure all quality requirements have been fulfilled." The NRC inspectors interviewed the SROs regarding the quality of maintenance paperwork sent to the Shift Managers Office. The inspectors determined that the quality of the completed maintenance work orders had increased since the reviews first began in January.
The inspectors also determined that neither the SROs nor maintenance department personnel were writing CRs for identified discrepancies.
Following the inspectors observations, the licensee began writing CRs for identified discrepancies.
Condition Re ort 99-18735 Lack of anlnte rated 0 eratin Philoso h
As noted in Section 01.2 above, only after inspector prompting was a CR initiated for the cross-tying of RHR trains and the lack of an integrated operating philosophy.
Condition Re ort 99-18044 Procedural Non-Com liance Durin Vendor Tube Pullin Activities As noted in Section M1.2 below, the inspectors identified that vendor personnel did not have their procedure sign-offs up-to-date during the pulling of two tubes from the Unit 1 West CCW heat exchanger.
The inspectors discussed this failure with engineering and Performance Assurance (PA) personnel.
Two weeks later the inspectors requested a
copy of the CR written to document the vendor noncompliance and was informed that one had not been written.
Condition Report 99-18044 was written July 9, 1999, documenting the issue of procedural compliance.
During a briefing on CR 99-18044, a member of the licensee's staff identified that the CR detection code had been designated as "self-identified," when the code should have been "external driven" since this issue was NRC identified.
Condition Report 99-18546 was written on July 15, 1999, documenting the inappropriate code and documenting that other organizations sometimes had wrong'detection codes entered.
The scope of the CR was expanded to ensure that CRs identified by PA, NRC, and other groups were being properly coded.
c.
Conclusions The licensee's efforts to increase the use of the corrective action program through the initiation of more CR had resulted in a lower threshold for initiating CRs.
However, the inspectors identifie three instances where CRs should have been written and CRs had not been initiated.
07.2 Licensee Res onse to Ne ative Performance Trend in Confi uration Control a.
Ins ection Sco e 71707 On June 29, 1999, operations management identified that a number of recent configuration control errors indicated that plant personnel were not maintaining an appropriate awareness of configuration control. The inspectors followed the licensee's response to the negative performance trend.
b.
Observations and Findin s As part of the followup to findings in the Operations Area Functional Assessment and several programmatic assessments, operations personnel identifie a negative performance trend in configuration control. The licensee identified a number of recent events which indicated this trend.
For example:
On June 7, 1999, operations personnel were draining the Unit 1 AB emergency D/G fuel oil from the duplex oil strainer into a 10 quart bucket in support of engine maintenance.
The draining took longer than a single shift; however, the oncoming operations crew was not informed that the D/G was being drained. A small fuel oil spill resulted when the 10 quart bucket overflowed. (CR 99-14821)
On June 10, 1999, the essential service water side of the Unit 1 west component cooling water heat exchanger was placed under a clearance order for work before the heat exchanger was fullydrained. The assistant shift manager
electronically prevented anyone from performing work under the clearance order until the equipment status could be verified. (CR 99-15129)
On June 24, 1999, the Unit 1 US identified an error in the requested position for several Unit 1 emergency diesel generator throw over switches.
A physical interlock would have prevented the switches from being tagged in the requested position; however, the clearance request had been reviewed and verified without catching the error. (CR 99-16705)
On June 29, 1999, operations personnel noted a declining trend in the performance of clearance requests.
Several instances of tagging errors and inadequate clearance boundaries were identified. None of the errors resulted in equipment damage or personnel injury; however, operations management determined that the errors increased the potential for either damage or injury.
(CR 99-17286)
In response to CR 99-17286, operations management stopped the hanging and removing of clearance orders. A training plan was developed which was used to brief the operators on the recent errors and retrain them on the procedural requirements for hanging and removing clearances.
The training plan included descriptions of the recent errors and management expectations for clearance orders.
The stop work order was lifted on July 5, 1999, after all of the operating crews had been retrained.
Condition Report 99-18475 was written to document the negative trend, and long-term corrective actions to address the trend were being developed.
