IR 05000397/1988037
| ML17285A149 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 12/13/1988 |
| From: | Bosted C, Crews J, Johnson P, Sorensen R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17285A148 | List: |
| References | |
| 50-397-88-37, IEB-88-007, IEB-88-7, NUDOCS 8812290024 | |
| Download: ML17285A149 (23) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION REGION V
Report No:
Docket No:
Licensee; Facility Name:
Inspection at:
50-397/88-37 50-397 Washington Public Power Supply System P. 0.
Box 968 Richland, WA 99352 Washington Nuclear Project No.
(WNP-2)
WNP-2 Site near Richland, Washington Inspection Conducted:
October 1 - November 13, 1988 Inspectors:
IZ iZFE
. J.
Boste
, Senior es dent Inspector a
e sgne
/Z l4
~/
~
n, Ress ent nspector te
>gne J.
r w, en>or eactor ng) neer (
vembe~1 - 4, 1988)
e sgne Approved by:
P.
.
o nson, se Reactor Projects Section
a e
sgne Summary:
Ins ection on October 1 - November 13, 1988 50-397/88-37
~A<<d:
R i
i p
i b
h id i
f room operations, licensee action on previous inspection findings, engineered safety feature (ESF) status, surveillance program, maintenance. program, licensee event reports, special inspection topics, procedural adherence, and review of periodic reports.
During this inspection, Inspection Procedures 30703, 61726, 62703, 71707, 71710, 90712, 90713, 92700, 92701 and 92702 were covered.
Results:
Two violations of NRC requirements were identified, involving fail-ure to follow procedures for control of measuring and test equipment (para-graph 10.a)
and control of combustible materials within vital areas (paragraph 10.b).
Two unresolved items were identified involving control of mechanical jumpers (paragraph 10.c)
and surveillance of charcoal filters (paragraph 11).
8812290024 881213 PDR ADOCK 05000397 G
PNU
DETAILS 1.
Persons Contacted L. Oxsen, Assistant Managing Director for Operations D. Bouchey, Director, Licensing and Assurance
"C. Powers, Plant Manager
"J. Baker, Assistant Plant Manager K.
Cowan, Nuclear Safety Assurance Manager
¹L. Harrold, Generation Engineering Manager C.
Edwards, guality Control Manager
"R. Graybeal, Health Physics and Chemistry Manager
"J.
Harmon, Maintenance Manager A. Hosier, Licensing Manager
"D. Kobus, guality Assurance Manager
"R. Koenigs, Technical Manager
- S. McKay, Operations Manager
"J. Peters, Administrative Manager J. Tellefson, Engineering Administration Manager N. Porter, Electrical/IBC Systems Manager
"W. Shaeffer, Assistant Operations Manager R. Webring, Assistant Maintenance Manager M. Wuestefeld, Assistant Technical Manager D. Myers, Mechanical Systems Analysis Supervisor P.
Harness, Mechanical Systems Engineering Supervisor S. Kirkendall, Reactor Sys'tems and Analysis Supervisor W. Bainard, Engineer,'uclear Systems and Analysis C. Foley, Technical Specialist The inspectors also interviewed various control room operators, shift supervisors and shift managers, maintenance, engineering, quality assurance, and management personnel.
"Attended the Exit Meeting on November 15, 1988.
¹Attended the Exit Meeting on November 4, 1988.
2.
Plant Status At the start of the inspection period, the plant was operating at 100K power.
The plant operated at this power level until October 28, at which time the plant power level was reduced to approximately 30X to allow changing the control rod sequence.
A planned steam plant inspection and minor. maintenance were scheduled for this reduced power level.
As a result of the steam plant inspection, a non-isolable steam leak was discovered on a drip pot for the number 3 steam line to the main turbine.
The plant was taken to cold shutdown to allow repairs.
During this outage, additional maintenance work was accomplished.
An additional potential steam leak was discovered on the number 2 line on October 29, and this line was repaired before starting up the plant.
