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TESTIMONY BEFORE THE COMMISSION HEARING W
4-g FOR ISSUANCE OF DIABLO CANYON UNIT 1 FULL POWER OPERATING LICENSE
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) / 7 k,1984 d4WStu Prepared By:
I. T. Yin Mr. Chairman and members of the Commission, thank you for inviting me to present my personal view of matters concerning the issuance of Diablo Canyon Unit 1 full power license.
As you know, I was requested by the Headquarters staff to participate in the NRC's investigation of allegations concerning the construction of Diablo Canyon.
I was specifically assigned to pursue allegations in the piping design control area.
Based on inspections conducted periodically from November 29.1983 to Mav 2. L93L I identified many significant technical and QA deficiencies.
Contrary to the approach normally taken by my Region with significant problems, no enforcement conference was held, nor was there any enforcement action taken.
No requests were made for licensee program upgrade, and there was no attempt to broaden the inspection areas and scope.
Defective programs, such as Quick Fixes and M
Onsite Project Engineering Group design activities were allowed to continue yf until June 1984, when the licensee decided to abolish these practices.
My request to followup on the licensee program revision was denied. ;{
g/ ' p,gf, In the followup of the seven License Condition items that were incorporated into the low power license, even though I was the instigator for six of the seven items,.and would normally be considered to be the most knowledgeable'"
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man on the issues and details, nevertheless, I was not considered essential in the followup review and evaluation.
Peer Review Team inspection for Items No. 1 and 7 was conducted on the third week of May 1984, during my vacation overseas.
Peer Review Team inspections for Items No. 2 to 6 were performed during the fourth week of May 1984, when I returned from vacation, and accompanied the ACRS on the site tour.
Subsequent review of the Peer Review Team reports contained in the draft SSER revealed that they contain mostly undocumented reviews and casual observations.
There were cases where the inspection sample selected was extremely small, where problems originally identified continued to exist, where review criteria were compromised without technical justification, and where Team failed to address the specific program deficiency issues.
For the number of staff assigned and hired to i
work in the Peer Review Teams, and the length of time spent since the April 13, 1984 Commission meeting, I don't feel as though have really addressed all the issues.
7e, The 29 page " Concern Items on IDVP Evaluation of L/B and S/B Piping and Pipe Support Design," resulting from my review of a number of Cloud reports, were submitted to NRR for evaluation on April 25, 1984.
Although these were a part of my original planned inspection, I requested NRR staff involvement based on the consideration that:
(1) since NRR co-managed the program, any 8708200227 870814 fG PDR FOIA DEVINEB4-743 PDR g
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findings would be against our'own staffers, and (2) since NRR-had already accepted the program, they should be able to explain the. situation if j
deficiencies were being identified. The inspection was not scheduled untiP the week of June 17, 1984.
Burdened b'y 1ong presentati'ons, indoctrinations I
for the Special Review Team members, discussion'on issues unrelated to the IDVP, unavailability of documents that had been stored in remote locations, and my personal schedule difficulties, the actual time that I spent inspecting that week was less than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. My request to travel back
-Sunday to continue the inspection first thing Monday was denied.
As you can see, I was not pleased with how NRR has been managing and resolving my inspection findings.
I believe additional investigation and inspection effort is warranted to properly close out identified areas of concern.
I believe this could be accomplished in three to'five weeks.
This followup inspection would provide the Commission a clearer picture of the extent of the problem or the lack of problem.
In any event, if the Commission decides to grant the Diablo Canyon 1 a full power operating license today, I shall respect the Commission's -
judgement and decision, and shall cooperate fully-in any followup actions deemed necessary..Looking back, I know that I have been honest in my work, and feel that I have fulfilled my assigned duty.
Despite difference in professional opinion, I have not doubted the NRR management's honesty and integrity, and wish them the best of luck in handling the many other ongoing troubled facilities.
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NUCLEAR REGULATORY COMMISSION
- I REGION lli 1
o, 799 RooSEVE LT ROAD GLEN ELLYN,ILLINolS 60137 9
July 10, 1984 I
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MEMORANDUM FOR:
Richard H. Vollmer, Director, Division of Engineering, Nuclear Reactor Regulation FROM:
I. T. Yin, Senior Mechanical Engineer, Division of Reactor Safety, Region III SU.BJECT:
COMMENTS ON SSER LICENSE CONDITION 2.C.(11) PREPARED BY THE DIABLO CANYON PIPING PEER REVIEW PANEL The draft SSER License Condition 2.C.(11) Items 1, 4, 5, 6, and 7 were telecopied to Region III on July 3, 1984.
Items 2 and 3 were received on July 9, 1984.
Provided herewith are my comments.
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I. T. Yin Senior Mechanical Engineer Division of Reactor Safety Region III a
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SSER for License Condition 2.C.(11), Item 1 PG&E shall complete the review of all small bore piping supports which were reanalyzed and requalified by computer analysis.
The review shall include consideration of the additional technical-topics, as appropriate, contained in License Condition No. 7 below.
Comments The following data is required before any meaningful comments can be provided:
1.
Subsequent to the DCP's review of all computer analyzed small bore piping supports, how many (among the 358 total population) will require hardware l
adjustment, modification or rework?
2.
In conjunction with 1 above, how many were unable to meet the Code and FSAR requirements after the first rerun in the computer?
These supports required alternative or additional computational effort in order to meet the design criteria.
3.
Peer Review Panel (PRP) identified that OPEG design judgement (design basis and criteria presumably) was not documented in some of the calculations. What PRP action, if any, was initiated to determine that these were just a few ' isolated cases?
If the situation was determined to l
be generic, was there any license program upgrade mandated by the PRP?
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PRP identified calculational deficiencies consisting of erroneous STRUDL input assumptions of structural' member properties and geometry.
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there a licensee procedure that had included quantitative or qualitative acceptance criteria for accepting these types of deficiencies?
If not, what are the PRP's criteria in determining that no further action is reauired?
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5 SSER for License Condition 2.C.(11), Item 2 The licensee shall identify all cases in which rigid supports are placed in close proximity to other rigid supports or anchors.
For these cases, the lic-ensee shall conduct a program that assures loads shared between these adjacent supports and anchors result in acceptable piping and support stresses.
Upon completion of this effort, the licensee shall submit a report to the NRC staff documenting the results of the program.
Comments 1.
The SD and 100 criteria was established by Peer Review Panel (PRP) on June 20, 1984 at Cloud office with my concurrence.
One week later the NRR staff telephoned me stating that the licensee had requested some exemption on the 10D proximity criteria for the snubber-anchor pair.
Decoupled branch connections designed by the span rule were requested to be excluded for the review because it will require excessive effort, and that may delay licensing process. The NRR staff honored the request.
i based on the reason that the decoupling branch connections are less important to safety.
Please provide technical justification on exempting the PRP criteria.
I remember clearly that Dr. Cloud haa stated, during l
various hearings and meetings, that the only small bore piping that will be overstressed during seismic event would be those lor w d at the connections to the large bore piping.
2.
The SSER states, "If unacceptable, the actual manufacturer's' test reports on lost motion were reviewed for the unique snubber." Please explain why snubber displacements under load were not a concern to the PRP in deter-mining snubber operability?
3.
The SSER stated, "The plant site inspection provided the NRC staff (PRP presumably) an opportunity to inspect the affected components on a first 1
hand basis.", and that three snubbers installed in proximity to the equipment nozzle and rigid restraints "were viewed" by PRP.
Please discuss the purpose and scope of the viewing, and what hardware attri-butes had bee,Lchecked and verified by PRP.
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Amongth[d95 "p'roximity" snubbers, please provide the following technicali 4.
informati I
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Install tion of the snubber is justified because of excessive (1/16" thermal movement at the location.
How many belong in this category?
b.
How many snubbers, subsequant to the evaluation, were determined to be inoperable at either DE, DDE, or Hosgri seismic condition based on the 0.06" deflection criteria?
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SSER for License Condition 2.C.(11), Item 3 The licensee shall identify all cases in which snubbers are placed in close proximity to' rigid supports and anchors.
For these cases, utilizing snubber lockup motion criteria acceptable to the staff, the licensee shall demon-strate that acceptable piping and piping support stresses are met. Upon completion of this effort, the licensee shall submit a report to the NRC staff l
documenting the results.
Comments 1.
The SD and 10D criteria was established by Peer Review Panel (PRP) on June 20, 1984 at Cloud office with my concurrence.
One week later the NRR staff telephoned me stating that the licensee had requested some exemption on the 10D proximity criteria for the restraint-anchor pair.
Decoupled branch connections designed by the span rule were requested to be excluded for the review because it will require exces.sive effort, and that may delay licensing process.
The NRR staff honored the request based on the reason that the decoupling branch connections are less important to safety.
Please provide technical justification on exempting the PRP criteria.
I remember clearly that Dr. Cloud had stated, during various hearings and meetings, that the only small bore piping that will be overstressed during seismic event would be those located at the connections to the large bore piping.
2.
Among th rigid restraints, how many required shimming?
3.
In conjunction with 2 above, if shimmings are not provided, will the conditions cause over-stress on the supports or piping systems?
4.
In conjunction with 3 above, if extensive potentially over-stress condi-i tions did exist without proper structural shimming having been performed, would it be a 10 CFR 50.55(e) reportable item that had never been reported?
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9 SSER for License Condition 2.C.(11), Item 4 PG&E shall' identify all pipe supports for which thermal gaps have ieen specifically included in the piping thermal analyses.
For these.cses the licensee shall develop a program for periodic inservice inspection' to assure j
that these gaps are maintained throughout the operating life of the plant.
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PG&E shall submit to the NRC staff a report containing the gap monitoring
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program.
Comments The licensee measures taken and proposed future actions are considered to be acceptable.
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s SSER for License Condition 2.C.(11), Item 5 PG&E shall provide to the NRC the procedures and schedules for the hot I
- walkdowns of the main steam system piping.
PG&E shall document the main steam hot walkdown results in a report to the NRC Staff.
Comments 1.
The objective failed to describe inspection of spacings provided for piping component seismic (DE, DDE, and Hosgri) movements at operating (hot) positions. The program did not provide measures to inspect for:
(1) piping components that may damage electrical panels and cable trays, (2) potential interferences such as,
components that may be damaged by closely spaced structures, and (3) interference that could change the piping natural ' frequencies thus caused redistribution of support loads, or shifting of higher loadings to the more critical equipment nozzle connections.
2.
Friction of the sliding type support was observed by the licensee to be a problem in meeting the Code, and it was replaced by a sway strut.
It can reasonably be assumed that certain types of. sliding supports installed at Diablo Canyon could cause excessive frictional force.
Did.PRP inquire into the licensee measure to review the issue on a generic basis?
3.
There appears to be a lack of an orderly.and systematic presentation on the PRP performance of their assignment at the site.
Please provide the following technical information:
a.
- Temperature-versus measurement matrix of all data points.
b.
P&lDs, piping isometrics, support details, and pertinent structural i
drawings _and sketches.
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Record of pretest walk' downs including review of maximum thermal plus seismic movements, and insp'ection of possible locations that j
could be in violation of the above review data conclusions.
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SSER for License Condition 2.C.(11), Item 6 PG&E shall conduct a review of.the " Pipe Support Design Tolerance Clarifica-i tion" (PSDTC) Program and the "Diablo Problem" (DP) System activities. The
-l review shall include specific identification of the following:
1 1.
Support changes which deviated from the defined PSDTC Program scope 2..
Any significant deviations between as-built and design configurations stemming from the PSDTC or DP. activities
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Any unresolved matters identified by the DP system l
The purpose of this review is to ensure that all design changes and modifica-l tions have been resolved and documented in an appropriate manner. Upon completion, PG&E shall submit a report to the NRC staff documenting the i
results of this review.
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i Comments i
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PDSTC f
a.
Approximately 15,000 TCs were written since the inception of the program. This means that about 70% of all the large bore and small bore support design including calculations had been " qui,ckly fixed l
(or more appropriately - deviated)" by few site engineers.
It was inconceivable that the licensee management was unaware of a OA program breakdown of this magnitude.
Did PRP investigate whether or not,there had been any DCP management's predetermined decision to bypass QA program commitments relative to design change control (FSAR commits.to 10 CFR 50 Appendix B QA criteria)?
b.
The SSER stated that, "Upon completion of construction of the support, the complete as-built package, including any PSDTC forms associated with that support, was forwarded by Construction to Engineering for final acceptance in accordance with project engineering procedures." The PRP conclusion was contrary to the evidence provided by an anonymous alleger during the staff interview conducted on May 22, 1984. The documentational evidence showed that some of the TCs were. not included in the as-built packages. These TC items included abandoned concrete expansion anchor bolt drilled l
holes, and added on wing plates to the original base plates.
c.
Many rather significant engineering concerns were brought forth during the May 22, 1984 meeting with the anonymous alleger. The transcript was still in confidential status.
The staff stated in the transcript that due to the lateness of the day, a followup on the meeting could probably be scheduled in two weeks.
The SSER should address specific reasons for which the followup meeting was not scheduled.
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Four of the support installations were examined by the PRP team, the team consisted'of one NRR Branch chief, one consultant from Battelle, and two consultants from EG&G Idaho. My concerns are:
l (1) Considering the. size of the group, the sample size selected for i
observation appeared to be unusually small judging by the NRC regional inspection standard.
(2) Have any or all of the team members had any prior hands-on j
hardware inspection experience?
4 (3)
Please provide sufficient detail descriptions on how the j
supports were inspected, and what attributes have been checked and verified.
2.
DP The licensee measures taken, and the PRP review and evaluation effort are considered to be acceptable.
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4 14 l-SSER for License Condition 2.c.(11), Item 7
- PG&E shall conduct a program to demonstrate that the following technical topics have been adequately addressed in the design of small and large bore piping supports:-
(a)
Inclusion of warping normal and shear stresses due to torsion in those open sections where warping effects are significant.
(b)
Resolution of differences between the AISC Code and Bechtel criteria with' regard to allowable lengths of unbraced angle sections in bending.
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(c) Consideration of lateral / torsional buckling under axial loading of angle members.
(d)
Inclusion of axial and torsional loads due to load eccentricity where appropriate.
(e) Correct calculation of pipe support fundamental frequency by Rayleigh's method.
(f) Consideration of flare bevel weld effective throat thickness as used on structural steel tubing.with an outside radius of less than 2T.
PG&E shall submit a report to the NRC Staff documenting the results of the program.
Comments i
Above allegation items were not assigned to me for followup actions.
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, j Opening Statement Before Subcommittee on Energy and the Environment Committee on Interior and Insular Affairs U.S. House of Representatives on August 3D, 1984 Prepared By:
I. T. Yin Mr. Chairman and members of the Congress, my name is Isa Yin.
I am a Senior Mechanical Engineer in NRC's Region III, Division of Reactor Safety.
Relative to the Diablo Canyon Nuclear Power Plant investigation effort, my assignment was to follow up on some of the allegations made by Mr. Charles Stokes.
The specific investigation areas were restricted to site small bore piping suspension system design control.
However, due to hardware deficiencies observed during plant walkdown, the licensee design control measures for large bore piping system were also included as part of the overview inspection and evaluation.
My inspection effort was carried out periodically from November 29, 1983 to May 2, 1984 My testimony before the NRC Commission hearing conducted on August 2, 1984 for the issuance of Diablo Canyon Unit 1 full power operating license focused on four main issues.
First, the staff's handling of inspection findings had not been forceful and thorough.
Defective programs such as the onsite quick change of piping a few appointed site individuals and the Onsite Project restraint design by(OPEG) design activities, which had been in violation of Engineering Group many regulatory requirements for substantial periods of time, were allowed to continue until June 1984, when PG&E decided to abolish these practices.
Having neglected the implementation of a QA program for years, the adequacy and effectiveness of the latest program upgrade remained questionable.
Second, the Peer Review Team did not fully address the six of the seven License Conditions that were instigated by me, and required resolution prior to the Commission's issuance of a full power license.
The Team reports contained mostly undocumented reviews and casual observations.
There were cases where the inspection sample selected was extremely small, where problems originally identified continued to exist, where review criteria were compromised without technical justification, and where Team failed to address the specific program deficiency issues.
Third, the management and acceptance of the Independent Design Verification Program (IDVP) were regrettable. The OPEG's technical review adequacy and overall 0A program measures were passes by IDVP and accepted by the staff.
The same areas were inspected later and had resulted 100% reevaluation of small bore pipe support computer calculations and the abolishment of OPEG design responsibilities. The followup review of my 29-page " Concern Items on IDVP Evaluation of Large Bore and Small Bore Piping and Pipe Support Design" performed by the Special Review Team, organized on-the-spot, did not fully address my concern of the apparent insufficient program scope and review depth to resolve the seismic design problems that had led to the Commission's g
suspension of a low power license in November,1981.
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Fourth, even though my QA program inspection, allegation investigation, and technical review findings had resulted in excess of two man-years followup effort conducted by the Peer Review Team from March 30 to July 11, 1984, my desire to participate in the resolution of the License Conditions with the Team was granted but made impossible due to concurrent work activities.
I subsequently made requests:
(1) to carry out followup observations on Diablo Canyon Project organization and program changes, (2) to review specific l
database from which the Peer Review Team drew its favorable conclusion on the License Conditions, (3) to' continue the interrupted review of IDVP technical measures at Cloud office, and (4) to be given opportunity to review Reedy records which had concluded that there was no design OA breakdown at OPEG.
All my requests were denied.
During the August 2, 1984 Commission hearing, I stated that, "I believe addi-tional investigation and inspection effort is warranted to properly close out identified areas of concern.
I believe this could be accomplished in three to five weeks. This followup inspection would provide the Commission a clearer picture of the extent of the problem or the lack of problem."
I still believe in the above statement today.
Mr. Chairman, and members of the Congress,.thank you for the opportunity to testify.
I shall truthfully answer any questions that you may wish to ask.
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Testimony Before Subcommittee on Energy and the Environment Committee on Interior and Insular Affairs U.S. House of Representatives on June 14, 1984 Prepared By:
I. T. Yin Mr. Chairman and members of the Congress, my name is Isa Yin.
I am a Senior Mechanical Engineer in NRC's Region III, Division of Engineering.
Relative to the Diablo Canyon Nuclear Power Plant investigation effort, my assignment was to follow up on some of the allegations made by Mr. Charles Stokes.
The specific investigation areas were restricted to site small bore (S/B) piping suspension system design control.
However, due to hardware Deficiencies observed during plant walkdown, the licensee design control measures for large bore (L/B) piping system were also included as a part of the overview inspection and evaluation.
I On March 26-27, 1984, during the NRC Commission's meeting held to consider reinstatement of the licensee's low power test Operation License (OL), I brought to the Commission's attention the following issues which had not been adequately addressed:
1.
Substantiation of design allegations.
NRC overview inspections concluded that there had been significant QA program deficiencies in the areas of S/B and L/B piping design control.
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A large number of calculational errors and deficiencies had not been identified through various reviews and checking stages.
3.
Diablo Canyon Project Organization's lack of implementation of a sound design control QA program which resulted in violation of NRC regulations in personnel training, document control, audits, design verifications, and raised questions in many technical and hardware related areas.
4.
Reinspection, and necessary hardware re-work and modification could be performed with less complication prior to reactor criticality.
My testimony contributed to the Commissioners' decision to defer the OL reinstatement decision pending review by the ACRS.
Prior to the ACRS meeting held on April 6, 1984, an NRC peer review team was formed under the direction of Mr. Dircks, the NRC Executive Director for Operations.
The peer review team reviewed all of the issues and discussed them with Pacific Gas and Electric Company (PG&E) representatives and with me.
During the ACRS meeting, the staff presented a consensual view that:
1.
It was acceptable to permit low power operation prior to completing corrective actions.
Such operation would not compromise corrective actions and would not be a risk to the public health and safety.
2.
Prior to operation above 5% power, the significant issues concluded by i
the NRC peer review team should be addressed and corrected by PG&E and evaluated and accepted by the staff.
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l The ACRS letter to the Commission, dated April 9, 1984, concurred with the staff position, and requested further review of staff resolution of the various relevant issues raised by NRC inspectors and others.
The low power OL was subsequently reinstated during the April 13, 1984 Commission hearing.
The Commission also asked that the peer review team issues be included in a license amendment.
This set forth License Condition 2.c.(11) in an Operating License Modification forwarded to PG&E on April 18, 1984.
Presently, the staff is working toward resolving the License Condition items, as well as Independent Design Verification Program (IDVP) concerns and programmatic issues raised by me.
l 1.
The License Conditions included:
l a.
Re-analyses and re qualification of all S/B piping support computer 1
calculations.
b.
Evaluation and shimming of closely spaced rigid to rigid restraints and anchors.
c.
Performing additional piping analyses to ensure functionability of snubbers that were installed in close proximity to rigid supports.
d.
Establishment of insersice inspection to maintain required thermal gaps within the rigid support structures thoughout plant life.
e.
Staff observation of hot walkdown inspections of Main Steam and
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Residual Heat Removal Systems to ensure absence of structural interference.
f.
Review of " quick fix" significant design changes; and design criteria that were prescribed in informal "Diablo Problem" correspondence.
g.
Consideration of additional technical topics raised by allegations.
These issues are presently handled by the NRC staff.
2.
My written concerns on possible inadequate IDVP for L/B and S/B piping stress analyses and support calculations, and seemingly insufficient followup evaluations after deficiencies had been identified were formally submitted to NRR management on April 25, 1984.
Joint review of these concerns will be conducted by NRR, IE staff, and me.
3.
In addition to the License Conditions, I believe there are other program-matic issues that could affect the quality of ongoing and future project 1
activities.
In my view, the following changes are warranted:
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Improvement of site personnel indoctrination and training program as well as measures to be taken to ensure effective implementation of program requirements.
a b.
More stringent ' control of site procedures, including removal of outdated documents, and avoidance of procedure revisions by unauthorized means,'for example Inter-office memoranda.
Upgrade of procedures to include better control of preliminary c.
design data, design interfact; between site Stress and Support groups, and PG&E and Westinghouse, d.
Improvement of timeliness of project responses to site personnel safety concerns, and QA audit findings.
Corrective actions should 1
include identification of underlying causes, and surveillance to prevent recurrence.
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Conducting more. extensive QA program audits that will:
(1) include broader scope and more in-depth review during the audit and prior l
to accepting audit finding corrective actions, and (2) ensure all aspects of design control requirements, such as design criteria, assumption, judgement basis, review, and approval are imple-mented in accordance with program provisions.
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Upgrade of Tolerance Clarification program (TC or commonly called Quick Fixes) to ensure that adequate design reviews will be made l
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l I have discussed these concerns with PG&E management and I am presently j
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reviewing the licensee's actions.
As it stands to date, followup actions are incomplete.
Mr. Chairman, and members of the Congress, I thank you for the opportunity to testify, and will truthfully answer any questions that you may wish to ask.