Plant management directed that a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> plant-wide work stoppage be used to brief the plant staff on the recent events and heighten their awareness to configuration control. Plant management expectations about configuration control were also discussed.
A procedure was being developed to more clearly define plant configuration ownership.
The inspectors determined that the work stoppage was timely due to the expected workload increase following the completion of the Expanded System Readiness Review discovery phase.
The inspectors discussed the negative trend with the licensee.
The inspectors determined that the use of the functional and programmatic assessment findings to assist in the identification of the trend was appropriate.
The inspectors also noted that management expectations about configuration control were presented in a timely
'anner, before the expected work load increase.
However, the long-term corrective actions for the negative trend had not yet been fullydeveloped at the end of this report period.
Conclusions Operations management noted a declining trend in configuration control and attention to detail. The inspectors concluded that the use of the functional area and programmatic assessment findings to identify the declining trend was effective.
In addition, the inspectors concluded that management expectations about configuration control were presented to the plant staff in a timely manner, before an anticipated increase in plant workload.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Ins ection Sco e 61726 62707 The inspectors performed routine observations of maintenance and surveillance activities in progress.
The inspectors observed procedure use and adherence, and radiological control practices.
~
Job Order (JO) C47952, 1 EHP [Engineering Head Procedure] SP.107, "Post Maintenance Testing For HFA Relays on Unit 1 AB Diesel Generator Controls,"
Revision 0.
,JO C47970, 12 IHP [Instrument Head Procedure] 6030.RLY.022, "General Electric Type HFA Multi-Contact AuxiliaryRelay Adjustment and Maintenance,"
Revision 3a.
JO R90310, 12 IHP 6030.IMP.334, "Fire Detection System Thermistor String Functional Test And Calibration - ATR Related," Revision 1.
1-OHP [Operations Head Procedure] 4030. STP [Surveillance Test Procedure]
022 W [West], Unit 1 West ESW Operability Test.
JO R71404 Inspect and clean as required Unit 1 East CCW heat exchanger 1-HE-1 5W The inspectors also reviewed a number of recent troubleshooting JOs. The inspectors'bservations on the licensee's troubleshooting practices are discussed below in Section M1.2. The inspectors had no comments on the Unit 1 West ESW operability test, but comments on the licensee's use of the data from the completed surveillance test were discussed in Section 01.4.
M1.2 Contractor Control Durin Maintenance a.
Ins ection Sco e 71707 During this inspection period the licensee removed the CCW heat exchanger from service in order to identify and repair the cause of internal leakage.
The inspectors performed routine observations and follow-up to the licensee's assessment and repair activities.
b.
Observations and Findin s On June 10, 1999, Unit 1 West CCW heat exchanger was removed from service to correct internal leakage.
The licensee identified several material condition issues including, flaw indications in the tubes, pitting on the inside surface of the end bell covers, and missing coatings from the inside surface of the end bell covers.
The licensee determined that two tubes should be removed from the heat exchanger and sent offfor analysis in order to better understand the causes and sizes of the flaw indications.
Design change package (DCP) 1-DCP-433 was issued to authorize tube removal and the plugging of up to 115 tubes (5 percent of the total) in the heat exchanger.
An outside organization was contracted to remove the two tubes and perform the tube plugging.
The contractor performed the safety-related tube pulling and tube plugging with a traveler written under the contractor's Quality Assurance (QA) program and approved by the licensee (Traveler 2008691.003, approved June 9, 1999). The traveler contained a procedure for pulling tubes (STD-100.236, Revision 0, "Tube Sample Removal D. C. Cook CCW Heat Exchanger" ). Another traveler (Traveler 20008691.002, approved March 20, 1999) performed the tube plugging and was also written under the contractor's QA program.
This traveler contained the procedure necessary for tube plugging of the Unit 1 West CCW heat exchanger.
Observations of Licensee Contractor Oversi ht at the Job Site On June 24, 1999, the inspectors observed portions of the tube pulling activities. During the observations, the inspectors evaluated the licensee oversight of the contractor's work and evaluated the contractors'erformance and procedural adherence, The inspectors observed that there were two representatives of the licensee's engineering organization, and one PA representative but no maintenance representatives.