The reactor was taken critical October 29 and the plant resumed power operation on October 30; after allowing xenon to build in at 70K power for
approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, power was reduced on October 31 to about 30K to set the control pattern to the 100K configuration, and power was raised in accordance with the fuel conditioning guidelines, reaching 100K power on November 2.
The plant continued to operate at this power level through the end of the reporting period.
Previousl Identified NRC Ins ection Items 92701 92702 The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
Closed Unresolved Item 397/87-19-34
SPDS Screen Glare is Excessive The cathode ray tube (CRT) display monitor screens for the safety parameter display system (SPDS) were very difficult to read due to glare from the overhead lighting system and possible low output from the monitors.
The licensee had changed out one monitor and installed a contrast-enhancing screen over the front of other monitors to reduce the glare.
This action was completed October 8, 1988.
This item is closed.
b.
Closed Enforcement 397/88-27-01:
Ash Fall Filters Filters to protect the various plant ventilation systems from a postulated volcanic ash fallout had not been thoroughly reviewed and proceduralized.
The licensee revised PPH 4. 12.4.5 "Ashfall Filters" on October 26, 1988 to formalize the method of changing the filters in the event of a volcanic event.
This revision included the expected numbers of filters to be needed and the location of the filters once they had been brought from their storage point in the site warehouse.
The manpower requirements to change these filters was also included in the procedure.
The inspector* reviewed the revised procedure and the engineering calculations for the number of filters expected to be used during a volcanic event.
This item is considered closed.
C.
The following items were examined by the inspector, but were not ready to be closed by the licensee:
Enforcement Item 50-397/88-21-01:
Enforcement Item 50-397/88-21-02:
Followup Item 50-397/88-19-11:
Plant Heatup Exceeded TS Limits LER Not Submitted Within 30 Days Nitrogen Tank Potential Threat
4.
0 erational Safet Verification 71707 Plant Tours The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Mater Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The following items were observed during the tours:
0 eratin Lo s and Records.
Records were reviewed against Technical Specification and administrative control procedure requirements.
(2) Monitorin Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
(3)
conformance with 10 CFR 50.54.(k), Technical Specifications, and administrative procedures.
The attentiveness of the operators was observed in the execution of their duties and the control room was free of distractions such as non-work related radios and reading materials.
(4)
E ui ment Lineu s.
Valves and electrical breakers were verified to be in the position or condition required by Technical Specifications and Administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specification limiting conditions for operation were verified by direct observation.
(5)
E ui ment Ta in
.
Selected equipment, for'which tagging requests had been initiated, was observed to verify that tags were in place and that equipment was in the condition speci fied.
(6) General Plant E ui ment Conditions.
Plant equipment was observed for indications of system leakage, improper lubrication, or other conditions that would prevent the system from fulfillingits functional requirements.
Annunciators were observed to ascertain their status and operability.
During a tour on October ll, the inspector noted that several panel screws were missing from motor control center MC-4A.
This was
brought to the attention of the maintenance management and this matter was corrected by the end of the reporting period.
Fire Protection.
Fire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures.
See paragraph 10 for additional comments.
(8) Plant Chemistr
.
Chemical analyses and trend results were reviewed for conformance with Technical Specifications and administrative control procedures.
Radiation Protection Controls.
The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being-.implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiation Exposure Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
On November 8, the inspector checked two dust mops on the 606 elevation of the Reactor Building for radiological contamination.
Both of the mops indicated radiation levels greater than 100 counts per minute above background.
The inspector notified the radiation protection group who sent a
technician to check the mops.
The technician confirmed that the mops were greater than the station limits and took charge of the mops and performed a survey of the area - no additional contamination was located.
The technician explained that the radiation protection technicians check the cleaning equipment daily and that this would have been checked later in the day.
The inspector checked all the other dust mops in the Reactor Building and no additional problems were identified; this appeared to be an isolated case.