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l U. S. NUCLEAR REGULATORY COMMISSION REGION V 3
Report No. 050-275/84-08 l
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DIABLO CANYON 1 INVESTIGATION / INSPECTION REPORT Prepared by:
- 1. T. Yin Senior Mechanical Engineer Division of Reactor Safety s
l Region III 3
- j Date:
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i CONTENT Page No,'
INVESTIGATION AND INSPECTION EFFORT 3
PERSONS CONTACTED 5
FUNCTIONAL OR PROGRAM AREAS INSPECTED 10 I.
Fol'lowup on Allegations A.
Allegation No. 79, Use of Controlled Document 10 B
Allegation No. 82, Personnel Training 17 i
C.
Allegation No. 84, Management Insensitivity to Concerns 28 O.
Allegation No. 88, Means to Accept Deficient Supports 30 E.
Allegation No. 89, Piping Interferences 40 F.
Allegation No. 97, Same as Allegation No. 79........
49 G.
Allegation, Quick Fixing Design Deviations....
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NRC Overview - Outgrowth of Followup of Allegation Items l
A.
Review of Design Procedures 57 s
B.
Review of OPEG S/B Support Calculations l'
and Piping Stress Analyses.
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Observation of L/B and S/B: Piping Suspension System Installations..
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D.
.L/B.and S/B Snubber / Rigid Restraint ~ Interaction-Evaluations 72
- E.
Review of PG&E Control of Field Problem
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Resolutions 77 1
F.
Review of Licensee and Bechtel QA Audits of l
-1 OPEG 80 G.
'PG&E and Bechtel Control of Procured Engineering Services.........................
100-H.
Concern Items on IDVP Evaluation of L/B and S/B Piping and Pipe Support Design.
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SUMMARY
OF FINDINGS FROM' FOLLOWUP 0F ALLEGATIONS AND i
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NRC INDEPENDENT OVERVIEW' 143 FOLLOWUP OF FINDINGS AND CONCERNS 155 i
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INVESTIGATION AND INSPECTION EFFORT 1
Dates
__ l Location l_ Inspector Hours l
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'11/29-30/83 i Site I
.20 12/1-3/83.
I Site 1
27 12/5-8/83 i Site 1
40 i
12/14-15/83 l Meetings w/NRR and PG&E at NRC, Betnesda, MDI 8
1/5-6/84-l Site l
18 1/9-13/84 i Bechtel' San Francisco, CA l
40 1/23-25/84' l Meeting w/NRR and Attending Congressional l
24
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Hearing l
1/31/84 l Meeting w/ licensee at PG&E, S.F., CA l'
8 2/1-3/84-llBechtel, S.F., CA l
24 l
2/7/84
'l Meeting w/NRR at NRC, Bethesda, MD l
8
-2/15-17/84 l Bechtel and PG&E, S.F.,.CA l
24 i
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.2/22-24/84 l Bechtel and PG&E,' S.F., CA l
26 i
3/5-8/84 l Site 1
28 3/14-16/84 i Bechtel, S.
F.,
CA l
12 3/26-27/84 l Meeting w/NRR and Testifying before i
16 l
Commission Hearing I
3/28/84 l Meeting w/PG&E at NRR Office 1
5 3/30/84 l Meeting w/NRR-IE Review Team in Bethesda l
5 4/2/84 l Attending Review Team meeting w/PG&E in S.F.I 8
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.4/5/84 l' Meeting w/ Review Team in Bethesda l
3 4/6/84 l Testifying before ACRS I
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Dates l
Location l Inspector Hours 4/10/84 l Meeting w/ Stokes (a NRR office 1
4 4/12/84 1 Discussion w/ Congress & Congressional staff l 2
- 4/13/84-l Testifying before-Commission Hearing l
4 4/3-5/2/84
'l Bechtel, S F.,
CA' I
24 5/22/84 l 8echtel, S.F., CA l
8
'5/23/84 l Accompany ACRS group _ site observations 1
6 5/24/84 l Site 1
5 6/5/84-l Meeting with peer review teams at NRC, l
6 i
Beth'esda, MD l
6/12/84 l Attending the Chairman's meeting in l
2 l
preparation for the Udall briefing l
lDiscussionwithCongressionalstaff l
2 l
6/14/84 l Attending the ACRS hearing, Udall briefing, l 3
I and meeting with Dr. Henry R. Myers l
6/19-20/84 i Review of adequacy of IDVP at Clouds, i
10 l
Berkeley, CA l
6/11-& 13/84 i Testify before the ACRS l
10 i
4
PERSONS CONTACTED f
i
. Pacific Gas and Electric Company (PG&E)
J. Arnold, Mechanical Resident Engineer
- h. E. Leppke, Onsite Project Engineer, OPEG i
E. R. Kahler, Senior Quality Engineer G. H. Moore, Project Engineer, Unit 1.
l M. R. Tresler, Assistant Project Engineer D. Tateosian, Deputy Group Supervisor, Piping G..W. Heggli, Acting Senior QA Engineer D. S. Aaron, Supervisor, Supplier Auditing M. L. Barham, Trai.ning Supervisor P. Hirschberg,. Piping Stress Analysist M. M. Sweeny, Quality Program Analyst R. R. Fray, Supervising Quality Engineer K. T.' Bergman, Acting Senior Engineer, Programs B. Norton,. Attorney T.' G. DeVriarte, Director, QA Program Manage > ment B. S. Lew, Project Licensing Engineer C. Holst, Quality Engineer T. L. Monti, Lead, Unit 1 Pipe Support Design Tolerance Clarifications T. P. Siekierski, Pipe Support Reviewer
.G. C. Wu, Licensing J. B. Hoch, Project Manager b
l l
J
i
-J. N. Walsh, QA. Engineer D. W. Ogden, Licensing Engineer l
Bechtel Power [orporation (Bechtel)'
M. J. Jacobson, Project.QA Engineer I
D. B. Hardie, Assistant Project Engineer, Quality
.R. R. Grey, Stress Group Leader, OPEG H; N. Shah, Stress Analyst Leader F. Zerebinski, Assistant Quality Engineer, Unit 1 L. E. Shipley, Assistant Chief, Plant Design M.' H. Lee, Piping Stress Group Leader G. K. Wang, Staff Engineer V. Juneja, Piping Support Group Leader S. S. Chitnis, Supervisor, Plant Design W. T. Kellermann, QA Manager, Programs and Audits C. H. Nichols, Engineering Supervisor R. W. Darcy, QA Supervisor, Training C. W. Dick,-Management H. Friend, Project Management R. Tinkle, Lead Mechanical Engineer, Unit 1 R. Nasadowski, Engineer L. Mangoba, Pipe Support Group Leader, OPEG D. Curtis,-Group Supervisor, OPEG-Plant Design G. Spease, Onsite Quality Engineer C. Ruud, Quality Assuranc'e Engineer 6
l
S. Aram, Lead Engineer, OPEG-Supports S. Soorma, Lead Engineer, OPEG-Stress A. Shusterman, Pipe Support Engineer R. C. Anderson, Engineering Manager R. G. Oman, Assistant Project Engineer D. K. Cosgrove, QA Engineer A. K. Jorgensen, QA Engineer J. A. Longworth, Assistant Onsite Project Engineer, OPEG P. Tam, Stress Engineer, OPEG R. Braboy, Civil Engineer F. Morsy, Civil Engineer M. Z. Khlafallah, Staff Impell Corporation J. B. McCathy, Project Manager W. 5. McLeod, Lead Senior Engineer, QA B. C. Morgan, Lead Senior Engineer W. D. Gallo, Section Manager J. A. Young, Supervising Engineer Westinghouse Electric Corporation D. N. Alsing, Manager, QA Systems and Compliance E. J. Domis, Senior Engineer C. W. Vernon, DCP Engineer
{
l E. M. Burns, Lead Licensing Engineer i
7
.Cygna Energy Services I
E. van Stijgeren, Vice President P. D. DiDonato, Assistant Manager, Management Services Division
)
1 Innova Corporation M. Shoikhet, Engineer, OPEG-Supports H. J. Thailer, DCP Pipe. Support Reviewer Bechtel Casual M. Durani, Engineer, Pipe Support Engineer J. Reas, Engineer, Pipe Stress Engineer R. B. Amin, Pipe Support Engineer
'A. K. Ghose,. Pipe Support Engineer Y. Igoinikoc, Pipe Support Engit:*er Code III Associates, Incorporated S. Jacques,. Stress Analyst T. H. Cummings, Pipe Support Engineer
'M. C. Kewalramani, Pipe Support Engineer l
Pace L. Tripsianes, Stress Analyst 8
l Kaiser Engineers D. W. Ogden, DCP Licensing Robert L. Cloud Associates, Inc.
R. L. Cloud E. Denison P. Anderson J. L. McLean j
.i C. I. Browne C. A. Beaulieu Teledyne Engineering Services S. L. Chin R. D. Foti R. Wray 9
___ J
I I
i FUNCTIONAL OR PROGRAM AREAS INSPECTED I.
Followup on Allegations A.
Allegation No. 79, ATS No. RV83A063, BN No. N/A 1.
Characterization Site design engineers were not required to use controlled documents in the performance of their work.
This resulted in different calculation bases, load ratings, and allowable stresses being used in small bore (S/B) piping analyses.
2.
Implied Significance to Design, Construction, or Operation Without uniform design bases, formulations, and acceptance criteria, the adequacy of plant system safety could not be verified and assured.
J
(
3.
Assessment of Safety Significance a.
Individuals Interviewed There were 30 hanger engineers and 25. piping stress engineers working at the site.
Three engineers from each group were j
selected for interview.
Length of employment at the site 1
10
was used as the criteria for selection.
In each group the oldest engineer, the newest engineer and an engineer with an intermediate length of employment was selected for interview, The initials of the 6 engineers are:
Support Design Group Names Initials Began Work Moisey Shoikhet MS October 1982 Manmohan Durani MD April 1983 Shahran Aram SA September 1983 Piping Stress Group Names Initials Began Work Stan Jacques SJ April 26, 1982 (assigned as pipe I
stress engineer) 1 John Reas JR February 1983 l
Suresh Soorma SS November 1983 l
b.
Maintenance of Out-of-date Work Procedures 1
(1) On December 2, 1983, the inspector interviewed MS at his work station and observed the following:
11 I
8 s
l
)
PG&E Design Criteria Memorandum (DCM) No. M-9,
" Guidelines for Design of Class'1 Pipe Support:
Units 1 and 2 Diablo Canyon Power Plant." Both Revision 6 and Revision 8 (dated August 10, 1983) were being kept.
At the time of this inspection the latest revision was Revision.9, dated November 18, 1983.
-l
-l PG&E Document No. 049243,_" Piping and Mechanical Standard Pipe Support for Design Class 1 Piping-2" and Smaller."
Revision 14, dated July 29, 1983, was the latest revision.
MS was maintaining-both Revision 14 and Revision 12.
1 (2) On December 2, 1983, the inspector interviewed MD at his work station and observed the following:
~j PG&E Document No. 049243, " Piping and Mechanical Standard Pipe Support for Design Class 1 Piping 2" and Smaller."
Revision 14, dated July 29, 1983, was the latest revision.
MD;did not have Revision 14.
He was using Revision 12, dated January 12, 1972.
3 L
(3) On December 5, 1983, the inspector interviewed SS, the Piping Stress Group Deputy Group Leader, and 12
)
observed that there was only one set of controlled i
procedures being maintained for use by the Piping Stress Groun.
Six procedures were selected for review from the latest listing, dated October 28, 1983.
Procedure Nos. P3, P11, and P19 were observed to be up-to-date.
Procedure No. P1, Rev. O was in the I
manual, Rev. 2 was the latest revision.
Procedure No.
.P2 was in the manue.f; however, it was listed as inactive.
Procedure No. P9, both Rev. O and Rev. 1 (the current revision,) were in the manual.
These con-trolled procedures were assigned to the Piping Stress Group Leader.
1 c.
Maintenance of Unauthorized Technical Articles and Data (1) On December 2, 1983, the inspector interviewed MS at his work station and observed the following unauthorized documents:
Bechtel SFPSM-3.12.1, " Frequencies, Stiffness and Deflection Requirements," Revision 0, dated July 14,1980 Bechtel Inter-0f fice Memorandum (IOM) File No. 925, " Guidelines in the Design of Skewed Welds," dated March 21, 1983 a
13 1
i Westinghouse Nuclear Technology Division Data for calculating double cantilever deflections, no sign-offs and date O
Bechtel Gaithersburg STRUDL II Computer Program Users Manual, CE901, dated November 3, 1982 Bechtel Gaithersburg IOM, from T. C. La Croix to Pipe Support Group Leaders, "GPD Pipe Support Group Newsletter No. 5, Proper Treatment of Beta Angle in STRUDL Input for Structural Analysis of Frames,"
dated November 11, 1980 Uncontrolled Form, "STRUDL Input for Best Choice of 2 Loading Cases."
(2) On December 2, 1983, the inspector interviewed MD at his work station, and observed the following unauthorized materials:
Control Data Corporation, Bechtel National Support Manager to Civil / Structural Projects and Staff,
" Baseplate II Usage Aids," dated March 14, 1983 Midland Nuclear Power Plant, " Pipe Deflection Formula" 14
(3) On December 3, 1983, the inspector interviewed SA, the Support Group Design Lead Engineer, and reviewed Calcu-1ation No. MP-1691 for Hanger No. 97-90 that was' checked by SA for the a',-built condition.
The inspector observed that the hane,er installation calculation was performed by Mr. V. Gliya (VG), and checked by Mr. A. Ghose (AG).
In the area of hanger deflection, the formula used by VG was cased on a McGuire Nuclear Station " Deflection Form la," dated September 25, 1980.
To check the design adequacy,'AG used a United Engineers Pipe Support Design Standard, dated August 15, 1979.
d.
Design Procedure System Deficiencies The following findings were identified:
(1) DCM M-9, Control No. P-149 was assigned to.MS, and Control No. P-126 was assigned to MD.
Stress Manual i
Procedures (Control No. P-75) were assigned to R. R. Grey.
Discussions with the On-site Project Engineering Group (OPEG) Quality Engineer, identified that these documents were controlled at the Project Administration Office in San Francisco.
No record was kept as to when the first issue was sent to the site for use.
The inspector was unable to determine how long the site staff was working without controlled procedures.
15
During a meeting held at NRC, Bethesda, MC on December 15, 1983, the inspector was informed that Control No. P-149, and Control No. P-126 were received by MS, and MD, respec-tively, on September 1, 1983.
Since MS began work in October 1982, he accomplished his work without a controlled copy of procedure No. M-9 for approximately 11 months.
Since MD began work in April 1983, he accomplished his work without a controlled copy of procedure No. M-9 for approximately 5 months.
As for the manual with Control No. P-75, the complete manual was not available for the Piping Stress Group until May 2, 1983.
People like SJ who started work at Diablo Canyon in April 1982 could have been working without controlled procedures for more than one year.
l (2) The latest listing of all the procedures was dated October 28, 1983, and was maintained by Mr. M. Leppke.
The listing of procedures maintained by the Quality Engineer, and by Leo Mangoba, the Support Group Leader, 1
were dated September 15, 1983.
(3) Some confusion was encountered during the inspector's
- review, i.e., several procedures and drawings are main-tained at PG&E Document Center, others are maintained at OPEG Document Center, and still others are maintained at the PG&E and Bechtel San Francisco offices.
16
4.
Staff Position The staff concluded that the administrative controls imposed on the site engineering activities have been inadequate and ineffec-tive.
The specific allegation items were substantiated.
B.
Allegation No. 82, ATS No. RV83A063, BN No. N/A 1.
Characterization There was minimal training for onsite pipe support engineers.
2.
Implied Significance to Design, Construction, or Operation l
Without adequate indoctrination and training, piping stress and support design engineers may not effectively perform their assign-ments.
3.
Assessment of Safety Significance This issue was addressed through examination of training require-1 l
ments, implementation records, interviews with engineers, and a I
review of engineering calculations.
1 i
W a.
Personnel Authorities and Duties j
i k
l l
17 s
]
_ _ ~.. _ _ _. _
_.______J
The staff interviewed five onsite design engineers selected 1
from'the personnel roster.
In addition, managers / supervisors 1
of the various design groups were interviewed.
There were l
no written job descriptions available for the pipe stress and support' group leaders, lead engineers, and engineers, l
l A. followup inspection was conducted on February 15-16, 1984, at the PG&E corporate office, San Francisco, CA.
The inspector
- reviewe'd the following documents:
1 PG&E Engineering Manual, Procedure 1.3, Attachment A, Rev. 2, dated August 9, 1982.
The Organization Chart did not show OPEG.
The staff. stated'that the procedure was being updated.
Bechtel NQAM Section I. No. 1, DCP Amendment dated July 5, 1983, Rev. 5-A, " Organization Charts."
DCP Instruction No. 9, "Onsite Project Engineering.
Group," Rev. O, dated August 17, 1982.
Bechtel Personnel Requisition of 15 " Job Shoppers,"
dated November 1, 1982.
Bechtel Personnel Requisition of 23 " Job Shoppers,"
dated February 14, 1983, i
18
PG&E Contract No. Z20-0023-84 with Code III Associates, Inc., dated January 13, 1983.
PG&E Contract No. 5-75-82, Change Order No. 5 with Innova Corporation, dated October 20, 1983.
l t
Subsequent to the review, the inspector concluded that the OPEG S/B piping design personnel authorities and duties were i
delineated in DCP Instruction No. 9; however, the site
]
personnel were not familiar with the procedure, and as a result they were unable to address the inspector's questions during site interviews.
Personnel qualifications and duties were prescribed in sufficient detail in Bechtel requisitions.
PG&E requisitions require the contractor organization to submit the work force qualifications and capability for PG&E's review and acceptance.
Both methods are considered to be acceptable by the inspector.
b.
Personnel Indoctrination and Training - General The general QA and technical training received by the engi-neers was not timely and consistent.
The bases for this determination are:
l 19
I Engineering QA Began Work Manual Survey Indoctrination Work Group Ho/Yr Training Date Date I
A (Support) 10/82 2/18/83 5/5/83 8 (Support) 4/83
'7/15/83 5/4/83 C'(support) 9/83.
12/16/82 10/23/81 D (Stress) 4/82 6/9/82 5/5/83 E (Stress) 2/83 4/19/83 5/4/83 The.' staff reviewed several design calculations which are identified in. Allegation No. 79.
Among the calculations
-i reviewed, the inspector identified that design verifications /
checking were not being performed in sufficient depth to catch calcul6tional errors.
It is the inspector's view that this is an indication of a lack of procedural knowledge and l
i training in project controls.
This allegation was substantiated, Subsequent irr.nections were conducted at the PG&E corporate office, San Francisco, CA on February 15-16, 1984.
The following training records were obtained for evaluation:
20
Date Date Reported Supervision to Work Requested Name
@ OPEG Training Training Received M. Shoikhet 10/19/82 2/8/83 EMS, 2/18/83, 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> SFPD QA Indoctrination, 5/5/83, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> M. Durani 4/83 7/7/83 EMS, 7/15/83, 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> SFPD QA Indoctrination, 5/4/83, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> S. Aram 9/83 12/15/83
- EMS, 12/16/83, 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> S. Jacques 4/82 EMS, 6/9/82, 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> SFPD QA Indoctrination, 5/5/83, I hour J.
Reas 2/83 3/14/83 EMS, 4/19/83, 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> SFPD QA Indoctrination, 5/4/83, I hour S. K. Soorma 11/1/83 12/15/83
- EMS, 12/16/83, 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />
)
- Since July 15, 1983, the EMS course included SFPD QA Indoctri-nation except on Design Drafting work modules.
21
The inspector also reviewed the pertinent portions of the following training procedures:
l PG&E Engineering Department Procedure (EOP) No. 2.1, "QA Program Training," Rev. 2, dated June 18, 1982, states in paragraph 4.2 "The Chief, Engineering Quality Control j
(EQC) shall arrange and have conducted specific training programs to assure that those engaged in nuclear safety-related work are knowledgeable in the applicable Proce-dures of this Manual, j
i 4.2.1 Personnel shall be appropriately indoctrinated, trained, and qualified prior to their performing quality assurance functions which may affect the final status of design or construction activities.
)
l Group leaders and supervisors shall send to EQC the names of all personnel, whether they be permanent or temporary, who are newly assigned to nuclear projects.
EQC shall arrange and conduct training in Engineering Procedures for these personnel as soon as work schedule permits."
DCP PEI No. 15, " Training," Rev. O, dated August 5, 1983, l
states in the following paragraphs:
1 1
1 1
22
l 3.1.3 "The Project Quality Engineer (PQE) will identify project personnel required to attend EMS training or retraining and request EQC by IOM to schedule these individuals for EMS training in accordance with paragraph 4.1.
Such individuals shall receive EMS training within 30 days of their assignment to tt;e Project."
c.
Specific Personnel Indoctrination and Training The staff also found that specific project group program training was not adequate.
During the inspection. conducted at the PG&E corporate office, San Francisco, CA on February 15-16, 1984, the following specific training records were j
l obtained for evaluation:
i l
Date Date Reported Supervision to Work.
Requested Name
@ OPEG Training Training Received L.'B. Mangoba 1/25/83 3/14/83 Engineering Manual i
Survey (EMS), 3/14/83, 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 1
1 4/7/83 PEI Training, 4/13/83 0.75 hour8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> 1
23
SFPD QA Indoctrination, 5/5/83, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> PEI No. 16, Rev 0,.&
EMP, 3.6 CN, 10/13/83, 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Mr. Mangoba is the OPEG Pipe Support Group Leader.
In discussion with the project management, it was stated that 1
specific PEI trainings received by the supervisors / leaders should be passed on to their subordinates.
The practice was subsequently determined not to have been carried out by i
the responsible supervisor.
1 OCP Project. Engineer's Instruction (PEI) No. 1, " Project Engineer's Instructions," Rev. 4, dated 2/1/84 states in Paragraph 4.6, "PEI Training will be conducted at the Engineering Group Supervisor (EGS) level.
Training will be conducted in accordance with the training. requirements for the Engineering Manual as described in procedure 2.1, Quality Assurance Program Training."
DCP PEI No. 15, " Training," Rev. O, dated 8/5/83, states in the following paragraphs:
3.2.1 "The Project Engineer (s) (PE) Unit 1 and Unit 2 are responsible for implementing 24
.a
the Project-Unique Training program on the Diablo Canyon Project.
Training sessions will be conducted within 30 days of the identified need.
The PQE shall assist in the development and presentation of the Project-Unique program (s) or other training as directed by the PE."