The inspectors also observed that the engineers and PA representative focused on the technical activities occurring and did not appear to be verifying contractor performance quality.
The inspectors questioned the contractor workers regarding their work activities and procedural adherence.
The inspectors noted that the workers were performing one step without signing offthe previous step as completed.
In addition, the contractor quality control worker was the only person who was knowledgeable of which specific procedural step the worker was performing. When questioned, the worker and the supervisor could not find which step in the procedure was being performed at that time. The inspectors determined that the quality of the work appeared adequate; nevertheless, the contractor was not complying with the licensee's QA program. The tube pulling was stopped while the workers signed offthe completed step; however, a CR was not initiated until prompted by the inspectors.
This issue was discussed in additional detail in Section 07.1 above.
The inspectors questioned personnel from the licensee's maintenance, engineering, and PA organizations to determine the effectiveness of the oversight performed during this maintenance activity. The inspectors had the following observations.
~
Maintenance Prior to June 22, 1999, the licensee had treated the tube plugging and sample removal as an engineering activity and not a maintenance activity. As such, maintenance had not been providing oversight.
On June 22, 1999, the licensee determined that maintenance should be providing oversight of the CCW maintenance activities. However, due to a miscommunication, the maintenance workers believed they were only to provide a coordination functio Consequently, maintenance personnel were not providing contractor oversight and control.
~
En ineerin The engineering personnel had not been trained on the procedural requirements for contractor control and were unaware of the requirements for contractor oversight.
As such, they were providing technical oversight but were not providing contractor oversight and control.
Performance Assurance The PA auditor did not identify that the maintenance organization was not providing contractor oversight and control. The PA supervisor also stated that the PA auditor was not required to provide contractor oversight and control but still should have identified the procedural adherence issue.
Review of A Pro ram Re uirements The inspectors reviewed the contractor procedures, QA requirements, and licensee procedure requirements.
The inspectors made the following observations:
10 CFR Part 50, Appendix B, Criterion II, "Quality Assurance Program," required, in part, that the quality assurance program shall be documented by written policies, procedures, or instructions, and shall be carried out throughout plant life in accordance with those policies, procedures, or instructions. The Cook QA Program Description (QAPD), Addendum 14A, dated March 26, 1999, Section 1.7.7.2.7, required that the originating or sponsoring department head review and approve contractor procedures.
Contrary to the above, the contractor procedure for pulling tubes, STD-100.236, Revision 0, "Tube Sample Removal D.C. Cook CCW Heat Exchanger," had been reviewed and approved by licensee engineers and supervisors but not by the originating or sponsoring department head.
The inspectors determined that the failure to have the originating or sponsoring department head review and approve a contractor procedure to assure that it met the quality requirements was a Violation of 10 CFR Part 50, Appendix B, Criterion II. This failure was documented in licensee CR 99-1 8559.
This Severity Level IVviolation is being treated as a Non-Cited Violation (NCV).
Appendix C of the Enforcement Policy requires that for Severity Level IV violations to be dispositioned as NCVs, they be appropriately placed in the licensee's corrective action program.
Implicitin that requirement is that the
~
corrective action program be fullyacceptable.
The D. C. Cook Plant corrective action program was not adequate and has been the focus of significant attention by your staff to improve the program.
While your staff and the NRC have not yet concluded that the corrective action program is fullyeffective, the corrective action program improvement efforts are underway and captured in the D. C. Cook Plant Restart Plan which is under the formal oversight of the NRC through the NRC Manual Chapter 0350 process, "Staff Guidelines for Restart Approval." Consequently, this issue is being dispositioned as an NCV (50-315/316-99015-01(DRP)).
The procedure being used by the contractor was inadequate, in that it could not be performed as written. Ifthe procedure had been used precisely as written then the contractor should have only pulled one tube.
Instead the contractor repeated those steps necessary to pull a second tube even though the procedure was not written to allow this. This is sometimes referred to as
"looping" back through the procedure.