(10) Plant Housekee in
. Plant conditions and material/equipment storage were observed to determine the general state of cleanliness and housekeeping.
Housekeeping in the radio-logically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
See paragraph 10 for additional comments.
(11) ~Securit
.
The inspectors periodically observed security practices to ascertain that the licensee's implementatio'n of the security plans was in accordance with site procedures, that the search equipment at the access control points was operational, that the vital area portals were kept locked and alarmed, and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functiona.
En ineered Safet Feature S stem Malkdown 71707 71710 Selected engineered safety feature systems (and systems important to safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
The inspectors also verified that the system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Accessible portions of the following systems were walked down on the indicated dates.
~Setem Diesel Generator Systems, Divisions 1, 2, and 3.
Dates October 11, 13,
Hydrogen Recombiners October 18, November
Low Pressure Coolant Injection, (LPCI)
Trains "A", "8", and "C" October 4,
November
Low Pressure Core Spray (LPCS)
October 4,
November 8 High Pressure Core Spray (HPCS)
October
November
Reactor Core Isolation Cooling (RCIC)
October 4,
November
Residual Heat Removal (RHR), Trains IIAII and IIBII Scram Discharge Volume System Standby Liquid Control (SLC) System October
November
October 18,
October 18,
November
Standby Service Mater System 125V DC Electrical Distribution, Divisions 1 and
250V DC Electrical Distribution October
October 17,30 November
October 17,
November
No violations of NRC requirements or deviations were identifie.
Surveillance Testin 61726 a.
Surveillance tests required to be performed by the Technical Specifications (TS) were reviewed on a sampling basis to verify that:
1) the surveillance tests were correctly included on the facility schedule; 2)
a technically adequate procedure existed for performance of the surveillance tests; 3) the surveillance tests had been performed at the frequency specified in the TS; and 4) test results satisfied acceptance criteria or were properly dispositioned.
b.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
Dates Performed 7.4.3. 1. 1.68 Scram Discharge Volume (SDV) High Level Trips October
7.4.3. 1. 1.47 Average Power Range Monitor/Reactor Protection System (APRM/RPS)
Bus Trip Channel E
November
7.4.5. 1.7 LPCS Operability Test November
No violations of NRC requirements or deviations were identified.
7.
Plant Maintenance 62703 During the inspection period, the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required gA/gC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectors verified that reportability for these activities was correct.
The inspectors witnessed portions of the following maintenance activities:
Descri tion Dates Performed Calibration check on reactor closed cooling (RCC) instrument RIS-606 per AT 7398 Condensate Snubber Replacement per AT 5538 October
October
Replace gasket on reactor building recirculating air (RRA) sample pump RRA-SR-39 per AT 7220 October
Tighten Packing on Valves in the Steam Tunnel per AT 7385 October
No violations or deviations were identified.
Closed TI 2515/98 - Information on Hi h Tem eratures Inside Containment/Or el 1 for PWRs and BWRs 71707 This Temporary Instruction requested the collection and submittal of drywell temperature data.
This was in response to a recent finding at another plant in which containment temperature was allowed to significantly exceed the temperature assumed in the FSAR.
The inspector selected a sample of completed surveillance records from PPM 7.0.0, "Daily and Shiftly Instrument Checks".
Specifically, data for various drywell temperatures were collected and reviewed for portions of the months of June, July, and August of 1987 and 1988.
Periods were chosen when the highest possible drywell temperatures were likely to occur.
Although some unusually high drywell average temperatures were noted during several hot days in July, 1988, at no time was the Technical Specification, or FSAR, averaged maximum permissible temperature of 135 degrees exceeded.
However, some localized temperatures in the area of the safety relief valves (SRVs) did exceed the 150 degree criteria by two or three degrees during those same days, which could potentially shorten the qualified lifetime of the SRV solenoid pilot valves.