3.2.2 "The following personnel are responsible to l
attend Project-Unique Training as appropriate and/or necessary, in addition to specifically directed personnel, o Project Engineer (PE) o Assistant Project Engineers (APES) o Group Supervisors / Group Leaders (EGS/EGL) o Project Quality Engineers / Quality Engineers (PQE/QE)"
On March 5, 1984, the inspector interviewed the following Pipe Support Engineers working under Mr. Mangoba:
e O
2S
Name Date Reported to Work at OPEG l
T. H. Cummings 11/15/82 T. B. Amin
.11/15/82 M. C. Kewalramani 11/28/82 A. K. Ghose 11/21/82 l
Y. Igolnikoc 1/31/83 M. Durani 4/26/83 In response to the inspector's questions, all members of the above group indicated that:
i i
There had been no supervisor training provided by.
the group leader relative to procedure technical changes that could affect the performance of safety-related calculations performed by engineers.
Training received by Mr. Mangoba on October 13, 1983, concerning changes made to PEI-16, " Design Changes for i
Nuclear Plant Under Construction, Rev. O, dated October 10, 1983, and PG&E MP 3.6 ON, " Operating Nuclear j
Power Plant Design Changes," Rev. 3, dated February 14, l
1984, was not passed on to the working group personnel.
The only specific training provided to the group pertained to administrative matters relating to calculation 1
26
'ts packages, such as how to handle page sequence revisions,
- hat and how to identify snubber numbers.
'e -
4.
Staff Position iat
- 1usion.
1.
The. failure to provide timely training for the newly employed or assigned site S/8 piping stress and isible-support design engineers was primarily the fault of
- ruc-supervision not requesting EMS training as required by il j
EDP 2.1'and DCP PEI 15.
4 iared i
2.
There was an apparent lack of PG&E QA training for the S/B piping group employees.
Comprehensive QA training l
was not conducted until May, 1983.
3.
There is an apparent program insensitivity for providing specific job related training for the working staff.
No documented evidence exists to indicate that the Project-Unique Training required by procedure PEI 15
- lures, for site supervisory personnel had been passed on to the support desigr and piping stress engineers.
4.
Since July 15, 1983, the EMS course was a ? art of the t that SFPD QA indoctrination training provided to the OPEG le s ta f f.,
The instructor for the EMS is a PG&E Quality Program Analyist who reports to the Sr. Quality Engineer i
27
-__-___-__--__--_--------------------A
3.
Assessment of Safety Significance The staff interviewed the alleger onsite on December 7, 1983, to. clarify his concerns in this area.
The alleger referred to a memorandum written by line management to upper management relative to his concern about a lack of controlled design pro-cedures.
The staff interviewed project team general construction personnel-in. relation to the memo purportedly written by supervision.
In
- )
discussion with the pipe support group leader, on December 6, 1983,.
he denied that he had written a memorandum to Messrs. R. Oman and M. Leppke in December 1982 (the On-site Project and Deputy Engi-neers) relative to the lack of controlled design procedures being
{
used in the pipe support group, in support of Mr. Stokes' concern.
Mr. Leo Mangoba agreed that he.was aware of the subject concerns raised by members of his staff, and that he had taken actions to obtain additional controlled design procedures.
In view of the task findings that are discussed in Allegations No. 79 and No. 82 concerning:
(1) the large number of out-of-date procedures arid drawings and the deficient document control system; (2) the lack of training for the personnel relative to the use of up-to-date procedures and revisions to design; and (3) that management did no; respond in a timely manner to correct the pro-i blem and to prevent recurrence, the spirit of the allegation was substantiated.
29 1
4.
Staff Position The staff concludes that site man 6gement must improve its sensi-tivity in addressing safety concerns and improve communication with the workers.
I D.
Allegation No. 88, ATS No. RV83A063, BN No. N/A Q
l 1
1.
Characterization Means existed that would accept on-site design supports that were determined to be incapable of meeting the loading conditions.
2.
Implied Significance to Design, Construction, or Operation Management practice to compromise the system design safety margin by juggling calculations and designs to accept supports that had been rejected by calculations performed by the original reviewers could result in structures unable to perform their intended function.
3.
Assessment of Safety Significance a.
The staff met with the alleger on site on December 7, 1983.
Clarification and additional information concerning spaific i
areas of his affidavit were obtained.
A broad characteri-zation of his concern references the following detail elements /
l l
l l
30
ways t'he design group'may compensate for unacceptable calculations:
o 1
(1) Revising pipe code break locations in order to reduce the number of safety-related supports and omitting many of
)
I the supports that failed in the review program.
i (2) Assuming gaps that did not exist and vice versa.
1 I
E (3) Assuming joint release for rigid connections.
No attempt was made to remove the welds.
(4) Performing calculations to determine maximum sapport load carrying capacity.
The results were then sent to the.
piping stress group for'line model change to-meet piping allowable stresses.
i (5) Adding new supports within six inches of the unacceptable supports.
The new supports consisted of an inaccurate assumption of restraint gaps.
The new supports did not have control or document numbers, b.
During the inspection conducted at the site on March 5-7, 1984, the staff obtained the records, calculation logs and design calculations necessary to examine the above concerns.
6 31
1 (1)
In response to the allegation that code break locations had been revised and failed supports were omitted in the review program, the inspector reviewed a number of P& ids, and determined that the code break locations were determined by the system engineers and could not be altered by the site support engineers.
OPEG practice is to protect the safety related piping that connects to non-safety related oiping to ensure total system functionability during adverse plant conditions.
Seismic analyses are extended to an anchor or to include a number of restraints located on the non-safety related portion of the system.
The rules are described in PG&E Mechanical 4
and Nuclear Engineering Procedure No. P-11 " Procedure for Piping Stress Analysis, Diablo Canyon Ur,its 1 &
2," dated October 15, 1983.
Paragraph 4.4.11, " Code Breaks," states that "In cases where there is a change in code Class from PG&E Class I to Class II piping (seismic to non-seismic),
l it is'necessary to include the Class II piping in the analysis up to a point on the Class II line at which an anchor or at least two supports in each perpendicular direction (vertical, horizontal perpendicular) and at y
least onc support in the axial direction has been included.
A suggestion would be to install two guides around an elbow for adequate code break protection.
t Verify the feasibility of design with field personnel."
I i
32 I'
To verify'that the site staff was implementing the procedural requirements, the following two S/B piping j
i stress analyses were selected for review.
l Analysis No 19-305, " Liquid Radwaste," Rev. 1, dated June 8, 1983.
Analysis No. 3-313 " Piping System No. 3 - Feedwater Line No. 2477," Rev. 1, dated April 12, 1983.
Findinas Procedure Analysis No.
Analysis No.
Requirements19-305 3-313 a
Vertical 57-20(R)20-401(SL) l Restraint
- 22-423SL 2165-15(R) l Horizontal-57-11(R) 2165-32(R) i Perpendicular Restraint
- Axial 57-20(R)22-400SL Restraint
)
.t
- 0ne of the two bi-lateral,'estraints 33
i (R) - Rigid Restraint SL - Snubber Based on the above review, the inspector concluded that
'0 PEG was handling-code break analysis it an acceptable manner.
The allegation was not substantiated.
(2) Relative to the allegations that " Gaps that did not J
exist were assumed and vice versa; New supports were added within six inches of an unacceptable support; riew supports consisted of an inaccurate assumption of restraint gaps," the inspector had difficulty inter-preting their specific meaning and the issues involved, even after discussions with the alleger.
- However, in view of toe inspector's findings concerning OPEG's failure to consider load synchronization between closely spaced rigid restraints, and tneir. failure to inadequately-control the modeling of thermal stress relief gaps within rigid restraints, the inspector determined ttit the spirit of the allegation was substantiated.
(3) In conjunction with (2) above, it was also alleged that new supports were not assigned control or document numbers.
During the period of the inspector's review that extended from late November, 1983 to March, 1984, all new or modified supports were observed to have assigned control 1
i 34 a
numbers.
On occasion restraints without a number were shown in a calculation.
One instance observed was snubber 22-521SL for a valve.in Analysis No.19-305.
Subsequent review identified that a detailed drawing j
was made.
This allegation was.not substantiated.
s (4)
In response to the allegation of joint release for rigid
.1 l
connections, the inspector discussed the issue with
'0 PEG engineering management.
They indicated that there are three ways to reduce the loads on the flexible structures to which the restraines are attached.
They are:
(a) Model the structure's physical properties and con-figuration in the support / restraint calculation.
(b) Calculate the structural attachment stiffness, then include the stiffness in the support / restraint calculation.
(c) Assume the joint connection as a pinned connection.
The. inspector stated that he had no problem with methods (a) and (b) above, but that he had some reservations
.regarding method (c).
35
i i
.i l
Calculation No, MP-583, " Pipe Support 2156-169," Rev.15, dated November 9, 1983, with a pinned; joint condition, wa's~
presented to the inspector as an example where joint-release was used.
The following pertinent calculation revisions were reviewed:
I Rev. 3, dated August 22, 1983 - Final support evalua-tion completed.
The Civil group requested that the hanger group to model the connection to the " double-angle steel stiffener bracing structural member"'
as a pinned joint.
Rev. 4, dated October 13, 1983 - Support complied with the civil group request.
l Rev. 5, dated November 9, 1983 - As-built evaluation made.
i During discussions after his review of the above Rev. 3 and Rev. 4 calculations, the inspector stated that he felt it was unrealistic to remove all the structural joint bending moments, torsional moment, and all direc-tional deflections.
He requested the calculation be re-done with the attachment steel configuration and properties included.
A summary of the outcome is as follows:
i 36
lNew Calculation lRev. 4 lRev. 3 Loadings &
Iw/ Double Angle l Joint R:;leaselFixed Joint Displacements ISteel l@ Node 3 l@ Node 3 I
I i
Fx (1) l
-174 1
24 l
25 Fy (1) l 54 l
32 1
57 F2 (1) l 46 l
27 l
45 l
\\
l Mx (2) l
-362 l
0 l
-501 My (2) l
-372 l
0 l
-319 Mz (2) l 393 l
0 1
-432 l
l l
Ax (3)
I
.000103 l
0 l
0 oy (3) l
.003815 l
0 l
0 az (3) l
.000058 1
0 1
0 l
I l
0x (4) l
.0086 l
.0042 l
0 By (4) l
.0006
.0015 1
0 Oz (4) l
.0023 l
.0118 1
0 l
l 1
o max (5) l
.0105 l
.0097 I
.0095 37
where:
(1) Local Hosgri seismic force in ibf (2) Local Hosgri seismic movement in in-lb f
l (3) Grobal linear deflection in inch under
]
Hosgri seismic condition (4) Rotational displacement in radiar under Hosgri seismic condition i
(5) Effective weight maximum frame deflection.
As a result of the review, the inspector stated that the modeling of pinned connection in support / structure design was unacceptable; however, the magnitude of the effect was considered to be small.
Exactly how many other pinned joints modeled in calculations were indeterminate, however, the OPEG responsible personnel remembered that one more similar condition existed.
The allegation was considered to be substantiated.
38
l J
l i
Subsequent revie of the issue by the NRC-NRR staff had determined tnat the isolated cases involved could not affect system safety.
This matter is closed.
f (5) Relative to the allegation concerning back calculating pipe stresses using maximum support loads, the inspector was informed of the following measures that were taken by the piping stress analyst:
(a) Providing gaps in the rigid restraint to eliminate thermal stresses.
i (b) Utilization of pipe support stiffness in stress analysis.
(c) Reduction in system temperature using the latest revisions and DCNs, (d) Re-evaluate TAM from the L/B piping system.
(e) Providing additional supports and restraints.
The inspector stated that all the above methods were considered to be acceptable, except cautions should be exercised in method (a).
The specific problems observed regarding utill-zation of " thermal gaps" within a rigid restraint was discussed l
j l
39 4
i in Paragraph II.B.2.b (Stress Calc. 8-314, Part'A) of this report.
The allegation was partially substantiate'd, i
No written procedures' existed that delineated en effective wotk interface between the Pipe Stress and Pipe Support groups.
This could have been the cause of some confusion among.the OPEG engineers, including the alleger.
j 4.
Staff Position i
The staff concluded that there had been cases identified where design conservatism had been compromised.
While the effects I
of the deficiencies might be less than significant, the practices i
were considered to be in noncompliance with the NRC regulation.
E.
Allegation No. 89, ATS No. RV83A063, BN No. N/A f
1.
Characterization l
Improper resolution of piping interferences.
2.
Implied Significance to Plant Design, Construction, or Operation i
Piping interferences or inadequate piping support could result in piping systems being overstressed during operational or design loading conditions.
40
3.
Assessment of Safety Significance a.
During a site inspection conducted on November 30, 1983, the pipe clamp for snubber 16-285L that is installed on Line K3281-12 (a part of the Component Cooling Water system) was observed resting on the top of the floor penetration located ~
on F1. E1. 115'-0".
Subsequently, during the inspector's review at Bechtel on February 2-3, 1984, the PG&E responsible staff stated that a Deficiency Report was issued, however,
'during a followup inspection, sufficient clearance was. observed and so no corrective action was required.
The inspector reviewed
.the Stress Walkdown package 4-102, " Component Cooling Water,"
dated 8/22/83, including several of the 21 Stress Walkdown Problem Resolutions-(SWPR).
One of the SWPRs reviewed was No. 4-102-3-Y-A, dated November 8, 1983.
The inspector bad no adverse comments.
The report package identified 3 intentional restraints and 13 out of approximate 1y'145' supports on the piping system that had not been either installed or removed per the latest design revisions.
The conflict between the inspectors and the licensees observation was discussed, i
The conclusion was that perhaps the pipe clamp for snubber 16-285L had been temporarily loosened to facilitate other
.l construction activities in the area.
I b.
On February 2-3 and 15-16, 1984, the inspector reviewed the following PG&E DCP Mechanical and Nuclear Engineering design i
field walkdown inspection documents:
)
41
)
)
ll
1 l'
1 l
Instruction (I) - 17, "NRC IE Bulletin 79-14 Field j
'I Reverification Procedure for Large Bore Piping Isometrics, l
i L
Units 1 & 2," dated May 7, 1982.
i 1-18, "NRC IE Bulletin 79-14 Field Reverification Proce-dure for Small Bore Piping Isometrics, Units 1 & 2,"
Rev. 1, dated September 2, 1982.
I
.{
I-50, " Stress Walkdown for Large Bore Design Class I i
Piping Systems, Units 1 & 2," Rev. 4, dated October 24,.
1983.
Also, Rev. 3, dated September 23, 1983; Rev. 2, I
dated August 22, 1983; Rev. 1, dated August 10, 1983; Rev. O, dated August 2, 1983.
I Procedure (P)-36, "Walkdown of Piping During Initial Heatup, Unit 1,"
Rev. 1. dated January 27, 1984.
1
\\
P-37, " Procedure for Measuring Hot Gaps on Rupture Restraints, Unit 1," Rev. 1, dated February 10, 1984.
l P-38, "Walkdown of Piping During Power Ascension, Unit 1," Rev. O, dated January 27, 1984.
l c.
The review identified the following findings:
(1) for I-17 and I-18, in the area of interference clearances l
I 42
_______-_a
(the only area that was reviewed), they do not meet the requirements delineated in the NRC IE Bulletin (IEB) 79-14,
" Seismic Analysi:; for As-Built Safety-Related Piping Systems," dated July '2, 1979.
The Supplement 2 of IER 14, dated September 7, 1979, states "For exposed attachments and penetrations, licensees are expected to measure or estimate clearances between piping and supports, integral piping attachments (e.g. lugs and gussets) and supports, and piping penetrations.
Licensees are not expected to do any disassembly to measure clearances."
Contrary to the above, I-17 and I-18 do not require documented field measurements at locations such as pipe penetrations and where piping.is near. walls, near beams, and near large components.
The procedures consider that pipe / structures with a clearance of 3/16" and above ace without interference.
(2) To implement I-50 procedural requirements, the licensee stated, during a meeting conducted at Bechtel on February 23, 1983, that "The first of these programs, the Final Stress Walkdown, has already been completed.
Every seismic category line was walked down in its entirety in the cold position to visually check for interferences of any kind.
The walkdown was done by teams consisting of 1
a piping analyst and a support designer.
The team carried along records of the calculated displacements of the
]
i
)
43
I pipe for all loading conditions, in.luding seismic, SAM, i
TAM, and all thermal operating modes.
At locations of
]
i potential interference, the walkdown team calculated the range of predicted movements, subtracted them from the observed clearances and determined whether an interference could occur.
for each instance of insufficient clearance, a problem report was generated, which was forwarded to l
the appropriate organization for resolution.
Approximately l
800 problem reports were generated, and all of the problems.
were resolved,"
4 (3) During the February 23, 1983 meeting, the licensee also l
addressed the implementation of the P-36 and P-38 proce-dures, stating that To eliminate the possibility of an
. interference occurring due to differences between the actual thermal movements and those that were caiculated, additional walkdowns will be tione during initial heatup and during power ascension.
Key points will be selected f
along the entire length of the system.
At these points l
the cold position of the pipe will be measured, followed by the hot position, and the net displacement will be l
l determined.
The displacement will be compared against j
the predicted movements, and any discrepancies in magni-tude or direction of significance will be documented in a problem resport.
The problem report will be forwarded to the appropriate organization for resolution."
44 l
]
(4) After discussions with Bechtel and PG&E responsible engineers the inspector determined that the present i
inspection program, described in Paragraphs a, b, and c above, is deficient in the following areas:
(a) The minimum acceptance interference clearance of 3/16" used in 1-17 and 1-18 is not sufficient for all applications since many piping systems displace more than 3/16" during various thermal and loading conditions.
Although I-50 inspection acceptante criteria does require the worst design conditior, piping displacements of (a) single directional for thermal expansion, SAM, and TAM; (b) double direc-tional for all dynamic loads, there was no guarantee that the piping movements discussed above will be exactly as predicted by design.
As a matter of fact, the inspector is aware of cases observed during system hot functional tests, conducted at other operating nuclear plants, where pipe lines moved in the opposite direction or sideways when compared with the predicted design movements.
(b)
In conjunction with (I~ o'ove, the movements in the opposite direction are difficult and sometimes impossible for detect.
The reasons for this con-clusion are:
(a) the few key points selected 45
p h.
I:
L under P-36, and P-38 program do not correspond exactly with the possible interference locations, and (b) system hot tests do not cover all design i
iy thermal, SAM, and TAM displacements that result from all combined adverse plant operating coditions.
(c) Without establishing a data base for all potential unintentional restraints that includes (a) inspection of clearances for all directions exceeding the maximum piping displacements, and (b) documentation of the measurements at the concerned locations included in the;IEB 79-14 requirements, any evalua-tion to ensure the absence of piping interferences during any given plant system operating condition would be difficult.
d.
Additional site inspection was performed on March 6, 1984 in Reactor Containment 1, Auxiliary Building Area "L" (F1. El. 115'-0"), and Pipe Way Area (F1.
El. 121'-0").
The following piping and restraint interferences were observed:
(1) Snubber 10-143 SL movement could be restricted by Rigid restraint 1-32R in the tension loading direction.
46
I I
e (2) On line " Loop 4 FTD Manifold Return to Cold Leg 4, 56-1158-3," the nonsafety-related portion of the valve leakoff line was'interferred with by a guard ra'il. 'Since-the non-safety related piping l
is connected to the safety-related piping, the interference is considered to be' unacceptable.
(3) The movement of snubber'.22-61SL, installed in pipe
~
axial direction, could be interferred with by piping insulation.
(4) The movement of snubber 22-65SL could be restricted l
in the tension loading direction.
Insulation on the pipe elbow was touching the wall.
(5) The entire section of the horizontal run of piping for line 1-56-51-2, where rigid restraint 2152-09 l
is located, is rm ting on the top of the pipesay.
(6) The pipe elbow below rigid restraint 2152-15 on line 1-56-51-2, touches with the wall surface.
(7) The pipe insulation stated above is made.of hard calcium silicate, with a metal cover.
i i
47 I
l L
i L
e.
On March 15,'1984, the inspector discussed the restraint.
interferences' dest.ribed in d above with the PG&E and Bechtel staff.
The fo'11owing conclusions were drawn:
j l
l (1) The 0.835" thermal movement observed at snubber 10-143SL represented the worst piping displacement
(.
l condition.
This condition is acceptable.
i (2) The valve leakoff piping on line 56-1158-3" is not a part of the " code break" line extension..The thermal and seismic movements at the guard rail are small.
This condition is acceptable.
(3) For snubbers 22-61SL and 22-65SL,-and line 1-56-51-2 Stress Walkdown Problem Reports (SWPRs) should have been written.
This was an inadvertent error made by the walkdown personnel.
(4) There is little thermal and dynamic piping movements at the pipe elbow' near rigid restraint 2151-15.
This condition is acceptable.
4.
Staff Position The staff concludes that the site walkdown inspection program was i
unacceptable.
In addition, the licensee's' program to identify potential piping interferences was inadequate.
The specific allegation item was substantiated.
48
F.
Allegation No.'97,-ATS No. RV83A063, BN No. N/A l
4
]
1.
. Characterization.
l 1
Site design engineers have not been required to work using controlled documents.
This laxity has resulted in the use.of i
different design assumptions as'wellL.as other problems.
l i
j 2.
Implied Significance to Plant Design, Construction, or Operation.
See' Allegation No. 79.
l 1
3.
Assessment of Safety Significance i
See Allegation No. 79.
i 4.
Staff Position 1
i See Allegation No. 79, i
G.
Allegation, Quick Fixing Design Deviations 1.
Characterization
. A " Quick Fix" design changt program was being iniplemented.
This program was not a part of the licensee's QA program.
I 49
i 2.
Implied Significance to Design, Construction, or Operation l
-The use of a " Quick Fix" to accept pipe support design field.
changes bypassed the normal QA nonconformance reporting system and circucnvented the formal design change review and evaluation requirements.
i 3.
Assessment of Safety Significance a.
On F-abruary 8, 1984, Mr. Charles Stokes executed a second' affidavit that supplements and updated his initial allega-tions.
One of the matters-involved was OPEG's quick fix program for pipe support design changes.
It was alleged that engineers were not informed of the proper procedures, yet they " completely redid the design of hangers, deleted hangers,-deleted weld symbols from the drawings, and took i
similar actions without'the benefit of any calculations,"
t The normal quality as#surance reporting system for noncon-formances was bypassed, even with respect to significant
]
hardware deficiencies recorded only on Quick fix sheets.
I
)
b.
On March 7, 1984, the inspector reviewed an DCP OPEG document titled " Guide for Issue of Pipe Support Quick Fix Design Changes," Rev.1, dated January 7,1:18 4.
j The use of informal guidance $n lieu of written procedures
'to perform safety-related design devihtion evaluations is 50
considered to be in noncompliance with NRC regulations.
However, responsible site personnel pointed out that the.
l l
PG&E QA Department Activity Audit No. 83341A, "0 PEG Control 1
d of Design Changes - Criterion III" conducted on August 5 i
i and 8, 1983, had identified this problem.
The inspector reviewed the audit report, and determined that the licensee's corrective action was inadequate.