10 CFR Part 50, Appendix B, Criterion V, stated that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.
Contractor Procedure STD-100.236, Revision 0, "Tube Sample Removal D. C. Cook CCW Heat Exchanger," was written in accordance
, with 10 CFR Part 50, Appendix B, Criterion V. Step 4.0, Performance, stated,
"NOTE: The following steps shall be performed in the sequence listed on each individual location...." Contrary to this requirement, the contractor employees repeated each step as often as needed in order to pull two tube samples from the Unit 1 West CCW heat exchanger.
Licensee personnel sometimes refer to repetitions such as this as "looping" through the procedure.
In Inspection Report 50-315/316-97002, dated March 27, 1997, a violation was issued for the looping of a procedure used for unloading new reactor fuel. The licensee's corrective actions for that violation did not appear to address contractor procedures.
As the violation issued in Inspection Report 50-315/316-97002 was more than 2 years earlier no inadequate corrective action violation exists.
This Severity Level IVviolation is being treated as a Non-Cited Violation (NCV).
Appendix C ofthe Enforcement Policy requires that for Severity Level IV violations to be dispositioned as NCVs, they be appropriately placed in the licensee's corrective action program.
Implicitin that requirement is that the corrective action program be fullyacceptable.
The D. C. Cook Plant corrective action program was not adequate and has been the focus of significant attention by your staff to improve the program. While your staff and the NRC have not yet concluded that the corrective action program is fullyeffective, the corrective action program improvement efforts are underway and captured in the D. C. Cook Plant Restart Plan which is under the formal oversight of the NRC through the NRC Manual Chapter 0350 process, "Staff Guidelines for Restart Approval." Consequently, this issue is being dispositioned as an NCV (50-315/316-9015-02(DRP)).
The licensee issued CR 99-99-18582 for the inadequate procedure formatting and CR 99-18411 was written for vendor procedural implementation requirements that differed from Cook requirements.
In discussions with both licensee and contract engineering personnel, the inspectors determined that the personnel did not understand the licensee's QA program. The personnel stated that ifa contractor had an approved QA program, then that contractor did not have to followthe licensee's QA program requirements as long as the contractor followed his own QA program requirements.
The licensee's QAPD is required by 10 CFR Part 50, Appendix B, Criterion II, to control activities affecting safety-related structures, systems, and components.
The vendor QA program did not supplant the licensee's QAPD and the inspectors followed up on the misconception.
The inspectors discussed the misconception with a PA supervisor.
The PA super visor discussed this finding with the PA auditors and determined that there was a similar misunderstanding within the PA department.
The inspectors than discussed this misconception with other licensee organizations including operations, maintenance, and engineering.
The same misunderstanding also existed in these organizations.
The licensee wrote CR'99-18508 to document a plant-wide misconception that vendors working under their own QA program were not required to followCook QA requirements.
The issue of licensee control of contractors was the subject of previous enforcement action. Enforcement Actions98-150, 98-151,98-152, and 98-186 were issued October 13, 1999. The licensee's response was issued March 19, 1999, and response to item A.3 addressed a violation for inadequate control of contractors on the ice condensers.
The licensee's corrective action for the inadequate control of contractors was still being implemented at the time of the maintenance on the Unit 1 West CCW heat exchanger.
As such, the corrective actions were still in progress during this inspection period. The licensee had issued a control of contractors procedure but had not yet implemented training for the revised program.
c.
Conclusions The inspectors identified that there was minimal contractor control for the safety-related work being performed on the Unit 1 West Component Cooling Water heat exchanger.
The inspectors also determined that there was a programmatic deficiency in the licensee's understanding of QA requirements.
Most licensee personnel assumed that if a vendor had an approved QA program that the vendor was not required to followthe licensee's approved QA program.
A non-cited violation was issued for the licensee's failure to have a department head review and approve the vendors procedure for pulling tubes from the Unit 1 West CCW heat exchanger.
A non-cited violation was issued for an inadequate procedure which was utilized to pull tubes from the-Unit 1 West CCW heat exchanger, in that the procedure did not provide guidance for removing more than one tube.
M1.3 Troubleshootin Practices Ins ection Sco e
On June 29, 1999, the operators energized the supply breaker for the Unit 2, loop 4 cold leg injection valve, 2-IMO-54, after its control transformer was replaced.