This was discussed with the Equipment Engineering Supervisor who was aware of the problem.
These solenoid valves have a qualified life of 6.4 years, which assumes an average temperature at the valves of 150 degrees.
Temperatures in the area of the SRVs have averaged much less than 150 degrees since initial criticality in 1984.
Therefore, several days of temperatures a few degrees above 150 degrees should have no noticeable impact on the Arr henius equation used to determine a qualified life.
Thermocouples will be installed on the solenoid valves themselves during the Spring 1989 refueling outage to more accurately determine the temperatures they are actually experiencing.
No violations or deviations were identified.
0 en TI 2515/99 - Ins ection of the Licensee's Im lementation of Re uested Actions of NRC Bulletin 88-07 BWR Power Oscillations 25599 The purpose of this Temporary Instruction was to ensure that licensed operators and shift technical advisors (STA's) had been briefed regarding the March 9, 1988 event at LaSalle Unit 2, and and that operating and abnormal procedures had been revised as necessary.
The inspector interviewed control room operators at random to determine if they had been briefed concerning the LaSalle event, as required, within 15 days of receipt of the Bulletin.
In addition, training records which documented this briefing for each operating crew were reviewe The licensee reviewed the adequacy of existing procedures and elected to revise PPM 4.2. l. 10, "Loss of Forced Circulation", to include guidance on responding to the onset of power osci llations after the loss of one or more recirculation pumps.
Following this review, a
new procedure, 4. 12.4. 7, "Entry Into Region of Potential Core Power Instabilities" was developed and approved.
This new procedure contained detailed guidance regarding how power osci llations could occur, how they can be recognized, and how they should be responded to, including manually scramming the reactor.
The inspector later verified that these procedures had been incorporated into the operator requalification training program, and that an examination containing questions related to these procedures had been administered.
Simulator training was observed for a requalification class where the operators'ecognition and response to such an event was emphasized.
It was noted that the operators and the STA participating in this simulator training were knowledgeable concerning the event at LaSalle, the new procedure, and the recent Technical Specification amendment that addressed the region of potential core instabilities.
All licensed operators, except one, had received the required training within the time limits.
The one individual received the training during the subsequent requalification cycle.
The inspector found the licensee's implementation of actions regarding training and procedures to be acceptable.
However, one aspect of the Bulletin that had not been addressed as of the end of the inspection period was the adequacy of the installed instrumentation (such as APRMs and LPRMs) to detect power oscillations within the core.
Therefore, this TI will remain open until this aspect has been addressed.
No violations or deviations were identified.
10.
Procedure Adher ence 71707 During the reporting period several circumstances were identified involving failure to follow approved procedures.
These observations indicated that previously observed problems involving failure to follow procedures and insufficient understanding of procedure requirements are still evident.
The observed areas of concern are discussed below.
a ~
Measurement and Test E ui ment N&TE During a tour of the reactor building on October ll, 1988 the inspector noticed two pieces of t4kTE (stopwatches)
sitting on a technician's cart on the 471'levation of the Reactor Building.
They had last been used, per the attached Usage Cards, on May 10, 1988, and June 15, 1988, respectively.
Further research revealed that one of these pieces, ID 39183, had been placed on the suspension list in July, when it had been reported lost.
(Placing a
piece of NTE on the suspension list means that it is not to be used.)
Since it was not really lost, it was unclear to the inspector whether or not it had been used subsequent to being placed
on the suspension list; it was found on the same cart with the other piece of M&TE that was known to have been used.
The other piece of M&TE, ID 43468, had been used nine times, according to the Test Equipment Log, between June 15 and October 11.
However, these nine usages had not been recorded on the Usage Card as required by PPM 1.5.4, Revision 12, "Control of Measuring and Test Equipment."
Further, per PPM 1.5.4, M&TE is to be returned to the M&TE tool crib or re-checked out within seven days from the time of the last checkout, or it is to be placed on the "overdue for return" list which is issued to the supervisor of the personnel that checked out the equipment.