The bases
~
i for this determination is discusses in Paragraph c below, c.
Subsequent to the PG&E internal audit finding, the " Quick I
Fix" guide was transformed into DCP Instruction No. 12, l
" Pipe Support Design Tolerance Clarifications", Rev. 1, dated August 5, 1983.
The inspector reviewed 1-12 and evaluated the records related.to 3 L/B and 1 S/B Tolerance Clarifications (TC),
The inspector considers this program is being improperly used based on the following:
i (1) TC-1-11202, L/B Hanger No.74-33R, approved on August 12, 1983.
The support base plate had been significantly altered.
The alterations included major dimensional changes, an increase in plate thickness, a reduction in the number of stiffeners, and modified bolt hole locations.
(2) TC-1-11306, L/B Hanger No. 322-7R, approved on August 15, l
1983.
51
i i.
The' restraint design was changed from a double U-bolt configuration to single box beam type structure.
The
-1 design alternation also included changing from a steel I
channel.and angle structure to a tube steel structure.
(3) TC-1-11369, 4B Hanger No 18-7R, approved on August.18,-
I 1983.
This TC was superseded by TC-1-11777, approved on August 25, 1983.
The as-built evaluation was dated September 14, 1983.
The support base plate was l
revised significantly.
Original design:
2'-5" x~2'-5" x 1" thick; w/o stiffener; 8 - 1h" dia, bolts l
Revised design:
l'-10 3/4" x 2'-5" x 1" thick; w/6 added stiffeners; 6 - 1\\" dia, bolts (4) TC-1-14057, S/B Hanger No. 57-15,~ approved on November 7, 1983.
i This TC was used to evaluate PPP's Deficient Condition j
I Notice No. 177-007, dated November 5, 1983.
q I
The closecut of the Notice was dated November 15, 1983, and was based on OPEG S/B Support Design Group Calcula-j 1
tion MP-1530, "As-built evaluation of Hanger No. 57-15",
52 i
Rev'.' 2,. dated November 9, 1983.
The inspector. reviewed calculation MP-1530 and identified the following deficiencies:
(a) The PPP construction deviation relating to the included angles between-several of the structural members had not been addressed in the as-built-evaluation.
(b) Structural bracing members No. 48 and 49 shown i
in the STRUDL run dated November 9, 1983, were modeled in a different location than that.shown on the as-built drawings.
l (c) The-81" long steel angle (2.x 2 x 3/8") that s
formed a part of the valve body restraint (STRUDL l
member Nos. 37, 38, 46, and 47) was not included as part of the computer input.
I i
In addition to the Rev. 2 problems discussed above, Rev. 1 of the calculation dated September 8, 1983, "Per S/B Review Program", and Rev. 3 of the calculation, dated January 1, 1984, "Per Analysis l
19-305 Rev. 1", had all been checked and approved by the responsible personnel.
The deficiencies identified above were not documented and justified.
i 53 l
d.
Followup on the three L/B hanger TCs listed above was conducted at Bechtel, S.F., on March 14-15, 1
1984.
The purpose of the inspection was to deter-mine if these TCs had received a timely and adequate revits and were resolved properly.
l (1) Hanger No.74-33R (Bechtel Calculation No.
5-45, Rev. 9, dated November 9, 1983 The base plate evaluation showed that:
(a) the maximum as-built condition and tension / shear stress interaction values (IVs) were within the program allowables, and (b) there was a signi-ficant increase in the IVs; from 0.958 at Node 27 and 0.974 at Node 28 for the as-built to 0.578 at Node 5 and 0.806 at Node 24 for the as designed.
The support structural evaluation showed that:
(a) maximum critical stresses were within AISC allowables, and (b) there was a maximum stress increase from 12,506 psi to 18,001 psi.
54
l l
I (2) Hanger No. 322-7B (Bechtel Calculation No.
n-742, Rev. 3, dated January 24, 1984.)'
The base plate evaluation showed that:
(a) the maximum as-built condition stresses and IVs were within'the program allowables, and (b) the previous hanger _
calculation did not include a base j
plate analysis, l
The support structural evaluation showed' l
l that:
(a) maximum critical stresses were l
l l
within AISC allowables, and (b) the previous hanger hand calculation was not in accordance with approved design y
documention control provisions.
(3) Hanger No. 18-7R (Bechtel Calculation No.
3 i
S-122, Rev. 15, dated December 21, 1983)
I l
I The base plate evaluation showed that*
(a) the maximum as-built condition i
stresses and IVs were within the program j
1 allowables, and (b) there was general decrease in the IV values.
55
1 l
1
(
The support structural evaluation showed that:
(a) maximum criticai stresses
. were within AISC allowables, and (b) there was a general decrease in stresses, i
4, Staff Position i
The staff concluded that, based on the finding's identified, there appeared to be a breakdown in the licensee's QA program.for site design change control.
In view of the fact that:
(1) there
.4 are thousands (more than 30 - 21" binders full) of support s
" Quick Fix" or TC. design changes that have not been' subjected to design cont'ol measures commensurate with those' applied to r
the original calculations, (2) a " guide" was used to perform safety-related' design reviews, (3) QA and management actions to correct the apparent program breakdown including investigation of the causes, the effects, were not effective, (4) the TC procedure in'effect'at the time of this inspection did not delineate specific limitations on when it is appropriate to use the TC system, (5) OpEG S/B support calculations continued to include errors and (6) several L/B support original calcula-tions were observed to be deficient, the allegation was fully substantiated.
The inspector's review of the L/B support design alterations (the three TCs selected) indicate that sufficient reviews have been conducted by Bechtel.
However, as this review was limited, an evaluation of the overall program and
)
its implementation would require additional inspection.
56
____...__.-__________._.__________.____________.____J
p.
-1 p
l II, NRC Overview - Outgrowth of Followup of Allegation Items l
l l
I A.
Review of Design Procedures Among the design procedures reviewed in the followup of Allegation No. 79, the inspector observed conflict in design criteria.
DCM M-9, Revision 8, Paragraph 3.1.1 states, in part, that, "A method that can be used for calculating natural frequency is to limit the deflection of the support in the restrained direction to less than or equal to 0.025" by hand calculation or STRUDL from analysis." This requirement was in conflict with the widely used uncontrolled Bechtel SFPSM-3.12.1, Revision 0 procedure, where it states in Paragraph 2, Table 2.1, " Support deflection in terms of support frequency should be limited to 1/16, or 0.0625 inch." -
During the inspection conducted at Bechtel on January 11, 1984, the l
inspector reviewed Robert L. Cloud and Associates, Inc. Interim Technical Report (ITR) No. 60, "Diablo Canyon Unit 1 IDVP Review of Corrective Action Large and Small Bore Pipe Supports," Rev. 1, dated October 3, 1983.
In Paragraph 5.7, this ITR identified an application of the incorrect 0.0625" criterion in DCP Calculation M-178, Rev. 2 for Supplement No. 2159/2.
i i
B.
Review of OPEG S/B Support Calculations and Piping Stress Analyses l
l l
57
.J
During an inspection at the site on December 2-3, 1983, the inspector reviewed 5 support calculations at the Support Group, and on December 5, 1983, reviewed 2 piping stress calculations at the Piping Stress Group.
The following are the inspector's. findings:
1.
Pipe Support / Restraint Calculations a.
Calculation No. MP-397, " Hanger No. H21-226," Revision 2, dated August 18, 1983 - MS.
No adverse comment, b.
Calculation No. MP-465, " Hanger No. 002-170," Revision 3, dated September 6, 1983 - MS.
Even though an unauthorized double cantilever beam deflection formula was used, it did not affect the technical acceptability of the calculation.
c.
Calculation No, MP-1691, " Hanger No. 97-90," Revision 1, dated December 1, 198' - SA.
Same comment as Calculation No.
3 HP-465.
d.
Calculation No. MP-942, " Hanger No. 99-20," - MS.
(1) A STRUDL run prepared on February 1, 1983, checked on February 2, 1983, and approved on February 12, 1983, included 19 errors in the 10 load cases.
58 l
1 l
i
The support utilized a steel angle structure to which six restraint members were attached.
The Node point locations modeled in the isometric drawing were as follows:
i Center line of the steel angle structure: 10 l 8 l 7l 51 4l 3I Center line of the pipe
)
where loading imposes: 11 I 9 l 15 i 6 l 14 l 16 1 Load Cases Loading Locations IA 11 9
15 6
16 1B 11 9
7 6
4 3
2A 11 9
15 6
14 16 2B 11 9
7 6
4 3
3A 11 9
15 6
14 16 3B 11 9
7 6
4 3
4A 11 9
15 14 4
4B 11 9
7 6
4 3
I 14 16 SA 11 9
15 5B 11 9
7 6
4 3
There were 5 (7s) + 5(4s) + 5(3s) = 15 miss-placed loading inputs.
These incorrect inputs reduced the moments at the steel angle structure.
59
There were 3(--s) = 3 missing load cases.
There was one (4) that should have been a (16).
(2) A STRUDL run prepared on July 25, 1983, checked on July 26, 1983, and approved on July 27, 1983, for MP-942, Revision 3 included 30 errors in the 10 load cases.
I Load Cases Loading Locations lA 11 9
7 6
4 3
1 IB 11 9
7 6
4 3
2A 11 9
7 6
4 3
2B 11 9
7 6
4 3
3A 11 9
7 6
4 3
3B 11 9
7 6
4 3
4A 11 9
7 6
4 3
48 11 9
7 6
4 3
5A 11 9
7 6
4 3
5B 11 9
7 6
4 3
There were 10(7s) + 10(4s) + 10(3s) = 30 miss-placed loading inputs.
These incorrect inputs reduced the moment at the steel angle structure.
60
The design staff failed to follow PG&E Engineering Department Procedure No. 3.3, " Design Calculation,"
Rev. 4, dated June 25, 1982 (latest Rev. 5, dated July 15, 1983).
The procedure states in Paragraph 4.2.4, that " Computer calculations shall be checked for compati-bility of the program and the design assumptions, correctness of inputs, and interpretation and applica-tion of outputs.
e.
Calculation No. MP-1621, " Hanger No. 2156-200," Revision 0, dated September 1, 1983, approved Septemoer 1, 1983, - MD.
(1) The support design load input was based on a piping stress preliminary run, dated August 24, 1983, that was telephoned to MD on August 27, 1983.
During the site 1
inspection conducted on December 3, 1983, the inspector compared the Calculation No. MP-1621 loading input against Pipe Stress Run No.13-112, Revision 3, dated August 29, 1983, and found that the load direction signs for ihe 4 lb. dead weight loads were reversed.
Although the i
inspector concluded that there would probably be no effect on the adequacy of the pipe restraint, it did l
bring up two issues:
l l
l This simple error resulted in all ten load cases being invalid.
l 61
There appeared to be a lack of provisions in the program to review and verify preliminary information provided over the telephone and to evaluate and document deviations from design.
The design staff failed to follow PG&E Engineering g
Department Procedure No. 3.3, " Design Calculation,"
Rev. 5, dated July 15, 1983.
This procedure states in Paragraphs:
4.1.2 Calculation. Sheets "For nuclear work, assumptions requiring verification at a later design stage shall be identified by marking the appropriate page or sections with an identifying symbol...and/or by labeling the Calculation Cover Sheet
" Preliminary" until the verification is completed."
5.1.2 Nuclear Calculations, (a) "A preliminary calculation is an approved calculation which supports design but contains assump-j tions which need to be verified."
f (2) The pipe riser was restrained by two rigid frames, one on top of the other, one foot apart.
Forces in the
~
X direction (South) were selected for review:
62
)
Load Cases Upper Frames (lb,) Lower Frames (lb,)
1A
-44 1546 3B
-54
-4 2A 1225 2934 2B
-1323
-1392 3A 1993 3838 3B
-2111
-2255 4A 808 950 48
-902
-958 SA 811 2541 5B
-929
-958 The present support construction tolerance procedure allows, in the X-direction, a maximum 3/16" gap at the upper frame and no gap at the lower frame.
For the loadcasesof2A,3A,4A,and5g,theappliedloads will not be resisted by the upper frame.
Any differences in upper and icwer frame restraint gaps could cause one of the frames not to assume its portions of the design load.
2.
Piping Stress Analyses a.
Stress Calculation No.12-501, " Containment Spray," Revision 1, f
prepared on November 17, 1983, checked on November 20, 1983.
)
63 I
The response spectra developed by the Bechtel, San Francisco office was reviewed on November 17, 1983, and checked on November 22, 1983, but had not been approved for final calcu-lation application.
During a followup inspection conducted on December 6, 1983, the correct values from Response Spectra 12-501, Rev. 1 dated October 4, 1983, was verified to have been utilized in the calculation.
1 i
l b.
Stress Calculation No. 8-314 (Part A), "CVCS:
RCS Pump 4 Water Seal," Revision 6, dated November 10, 1983.
The modeling of 1/8" gaps at restraints 66-22, 2185-1, and 66-25 is allowed per Procedure No. P-11, " Procedure for Stress Analysis of Diablo Canyon Piping," Revision 6, dated October 5,'1983.
Daragraph 4.6.2 of this procedure states, l
that " Initial thermal analyses are to be performed without support gaps modeled.
As-built verification must be included in the documentation package for all modeled support gaps."
It is the inspector's opinion that the assumption that the pipe will move to the designed gap location during system thermal expansion so that there will be no stress on the pipe and no load en the restraint is unrealistic.
This opinion is based on (1) the records from startup tests observed at other nuclear plants indicate the actual piping thermal movements, 64
/
in many cases, differed from design, and (2) snubber cold position setting inspection results have been observed to differ under different conditions indicating that piping configuration and restraint gaps will not be maintained throughout plant life.
The generic issue related to the design control of thermal gaps within a rigid restraint was discussed during a meeting with PG&E and Bechtel personnel on December 15, 1983 at NRC office in Bethesda, MD.
PG&E responsed to this issue, as well as other issues in two letters to the NRC titled "Diablo Canyon Unit 1, Response to small Bore Piping Issues."
Both letters were dated December 28, 1983.
Their response stated, that "The (thermal gap) procedure was used on 59
)
supports, in 25 piping analyses, which accounted for 3.2% of the total small bore supports specifically analyzed....We have reviewed the 25 analyses and determined that there are 16 calculations below 200 F and 9 calculations above 200 F."
During a site inspection on March 6, 1984, the 19 small bore supports, where thermal gaps were remodeled ir, the 9 calcula-tions, were observed and evaluated by the inspector (See Table 1).
As to the systems below 200 F, including those with heat tracing, the inspector determined that the effect l
of thermal gaps would be minimal.
No additional review is planned.
65
1 Table 1 Evaluation of Thermal Gaps within Rigid Restraints l
15 mall Bore Support l
l l5 mall Bore Piping lNo. for which Gap l Thermal Gaps were l
l Calculation No.
lwas Modeled l Justified
- l l
5118 l
63-7 l
Yes l
l l
181-64 l
No l
l l
181-96 l
No l
l 1
3-302A l
53-1 l
Yes 1
j l
l l
53-1 I
Yes l
l l
53-1 l
Yes l
l 3-302B l
53-1 l
Yes l
l 4-302 l
42-6 i
No l
i i
l 8-310 l
2152-09 l
No l
I l
8-312 1
47-19 l
No l
l i
47-24 l
l l
8-314A l
66-22 l
Yes l
l l
2185-1 i
No l
l l
66-25 l
No l
l l
66-24 l
No l
l l
66-51 l
Yes
_l l
8-328 l
2157-14 1
Yes l
l 9-309 l
181-20 l
Yes l
l l
181-42
(
Yes 1
66
- The inspector considers that the thermal gaps were not justified if i
l the piping between restraints had 4 or more directional changes after the nearest anchor cr equivalent restraint, or if there was an extended length of pipe with 2 or more directional changes.
C.
Observation of Large Bore and Small Bore Piping Suspension System Installations 1.
On November 30, 1983, the inspector toured several areas in the auxiliary building.
Many of the snubbe rved installed on large bore piping systems were in close proximity with rigid l
restraints.
The snubbers observed are listed in Table 2.
The 1
functionability of these snubbers could be adversely affected.
l Mechanical snubbers require approximately 1/8" travel (less for small snubbers) to accour.t for ine play in the internal components and to close the gaps in the ball bushings installed in the structural and piping end connections and to assume the applied design load.
Under the existing installed condition the following problems could exist:
a.
The operability of snubbers could be impaired by the close proximity of the rigid restraints and guides.
b.
The non-functional snubbers could mean load increases at the affected rigid restraints and guides.
67
l l
l c.
The piping system natural frequencies and the reactive support loading distribution could be altered.
1 1
d.
The piping thermal movements at these locations are minimal.
It is the inspector's opinion that the lines could be restricted without causing unacceptable increases in the secondary pipe stresses.
The selection of these snubbers could be considered to be unjustifiable, e.
The radiation exposures received by plant personnel performing i
i required Technical Specification visual inspection and func-l tional tests for these snubbers with little or no thermal movement, could be avoided if the snubbers were replaced by rigid restraints that require only minimum 151 inspection and no functional testing.
This use of mechanical snubbers inplace of rigid supports does not appear to give appropriate consideration to ALARA (ALARA design review guidance is l
contained in Regulatory Guides 8.8 and 1.70).
2.
During the inspection conducted on March 6, 1984, inside the Unit I containment, the following snubbers were observed on Line 1-56-51-25PL installed in between rigid restraints 2185-19, 2152-19, 2152-63, 2152-12, and anchor 23-2A, The operability of these L/B pipe snubbers is questionable.
68
l Snubbers l
Max. Thermal Mvt. (in.) l l
22-326SL l
0.172 l'
i l
22-62SL i
0.016 l
l 22-63SL l
0.472 l
l 22-61SL l
0.211 l
Table 2 Large Bore Piping Snubbers Observed l
Affected i
Problem l
l l
Snubber No.
l Description l
Line/ Location l
l 4-2SL l Installed less l 1-K-149-10 l-1 I than 2 ft. from l CCW/ Safety Inject-l l
l l Strut 98-16R l tion Rm. on F1.
l l
l l E1. 85'-0" l
l 4-33SL l Installed on l 1-S2-1984 SI/
l l 4-32SL l valve operator. I Safety Injection l
l l The Piping con-l Rm. on F1. E1.
l l
l l necting to he l 85'-0" l
l l valve was rigid-l l
l l ly restrained l
l l 16-495L l Same as above l 1-K16-572-3 Steam l l 16-475L I
l Generator Aux. FW l l
l l
l Supply / Containment l
l l
l Penetration Area l
l l
l on F1. El. 115"-0"l I
69 f
c t
.s l 16-285L l Snubber movements) 1-K3281-12 Cont, l'
~
l 16-63SL lwere restrained l Fan CLR Supply-l l
lby 5-28R above & l From HDR A&B/ Cont.1 l
l5-5R below l Penetration Area l
q l
I
- 1 I
l on F1. E1. 115'-0"l l 16-675L l Snubber movements l 1-51-279-8 RHR
.l l
lwere restrained l' Supply to Spray l
L
- l lby 535-33A &.
l HDRs 1&3/ Cont.
I l
l585-32R l Penetration on F1.I I
l l
l El. 115'-0" l
l 16-795L (Snubber movements) 1-52-264-8 Cont.
l l
Irestrained by l Spray PP1 Dis-I i
1585-33A, 585-22R,l charge / Cont. Pene-l l
l l& 585-142R l tration on F1. E1 1 l
l l 115' - 0" l
' l 16-685L l Snubber movements l 1-S2-265 Cont.
I l
Irestrained by l Spray Header / Cont.1
' l l585-126A &
l Penetration on F1.l l
l585-28R l El. 115'-0" l
l 15-63SL l Snubber movements l 52-2520-8 RHR PPS l l
l restrained by l WTR Spray Headers /l l
l585-126A, 585-l Cont. Penetration l l
l159R, 585-127R, &l on F1. El. 115'-0"l l
l58-160R I
l i
70
6 1 4-16SL l' Installed on:
l 1-56-48-3 CVCS/Lett l
'l l
l valve operator.. I Down Ht. Exchange l
')
l l The piping con I Rm. No. 11 on Fl. f l
l necting to the l El. 85'-0" 1
f I
- l. valve was-' rigid-l l
l l ly restrained-l l
l 22-401SL 1 These small borel K16-2477-3/4"/.
l l 22-400SL l branch pipes l Cont. Penetration l l
l were restrained I on F1. E1. 115'-0"l l
l by the large l
l l
l bore pipe. rigid l l
l-l restraints l
l
- l 16-775L iSnubber movements l 1-K2-316-12/ Cont. l l
lwere restrained -l Penetration on F1.l l
lby 5-14R l.El. 115'-0" l
l l 16-80SL l Installed on l 1-52-265-8 Cont.
l i 16-81SL l valve operator. I Spray / Cont. Pene-l l
l The piping con-l tration on F1. El.1 l
l necting to the i 115'-0" l
l l valve was rigid-l l
l l ly restrained l
l l 22-401 SL i S/B snubbers l K16-2477-3/4"/
l l (Vert.)
l were installed l Cont. Penetration l l 22-400 SL l in the same l on F1. El. 115'-0"l l (Hori.
I direction as l
l l
l rigid restraints l l
l l on connecting l
l l
l L/B pipes i
I 71
l 22-493 SL l Possible inter-l Stress Analysis l
l (Hori. on S/B l action w/ rigid 1 No.19-305, Rev. II I
pipe) l restraints l
l l 22-521 SL l 57-12 and the l
l l (Hori. on S/B i pipe penetration!
l l
valve)
I anchor l
l t
3.
Similar conditions also existed in anchor and rigid restraint installations.
Anchors and rigid restraints with gaps were l
installed close to each other.
An example is 585-33A and 585-32R.
i Unless the anchor is loaded to plastic deformation (beyond the design limit), the rigid restraint would probably not assume the design load.
l D.
Large Bore (L/B) and Small Bore (S/B) Snubber / Rigid Restraint Interaction Evaluations
{
1.
Review of Bechtel Piping Stress Analyses On January 9-11, 1984 and March 6-7, 1984, the inspector reviewed the subject material at the Bechtel office and at the site.
The review and evaluation of piping stress analysis included analyses 1
performed at the request of the inspector.
In these analyses the questionable snubbers were omitted from the computer models.
The results of the review and evaluation were summarized in Tables 3 l
and 4.
i l
i l
72 j
l J
l 1
In Tables 3 and 4 the snubber operability acceptance criteria was based on the following manufacturer's test data:
Snubber Operability Acceptance Criteria l
l Pipe l Corresponding Snubber l
l Frequency IDynamic Displacement, l Test Load Snubber i
at 1st l Tension or Compression l Tension or Type or i
Vibration ILoss of l Tota' (Compression Size l
Mode (Hz)
IMotion (in) (Deflection (in))
(1b,)
l PSA-l-
9 1 011 to.016]
025 1
360 l
PSA-l 9
l
.010 l
.0375 l
650 l
PSA-1 l
9 l.003 to.0101
.020 l
1,500 PSA-3 l
9 1.012 to.0161
.0625 l
6,000 PSA-10 l
8 l
.021 l
.052 1
15,000 l
A/D-41 l
9 l.005 to.0101
.030 l
422 A/D-71 l
9 l
.012 l
.031 l
767 A/D-501 l
9 1
.030 l
.051 1
5,000 A/D-5500 l 9
l
.021 l
.0585 1
60,392 2.