Approximately five minutes later, smoke was reported in the Unit 2 Kilovoltswitchgear room, and the control transformer was found to be damaged.
The inspectors interviewed maintenance personnel and reviewed operations togs, and condition reports regarding the event and the licensee's troubleshooting practices.
In addition, the inspectors reviewed a sample of recent corrective maintenance job orders.
'17
Observations and Findin s Re etitive Control Transformer Failures The control transformer in breaker 2-EZC-A-5B, the supply breaker for the Unit 2, loop 4 cold leg injection valve, 2-IMO-54, had been replaced following a failure in August, 1998.
Condition Report 98-3978 was written to document the event, and Job Order (JO)
C48726 was written to replace the transformer.
On June 26, 1999, the control transformer was replaced in accordance with JO C48726.
After the old control transformer was removed, the JO directed the electrician to
"Perform an inspection of the tub cavity to determine possible cause for control transformer failure." The electricians did not find any discrepancies in the tub cavity. No further troubleshooting was performed, and a new control transformer was installed in the breaker.
Approximately five minutes after being re-energized, the new control transformer for breaker 2-EZC-A-5B was damaged.
Following the second failure, more extensive troubleshooting was performed.
Maintenance electricians measured the cable resistance and found that the cables leading from the control transformer to containment penetration 2-CEP-4C1 were shorted at the penetration.
The licensee determined that the short at the containment penetration was the most likely cause for the damage to the control transformer.
The licensee concluded that the short existed prior to the June 1999, failure and that both control transformer failures were most likely caused by the same fault.
The licensee identified a similar recent event involving inadequate troubleshooting of a control transformer failure. The control transformer in the supply breaker to the Technical Support Center Ventilation AirConditioner, 12-TSC-S-1A failed on April24, 1999; however, no troubleshooting to identify the cause of the failure was performed prior to replacing the control transformer with one taken from a nearby breaker cubicle under JO C48897.
Shortly after being re-energized, the replacement control transformer also failed. The licensee began an investigation into these control transformer failures, but at the end of this report period, the cause of the control transformer failures had not been Identified.
The inspectors reviewed JO C48726 and JO C48897 and determined that the troubleshooting required by these JOs was not adequate to identify the root causes of the initial control transformer failures.
ln the case of breaker 2-EZC-A-5B, the cause of the control transformer failure was outside the tub cavity, at containment penetration 2-CEPAC1, but the wiring to the breaker was not inspected prior to installing a replacement control transformer.
The inspectors discussed this observation with maintenance supervision.
The maintenance supervisor stated that troubleshooting was not rigorous following the initial control transformer failures because the failures were assumed to be age-related.
The supervisor stated that, as a short-term corrective action, the maintenance staff had been briefed on the failures and the need to determine the root cause of equipment failures prior to performing corrective maintenance.
The inspectors determined that the safety significance of these control transformer failures was minimal since the affected equipment was not required to be operable while both units were shut down. However,
the lack of rigor in troubleshooting contributed to repetitive failures in safety-related equipment.
b.2 Recent Corrective Maintenance Job Orders The inspectors reviewed a sample of recent JOs involving corrective maintenance on safety-related equipment.
Most of the JOs reviewed required some troubleshooting as part of the corrective maintenance, but the inspectors found that the quality of troubleshooting varied. The inspectors discussed corrective maintenance JOs with maintenance management.
The maintenance supervisor stated that the maintenance departments performed troubleshooting inconsistently.
Troubleshooting plans were used when an obvious electrical or instrument failure had occurred, but plans were rarely used for mechanical failures. The inspectors identified two corrective maintenance activities which were completed with little or no troubleshooting.,
On May 4, 1999, a minor maintenance activity was performed to replace incorrectly sized bolts on the Unit 2 CD emergency D/G duplex fuel oil filter housing. As the maintenance worker was tightening the bolted connection, the
,filter housing fractured at one of the bolt holes.
Condition Report 99-10446 was written to document the event, and JO C49235 was written to replace the filter housing. The inspectors did not find any documented plan for troubleshooting the filterhousing fracture; instead, the JO directed the workers to replace the filterhousing. A new filterhousing was installed on June 29, 1999.