If the supervisor does not respond within ten days, an NCR is. to be issued.
The Technical Specifications, Section 6.8. 1, and Appendix A (paragraph 8. 1) of Regulatory Guide 1.33 require that such procedures be in effect to ensure that measuring and testing devices are properly controlled and calibrated.
A review of the Test Equipment Log for item ID 43468 indicated that this piece of M&TE had been checked out for significantly longer than seven days on a number of occasions, including one occasion between July 1 and July 20, 1988, when it had been out for 19 days without being checked in, re-checked out, or a
NCR having been written.
This was identified to the licensee as a
Severity Level V violation (88-37-01).
Pursuant to the NRC Enforcement Policy (discussed in paragraph 17), since the licensee had initiated corrective actions prior to the conclusion of the inspection, a Notice of Violation was not issued.
Another observation the inspectors made during the inspection period was excessive amounts of unattended M&TE left about the plant'.
Although most items observed were still within the seven day use period, one other piece of M&TE, a digital voltmeter (ID¹ C005260)
was observed by the inspector on November 8, and again at the same location on November 14, on the 606'levation of the Reactor Building.
A check of the Test Equipment Log indicated that this meter was five days overdue for return to the M&TE Tool Crib.
The inspector pointed this out to licensee maintenance management, who noted that this meter had been included on the overdue M&TE list issued that day, and would have been corrected by the licensee's system.
The inspector also noted there appeared to be no provision in PPM 1.5.4 concerning how to handle lost M&TE.
At the exit meeting, the maintenance manager acknowledged the problems identified in the area of M&TE, and indicated that gA would be requested to audit the area to determine the extent of the problem.
Fire Protection During various tours of the reactor building between October 19 and November 2, the inspectors noted areas with excessive amounts of combustible material present for several days, contrary to the requirements of PPM 1.3.35, "Fire Protection Program - Controls,"
posing a fire hazard.
Examples noted were as follows:
On October 19, trash and a fabric chair were observed in instrumentation rooms R316 and R415 that were not permitted to have unattended combustibles in them.
On October 24, excessive lubricating oil was observed on and under sample rack RRA-SR-39, a result of gasket replacement on the sample pump.
This condition had existed for several days, even after it was brought to the attention of licensee management.
Section 6.8. 1 of the Technical Specifications requires that written procedures be established and implemented which address implementa-tion of the fire protection program.
PPM 1.3.35, Revision 6, "Fire Protection Program - Controls," states that oil spills or other combustibles resulting from work activity shall be removed from all vital areas immediately following completion of the job or at the end of the shift if the work is not continuous.
Contrary to these requirements, the above combustibles were not removed from vital areas at the end of the shift several days prior to the inspectors'bservations.
This was identified to the licensee as a Severity Level V violation (88-37-02).
Pursuant to the NRC Enforcement Policy (discussed in paragraph 17), since the licensee had initiated corrective actions prior to the conclusion of the inspection, a
Notice of Violation was not issued.
These problems observed by the inspector and other similar cases observed by the licensee's fire marshal indicated insufficient attention by the plant staff in implementing the requirements of the fire protection program.
Although the plant fire marshal had identified many of these problems in a memo to the various area coordinators, the inspector was concerned that this action was necessary.
The observations by the inspector and the fire marshal indicated a need for improved communication by plant management of their expectations concerning the requirements of this procedure, and proper implementation of those expectations by the plant staff.
Mechanical Jum ers During a plant tour on October 31, the inspector observed that a
one-inch hose.was connected from the fire protection system to the
"B" air compressor (CAS-C-1B) heat exchanger cooling water filter drain valve (TSM"630).
The normal cooling water valves were
"red-tagged" shut, and cooling water for the air compressor was being supplied via the fire protection system through this hose arrangement.
This air compressor is 'not safety related, but the service air system supplies instrument air which is important to safety and to plant operations.