Pipe Snubber / Rigid Restraint Interaction Evaluation Results a.
L/B Pipe Snubbers (1) 8 out of 9 units or 89% will not function as required by design during the seismic event.
(2) 6 out of 9 units or 67% can be replaced by rigid restraints without causing a piping thermal stress problem.
73
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t (3) 9 out of 9 units or 100% can be removed without causing piping stress or support load that exceeds' design limit.
(4) Maximum rigid restraint loading change due'to inoper-able installed snubbers in'close proximity.
+ 39.3%; -
37.6%.
(5) There would be a significant pipe anchor stress increase if the nearby snubber failed to function as required.
i (6) It is possible that the snubber is required because of i
large thermal piping movements; however, it would not be operable during a seismic event.
b.
L/B Valve Snubbers
]
(1) 5 out of 6 units or 83% will function per design.during the seismic event.
(2) 6 out of 6 units or 100% can be replaced by rigid restraints without causing piping thermal stress problem.
c.
S/B Snubbers (1) 4 out of 5 units or 80% will function per design during the seismic event.
76
1 (2) 1 out of 5 units or 20% can be replaced by rigid restraints without causing a piping thermal stress problem.
E.
Review of PG&E Control of Field Problem Resolutions 1.
Pullman Power Products Procedure ESD 223, " Installation and Inspection of Pipe Supports," dated August 23, 1983, states in Paragraph 6.7.1.2:
" Clearance dimensions specified as 0" on either side, top or side, top l
or bottom, and 1/8" on the opposite side shall have the following tolerances:
t 0" clearance on large bore supports must be maintained.
For large bore supports 1/8" clearance shall be 1/8" within plus or minus 1/16" (from 1/16" minimum to 3/16" maximum).
The gaps on all small bore supports shall be acceptable if the sum of the gaps on any axis is less than or equal to 3/16" except that the 0" gap in the negative-Y direction shall be maintained."
I 2.
The following documents involved in PG&E engineering evaluations and approval of Hatfield questions concerning construction tolerances of 1/16", were reviewed by the inspector:
77
i i
a.
Diablo Problem (DP) Lot, Item H-1183, " Pipe Hanger Tolerances,"
General Construction to PG&E Headquarters dated February 14, 1977, PG&E Headquarters responded on February 18, 1977.
l b.
Intra-Company Letter, M. R. Tresler, Mechanical Resident Engineer to A. G. Walter (Supervising Engineer) " Pipe Hanger Tolerances,"
dated February 34, 1977.
Items submitted for approval included:
Item 4.
"A clearance gap of up to 1/8" between pipe or pipe 2
attachment and the support is acceptable where 1/16" clearance gap is specified." The memo requested a return copy of approval with signature and date on the lower right corner, c.
Above letter was retyped, given a control number of DP 1183-M(H), and a new date of February 18, 1977.
Item 4,
" Total gap not to exceed 3/16"" was added.
The acknowledgment 1
was signed by R. E. Bancher (Senior Engineer), dated February 18, 1977.
d.
DCP Engineering Of fice Special Instruction, ' Design Questions Submitted by Steam Generation Department," dated November 22, 1977.
This document was issued without review and approval sient "s.
e.
Procedure Implementing Instruction, " Procedure for Handling DP's," by D. Polly (Licensing Engineer), dated August 12, 1978.
)
k 78
[
i i
L f.
PG&E Co. Engineering Department, Nuclear Projects Department, t.
Implementing Engineering Instructions, No. NPI-6.1, Supplement 1, " Design Questions," dated. August'20, 1979.. Approved by the Nuclear Projects Engineer.
g.
PG&E Co. Nuclear Power Generation Department Procedure, No.
D-444, " Design Question Administration," Rev. O, dated June 3, 1981.
Approved by Manager, NPS.
h.
DCP Instruction No. 7, "frocessing Diablo Problems," Rev. O, dated August 10, 1982'; Rev. 3, dated October 10, 1983.
3.
Subsequent to the above' document review, the inspector. concluded that until August 12, 1978, there was no instruction on how to handle DPs.
It was not until August 20, 1979, that a formal proce-dure was established on design question / problem evaluation by the design engineering organization.
The problems concerning specific constr.uction tolerance of 1/16"'are as follows:
a.
The February 14, 1977, field letter did not request an addi-tional tolerance.
The content of the letter was revised by the recipient and given a new date of February 18, 1977.
j Instructions on how the PG&E home office engineers can alter I
a field originated request'is not specified in a procedure i
and as a result this alteration is considered improper.
l I
l 79
__-_________ _-_____ - ____-_______ _ __ _ _ a
b'.
.The February 14, 1977,- field letter requested PG&E Supervising Engineer's approval of the' construction tolerance.
The request was approved by a Senior Engineer..There were no provisions in procedures to permit.a lower. level of engineering approval of a field request.
Furthermore, there was no document' listing'quali-fied reviewers who were designated to' evaluate and approve specific field problems.
c.
It was apparent that since August 10,1982, (during the.. period of IDVP/ CAP activities) control of the DP process had been upgraded.
However, there was no evidence of any retroactive ~
effort to retrieve all previously approved DPs to determine
-l
.that (1) engineering dispositions and resolutions had been reviewed by qualified and designated engineers / departments, and (2) documentation was not maintained to substantiate that sufficient engineering evaluations had been made by the 4
i responsible individuals.
F.
Review of Licensee and Bechtel-QA Audits of OPEG-l 1
1.
On December 6, 1983, during discussions with an OPEG QA Engineer, I
a Bechtel employee, the inspector requested audit and surveillance records covering the last 12 months.
The areas of site design and l
document control were selected for review.
The following audit reports were presented to the inspector:
I 1
80 j
a.
Bechtel QA Audit No. 28.2-1, audit of onsit'e engineering in the areas of drawing control, conducted on November 5, 1982, b.
Bechtel QA Audit No. 28.4-1&2, aadit of onsite engineering including personnel training, conducted on February 18, 1983.
c.
Bechtel QA Audit No. 28,1-2,. audit of onsite engineering including record retention, marking of SAR changes and super-seded calculations, and verification of design assumptio.ns, conducted on August 10, 1983.
2.
During a meeting held at NRC Headquarters.in Bethesda, MD, on December 15, 1983, licensee representatives presented the following additional QA audits:
Audit Date a.
PG&E QA Audit 20703, " Approval of 09/17/82 Implementing Procedures" b.
PG&E-QA Activity Audit 20937, "0 PEG 10/05/82 Drawing Control" c.
PG&E QA Activity Audit 20813, " Incorrect 10/14/82 Loads Used in Hanger Calc" 81
!L_
d.
Project QA Audit 28.1-1, "0 PEG Design 11/03/82 Calculations" e.
PG&E QA Audit 83087A, "0 PEG Control of 03/15/83 Deviation from Design" l
f.
PG&E QA Activity Audit 83159A, 04/18/83 Maintenance of QA Records" g.
PG&E Activity Audit 83161A, " Document 04/18/83 Control:
Indoctrination and Training Records h.
PG&E QA Audit 83171A, "0 PEG System 05/16/83 Interaction Program - Inside Containment" i.
PG&E QA Audit 83173A, "0 PEG System 05/18/83 Interaction Program - Outside Containment" j.
Project QA Audit 28.2-2, "0 PEG Design 06/15/83 Change Procedure Compliance" k.
PG&E QA Activity Audit 83259A, "0 PEG 06/20/83 Problem Report System"
=
1.
PG&E QA Audit 83187A, " Review and Approval 07/27/83 q
Cycle of Drawings and Calculations" 82
- - - - D
m.
PG&E QA Audit 83341A, " Control of Design 08/05/83 I
Changes"
]
n.
PG&E QA Audit 83339A, "0 PEG Control of 08/08/83 Design Doc :ments" i
o.
Project QA Audit 30.1-3, "0 PEG SIP 08/24/83 Activities l
p.
PG&E QA Audit 83463A, "0 PEG Audits" 09/12/83 3.
On February 1-3, 1984, the inspector visited the 8echtel and PG&E offices and reviewed the following QA audit procedures, plans, and reports:
a.
Audit Procedures and Plans (1) PG&E QA Department QADP-18.2, "QA Audits," Rev. 2, dated October 3, 1983.
(2) Bechtel QA Department Procedure, Section C, Number 5,
" Project Quality Audits," Rev. 7, dated September 24, 1
1982.
(3) PG&E QA Department - 1983 Activity Schedule for months of July to December.
83
_----___-------______J
(4) PG&E 0A Department - 1982 Activity Schedule, approved on April 1, 1983 (as performed QA audits),
(5) Bechtel "QA Master Plan for DCP," Rev. 1, dated October 26, 1983.
(6) Bechtel "QA Quarterly Audit Schedule for DCP, August 30, 1982 through October 1, 1982," dated July 27, 1982.
(7) Bechtel "QA Quarterly Audit Schedule for DCP, October 4, 1982 through December 31, 1982," dated October 22, 1982.
(8) Bechtel "QA Quarterly Audit Schedule for DCP, January 3, 1983 through April 1, 1983," dated January 3, 1983.
(9) Bechtel "QA Quarterly Audit Schedule for DCP, April 8, 1983 through July 1, lo83," dated March 28, 1983.
(10) Bechtel "QA Quarterly Audit Schedule for DCP, July 5, 1983 through September 30, 1983," dated July 11, 1983.
(11) Bechtel "QA Quarterly Audit Schedule for DCP, October 7, 1983 through December 30, 1983," dated October 28, 1983, i
b.
PG&E Audit Reports j
i
(
84 J
(1) No. 20703, dated September 14, 1082, "New OPEG Personnel Compliance with Approved Procedures," conducted on August 23-September 1, 1982.
Review included:
(a) Open Item Report (0IR) No. 147-82, dated September 17, 1982, stating that several implementing procedures were without required approvals.
OPEG responded on December 21, 1982.
QA close-out was dated October 6 1983.
3 (b) DIR No. 148-82, dated September 2, 1982, stating that there was a lack of a controlled distribution system for site originated procedures.
No project response was required.
QA close-out was dated January 31, 1983.
(2) No. 20917, dated October 12, 1982, "0PFG Control of Velums per Procedural Requirements," conducted on September 23-October 5, 1982.
Revies included:
(a) OIR No. 152-82, dated October 6, 1982, stating that superseded vellums were not marked and that there was a lack of controlled work procedures.
OPEG responded on December 15, 1982, and a Discrepancy Report (DR) No.
85
82-184-5 was issued.
OPEG close-out of the DR was on April 18, 1983.
QA close-out of the DR was dated May 17, 1983.
(3) No. 20813, dated October 19, 1982, "0 PEG Support Modification in Compliance with DC1-EM-1090," conducted on October 14, 1982.
Review included:
(a) O!R No. 153-82, dated October 14, 1982, stating that there had been incorrect load data and deficiency docu-ment control and.retrievability identified.
OPEG.
responded on December 15, 1982, with DR 82-183-M.
The DR was closed out on April 12, 1983 by OPEG.
QA close-out of the OIR was dated May 9, 1983.
(b) OIR No. 154-82, dated October 14, 1982, stating that l
deficiencies had been identified in Pullman Power Product (PPP) as-built drawings.
PPP responsed on j
i November 3, 1982.
QA close-out was dated August 17; j
J 1983.
(4) No. 83087A, dated March 22, 1983, "0 PEG Control of Construc-tion Deviations," conducted on March 15, 1983.
86 I
(5) No. 83159A, dated June 2, 1983, "0 PEG Quality Record Mainte-nance and Control," conducted on April 18, 1983.
(6) No. 83161A, dated May 28, 1983, "0 PEG Personnel Indoctrination and Training Documentation Compliance with Engineering Manual Procedure 2.1," conducted April 18, 1983.
\\
(7)
No. 83171A, dated June 1, 1983, " System Interaction Program -
Inside Unit 1 Containment," conducted on May 16-18, 1983.
(8) No. 83173A, dated May 5, 1983, " System Interaction Program -
Outside Unit 1 Containment," conducted on May 10-17, 1983.
I l
(9)
No. 83187A, dated July 26, 1983, "0 PEG Review and Approval of Calculations, Drawings, etc.." conducted on July 7, 13, and 14, 1983.
Review included:
(a) OTR No.83-125, dated July 27, 1983, stating that approval of calculations by the Deputy Group Leader was not in accordance with work procedures.
OP[G responded on 1
August 4, 1983. -QA close-out was dated August 16, 1983.
(10) No. 83259A, dated July 1, 1983, "0 PEG Problem Report Process i
and Control," conducted on June 20, 1983.
4 87 I
4 (11) No. 83341A, dated September. 15, 1983, "0 PEG Procedures for l
Design Change Control," conducted on August 5 and 8, 1983.
Review included:
(a).0TR No.83-185, dated August 17, 1983, stating that pipe support design tolerances were not approved properly and design changes were being made without documentation of-calculations or assumptions.
OPEG responded on Sept-ember 30, 1983.
QA close-out was dated October 17, 1983.
(12) No. 83339A, dated September 15, 1983, "0 PEG Design Document Control," conducted on August 8-9, 1983.
l (13) No. 83463A, dated September 27, 1983, "0 PEG Internal Audit Planning, Performance, Reporting, and Followup Action Activities," conducted on September 12, 1983.
c.
Bechtel Audit Reports 1
(1) No. 28.1-1, dated November 16, 1982, "0 PEG Small Bore Pipe i
Support Calculation," conducted on November 3-5, 1982.
{
)
Review included:
88
(a) QA Finding (QAF).No. 1, dated November 4, 1982, stating that (1) calculation cover sheet incomplete (2)- sheet identification missing orcincorrect, and (3). log indices 4
incomplete.
The scheduled. correction completion date was December 31, 1982.
OPEG completion was-dated January 11, 1983.
QA close-out was dated April 28,11983.
(2) No. 28.2-1, dated November 16, 1982,,"0 PEG Review of Contractor Developed S/B Piping land. Support Drawings," conducted on week ending November 5, 1982.-
Review included:
(a) QAF No. 1, dated November 4, 1982, stating that.the P-10 procedure used was not approved.
The scheduled correc-tion completion date was November 30, 1982.
OPEG completion was dated November 30, 1982.
QA close-out 4
was dated Apri? 8, 1983.
I (3) No. 28.4-1&2, dated February 28, 1983, "0 PEG Personnel i
Indoctrination & Training," conducted on February 17-18, 1983.
Review included:
(a) QAF No. 1, dated February 18, 1983, stating that not all 0 PEG engineering personnel had received Engineering 89
Procedure Manual training.
The scheduled correction completion date'was March 31, 1983.
OPEG completion was dated March 14, 1983.
QA close-out was dated May 10, 1983.
(b) QAF No. 2, dated February 18, 1983, stating that, "With one exception, no evidence was available to document training of supervisors to PEI's."
The scheduled correction completion date was March 31, 1983.
OPEG completion was dated April 20, 1983.
QA close-out was dated April 21, 19.83.
(4) No. 28.1-2, dated June 21, 1983, "0 PEG Compliance with DCN Procedure," conducted on June 10-17, 1983.
Review included:
(a) QAF.No. 1, dated June 17, 1983, stating incorrect use of DCNs had been identified.
The scheduled correction completion date was July 1, 1983.
OPEG completion was dated July 5, 1983.
QA close-out was dated July 28, 1983.
(b) QAF No. 2, dated June.17, 19J3, stating change reasons had not been given in DCNs.
The scheduled correction completion date was August 1, 1983.
OPEG completion was dated July 27, 1983.
QA close-out was dated August 10, 1983.
90
l (c) QAF No. 3, dated June 15, 1983, stating DCN sketches not been signed and dated.
The scheduled correction completion date was' August 1, 1983.
OPEG completion date was July 27, 1983.
QA close-out was dated August 10, 1983.
(5) No. 28.1-2, dated August 24, 1983, "0 PEG Calculation for DCP
~
Unit 1 Compliance with Procedure," conducted on July 29 -
August 16, 1983.
Review included:
(a) QAF No. 1, dated August 10, 1983, stating that prelimi-nary and final calculations had not been entered into the Record Management System.
The scheduled correction
(
completion date was September 15, 1983.
OPEG completion was dated October 27, 1983.
QA close-out was dated December 20, 1983.
(b) QAF No. 2, dated August 10, 1983, stating where SAR i
change is required, no evidence of change was made.
The scheduled correction completion date was September 15, 1983.
OPEG completion was dated October 19, 1983.
QA close-out was dated November 2, 1983.
91
(c) QAF No. 3, dated August 10, 1983, stating that inade-t quate references were stated in the final calculations.
The scheduled correction completion'date was September.
~15, 1983.
OPEG completion was dated October 19,.1983.
QA close-out was dated November 2, 1983.
(d) QAF No. 4,' dated August-10, 1983, stating that Calcula-tion No. 8-306 referenced incorrect design documents.
The scheduled correction completion date was September l
15, 1983. '0 PEG coepletion was dated October 19, 1983.
l QA close-out was dated November 2, 1983.
(6) No. 30.1-3, dated September 13, 1983, "0 PEG System Interaction Program Implementation," conducted on August 22 - September 9, 1983.
Review included:
(a) QAF No. 1, dated August 24, 1983, stating that construc-j tior, drawings were issued prior to approval of design j
calculations.
The schedu?ed corrective completion date was October 20, 1983.
OPEG completion was dated October i
5, 1983.
QA close-out was dated October 24, 1983 l
d.
Review Findings l
1 I
l-92 j
)
Subsequent to the review, the inspector determined the PG&E and Bechtel QA audit programs and their implementation were deficient in.the following areas:
Findings Audits (1)
Inadequate Corrective Action (a)
Lack of timely (15 days was
.20703, dated 9/14/82 specified in the PG&E procedure) 20917, dated 10/12/82 response to the QA findings from 20813, dated 10/19/82 OPEG.
The delays were without documented justification.
(b) The lack of timely response to an OIR was identified in a PG&E Nonconformance Report (NR) No.
N005, dated Nocember 19, 1982.
No documented evidence existed to indicate that QA had initiated actions against OPEG to ensure corrective actions.
Instead, the NR was written stating that there was a lack of a tracking system within the QA Department and 93
t
-that the QA procedure should be revised.
The development of a QA program revision was approved by management on September 21,.
1983.
The revision had not been carried out as of the date-of review (February 3', 1984).
(c) Bechtel audit finding corrective 28.1-1, dated November action scheduled completion
-16, 1982' i
dates were delayed without 28.4-1&2, dated February documented justification from 28, 1983 OPEG.
28.1-2, dated August 24, 1983 (d) Lack of PG&E audit finding 20703, dated September corrective actions to identify 14, 1982 the cause of the problem and 20917, dated October the measures needed to prevent.
12, 1982 recurrence.
20813, dated October 19, 1982 (e) Project corrective action only 20813, dated October addressed specific problem areas 19, 1982 identified in the PG&E audit findings and did not consider 94 s
generic implication of the problems.
QA concurred with this apparently inadequate corrective action; (f) Inadequate Bechtel QA verifica-28.4-1&2 tion of OPEG corrective actions
-)
prior to close-out of audit findings.
OPEG Personnel r
training continued to be inadequate.
(g) Additional DDR's were reviewed Discrepancy and at PG&E on February 15-16, 1984.
Departure Report (DDR)
A large number of DDRs show a No.80-025 close-out date many months after j
the problem disclosure.
DDR No.
p 80-025, issued on October 16, 1980, was selected for review.
The problem relates to engineering procedures do not require verifi-cation that only current documents are used.
Engineering Department Procedure No. 2.4 was not revised to incorporate the requirement until Revision 2, dated February 22, 1982.
n 95 V
l (h)
In conjunction with (g) above, on i
1 4
February 16,~1984, the inspector discussed the numerous late corrective action DDRs with the
)
4 PG&E Acting Senior QA Engineer.
The inspector was informed that it was a PG&E management decision to l
place priority on closing out.
1 DCNPP Unit 1 DDRs.
However, the
'i inspector noted that there was as I
apparent _ lack of measures to
)
evaluate the effects of the program deficiencies that were not corrected in timely manner and not covered by the IDVP and CAP.
(2)
Inadequate QA Audits (a) When a QA audit item could not 83087A, dated March be evaluated due to a lack of 22, 1983 project activities, followup of the item was not planned.
l (b) Lack of a QA audit verification 28.1-1, dated November j
that includes documentation of 16, 1982 the material reviewed before an audit finding is closed out.
I 96
(c)
Lack of QA documentation of 83161A, dated May 28, material reviewed during the 1983 course of the audit.
The QA i
]
audit conclusions that stated i
" Indoctrination of training records are being maintained and
)
controlled as required," and a
" Training and retraining have been conducted as required" were without basis and are contrary to NRC and subsequent Bechtel QA audit findings.
(d) Lack of technical QA audits to 83187A, dated July independently verify.that OPEG 26, 1983 calculation inputs were checked 28.1-1, dated November to be in compliance with engi-16, 1982 neering procedures.
(e) An audit was planned to verify Bechtel Audit No. 28.3 that OPEG issuance of Discrepancy originally scheduled Reoorts (DRs) was being imple-(w/e):
December 17, mented in accordance with 1872 procedures.
DRs were not issued 1st postponement:
by 0 PEG until 1983.
The DRs August 5, 1983 issued by OPEG to date are listed 2nd postponement:
below.
These DRs were issued November 11, 1983 during the NRC investigation.
97 i
I
i DR 83-047-5, Procedures were not kept current, dated December 6,.1983 i
DR 84-001-S, Support was modified for stress analysis, dated December 16, 1983 DR 84-004-S, Base plate design was not per IE Bulletin 79-02, dated February 2, 1984 1
From late 1982 to Nov. 1983, there were hundreds of S/B i
piping stress analyses and support calculations performed by OPEG.
The inspector considers that the Bechtel QA audits at the site were inadequate and that audits were not conducted or verifications made to determine the adequacy of OPEG actions taken to identify and ' correct design deficiencies 98 l
i l
(f) An audit was planned to verify Bechtel Audit No. 28.5 proper control of issuing and Originally scheduled distribution of OPEG procedures.
(w/e) March 11, 1983
-Two audit deficiencies were 1st postponement:
identified as:
May'6, 1983 2nd~ postponement:
August 2, 1983-3rd postponement:
December 16, 1983 Conducted:
January 9-February 2, 1984 The auditor discovered that, since March, 1983, the con-trol of OPEG procedures was conducted at the PG&E and Bechtel, San Francisco offices.