Several days after the new filterhousing was installed on the Unit 2 CD D/G, cracks were identified around the same bolt hole where the original housing had broken.
On May 13, 1999, licensee electricians tested the north boric acid storage tank heater thermal overload relays and wiring under JO C48810 to investigate the cause of a heater thermal overload trip. The same thermal overload had tripped in August 1998. The thermal overload was tested as a minor maintenance activity, and no abnormalities were found. The thermal overload was reset, but no further troubleshooting or work was done. When tested again after the second trip, no abnormalities were found. No further troubleshooting was performed; however, a JO was written to replace the thermal overload relay.
The cause of the heater thermal overload trip was not determined.
b.3 Job Orders with Troubleshootin Plans The licensee had identified that a tool was needed to control the development of a troubleshooting plan when problems and malfunctions occurred with plant equipment.
Previously, written troubleshooting guidance was provided within the job orders steps.
. Consequently, the quality of troubleshooting varied.
On May 24, 1999, a new Plant Managers'rocedure, PMP 2291.TRS.001, "Troubleshooting," Revision 0, was issued.
This procedure provided consistent troubleshooting guidance to maintenance personnel.
In addition to the troubleshooting discussed above regarding the control transformer in breaker 2-EZC-A-5B, the inspectors reviewed several troubleshooting activities which were written after the PMP was issued.
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On June 5, 1999, while performing a post maintenance test for the Unit 1 west ESW pump left strainer backwash drain valve (JO C48986), the thermal overload on the west strainer gate tripped. Job Order C49291 was written to
investigate the cause of the thermal overload trip. This JO required that PMP 2291.TRS.001 be used to develop a troubleshooting plan. The troubleshooting plan included checks for motor electrical failure, strainer mechanical failure, actuator failure, and limit switch failure. The licensee's inspection identified that the most likely cause of the failure was mechanical binding inside the strainer, and the additional inspections required by the troubleshooting plan identified several other minor electrical problems with the control transformer wiring and limit switch settings.
Action requests were written to correct the additional problems.
On June 27, 1999, the operators attempted to close the Unit 2 breaker 287 to complete placing Unit 2 on electrical back feed. The operators received a synchronization permissive indication, as expected, but when the hand switch was taken to the close position the breaker did not close.
Condition Report 99-17209 was written to document this event.
The licensee initially.
suspected a problem in the synchronization circuitry; however, while gathering component data as required by PMP 2291 TRS.001, the licensee identified that the breaker control wiring was wired incorrectly. Afterfurther investigation, the licensee identified that this particular breaker had been purchased from the vendor under a separate purchase order which did not clearly state that the breaker needed to have a non-standard control wiring configuration, and the vendor delivered a breaker with the standard control wiring configuration. A spare breaker with the correct control wiring configuration was installed in the Unit 2 breaker 287 cubicle, and Unit 2 was successfully placed on electrical back feed.
Only a small number of troubleshooting activities had been performed since PMP 2291.TRS.001 was issued.
As a result, the inspectors could not determine ifthe overall rigor of the licensee's troubleshooting activities had improved.
However, for the JOs in the sample which used the PMP to develop troubleshooting plans, the troubleshooting was effective in identifying the root cause of the equipment malfunction.
b.4 Corrective Maintenance Job Order Backlo The inspectors questioned the maintenance supervisor about how the troubleshooting plan would be used for corrective maintenance JOs written prior to May 24, 1999, when the troubleshooting PMP was issued.
The maintenance supervisor stated that all previously identified equipment failures would be reviewed to determine the need for a formal troubleshooting plan. However, the maintenance supervisor also stated that review of previously identified corrective maintenance activities was hindered by the lack of clear expectations for when the use PMP 2291.TRS.001 was required.
c.
Conclusions Plant maintenance personnel have not always been effective at identifying and correcting the root cause of an equipment failure, and repetitive failures of safety-related component have occurred.
Within the maintenance organization, the quality of troubleshooting has varied. The licensee recognized this problem and issued guidance on how to perform troubleshooting activities. The troubleshooting guidance appeared to be effective; however, only a small number of troubleshooting activities have been performed since the troubleshooting guidance was issued.