The inspector also noted that the FSAR description of the system states that cooling water for the air compressors is provided by the plant service water system.
No identification tags or yellow "Caution Tags" had been installed on the hose, although several members of the operations staff including the shif't manager were aware of the hose arrangement.
A check of the "Lifted Leads and Jumper" log on November 1 indicated that this hose was not recorded in the log.
In discussions with members of
plant management, it was determined by the licensee's staff that this hose and other similar temporary hoses should be considered as mechanical jumpers and treated in accordance with PPM 1.3.9, "Lifted Leads and Jumpers".
A review of PPM 1.3.9 by the inspector showed that a definition of mechanical jumper was not included in the procedure.
The procedure did provide for the conduct of a review per 10 CFR 50.59, had a jumper log sheet been completed.
This item is unresolved (88-37-03).
Discussions of mechanical jumpers with several members at different wor king levels indicated that a more complete definition of a mechanical jumper needed to be included in the procedure and conveyed to the'lant staff.
After the inspector's observation was made, the hose was promptly tagged and logged, and plant management proceeded to revise the procedure to include more specific guidance for mechanical jumpers.
This guidance would include not only hoses, but other changes to the systems which could alter its function.
ll.
Control Room Ventilation 71707 On November 7, the inspector noticed a deficiency sticker on the operating panel for the control room ventilation system which indicated that the run time on the "B" train charcoal filter had exceeded 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> and a sample was needed.
This was in reference to Technical Specifi-cation 4.7.2.d which requires that a sample of the charcoal in the emer-gency filtration units be taken after every 720 hour0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> s of operation.
The
"B" train had reached 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of operation on October 24.
The charcoal was sampled on November 8.
At the time of sampling; the inspector learned that the "B" train had been run for approximately 943 hours0.0109 days <br />0.262 hours <br />0.00156 weeks <br />3.588115e-4 months <br />.
Discussions between the inspector and licensee representatives regarding Technical Specification 4.7.2.d revealed a difference of opinion as to the interpretation of the requirements.
This issue was identified near the end of the inspection period, was still under review and evaluation, and remains unresolved (88-37-04).
12.
Licensee Event Re ort LER Followu 90712 92700 The following LERs associated with operating events were reviewed by the inspectors.
Based on the information provided in the report it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are considered closed.
LER NUMBER LER 87-27"00 DESCRIPTION APRM Surveillance not Performed Within Required Time Due to Personnel Error LER 88-06-00 88-06-01 Low Reactor Vessel Level RPS Actuation Due to Inadequate Procedure and Personnel Error
No violations of NRC requirements or deviations were identified.
13.
Review of Periodic and S ecial Re orts 90713 Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9. 1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required to be reported by NRC requirements; test results and/or supporting information were consistent with design predictions and performance specifications; and the reported information appeared valid.
Within the scope of the above, the following reports were reviewed by the inspectors.
Monthly Operating Report for September 1988.
No violations of NRC requirements or deviations were identified.
14.
En ineerin Im rovement Pro ram During the inspection period a review was conducted of the licensee's Engineering Improvement Program (EIP).
The EIP and associated recommen-dations were examined, and discussions relating thereto were held with key Generating Engineering representatives (at the manager, supervisory and engineer level) involved in the development and implementation of actions in support of the EIP.
The following findings and observations resulted.
a ~
~Back round The findings of NRC's Safety System Functional Inspection (SSFI),
conducted in August 1987; and the identification of numerous errors in the ATWS/ARI design package, identified in February 1988 (see NRC Inspection Report No. 50-397/88-02),
led the licensee to initiate a self-critical evaluation of engineering performance.
This evaluation was conducted by a Task Force of senior engineering personnel from the Generation Engineering staff with overview by Generation Engineering management.
The evaluation effort culminated in the issuance of a Task Force report entitled
"WNP-2 Engineering Improvement Program,"
dated May 24, 1988.
b.