There was no attempt made to revise the audit checklist to cover these activities.
Approximately 10 months later the audit checklist was modified to cover the related OPEG activities.
The inspector 99
considers that the benefits of timely audit to ensure program compliance had been compromised.
i G.
PG&E and Bechtel Control of Procured Engineering Services During review of L/B snubber and rigid restraint interaction problems, I
the inspector was made aware that many of the L/B piping stress analyses were performed by outside consultants.
1 On February 21-23 and March 15, 1984, PG&E and Bechtel' control of the procured engineering services was reviewed by the inspector.
1.
Work Performed by the Consultants Based on the Piping Stress Analysis Index-as of January 6, 1984, the Bechtel engineers presented the following information:
a.
Imprell Corporation (Previously EDS, Nuclear Inc.)
Bechtel contracted with Impell in 1981.
Most of Impell's work activities were conducted between October 1982 and August, 1983.
The analysis performed included:
i 100
I ANALYSIS REV ISSUE l
NUMBER SYSTEM SERVICE NO.
DATE l
l 1-109 Main Steam Lead 3-Valve 3
06-06-83 j
Bypass 1-111 Steam Generator Blowdown 1 2
05-06-83 1-112 Steam Generator Blowdown 2 2
05-11-83 1-113 Steam Generator Blowdown 3 2
05-11-83 1-114 Steam Generator Blowdown 4 3
07-29-83 1-116 Main Steam Isolation Valve 1 3
08-12-83 1-117 Main Steam Isolation Valve 2
- 4 09-19-83 1-118 Main Steam Isolation Valve 3
08-12-83 Bypass 4 l
2-115 Auxiliary Feedwater Supply 3
08-12-83
'2-118 Auxiliary Feedwater Supply 3
08-18-83 2-119 Auxiliary Feedwater Supply 3
06-27 l 2-120 Feedwater Auxiliary' Supply 4
06-23 l 4-109 CCW Return from PEN-20 2
06-06-83 4-110 CCW Return from PEN-21 3
06-03-83 i
4-110 CCW Return from PEN-21 4
08-12-83 Thermal Only 8-105 Cont. Spray Pump 1-1 0
11-17-82 8-118 Cont. Spray Suct. & Disch.
2 05-24-83 12-100 Fire Water Piping 2
07-29-83 12-101 Turbine Bldg Fire Prot.
2 07-18-83 12-102 Turbine Bldg North Fire Prot.
2 07-21-83 l
101 l
l f
I
l 12-104 Fire Protection System 2
07-22-83 j
12-105 Fire Pumps 1 & 2 - Header
- 5 10-21-83 12-106 Aux. Bldg Fire Protection 4
07-18-83 12-107 Aux. Bldg Fire Protection 3
08-15-83 13-104 Spent Resin Transfer System 0
11-05-82 13-109 Makeup Water Transfer Pumps 1
05-25-83 13-116 Makeup Water System 2
07-01-83 13-117 Makeup Water System
- 2 12-24-83 118 Makeup Water System
- 3 01-31-84 13-119 Cond. Stor. Transfer Pump 2
05-16-83 13-120 Makeup Water Trans Pump Disch 2 05-16-83 13-121 Makeup Water to Spent 1
05-18-83 Fuel Pit
- Subsequent revision by DCP i
b.
Cygna Energy Services Bechtel contracted with Cygna in 1981.
Most of Cygna's work activities were conducted between October 1982 and August 1983.
The analyses performed include:
ANALYSIS REV ISSUE NUMBER SYSTEM SERVICE NO.
DATE 2-109 Steam to Aux. Feed Pump-1 05-11-83 Turbine 102
2-112 Aux. Feed-Steam Supply 3
05-26-83 l
2-113 Aux. Feed Pump Exhaust 11 06-01-83 2-114 Aux. Feedwater Pumps
- 4 12-20-83
.2-116 Steam Gen. 1 Aux.
- 2 10-19-83 Feedwater 2-117 Aux Feed Pump Turbine 3
05-24-83 Supply 2-121 Make-up Water System
- 4 10-21-83 2-122 Raw Water Storage
- 1-12-30-83 Reservoir - Discharge 3-104 Primary Water. Support to PRT 2
- 2 12-07-83 4-115 CCW Branch Supply C 0
10-23-82 4-117 CCW Surge Tank Vent 1
05-17-83 4-118 Aux. Steam Drain Vent 1
06-16-83 4-119 Aux. Steam' Drain vent-CCW Ret 1 06-17-83 4-120 CCW Evaporator-Condenser 1
02-14-83 4-121 Boric Acid-Concentrator 0
11-17-82 Return 4-122 Evap. Cond. CCW Supply & Ret.
0 10-22-82 4-123 Component Cooling Water 1
01-12-83 4-124 Boric Acid Conc. Evap. Cond.
- 1 12-29-83 4-125 Boric Acid-Concen Ret Hdr 2
07-27-83 4-126 Recip Charging PP-CCW Ret 2
07-27-83 4-127 Waste Gas Comp. CCW Hdr.
1 01-13-83 4-128 Waste Gas Comp. CCW Ret Hdr.
2 06-01-83 103
4-129 Waste Gas. Comp. CCW Sup Hdr.
1 05-19-83 4-130 Water Gas Comp CCW Ret Hdr.
1.
05-19-83 6-105 8oron Injection Line 3
08-08-83~
8-104 Containment Spray Pump.
0 10-23-82 Suction-8-120 SIS Test Line RWST 3
06-14-83 8-122 Ventilation-Air Conditioning ~ 1 04-07-83 i
8-123 Ventilation-Air Conditioning 1
07-27-83 8-124 Ventilation-Air Conditioning 0
11-16-82 8-125 Ventilation-Air Conditioning 0
11-17-82.
8-126 Ventilation-Air Conditioning 1
02-08-83 8-127.
CHPS. Exhaust Air Filter 2
07-27-83 8-128 Containment Hydrogen Purge 2
07-27-83 System 8-129 CHPS Exhaust Air Filter 4
08-15-03 8-130 CHPS Exh. Air Fan Disch.
1 07-27 8-131 Ventilation-Air Conditioning
- 4' 10-07-83 8-132 Ventilation-Air Conditioning
- 5 11-22-83 8-133 Ventilation-Air Conditioning 3
07-27-83 8-134 Ventilation-Air Conditioning 1
07-27-83 8-136 Ventilation-Air Conditioning 1
'04-06-83 8-137 Ventilation-Air Conditioning ll 04-06-83
~9-118 Charging Pumps Disch Header
- 2 10-12-83 9-119 CVCS Letdown-Vol Control Tank *2 12-20-83 9-120 Sea 1 water Heater Ret-Part 1 2
06-01-83 9-121 Seal Water Return
- 5 02-08-84 i
104
s 9-122 CVCS-Seal Water Return
- 2 12-08-83 9-123 Chem & Volume Control 2
05-19-83
, 124
. Seal Water Return from Cont.
1 05-19-83 9-125 Condensate Storage Water
- 2 02-09-84 9-126 Vol & Cont Tank-Vent & Relief 1 06-01-83 9-127 CVCS Letdown Line-Vol Cont 2
01-05 Tank i
9-128 RHR 0
02-14-82 I
13-103 Refueling Canal Rearc. Inlet 1
01-10-83 1
13-105 Refueling Canal Return 2
07-27-83 i
13-106 Service Air Penetration 2
07-29-83 Header I
13-107 Spray Additive Tank 1-1 0
'10-29-82'13-111 Refueling Canal Rearc. Inlet 1-04-07-83 13-112 Service Air Penetration
- 3 08-29-83 Header l
13-113 Refueling Canal Return 2
05-25-83 13-114 Primary Water Supply to PRT 2
06-08-83' 1
13-115 Spray Additive Tank 1-1 2
07-06-83 l
13-123 CVCS Letdown Line
- 2 12-02-83 17-100 Aux Saltwater Piping 4
06-29-83 17-101 Aux Saltwater Piping 4
06-29-83 17-102 Aux Saltwater Piping 0
06-23-83 17-103 Aux Saltwater Piping 0
06-23-83 21-100 Engine Crankcase Exhaust 1-1 2
07-19-83 21-101 Engine Crankcase Exhaust 1-2 2
07-18-83 105 l
21-102 Engine Crankcase Exhaust 1-3 2
07-18-83 21-103'
' Diesel Eng. Gen. Systems 0
10-31-82 21-104 Diesel Eng. Generator 1
04-27-83 4
l 21-105 Fuel Oil Transfer 1
04-27-83 l
21-106 Diesel F. O. Pump Discharge 0
11-02-82.
Out 21-107 Diesel F. O. Pump Discharge 0
11-02-82 Out j
21-108 Diesel Engine Gen. Systems 0
11-22-82 21-109 Diesel Engine Generator 0
11-11-82
- Subsequent revision by DCP l
c.
Westinghouse Electric Corporation (W)
PG&E has had a contract with PG&E since 1975.
Most'of the l
W work activities relative to the CAP were conducted between i
i late 1982 and August, 1983.
The analyses performed include:
J
/dALYSIS REV ISSUE NUMBER SYSTEM SERVICE NO.
DATE k
1 ACC1/RHR1 Accumulator & Residual 1
08-24-83
]
Heat Removal ACC2/RHR2 Accumulator & Residual 1
08-01-83 Heat Removal 106
ACC3/RHR3 Accumulator & Residual 1
08-01-83 Heat Removal ACC4/RHR4 Accumulator & Residual 1
08-24-83 Heat Removal FW1-4 Feedwater 1-4 2
08-24-83 SI-1-2 Safety Injection
.1 08-01-83 SI-3 Safety Injection 1
08-24-83 P SURGE Pressurizer Surge 1
08-24-83 RHR-4 Residual Heat Removal 1
08-24-83 Loop 4 MS1/MS2 Main Steam Leads 1 & 2 2
08-09-83 MS3 Main Steam Lead 3 1
08-09-83 MS4 Main Steam Lead 4 1
08-24-83 PSARV Pressurized Safety Relief 0
10-12-83 Valve 2.
Review of Engineering Service Contracts i
The inspector reviewed the following contracts and agreements and determined that the scope of work was properly defined:
a.
Agreement for Technical Services, No. 7PE-TSA-2, Between Bechtel Power Corporation and EDS Nuclear, Inc. (now Imprell),
dated February 5, 1981.
b.
Agreement for Technical Services, No. 7PE-TSA-13, Between
)
Bechtel Power Corporation and Earthquake Engineering Services (now Cygna), dated February 5, 1981.
107 i
__a
}
c.
PG&E Request for Services No. 5-24-82 to Westinghouse Electric Corporation, " Technical Support of Seismic Reverification, Unit 1 - Diablo Canyon Site", dated May 4, 1982, including Change Orders No. 1 to No. 6 from June 18, 1982 to October 20, i
1983.
1 3.
PG&E and Bechtel Acceptance of Contractor QA Manuals The inspector reviewed the following correspondence and related confirmatory review and commentary documentation and had no adverse I
findings.
a.
W 1etter, No. PI&DA-82-639, Manager, PG&E Project to PG&E Chief Mechanical Engineer, "PG&E Co. Nuclear Plant, Diablo Canyon Site Westinghouse WRD QA Program", dated March 11, 1982.
b.
Bechtel letter, Chief Plant Design Engineer to Imprell QA Manager, " Review of EDS QA Manual, REv. 16", dated January 7, 1983.
c.
Bechtel Interoffice Memorandum, No. 303QE101, 0020MCYGNA, Supervisor Quality Engineering to QA Manager, "Cygna QA Manual, Rev. 11," dated April 18, 1983.
l 4.
Design Interface Control
{
108 l
\\
a.
The inspector reviewed DCP Instruction No. I-26, " Instruction-for Control.of Interfaces Between DCP0 and Outside Consultants",
l dated September 14, 1982, prepared and approved by DCPO, Cygna,- and Impress and had no adverse comment.
b.
There was no documented and proceduralized control relat'ive to design interfaces between PG&E and W for performing seismic re-verification work as' defined in the IDVP and Corrective l
l Action Program.
)
1 l
'5.
DCP Control of Procedures to be Used by the Contractors l
l The following Procedures (P's), Instructions (I's), and Design
~
Criteria Memoranda (M's), effective September 1982 to October 1983, i
were determined'to be necessary for the engineering consultants to perform the L/B piping stress analyses and pipe support calculations:
.i P-6 Procedure for Assembling Pipe Support Calculation Packages, j
Rev. 2.
P-9 Qualification and Acceptance Procedure for Class 1 Supports with Natural Frequency 20 cps in the Unrestrained Direction, Rev. 1.
P-11 Piping Stress Analysis, Rev. 1, 3, 4, and 5.
l l
l 109 l
i i
1
if-e
,. p./.
P-27 Procedure for Controlling Seismic Response Spectra, Rev. O, 1, and 2.
.I-6 Pipe Support Stress Allowables, Rev. 1, 2, 3, and 4.
i I-26. Interface Instructions for Outside Consultants, Rev. O, i
I-28 Seismic Response Spectra as Printed in' Stress Analysis for l
use.in Pipe Support Design, Rev. O.
I-29 Temporary Instruction for Review for Welds Associated with Pipe Attachments on PG&E Code Class B, C, E, El, and G.,
Rev. O, and 1.
I-39 Header and Branch Piping Analysis Interfaces, Rev. O.
t M-9 Guidelines for Design of Class 1 Pipe Supports, Rev. 6, 7, and 8.
4 M-42 Units 1 and 2 Pipe Stress Criteria, Rev. 1, 2, and 4.
M-46 Pressure and Temperature to be Used in the Analysis of i
Piping, Rev. O, and 1 to 6.
M-58 Active Valves:
Units 1 and 2, allowable accelerations and frequencies, Rev. O, and 1 to 5.
110
On April 30, and May 1, 1984, the inspector reviewed the DCP transmittal and the contractors' receipt acknowledgment records at Bechtel, S.F., CA.
The record showed that Cygna, Imprell, and W all had receivsd the required P's, I's, and M's in a timely manner, except P-27, Rev. O, 1, and 2 that had never been received by W.
In discussion with tne PG&E, the inspector was informed j
that P-27 was never intended for W's implementation.
W has developed its own inhouse procedures to control the use of seismic response spectra in performing Diablo Canyon L/8 piping analyses.
The inspector stated that he had no further question in.
I this area.
6.
<DCP Audits of Procured Engineering Services a.
DCP's technical review of Bechtel, Cygna, and W was based on PG&E, Engineering Department Procedure No. 3.8, " Design Documents Prepared By A/E's And Consultants", Rev. 2, dated 6/18/82.
The inspector selected the following piping stress analyses for review and considered that the procedure had 1
been implemented adequately, except W works.
Rev. O, Technical 1
Organization Analysis No Audit Date Cygna 2-112 11/14/82 Cygna 8-104 10/19/82 111
Imprel1 1-112 10/13/82 Impre11 1-116 11/10/82 W
SI-1-2 See Note W
MS4 See Note
)
Note:
IOM to File No. 146.10, dated 9/30/83, documenting DCP review of 12 piping analyses performed by W.
Some findings were identified by DCP.
The nature of the findings was not readily available for review.
b.
Design procedures and instructions utilized by Imprell, Cygna, and W had not been reviewed and approved by the PG&E and Bechtel engineering and QA departments.
c.
The PG&E QA program audit of W, No. 20506, " Seismic Re-Verification", conducted on May 25-28, 1982, included a review of piping analysis and pipe support calculation to ensure implementation of procedural requirements.
d.
PG&E did not perform QA program type audits of W in 1983, i
when most of the CAP analytical work was carried out, i
l e.
The inspector review the following Bechtel QA program type audits of Imprell and Cygna, and considered them to be adequate.
l i
l
(
112 l
l 1
,j l
Bechtel.-QA Audit OE-332, audit of Impress's implementation
'of the QA program for.DCNPP, conducted on June 20-21, 1983.
l l
Bechtel.QA Audit OE-331, audit of.Cygna's implementation l
i of the.QA program for DCNPP,' conducted on June 7, 1983.
j
.- 1 7.
Review of Contractor Engineering Company Internal Audits a.
Imprell l
(1) QA program type audits included:
Audit No. A04-1030, "DCPs" conducted on October 5-14, 1982.
i Audit No. A-83WR-13, "DCPs", conducted on May 31 through July 5, 1983.
(2) The technical audits included the following Engineering e
Division " Design Review Reports":
j
" Pipe Support Design Prof ui Instructions and Design l
Drawings and Calculations", dated October 15, 1982.
j 1
" Pipe Support Design and Qualification," dated i
March 8; 1983.
113 l
___-.----__-.________-________________--.-_._j
)
.\\
p
" Piping Analysis", dated April 8, 1983.
?
" Pipe Support Verification Task", dated October. 4,
.1983.
1
" Piping Analysis", dated November 25, 1983.
The inspector concluded that the audits and 6ssociated l'
reviews conducted by Imprell were adequate and acceptable.
b.
Cygna (1) QA program type audits included:
Audit ~No. 83-1,." Report'of Audit of the San Francisco Office", conducted by Cygna, Boston office QA on January 17-21, 1983.
Paragraph V contains areas related to DCNPP.
Inspection / Surveillance Reports No. I to No. 17, conducted between September 21, 1982 and November 23, 1984.
i (2) Internal technical program audits have not been performed by Cygna.
Cygna management stated:
(1) contractually, j
the technical audits are to be performed by Bechtel, 114 l
l
(2) there had been a total of 142 informal " Design Verification Reports" prepa' red for various. types of supports, and (3) piping stress computer runs were
. checked against the printout configuration plots.
The-
. isometric drawings that were plotted were discarded after use.
The inspector concluded that the Cygna QA program type audits were acceptable, but the adequacy of technical review for design analysis calculation was questionable.
c.
Westinghouse (1) QA program type audits included:
Audit Report IA-83-03, " Design Control -
Structural and Equipment Engineering", dated August 5, 1983.
The audit areas involving DCNPP were contained in Paragraph 4.0 which indicated.a review of as-built piping analysis t
packages of Safety Injection System (SIS) and Pressurizer Surge System (PSS) had been per-formed.
The report found that there was a lack of a formal interface syt, tem.
The audit concluded that the matter was insignificant because the NSSS contract had been completed.
i 115 i
t i
i e
i (2) Technical audit; had not been performed.
The inspector concluded that the W internal audits were inadequate and unacceptable in both the QA and technical areas.
The QA program type audit was j
deficient in that:
(a) +1ere was no discussion
{
on what specific areas of the SIS and PSS had been reviewed, and (b) the original audit checklist findings / records had been systematically, destroyed in accordance with W management policies.
H.
Concern Items on IDVP Evaluation of L/B and S/B Piping and Pipe Support Design The.following concern items were forwarded to NRR for evaluation on April 25, 1984:
Concern Items - ITR's 30 and 61, "S/B Piping" Concern Items - ITR 59, "L/B Piping" Concern Items - ITR 60, "L/B & S/B Pipe Supports" Table 1 NRC Review of DCP S/B Piping Analysis and Support I
Calculations - ITR 30 and 61 Table 2 S/B Piping Stress Analysis - ITR 61 Table 3 Review of Computer Analyzed Fiping - ITR 61 Table 4 Completion Review of Computer Analyzed Piping - ITR 61 116
Table 5 R'eview of Span Rule (M-40) Applications - ITR 61' Table 6 Completion Review of Span Rule (M-40) Applications - ITR 61 i
Table 7 L/B Piping Stress Analysis.- ITR 59 Table 8 L/B Piping Local Stress Analysis - ITR 59 Table-9 Overall Reviews of DCP Piping Analysis - ITR 59 Table 10 Specific Reviews of DCP Piping Analysis - ITR 59 Table 11 L/B Support Calculation - ITR 60 i
Table 12 ReviewofL/BPipeSupportAnalysesPer[ohmedbyDCP0-ITR 60 Table 13 Review of L/B Pipe Support Analyses Performed by Cygna and Imprell - 60 Table 14 L/B Support Calculations Completion-Review - ITR 60 Table IS S/B Support Calculation - ITR 60 i
i 117
Concern Items - ITR 30 and 61, "S/B Piping" 1.
In reference to Table 1, the' justification for accepting'15,000' of S/B pipe and the associated 1,500 safety-related supports, without further evaluation, is based on a review of a sample of piping analysis for 5,000of pipe using the ME-101 computer program.
Analysis Methods Included in the 5,000' of Pipe 1,000' Hot Pipe 4,000' Cold Pipe Thermal - MEL 40 600' - PIPSD Seismic - PIPSD 3,400' - File 44 19 ME-101 Analyses were Performed on the 5000' of Pipe 10 ME-101 Included:
9 ME-101 Included:
4 active valves How many feet of 4 Code Breaks Pure File 44?
5 SAM / TAMS 118
2.
In reference to Table 1, are all 15,000' S/B piping that were without additional review, 2" and below?
3.
In conjunction with Item 2 above, are they all located below F1' El. 140' in containment and auxiliary buildings?
(p. 15) 4.
The old span rules contained in PG&E Drawing 049243 for field run of " to 2" S/B and Drawing 049239 for field run of 2 " to 4" S/B do not address'all piping configurations (p. 6).
The application of these drawings was largely based on undocumented engineering judgments (p. 6).
In view of the situation, the staff would like to know the basis of IDVP acceptance-of the 15,000' S/B that were designed by non-uniformly applied S/B span rule criteria, and were l
without design documentation.
J 5.
With the large amount of identified deficiencies (Tables 2 to 6), why I
were S/B computer and span rule (M-40) piping analyses considered to be I
acceptable without expanding sample size of the IDVP review?
i i
J w
119
i TABLE 1 - ITRs 30 and 61 NRC Review of DCP S/B Piping Analysis and Support Calculations I
l Piping Analysis Support Calculation Hardware Change i
1.
Total footage of pipel 1.
Total estimated number i
based on summation ofl of supports
[
~
average measurement l
l on piping isometrics l l
l l
43,000 l
3,715 l
l l
2.
Total ME-101 computer l 2 & 3.
Total pipe supports l 2 & 3.
Total support analysis l
evaluated I
modifications l
l including addi-25,000' l
a.
Detailed l
tions, deletions, I
analysis 1,800 l and component l
l upgrading 1380, l
l or 1380/2215 =
l l
62.3%
l l
3.
Total M-40 hand l
b.
Prequalified I
calculations I
standard l
l supports 415 l l
l 3,000 1
2,215 i i
l 4.
Total number of cook-l 4.
Total pipe supports l 4.
None book type analysis l
that have not been i
that were without l
reanalyzed l
design documentation l l
and were not verified l 1,500 l
by PG&E I
or 40.4% of total S/B l
l supports l
15,000' 1
l j
or 34.9% of total l
l S/B piping l
l l
l l
120 l
l
t 2
l TABLE'2 S/B Piping Stress Analysis - ITR 61 Review 1
l l
l No of Analyses l No. of Completion l l Analysis l Total No.