Also, the licensee had not
yet developed clear expectations for when the use of the troubleshooting guidance was required.
r E1 Conduct of Engineering III. En ineerin E1.1 General En ineerin Comments The effectiveness of observed engineering performance this inspection period was inconsistent.
The licensee's engineering organization expended considerable effort in assisting in restoring the core safety to a Green Path status discussed in Section 01.1. The effort reflected engineering's support to plant operations and to conservative decision making.
This is contrasted with the operators failure to involve engineering personnel in the decision that the Unit 1 West ESW pump was still available even though the pump had failed an IST for unknown reasons.
However, the ins'pectors observed that as discussed in Section M1.2, that engineering personnel were involved in the maintenance activities on the Unit 1 West CCW heat exchanger and did not provide oversight to the contractors performing the work. In addition, as discussed in Section 07.1, once the inspectors identified the failure of the contractor to followprocedure the engineering personnel did not initiate a CR.
IV. Plant Su ort R1 Radiological Protection and Chemistry Controls (71750)
During normal resident inspection activities, routine observations were conducted in the area of radiological protection and chemistry controls using Inspection Procedure 71750.
No discrepancies or uncontrolled releases of radioactive material were identified.
S1 Conduct of Security and Safeguards Activities (71750)
During normal resident inspection activities, routine observations were conducted in the area of security and safeguards activities using Inspection Procedure 71750.
No discrepancies were noted.
F1 Control of Fire Protection Activities (71750)
During normal resident inspection activities, routine observations were conducted in the area of fire protection activities using Inspection Procedure 71750.
No discrepancies were noted.
V. Mana ementNleetin s
X1 Exit Nleeting Summary The inspectors presented the inspection results to members of the licensee management at the conclusion of the inspection on July 16, 1999. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the-inspection should be considered proprietary.
No proprietary information was identified.
Licensee PARTIALLIST OF PERSONS CONTACTED
¹G. Arent, Acting Director, Regulatory Affairs
¹J. Arias, Compliance Manager
¹C. Bakken, Site Vice President
¹B. Bishop, Engineering
¹R. Gaston, Acting Compliance Manager
¹R. Keppeler, Engineering
¹W. Kropp, Performance Assurance
¹D. Kunsemiller, Engineering
¹G. Mountain, Regulatory Affairs
¹T. Nooman, Plant Manager
¹J. Reed, Maintenance
¹M. Rencheck, Vice President, Nuclear Engineering
¹B. Smalldridge, Operations
¹C. Vanderniet, Performance Assurance
¹K. VanDyne, Regulatory Affairs
¹D. Walker, Operations
¹L. Weber, Operations
¹ Denotes those present at the July 16, 1999, exit meeting.
IP 37551 IP 40500 IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92700:
IP 92901:
IP 92902:
INSPECTION PROCEDURES USED Onsite Engineering Corrective Action Surveillance Observations Maintenance Observation Plant Operations Plant Support Activities Onsite Review of LERs Followup - Operations Followup - Maintenance
~Oened 50-315/99015-01 50-315/99015-02 ITEMS OPENED, CLOSED, AND DISCUSSED NCV failure to comply with Quality Assurance program description NCV failure to followprocedure while pulling tubes from Unit 1 West CCW heat exchanger Closed 50-315/99015-01 NCV failure to comply with Quality Assurance program description 50-315/99015-02 Discussed None NCV failure to followprocedure while pulling tubes from Unit 1 West CCW heat exchanger
ccw CFR CR D/G DRP ESRR ESW IHP IST JO LER OD PA PMP QA QAPD RCS RHR RO SRO STA STP US LIST OF ACRONYMS USED Component Cooling Water Code of Federal Regulations Condition Report Diesel Generators Division of Reactor Projects Expanded System Readiness Review Essential Service Water Instrument Head Procedure In-Service Test Job Order Licensee Event Report Operability Determinations Performance Assurance Plant Manager's Procedure
, Quality Assurance Quality Assurance Program Description Reactor Coolant System Residual Heat Removal Reactor Operator Senior Reactor Operator Shift Technical Advisor Surveillance Test Procedure Unit Supervisor 25