Sco e and Findin s of EIP Task Force The EIP Task Force report discussed findings and presented
recommendations for improvement in the following eight broad areas.
(1)
Planning and Schedul ing (2)
Feedback and Communications (3)
Technical Leadership (4)
Inter-organizational Interfaces (5)
Process Improvements (6)
Training (7)
Tools (8)
Morale Issues
Develo ment of an Im lementation Action Plan Licensee management stated that, with the exception of a recommenda-tion to establish the position of Chief Engineer, all recommenda-tions of the Task Force report were to be adopted.
A comprehensive Implementation Action Plan was in the process of development at the time of the inspection.
For each recommendation, an estimate of the resources required for implementation and an initial proposed schedule for implementation were being prepared.
Generation Engineering management stated that an overall Implemen-tation Action Plan defining the tasks, proposed schedules and individual responsibility assignments was to be finalized for senior management review by mid-November 1988.
It was anticipated that supplemental budget consideration will be necessary for the implementation of some tasks, according to licensee management.
The Task Force report included nine short-term action recommenda-tions which were proposed for initiation within 90 days.
These recommendations included the restructuring of Engineering to provide more technical leadership, and the establishment of committees and/or working groups to (1) review and streamline procedures, (2)
develop a set of controlled criteria documents, (3) develop departmental standards and checklists, (4) develop a procedure compliance standard, and (5) evaluate the design data base structure and provide a plan for simplifying its use.
Additional short-term actions recommended included the assignment of a planner/scheduler to each of the four Generation Engineering departments to assist managers in work planning and scheduling, reestablishment by managers of the list of critical work procedures for their staffs, and the establishment of training needs in accordance with Task Force training recommendations.
An examination of facility records and discussions with licensee representatives revealed that tasks had been initiated regarding each of the short"term recommendations.
A restructuring of Generation Engineering had been implemented by the addition of twelve new Group Supervisor positions.
Ten of the twelve positions had been filled by internal promotion.
The two remaining positions were to be "posted" for both internal (within WPPSS)
and external candidate consideration.
Additional funding had been authorized to provide contract engineering support to replace the ten individuals selected for the Group Supervisor positions.
The establishment of the Group Supervisor positions resulted in a supervisor-to-engineer ratio of approximately six, thus substantially increasing the supervisory attention to engineering work.
Four additional scheduler/planner positions had been added, making a total of six such positions within Generation Engineering.
The four new positions had been fil1ed with contract personnel.
All other short-term action recommendations had either, been com-pleted or definitive action plans had been developed in accordance with the individual recommendations.
For example, tr'aining needs
had been identified together with resource estimates and a proposed schedule for implementation.
Committees or working groups had been established, and substantial progress had been made in the identification, review, revision and/or development of procedures, departmental work standards, checklists and compliance standards.
A proposal had been developed to identify and simplify the organiza-tion of system design criteria and design data.
Implementation of this proposal was recommended as a separate task to follow the reconstitution of design basis documents (DSD's),
a work task currently in progress.
(See discussion in Paragraph 15).
Other actions initiated to improve the quality and efficiency of engineering work included the establishment of a Modifications Review Committee and a substantial allocation of engineering resources to the design review process.
The Modifications Review Committee, established in mid-August 1988, is comprised of representatives of Generation Engineering (serves as chairman),
Plant Operations, Plant Maintenance, Plant Technical (Project Engineer),
Technical-Training, and Estimating/Scheduling.
The purpose of the committee is to promote teamwork among departments most closely involved in plant design changes.
Meetings of the committee commence at the conceptual design phase, at which time the proposed change is discussed with the ideas, expectations and objectives of all parties expressed.
A "walkdown" of the proposed change is also conducted.
This process continues through final design and installation.
Facility records showed that there had been more than fifty meetings of the Modifications Review Committee since its formation.