I Reviewed l
Review l
l Method l of Analyses l w/ deficiencies) l w/ deficiencies) l l
l 1
l l
j l Computer l 129 l
8 (8) l' 3 (2) l l
l l
1 1
l Span Rulel 110 1
4 (4) l 4 (4) l l
(M-40) l l
l l
450 feet of S/B piping were evaluated in'ITR 61.
Note:
Approximately 30 additional small bore analyses were included in large. bore packages.
121
TABLE 3 Review of Computer Analyzed Piping - ITR 61 l
l l Incorrect Thermall l
l l
i l
l
.l Modes; Valve 1
IIncorrectl Piping l
l Analysis l l Weight; Support lIncorrectl Piping l Interference l
l No.
IPipe Size (in.)lModeling; SAM /TAMI SIF (Geometry lNot Consideredi 1
I i
l l
1 l
l l
7-301 1 3/4, 1, 2 l
X l
X l
X l
l
]
8-305 l 2
l l
l l
X l
l 8-306 1 3/4, 2 l
X l
l X
l l
l 8-310 l 3/4, 2 l
X l
l X
l X
l l
8-311 l 3/4, 2 l
X l
l X
l l
l 9-304 l 3/4 l
X l
l l
l l
9-307 l 3/4, 1, 2 l
X l
l l
l l 10-301 l 1/2, 3/4, 2 l
X l
X l
l l
l l
l 122
TABLE 4 Completion Review of Computer Analyzed Piping - ITR 61
] Analysis No. I Pipe Size ~(in.) l Review Results 1
l.
l l
1 I
S-118 l
3/4,-1 l No deficiencies identified.
l l
l 1
'l l
.7-300 l
1 1 Incorrect SIF.
l l
l l
1 l
9-308 l
3/4 l Incorrect comparison of valve l
l l.
I accelerations to allowables.
l l
l 1,
I 123
TABLE 5 Review of Span Rule (M-40) Applications - ITR 61 Y
l I
I 1
l' Analysis No.
l 3-303H-6-301H 9-327H 19-307H I
l l
l l
l l
l 1
1 Pipe Size (in.)
l 3/4 2
1 2
l l
l l
i l
l l
l Incorrect Pipe and Component l
l l
Flexibility Evaluation', Valve X
X X
l I
Weight; Span Weight; Design l
l l
Temperature I
I I
I I
i l
l
. Auxiliary Building. Flexible l
l l
Slabs Not Considered I
X l
l'
_l l
I I
l l
Seismic Stress Acceptability I
l' l.
Not Documented I
X l
l
___ I l
l l
l l
l l
Shown on Review Sheet I
X X
l l
I I
I I
I l Anchor Movement Not Considered l
(X) l I
I l
l I
I l-Underestimate Support Loadings I
X l
l l
1 1
I l
I Active Valve Qualification Not-I l
l Documented I
X j
i l
l (X) An E01 was issued.
l l
124 l
l 1
1 t
- l i
i TABLE 6-Completion Review of Span Rule (M-40) Applications - ITR'61-r.
.l Analysis No.
I Pipe Size'(in.)
l Review Results I
l-1 I
I i
l 3-313H l
1 l Incorrect spectral acceleration factors!'
.d l
l l for support loads.
l l
l-1 I
l 8-324H l
1/2, 1 l Incorrect support design loads.
I l-1 I
I l
25-300H l
1 1/2, 2 I Did not'use envelope of spectral 4
l
'l' l
l acceleration factors of the elevations l
.l' l
l in the building for determining supportl l
l l loads.
l I
I I
I i
l 26-302H l
1
-l Same as 25-300H.
l l
l l
l l
i i
125
Concern Items - ITR 59, Rev. 1, "L/B Piping" I
1.
Did IDVP evaluate any L/B Quick Fix dispositions that were performed in DCP, SF office before and af ter June 30, 1983?
(p. 3-1) 2.
One of the factors in selecting sample weld attachment for evaluation is the group that performs the analysis.
Why was Impell work not evaluated?
(p. 3-2) i i
3.
Was IEB 79-14 requirements adequately implemented?
(p. 3-3) 4.
Since Cloud reviewed mostly preliminary analyses, were there any measures taken to check whether or not the " final" package has changed the Cloud I
review findings and resolutions?
(p. 3-4) 5.
Cloud field verification identified several piping interferences.
What i
were the DCP's generic corrective measures?
(p. 9-1) 6.
Need to know the basis for determining the L/B piping analysis review sample sizes that are disproportional to the work performed.by the responsible organizations.
(Table 7) 7.
With the large amount of identified deficiencies (Tables 7 to 10), why were the L/B piping analyses reviewed considered to be acceptable without expanding review sample size?
126
=
8.
Evaluation of W l./B piping analysis appears to be warranted.
(Tables 1 to 2; Attachments 1 to 3) l I
1 127
TABLE 7 L/B Piping Stress Analysis - ITR 59 Review l
'l l No. of Completion-l l
l-Review Among l
l No. of Pipina i
the Selected Design-l Total.No.
l-Analyses' Reviewed l,. Piping Analyses Organization l
of Analyses l'
w/ deficiencies) l w/ deficiencies l
I l
DCP0 l
78 1
0 11 '(11) l I
I S
6 (6) l l
l 17 (17).
.I 5.(2) l l
l I
Cygna l
33 l
0 1
(1)
[
I l
S 1
(1)'
l l
l 2
(2)
'l 1 (1) l l
I Impell
-l 136 l
0
.1.
(1) l l
l S
1 (1) l l
l
-2 (2) l 1 (0) l l
l W
l 14 l
0 1
0 l
l l
l l
I I
l l
l l
1 L
l l
1 1
NRC Requested l
8-102 l
l I
l l
l DCP0 Analyses i
0 - Overall Review l
S - Specific Review 1..
1 i
128 i.
4 TABLE 8 l
L/B Piping Local Stress Analysis - ITR 59 Review l
'l No. of Analysis. Reviewed-Design Organization l
Total No. of Analyses I
(w/ deficiencies)'
I I
'DCP0 l
669 l
15 (4)-
l 1
l Cygna l
162 l
8 (4) i i
I I
i Impe11 1
89 l
0 l
l W
l Unknown l
0 i
i 129 l
3
A C
4 D
1 0
1 P
C X
X X
6 D
l 0
l 2
e
)
1 p
X m
(
2 I
5 0
1 P
C 2
D X
X 3
a 1
n 1
g X
y X
4 C
X X
6 s
0 i
1 P
X X
s C
y 8
D l
a n
0 A
0 1
g P
n A
C X
X X
X 9
i 4
D 5
p i
R P
2 T
0 I
P 1
P C
C X
D 4
D 9
f o
0 E
1 L
s 1
P B
w C
X X
A e
9 D
T ive 1
R 1
1 P
l C
X X
X 2
D lare 9
v 1
O 1
P C
X 1
D 80
)
1 P
X X
C
(
9 D
0 0
1 P
C X
X X
4 D
l I l li l l ! l l
l l l l l l l l l
l l
I l l l l l l
l d
d e
d e
u o
n r
g s
N at a;n t
e n
s h
nrs o gr
- d i
i s
eg geei no ri l
pst i
vi i
i p es e
s s
l e
smaa pp F
f n dt a
y y
aW eeC n i un I
ro or w
B V
DT i
PS o S
eC Mo la t
dd i
t p
I n
d t n t ; ar t ;t t
nt t p D
A e
ce ceoo cya c
I o cu E
m en erL o erc e
n eS g
r ro ru C
rt o r
g r
n n
o rp rs ;
reL r
ns rf A
i f
om osed om o
i e oo p
r co cera co c
pc c
e nC nruo ne n
i n n
)
i P
P I
I PtL I G I
P e I
X il 1 I Il l l l I l
l l
1 l l
l l
l l l 1 I I l l 1 1 l l
(
1 TABLE 10 - ITR 59.
i Specific Reviews of DCP Piping Analysis l Piping AnalysisLNo.1 4-101 2-114 7-103 8-116.8-117 4A-111 8-102' 12-1011 l
I
'l-l Performed By l
DCP Cygna DCP DCP DCP DCP DCP Impe111 1
I-
__l l Incorrect Valve l
='
l l
Weight-
.l.
(X)
X (X)
X l
l'
__,_ l -
l l Incorrect Design 1 l
=-3 l Pressure; Responsel X
X X
l l
Spectrum l
l~
l I
1.
l-Incorrect Support l l
'l Location l
X
-l 1
I I
l.
1 Incorrect SIF l
X X
X X
-X X
X X
l I
I I
I (X) 'An'E0I was issued.
t 131
Concern Items - ITR 60'~"L/B &'S/B Pipe Supports" A.
L/B Supports 1.
Need to know the basis for determining the L/B support calculation review sample sizes that are disproportional to the work performed by the responsible organization.
(Table 11) 2.
With the large amount of identified deficiencies', why was the L/B
.j l
support work done considered to be acceptable without expanding.
review sample size? (Tables 11 to'14) l
)
3.
Evaluation of W L/B piping ' support calculation appears to be l
warranted.
(Attachments I to 3)
I b.
S/B Supports
.j 1.
In reference to Table 15 with less than 1% S/B support calculations evaluated, could it possibly represent all plant areas, original hardware conditions, support types, etc.? Concern was addressed with 100% re-evaluation of computer calculated S/B supports.
.l 2.
62.3% S/B support hardware modification was made as a result of re-evaluation of 2,215 supports.
Shouldn't the remaining 1,500 supports be looked at?
(Table 1) 132
l-J TABLE 11 1
1 L/B Support Calculation - ITR 60 Review.
- l l'
.l.
'l No."of Completion-1:
I
'l Review Among l
l No.-of Calculations the Selected Design
.I T0tal No.
l
. Reviewed l'
Pipe Supports l
Organization I
of Calculations I
(w/ deficiencies) l (w/ deficiencies) l l
l t
i DCPO-l 2089 l
17, (13) l 1 '(1) l I
l' Cygna l
516 l
3 (3) l 2 (2)
-l I
l l
Impell l
894 1
2 (1)
I 1 (0).
I l
I W.
l 505 1
0 1
0 i
133
..__.___.__._____m____
TABLE 12 - ITR 60 Review of L/8 Pipe Support Analyses Performed by DCP0 l
l Incorrect orl Incorrect ori l
l l
l l Lacking of ILacking of l
Lack of l
l l
l l Steel or
'l Structural IReflection l Lack of l
l i
l l Support fn land Piping lof As-Built lCalculationjNo Deficiencies f
ISupport No.(Calculation l Calculation (Conditions I on Welds l
Identified l
l l
l 1
I i
l i
l 10/70 SL i
(X) l X
l.
X l
l l
l 10/104 SL l l
l l
l X
l l 13/23 SL i X
l l
X l
X l
l l 41/15A l
X l
X 1
l X
l l
l 51/4V l
l l
l l
X l
l
[ 51/10R l
l l
l X
l j
l l
l 51/13R l
l l
l l
X
/
l 1 55A/41A l
l X
l l
X l
l l
l 56N/35A l
X l
X l
l X
l l
l 565/6A 1
X l
l l
l l
I 57N/90V l
l X
l I
X l
l
'l 585/16V l
l l
X l
X l
l l 58S/39V l
l l
l X
l
.l I 58S/44V-l l
X l
l l
l l 63/26V l
l X
l l
(X) l l.
l 85N/34R I.
l l
l l
X l
l 98/134R l
.X l
X l
l X
l l
i l
l I
I I
l l-(X) An E01 was issued.
)
i 134 l
I TABLE 13 - ITR 60 Review cf L/B Pipe Support Analyses Performed by Cygna and Impell
)
l
-Support No.
l 56S/3A 85N/31R 92/11R 58S/37A.
585/69R l
1 l-I j
l Performed By J,Cygna Cygna Cygna Impell Impell
. l l
1
- l l
Incorrect or Lacking 1 l-l of Steel or Support-X X
X l
l fn Calculation ~
l
-l I
i I
l Incorrect or Lacking l l
l of Structural and I
X X
X-l-
l Piping Calculation l
l s
l l
l' l Lack of Reflection of l
l l
As-Built Conditions l
.X X
X-l l-1 I
i l Incorrect or Lacking l
1
- i l
of Calculation on 1
(X)
X X
l l
l Welds l
l l-1 I
l
- l. Incorrect Base Plate l
l l
Analysis-l X
l l
I l
l No Deficiencies l
l l
Identified I
X l
l l
l.
l (X) An E01 was issued.
.)
l l
135 l
TABLE 14 - ITR 60 L/B Support Calculations Completion' Review.
I Support No. I Performed'By-l Review Results I
i
'l l
l I
l 41-39A-l DCP0 l
Load sheets not included.
1 I
I I
I 1
1 I
I l
l Cygna l
Incomplete references for. loads.
l l
l l
l 1
.I I
I I
l 57N-34R j
Cygna ~
l Stresses compared to incorrect allowables.
I l'
l-l l
1 l
l l.
l 384-181R I
Impell l
No deficiencies identified.
l l
l l
l 1
136 l-.
o
\\
TABLE 15-
-l l
S/8 Support Calculation - ITR 60 Review.
.l l~'No. of: Calculations l No. of' Completion.
j Design 1
Total No.
l
-Reviewed l
. Review b,
Organization i of Calculations
!- (w/ deficiencies) l (w/ deficiencies)'
'l l.
l*
1 DCP0 - OPEG l.
1,800*-
~l 8 (6).
I 11[(3)'
{
I
- Estimated Numbers:
w/Datailed Calculat; ions 1,800 Standard Supports 415 s
l.
.Old Supports w/o Analyses.
'1,500 l
V l
3,715 Total l
f 1
1
.l 1
L i
l l
I 137 L
___---_-----_-_----------__O
ATTACHMENT 1
}
Portions of RIII Inspection Report 50-266/81-09; 50-301/81-10 The inspection was conducted on May 7-8, 1981.
"1.
Westinghouse Work Most parts of the Westinghouse B ) stress calculations, such as computer configuration models and output details were considered to be proprietary information.
To verify the adequacy of W evaluations Bectitel re-ran two
}
of the stress calculations on their ME-101 computer program.
W Calculation, No. P-136, "SI From Penetration P-22 to RPV (SI-601R-2, SI-2501R, RC-2501R-5) dated January 3, 1980 was compared in the areas of system modes / frequencies, f
stresses, forces, moments, and defections, on January 14, 1981 and was determined to be acceptable by the Bechtel engineers.
The second W Calcula-
- tion, No. P-120, "SI from P27 to RCS", dated November 21, 1979 was deter-mined to be unacceptable, and the W calculation was subsequently superseded.
j The inspector reviewed the W letter, WEP-81-10, to Bechtel Power Corporation, j
dated March 17, 1981, which stated that W performed a thorough comparison j
between its internal analysis packages and the data previously provided by Bechtel, and had found no differences, except P-120.
The second W submittal of P-120 calculation was evaluated by Bechtel engineers on January 13, 1980, and was considered to be acceptable.
138
In review of the W and Bechtel calculation packages, including the com-parison data and in discussions held with the licensee and Bechtel representatives, the inspector considers thn licensee measures taken to d
resolve the subject concern to be adequate.
Such consideration was based on:
a.
Since the original 38 W calculations were made, there were some system
-modifications that invalidated the W analysis.
The affected systems were re-calculated by Bechtel.
As of the date of the inspection, there were 23 W packages in final status.
b.
A licensee au'dit of W was performed at the W Design Engineering office i
on September 16, 1980.
No problem areas were observed by the licensee.
The licensee audit included three stress calculations pertaining to piping isometric drawings P-143 and P-128.
i c.
The load combination methods utilized by W, i.e., the absolute value summation, was considered more conservative than Bechtel's method of q
using the square root of the sum of the squares.
l l
d.
For some of the stress values where Bechtel exceeded the W computation, the explanation was that frequencies calculated for W and Bechtel were i
slightly different in the first five vibration modes.
The differences in stress and deflection magnitudes evaluated were not considered to 4
be significant.
The inspector concurred with Bechtel's determination.
No items of noncompliance or deviations were identified as a result of the record review."
139
")
i ATTACHMENT 2 1
i Portions of RIII Inspection Report 50-454/83-06; 50-455/83-05 i
i
'The inspection was conducted in December, 1982 and January, 1983.
l i
"2.
W Design of Friction A'nchors The inspector reviewed the W Disposition of Hunter Field' Problem No.
1 FC 05119A, Revision A, dated November 29, 1982 and W calculation " Unit 1 Auxiliary Building Drawing No. 1FC05119A, Line No. 1FC22A-2" Area 6, Interface-with' Hanger IFC501011," dated December 17, 1982.
In checking i
the design methods for the friction anchor, the inspector observed that the procedure was documented in a Structural Design Engineering Department Memorandum to G. J. O' Hare and J. Shulmann, "ELCEN Friction Anchor Capa-cities", dated December 13, 1982.
This memorandum was not included in the I
BPSS Group" SAMUI Approved Structural Reference List", Revision 0, dated l
November 5, 1982.
The use of interdepartment memorandum to document design procedures bypasses the site document control system.
This is a violation (454/83-06-02; 455/83-05-02).
l 140
j a-
- > y x l
"T l
ATTACHMENT 3 1
w i
Portions of RIII Inspection Report 50-454/83 70; 50-455/83-17 l
9 l
l The inspection wac conducte'd in May, 1983.
1 "2,
c.
' Inspection of Westinghouse (W) Snubbed Design g
i s
T
]
Dudr,g inspection of steam generatof s,nubbers in Byron Unit 1, the i@,pector also checked piping snobber installations on the four main
'feedwaterlinesthatconnecttkthefoursteamgenerators.
No abnormalities were identified hxcept with snubber M-1FWO90015, a P5A35snubberwithafaultedconditionloadingof 35,240 1:f.
The snubber was installed on the other end of the 6" pipe 1FW87CD-6" elbow B,
that was welded directly to the SG nozzle.
The inspector discussed the
...v following concerns with the W site management, including:
,\\
, c (1) if there frja elfference between the steam generator snubber or pipe snubber lock-up rates, the SG nozzle could experience excessive " lock-in" stresses.
(2) ifthepipingsjgessanalysismodeldethenozzleasapipeanchor, 3
as is normal' industrial practice, the small amount of dynamic /
seismic movements may not be sufficient to cause the snubber to N\\
~
I i
T 141
_w
lock-up and perform its intended function.
The W engineers reviewed the piping stress analysis and concluded that the steam generator snubber will lock up ahead of the PSA snubber; however, piping seismic motions (anchor movement of 0.079", SSE of 0.026" and OBE of 0.008") were insufficient to ensure snubber function-ability, and as a result the snubber was deleted in ECN No. 48436, dated May 9, 1983.
The W engineers further stated, that with the removal of the snubber, the pipe stresses were still within code allowable at both the OBE and SSE conditions.
In review of a W internal letter from the Manager, Commonwealth Edison Projects to Projects Engineering Manager, Byron and Braidwood Projects, " Byron Station Unit 1, Review for Snubber Close to Equipment," dated May 10, 1983, the inspector concurred
)
with the W proposed sample review plan to be completed by June 10, 1983 for reviewing similar problems.
Followup inspec-tions are planned.
This is an unresolved item (454/83-20-08; 455/83-17-08)."
142 b
SUMMARY
OF FINDINGS RESULTING FROM FOLLOWUP OF ALLEGATIONS AND NRC INDEPENDENT OVERVIEW Item Description Paragraph (Affecting L/B, S/B, or Both)
(Functional or Program Areas q
Inspected)
Li A.
Against Criterion II There were inadequate provisions in the-program for personnel ' indoctrination and training.
The 5/B pipe support engineers were not familiar with important elements in both the QA and technical programs.
1.
In the area of general technical and I.B.3.b QA training, the program permits personnel performing safety-related design work w/o training up to 30 days.
(L/B and S/B) 2.
No measures or program provisions I.B.3.c established to ensure adequate special training for the working 1
staff on matters such as procedure revisions and problem trendings.
(L/B and S/B) 143
=-
1.____
B.
.Against Criterion XVI QA program deficiencies and design j
nonconformances had not been identified and corrected promptly.
i 1.
Site design organization management I.C was insensitive to staff concerns, and did not initiate timely l
corrective actions.
(S/B) 2.
Lack of project timely response to II.F.3.d.
The delays were (1)(a) w/o justification.
(S/B) 3.
Lack of PG&E management attention II.F.3.d.
to ensure timely responses to the (1)(b) audit findings.
(S/B) 4.
Bechtel audit finding corrective II.F.3.d. 93 action scheduled completion dates (1)(c) were delayed without documented justification.
(S/B) 5.
Lack of PG&E audit finding corrective II.F.3.d.
actions to identify the cause of the (1)(d) problem and the measures needed to prevent recurrence.
(S/B) 144 A
.q 6..
Project corrective. action only II.F.3.d.
addressed speci.fic problem' areas (1)(e) identified in the PG&E audit findings and did not consider generic implication of the problems.
QA concurred with this apparently inadequate corrective action.
(S/B)
- 7.
InadequateBechtelQdverification II.F.3.d.
of OPEG corrective actions prior to (1)(f) close-out of audit findings.
OPEG Personnel training continued to be inadequate, (S/B) 8.
Lack of PG&E QA program measures II.F.3.d.
to evaluate the effects of program (1)(g) efficiencies resulting in long delay of QA finding corrections prior to II.F.3.d.
IDVP and CAP actions.
(L/B and S/B)
(1)(h) i C.
Against Criterion VI 1
1 Document control deficiencies were observed
]
at the site design organizations.
J 1.
Engineers were using out-of-date proce-I.A.3.b.
dures for perfor.ning calculations.
(S/B) 145
/s
1 0
2.
Inter-office memorandums were issued I.A.3.c.
in lieu of procedures that bypassed review and approval process.
(S/B) 3 1
3.
Site Quality Engineer and Support I.A.3.d.(2)
Group Leader maintained outdated listings of the latest work procedure.
(S/B) l 4.
Design personnel was performing I.A.3.d.(1)
I calculations without having adequately controlled procedures for extended periods of time.
(S/B)
D.
Against Criterion V There had been inadequate or lack of proce-dures for the design organizations.
1.
Lack of provision to handle and resolve II.E.
field initiated design questions and requests by the PG&E home office.
(L/B and S/B)
This is a part of License Condition 2.c.(11) No. 6, 146 A
t 2.
Lack of prescription of the limited II.B.2.b conditions where piping thermal stresses could be released by installation of i
gaps within rigid restraints.
(L/B and S/B)
This is License Condition 2.c.(11) No. 4.
s l
3.
Inadequate stress walkdown inspection I.E.
program to ensure freedom of inter-ferences.
Procedures did not fully incorporate IEB 79-14 requirements, and the acceptance criteria were relying on design piping movement predictions that were not always observed to be accurate.
(L/B and L m)
This is a part of License Condition 2.c.(11)
No. 5.