Plant management expressed strong support for such meetings and stated that the meetings had identified numerous potential problems that were resolved prior to the finalization of design, thus eliminating time consuming and costly field changes.
Engineering management expressed a similar view, and also stated that the process had made it possible to reduce substantially the number of design options considered at the conceptual design phase, thus reducing the overall design effort and resources expenditure.
With regard to incr eased resources allocated to design review, Engineering management stated that resources equal to approximately 50K of the original design effort are currently expended on planned design review effort.
In addition, all previously completed design change packages scheduled for implementation during the 1989 refueling outage are not to be released for plant work pending the completion of a design re-review in accordance with preestablished criteria.
The latter criteria consider the safety significance of the change, the engineering discipline(s) involved in the design, and previous experience with designs of a similar nature.
This practice was initiated with regard to design changes installed during the 1988 refueling outage and, according to Engineering Management, resulted in a reduction of approximately 25K in the number of field changes when compared to previous outages.
The licensee had also initiated the practice of holding a critique on each Field Change Request.
The responsible engineer and Engineering supervisor participate in such critiques to determine
the root cause of the field change.
The results of these critiques are documented for subsequent trending analysis and feedback of
"lessons learned",
according to Engineering management.
The EIP was judged by the NRC inspector to reflect a comprehensive, in-depth, self-critical evaluation by the licensee.
The recommen-dations of the licensee's Task Force were found to be meaningful, and if adopted and effectively implemented should result in substantial improvement in engineering work by the licensee's staff.
15.
Desi n Basis Documentation Pro ram The licensee had initiated a program to update Design Basis Documents (DBO) for important plant systems.
The program, as presently defined, will cover approximately 57 plant systems, 17 of which are key safety-related systems, and 20 topical design basis documents.
The topical OBD's are to cover. generic requirements such as seismic design, fire protection, ALARA, tornado missiles, etc.
The program is scheduled for approximately five years duration, commenc-ing in July 1989.
A pilot project involving the preparation of OBD's for the Low Pressure Core Spray (LPCS) system and the Onsite AC Electrical system was in progress at the time of this inspection.
Revision A of the OBD for the LPCS system was approved for review and comment
"As to Form Only" in July, 1988.
This DBD was expected to be issued as Revision "0" in March 1989, after revisions are made to'incorporate numerous comments from an internal SSFI as well as the plant staff and other WPPSS organizations.
It was anticipated that the second DBD in the pilot project will be issued for review and comment (Revision A) in early March, 1989.
The DBD for the LPCS system, although not examined in depth, was observed to be similar in format and content to DBD's completed or in preparation by other Region V utilities.
Discussion with Engineering personnel involved in the DBD program revealed that the licensee plans to manage the program in-house, although contract engineers are expected to be utilized for up to 40K of the estimated 25 (peak) staff level associated with the program over the next 5 years.
The licensee's OBD program was judged to be proceeding in a manner which, when effectively implemented, should provide a substantially improved understanding of the technical and regulatory design basis of important plant system.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable items,'violations, or deviations.
Unresolved items addressed during this inspection are discussed in paragraphs 10.c and 11 of this report.
17.
Severit Level V Violations As stated in Section V.A of 10 CFR Part 2, Appendix C, "General Statement of Policy and Procedure for NRC Enforcement Actions," 53 Fed.
Reg.
40019 (October 13, 1988),
a Notice of Violation will not normally be issued for isolated Severity Level V violations provided that the licensee has initiated appropriate corrective actions before the inspection ends.
Two Severity Level V violations for which a Notice of Violation was not issued are discussed in paragraphs 10. a and 10. b of this report.
18.
Exit Meetin 30703 The inspectors met with licensee management representatives periodically during the report period to discuss inspection status.
An exit meeting was conducted with the indicated personnel (denoted in Paragraph 1) on November 15, 1988.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed and acknowledged by the licensee represen-tatives.
The licensee did not identify as proprietary any of the information reviewed by or discussed with the inspectors during the inspectio