4.
Lack of " Tolerance Clarification" proce-I.G.
dural prescription on what could be I
"quickly fixed" at site without major
)
revision of the existing calculations.
(L/B and S/B)
This is.a part of License Condition 2.c.(11) No. 6.
147 I
5.
Lack of sufficient references and I.A.3.c.
engineering data for the site engineers to perform calculations-that had resulted in' personnel reliance on uncontrolled l
'outside materials.
(S/B)
E.
Against criterion V Deficiencies observed that could have been the results of personnel not following the procedures.
1.
Lack of S/B support calculation checks II.B.1.d.
resulted in errors unrevealed.
(S/B)
(1), (2)
I.G.3.c.(4)
This is a part of License Condition 2.c.(11) No. 1.
2.
" Preliminary" data identification and II.B.1.(e) i subsequent review of the calculation (1) against final data were not done.
(5/B)
This is a part of License Condition 2.c.(11) No. 1.
3.
Personnel Training was not requested by I. B. 3. r the supervisors in a timely manner.
(S/8) 148
s 4.
Stress walkdown' inspections failed to-I.E.
identify all unintentional piping restraints.
(L/B and S/B) s is a part of License Condition z.c.(11) No. 5.
F.
Against Criterion III There had been design control deficiencies identified during the program review and hardware inspections.
1.
Design criteria conflict in control II.A.
of pipe support structural frequencies.
(L/B and S/B)
This is a part of License Condition 2.c.(11) No. 1.
2.
Inadequate design evaluation of as-I.G.3.c.(4) 1 built deviations from design.
(S/B)
This is a part of License Condition 2.c.(11) No. 1.
i 149 a
i l
3.
Lack of program provisions to control II.B.1.Ce) preliminary design data provided (1) through telephone, and to verify the calculation against subsequent final data when made available.
(S/B) l l
l 4.
There was no design consideration for II.B.1.(e) l l
synchronizing loading between closely (2) l 1
spaced rigid / rigid restraints, and II.C.3.
rigid restraint / anchors.
(L/B and S/B)
This is License Condition No. 2.c.(11)
No 2.
5.
Snubbers were inoperable due to placing II.C.
them in close proximity with rigid II.D.
restraints and anchors.
(L/b and S/B)
This is License Condition 2.C.(11) No. 3.
6.
Lack of ALARA considerations associated II.C.
with the use of snubbers.
(L/B and S/B)
II.D.
7.
Lack of documented design interface I.D.3.b.
procedure for OPEG Piping Stress Group (5) and Pipe Support Group.
(S/B) 150
8'.
Support field design change breakdown -
I.G.
Quick acceptance and fixes of design deviations bypassed measures including prior calculatio'ns made, review, and approval.
There had been thousands of supports being " fixed" this way.
(L/B and'-S/B)
This is a'part of License Condition 2.C.(11) No. 6.
G.
Against-Criterion XVIII Inadequate licensee. technical QA audits and surveillance to identify and correct the design control and program deficiencies revealed during this inspection / investigation.
4 1.
When a QA audit item could not be II.F.3.d.
evaluated due'to a lack of project (2)(a) activities, followup of the item was not planned.
(S/B) 2.
Lack'of QA audit documentation.of II.F.3.d.
specific materials reviewed that (2)(b) leads to closing out of the audit i
findings.
(S/B) 151
l t
3.
Lack of QA documentation of materials II.F.3.d.
reviewed during the conduct of the (2)(c) audit.
(S/B) 4.
-Lack of technical QA audits to II.F.3.d.
)
independently verify that OPEG (2)(d) calculation inputs were checked to be in compliance with engineering procedures.
(S/B) 5.
Auditor did not take the initiatives II.F.3.d.
to investigate why there had not (2)(e) been any Discrepancy Reports issued I
by the site design group.
(S/B) 6.
Relative to a document control audit, II.F.3.d.
the auditor discovered that, since (2)(f)
March, 1983, the control of OPEG procedures was conducted at the PG&E and Bechtel, San Francisco offices.
There was no attempt made to revise the audit checklist to cover these activities.
(S/B) l 152
7.
Relative to the same document control II.F.3.d.
audit, the checklist was modified to (2)(f) cover the subject OPEG activities, 10 mo, later, the benefit of timely audit i
to ensure program compliance had been compromised.
(S/B) 1 H.
AgainstCriterion_VE Inadequate PE&E and Bechtel control of procured engineering services.
i 1.
Lack of procedure to ensure effective II.G.4.b.
design interface between PG&E and W.
(L/B) 2.
Design procedures and instructions II.G.6.b.
utilized by Imprell, Cygna, and W had not been reviewed and approved by the 4
PG&E and Bechtel engineering and QA departments.
(L/B) i 3.
PG&E did not perform QA program type II.G.6.d.
j audits of W in 1983, when most of the CAP analytical work was carried out.
(L/B) 153 l
4.
Relative to contractor internal audits, II.G.7.b.
Cygna technical review for design analysis and calculation was question-able.
(L/B) 5.
Relative to contactor internal audits, II.G.7.c.
I l
the W QA program type audit was con-sidered to be inadequate and deficient.
(L/B)
I 6.
Relative to contractor internal audits, II.G.7.c.
there had not been any technical audits conducted by W.
(L/B) 154
l 1
FOLLOWUP OF FINDINGS AND CONCERNS A.
Site Document Control On May 24, 1984, the inspector reviewed the upgraded licensee site piping design document control system.
The latest PG&E Mechanical and Nuclear j
i Engineering (M&NE) Procedure P-1, " Procedure, Instruction and Design Criteria
)
Control," Rev. 8, dated April 4,1984 was an improvement, but it still contains implementational deficiencies.
The observation was forwarded to NRR and RV for evaluation on May 31, 1984.
1.
The distribution of complete sets of M&NE procedures and instructions and Engineering Manual Procedures (EMPs) appears to be disproportionate.
For example, for the 40 plus Pipe Support Engineers, there was only one set of M&NE and EMP procedure in their work trailer.
However, for the 30 plus Pipe Stress Engineers, there were three sets of M&NE and four sets of EMP procedures.
2.
The status of M&NE and EMP procedure distribution was identified in OPEG's " Controlled Manuals Controlled Distribution List." These listings were used by project as well as QA to ensure adequate control over the use of the procedures including the use of latest revisions and reception of needed procedures by the design engineers.
As important as it was, the lists were not a controlled document, i.e., without any issuance / review / approval and controlling dates.
At the beginning of L
l 155
l i
FOLLOWUP 0F FINDINGS AND CONCERNS A.
Site Document Control On May 24, 1984, the inspector. reviewed the upgraded licensee site piping design document control system.
The latest PG&E Mechanical and Nuclear Engineering (M&NE) Procedure P-1, " Procedure, Instruction and Design Criteria Control," Rev. 8, dated April 4, 1984 was an improvement, but it still contains implementational deficiencies.
The observation was forwarded to NRR and RV for evaluation on May 31, 1984.
1.
The distribution of complete sets of M&NE procedures and instructions and Engineering Manual Procedures (EMPs) appears to be disproportionate.
For example, for the 40 plus Pipe Support Engineers, there was only one set of M&NE and EMP procedure in their work trailer.
However, for the 30 plus Pipe Stress Engineers, there were three sets of M&NE and four sets of EMP procedures.
2.
The status of M&NE and EMP procedure distribution was identified in OPEG's " Controlled Manuals Controlled Distribution List." These
\\
listings were used by project as well as QA to ensure adequate control over the use of the procedures including the use of latest revisions and reception of needed procedures by the design engineers.
As important as it was, the lists were not a controlled document, i.e., without any issuance / review / approval and controlling dates.
At the beginning of u
155
l I
l the inspection, the inspector was presented with an outdated list.
When the inspector started questioning the reason why both the Stress and Pipe Support Group Leaders did not possess a set of M&NE procedure, the responsible personnel then realized that the list was not up to date.
3.
Where it stated in Paragraph 3.5, that "The Piping Group Supervisor is responsible for notifying Project Administration in writing when applii cable engineers are either added to or deleted from the documentation distribution list.
The notification should include the engineer's group and location." Contrary to the requirement, the written requests were made by the Quality Engineer without documented acknowledgment from the Piping Group Supervisor.
Furthermore, there had not been any request for return receipt so that the implementation of site requests by the SFHO could be easily retrieved and verified.
4.
The present organization chart, dated May 2, 1984, showed site QA under the OPEG administration.
The controlled procedures used by site QA for work surveillance and audit were also distributed by OPEG.
The site management recognized this error in their organization chart, and future procedures for site QA use will be distributed directly from the Bechtel QA home office.
s l
B.
Proximity Rigid Restraints and Snubbers l
In accordance with License Condition 2.c.(11), Items 2 and 3, the licensee was requested to evaluate rigid restraints and snubbers that were placed I
156
l in proximity with the equipment nozzles, anchors, and other restraints to ensure their load carrying capability and operability will not be adversely affected by the design arrangements.
During a review meeting held on June 5, 1984 in the NRR office, the inpector objected to the. licensee i
review screening criteria of use 3D for 8" and larger diameter pipes, 50 for 6" and below diameter pipes, and excluding 2" and below for evaluation.
On June 6, 1984, the inspector forwarded to the responsible staff members a copy of the screening criteria developed by Sargent and Lundy Engineers-(S&L) and used in LaSalle and Fermi projects for their review and evaluation.
The S&L screening scope is much broader than the Bechtel's.
Based on the staff review and studies made by EG&G, Idaho, the licensee was requested to revise the 3D and 50 criteria to SD and 100 shown as follows on June 20, 1984 at the Cloud off. ice.
These revised criteria were accepted by the licensee technical representatives.
i 157 j
PROXIMITY CRITERIA FOR SUPPORT REVIEW l
LARGE BORE I
SMALL BORE I
I l
l l
1 Support Pair l 8"
5D l
8" 2 0 2 2" l
D 5 2" l
l l
l l
l l Rigid-Rigid I
50 1
50 l
N/A l
l l
l l
l l Rigid-Anchor i 100 l
100 l
100 l
l l
l l
l l Snubber-Rigid i 50 1
50 l
N/A l
l l
l
'l I
l Snubber-Anchorl 100 l
100 l
100 l
J l
l l
l l
j Subsequent evaluation and comparison were made by the inspector, and the results were shown as follows.
Since the licensee has committed to evaluate all systems to the S&L criteria during the next two refueling outages to exclude all unneces-j sary (based on thermal movement consideration) snubbers and to minimize ALARA concerns, the licensee's short-term and long-term program and corrective actions appeared to be adequate.
158
I 4
- )
4 l
]
I S&L Ratios Between Pipe Bechtel Screening Criteria S&L and Bechtel i
Size (in)
Criteria (ft)
(ft)
Criteria
]
l
)
100
.50 S&L/100 S&L/50 S&L/3D
.j
-2' 1.67
'0,83 7
4.2 N/A N/A l
4 3.33 1.67 10 3.0 6.0 N/A 6-5.0
- 2. 5 13' 2.6 5.2 N/A 8
6.67-3.33 14 2.1
' 4.' 2 7
i
)
10 8.33 4.17
-16 1.92 3.84 6.4 12 10.0 5.0 17 1.7 3.4 5.7 20 16.67 8.33 21 1.26 2.52
.4.2 l
24 20.0 10.0 23 1.15 2.3 3.8 l
l I
I i
159 i
l
1 l
l
/
C.
Followup on IOVP Concern Items J
I t
1 General reviews were performed by the inspector at Robert L. Cloud Associates office on June 19 and 20, 1984.
Due to lack of availability
)
of inspection time and records (in remote storage), no conclusive state-ments could be reported.
i i
I 160
g63Efo,
UNITED STATES u
'C
[
g NUCLEAR REGULATORY COMMISSION
{
e,i "e
REGION 111 I
l 199 ROOsE vC L t RO AD 5 h,y[.j t
cet~cetvs.itusOis soin s,
MEMORANDUM FOR:
Richard H. Vo~llmer, Director, Division of Engineering, Nuclear Reactor Regulation FROM:
- 1. T. Yin, Senior Mechanical Engineer, Division of i
Reactor Safety, Region III SUGJECT:
DIABLO CANYON 1 REPORT Please find attached Region V Report No. 050-275/84-08, "Diablo Canyon 1 Investigation / Inspection Report", dated July 23, 1984.
This concludes my assignment under the NRR directory.
/
, /. 'l-
'/
I. T. Yin Senior Mechanical Engineer Division of Reactor Safety Region III cc w/att:
James G. Keppler J. 8. Martin i
i ames d
suF
e s
k.
..i i.
!ei ~.Q OCT 1 1984 Docket No. 50-275
- MEMORANDUM FOR:
Hans Schierling, Project Manager, Licensing Branch No. 3, Division of Licensing FROM:
I. T. Yin, Senior Mechanical Engineer, Engineering Branch, Division of Reactor Safety, RIII
SUBJECT:
SALP INPUT FOR DIABLO CANYON
^
Per your memo dated September 20, 1984, ple'ase find attached assessment for the SALP Board meeting for Diablo Canyon Units.1 and 2 currently scheduled on October 17, 1984.
I. T. Yin, Senior Mechanical Engineer
Enclosure:
As Stated cc:. J. G. Keppler Ruu mp, s e.
e Yin /lc 9/28/84 A
Piping and Support Review Effort Prepared By:
I. T. Yin, Engineering Branch, RIII Overall Performance Category:
3 1.
Management Involvement in Assurinn Ouality j
l Performance Category 3
Basis The lack of licensee management concern of QA provision and implementation resulted in violation of just about all the NRC regulations applicable to piping design control including 10 CFR 50, Appendix B, Criteria 2, 16, 5, 3, 18, and 17.
2.
Approach to Resolution of Technical Issues from Safety Standpoint Performance Category 3
Basis The approach to resolution of NRC identified significant technical issues resulted from its QA breakdown has been:
(1) analyzing it away rather than improving (the component design, (2) minimum in review and evaluation coverage, and 3) ignoring the possibility that similar problems could exist in other areas.
3.
Responsiveness to NRC Initiatives Performance Category 3
Basis The licensee has not been responsive to the inspection findings. The common approach was to negotiate with the staff management rather than to resolve the noncompliance and issues with the inspector.
Some of the corrective actions had been lacking in depth or unjustifiably compromised.
4.
Enforcement History Performance Category Basis No inspection or evaluation conducted.
i 1
n 5.
Reporting and Analysis of Reportable Events Performance Category Basis No inspection or evaluation conducted.
6.
Staffing (Including Manaaement)
Performance Category 3
Basis There has been a severe shortage of site OA/QC personnel to ensure that piping design activities are in compliance with the NRC regulations and the established program provisions. The head of the Onsite Project Engineering Group, himself the former licensee site QA supervisor, ignored or bypassed many QA program requirements.
i I
7.
Training Effectiveness and Qualification i
Performance Category 3
Basis The general and special technical /QA training programs were inadequate.
Procedure requirements had continuously been ignored.
Site contractor design personnel had been working months without indoctrination or training using unapproved methods and reference materials.
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION a
g,.$".
WASHING ton, D. C. 20656 g
- *$, e SEP 2 0 884 Docket Nos.:
50-275 and 50-323
' MEMORANDUM FOR:
Attached List THRU:
George W. Knighton, Chief f
c Licensing Branch No. 3
/?
I Division of Licensing
//.
FROM:
Hans Schierling, Project Manager Licensing Branch No. 3 Division of Licensing I
SUBJECT:
SALP INPUT FOR DIABLO CANYON The SALP Board for Diablo Canyon. Unit 1 and Unit 2 is currently scheduled to meet on October 17, 1984.
In accordance with NRR Office Letter No.!44, "NRR Inputs to SALP Process," you are requested to. provide input to the >lRR SALP evaluation for NRR activities on Diablo Canyon Unit 1 for the 18 mor th period from January 1, 1983 through June 30, 1984. is the listing of the NRR activities selected for evaluftion including the assigned individual. It is noted that the activities i do not always cover the entire 18 month period.
You are requested to evaluate each of the activities from the NRR perspective with regard to the 7 criteria provided in Enclosure 2. You should designate PG&E's performance as Category 1, 2 or 3 in accordance with the definitions in Enclosur,e 2.
An overall performance category should also be provided. Specific elements to be considered in the evaluation are given in NRC Manual Chapter 0516.
This evaluation is for Diablo Canyon Unit'l only.
You should identify any NRR effort during the evaluation period.that specifically relates to Uni't 2.
If you previously provided any SALP input on Diablo Canyon for the evaluation period, please indicate.
You are requested to provide your SALP inp inaccordancewiththeattachedformat(Enclosure lutby
' September 26, 1984 3).
(lsh
- Ha'ns Schierling, Project Manager Licensing Branch No. 3 Division of Licensing j
cc:
D. Eisenhut l
i R. Vollmer R. Bernero j
Y
[k, on T. Novak
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Diablo. Canyon Unit 1 Selected NRR. Review ard Licensing Activities SALP Period January 1,1983 - June 30,1984 1
1.
IDVP, ITP. Related NRC Issues (SSERs 18, 19, 20 and 24)
J Review Period 1/1/83 - 3/31/84 (overall evaluation J. P. Knight) 1
, a.
seismic aspects in civil / structural area (P. T. Kuo, H. Polk) b.
piping, supports and mechanical equipment, excluding recen4
'l effort by Review Group (M. Hartzman)
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c.
auxiliary systems (J. Wermiel) s.
d.
equipment qualification (H. Walker) 2.
Allegations (effort related to SSER 21, 22 and 26) a.
CCW operational limits (J. Wermiel)
I b.
systems interaction program (D. Lasher, F. Coffman) i c.
coating concerns (F. Witt, J. Pulsipher)
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d.
RHR low flow alarm (T. Marsh, C. Liang) e.
bolted connections (H. Polk) 3.
Pipina and Supports Review Effort,(allegations, staff concerns,!
license conditions, effort related to SSER 25) j l
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(evaluation to be provided by each of NRC participants:
J. P. Knight, j
R. Bosnak, M. Hartzman, K. Manoli, T. Sullivan);r. yin) l 4.
Seismic Desian Bases Reevaluation Program (S. Brocoum, L. Reiter)
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5.
Shift Advisor Qualifications (L. Crocker) 6.
Technical Specifications (F. Anderson) 7.
Programmatic Provisions for Onsite Activities (engineering, training, procedure controls, QA audits and findings) (R. Heishman)-
8.
Fire Protection (D. Kubicki) 9.
_SSER 27 and License Amendment 10 Activities (B. Buckley) j 10.
Event Reporting (G. Holahan)
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Evaluation Criteria (1)- Management involvement in ass'uring quality (2) Approach to resolution of technical issues from safety standpoint (3) Responsiveness to NRC initiatives (4) Enforcement history (S)' Reporting and analysis of reportable events (6) Staffing (including management) l (7) Training effectiveness and qualification II.
SALP Performance Categories i
Category 1.
A combination of attributes which demonstrates achievement of superior safety performance;f.e.,licenseemanagementattentionandinvolvementare!agressive and oriented toward nuclear safety; licensee resources are ample and, effectively used such that a high level of performance with respect to operational safety or construction is being achieved.
Category 2.
A combination of attributes which demonstrates achievement of satisfactory safety performance; i.e., licensee management attention and involvem evident and are concerned with nuclear safety; licensee resources ar,ent are e adequate and are reasonably effective such that satisfactory performance with respect to operational safety'or construction is being achieved.
Category 3.
Acombinationofattributeswhichdemonstratesachievementofonlyabnimally satisf actory safety performance; i.e., license management attention or involve-ment is acceptable and considers nuclear safety, but weaknesses are evident; licensee resources appear to be strained or not effectively used such that minimally satisfactory performance with respect to operational safety or construc, tion is being achieved.
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I ADDRESSEES:
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P. T. Kuo 3
4 H. Polk 3
,s M. Hartzman 4
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J. Werwiel 1
H. Walker w
- 0. Lasher
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" F. Coffman
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'J. Pulsipher
'I T. Marsh C. Liang 1
R. Bosnak K. Manoli T. Sullivan-L. Reiter L. Crocker F. Anderson R. Heischman D. Kubickt
- 8. Buckley
- 5. Brocoum
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December 20, 1983 Mr. John B. Martin, Regional Administrator U. S. Nuclear Regulatory Commission, Region V 1450 Maria Lane, Suite 210 Walnut Creek, CA 94596-5368 Re: Docket No. 50-275, OL-DPR-76 Diablo Canyon Unit 1 License Event Report 83-034/01 -T Improper Wiririg - RHR Pump Control Circuit
Dear Mr. Martin:
Pursuant to Section 2.H of the Diablo Canyon Unit 1 Operating License, the enclosed Licensee Event Report is submitted concerning the discovery of improper wiring on the RHR Pump control circuits as required by License Condition 2.C.(6).
This event has in no way affected the public's health and safety.
Sincerely, Us'..x
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Enclosure cc:
G. W. Knighton Director, Office of Management Information and Program Control Service List W
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I F6Til IWhile in mode 5. several wirina terminations were discovered which wara
[6TG inconsistent with circuit schematics affecting control power transfer relays for I lo le l lthe RHR pump control circuits. This event has in no way affected the public l
g l health and safety, and is reportable per Part 2.H of the Diablo Canyon Unit 1
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CAUSf DESCRIPTION ANo CoARECTIVE ACTIONS 27 lilo ll This is an interim report.
The modification to the RHR control power transfer l
lili ll relay was not fully implemented and the post installation test procedure J
[_i_12,_J l was not adequate to check that the modification was instal _ led correctly.
l I!!311 The circuit inconsistency is beina corrected.
A final report will be l
js!e!j submitted by 02/18/84.
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William W. Kessinger b*NI"NM PHONE NAME OF PREPARER
1-ATTACMENT TO LER 83-034/01T-0 DIABLO CANYON NUCLEAR POWER PLANT DOCKET NO. 50-275 LICENSE NO. DPR-76 l
SUPPLEMENTAL INFORMATION On Tuesday, December 6,.1983, some wire terminations were discovered which were inconsistent with circuit schematics affecting control power transfer relays for the RHR pump control circuits.
This wiring is part of a modification to isolate RHR pump control circuitry from the control room.
This modification disab* led the control room's capability to start the RHR pumps and still maintain the ability to operate the RHR pumps from a remote location in the event of a fire in the control room or cable spreading room.
Subsequently, the Appendix R submittal deemed j
this circuitry not required for safe shutdown because these pumps can be manually operated to bring the plant to cold shutdown condition.
This modification was in response to a NRC inquiry regarding the Diablo Canyon Fire Protection Review; and, is referenced in answer to question No. 51 of the November 13, 1978 letter to John F. Stola of the NRC from PGandE's Philip A. Crane Jr.
Further reference is included in Supplement 8 to the Diablo Canyon Safety
)
Evaluation Report.
Investigation of this event is ongoing and a supplement to this report will detail further causes and corrective action.
0020J
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