ML20011F394
| ML20011F394 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 06/21/1989 |
| From: | Phillips H Office of Nuclear Reactor Regulation |
| To: | Charemagne Grimes Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20011D121 | List:
|
| References | |
| EA-88-310, NUDOCS 9003050277 | |
| Download: ML20011F394 (89) | |
Text
{{#Wiki_filter:~ / UNITED STATES NUCLE AR REGULATORY COMMISSION { nasmwotom.o. c. m6s k N 2I N MEMORANDUM FOR: Christopher I. Grimes, Director Comanche Peak Project Division office of Nuclear Reactor Regulation FROM: H. Shannon Phillips, Senior Resident Inspector for Inspection Programs Comanche Peak Project Division office of Nuclear Reactor Regulation
SUBJECT:
TU ELECTRIC RESPONSE To EA 88-310 The information presented by TU Electric during the enforcement conference related to the SWs coating removal conference and their subsequent response to EA 88-310 on that matter is innacurate and incomplete. The deficiencies in their review of procured services (Code V) are addressed in my inspectitn report 50-445/446 89-23, as a follow-up to that action. However, other aspects of TU Electric's position during the enforcement conference and their attitude regarding the lessons learned from the SWS coating removal project are not included in that report, at the direction of my management. Nevertheless, I feel very strongly that this additonal information is relevant to the enforcement action and may warrant a higher severity level upon review of new information. The following is a brief summary of examples which show that TU Electric did not provide complete and accurate information to the NRC concerning enforcement matters that were being evaluated. Details which support these examples are discussed in Enclosures 1 through 8. l TU Electric management reacted emotionally to the SWS deficiencies identified in the exit for 50-445/88-47; 50-446/88-42. This caused TU Electric's staff to provide incomplete information. (see Enclosure 1 for details.) TU Electric management was aware of other Code V procurements i for services (work) on the CCW heat exchangers, steam 1 generators, and emergency diesel generators that were similarly deficient, but did not provide this information to the NRC. (See Enclosure 2.) TU Electric management erroneously concluded that the procedures, work; inspection, and surveillances were adequate because a comprehensive review of the procedures, work, and records was not performed. Instead, they relied on inspections and QA surveillances that apparently were inadequate. (see.) 9003050277 9oo22e D ps nwcxosoopggs g
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M 2 l 19.ib TU Elet:tric management stated that spinblaster damage did not occur in Train B, but three inspectors observed apparent damage. (see Enclosure 3.) 70 Electric management stated that damage to the piping did not affect the integrity or the functioning of the piping.
- Also, the defects were not considered significant.
This statement is misleading, because the integrity and the function was affected and the defects were significant from a partial QA program i breakdown and construction deficiency standpoint (50.55(e)). (see Enclosure 4.) TU Electric management stated that a contributing cause was work occurring at the safety /nonsafety interface of the metal { surface of the piping and the plasite coating. This statement j was misleading because the impact of nonsafety-related activity on safety-related activity must be considered from the start of construction through deactivation of nuclear plants. This issue had previously arisen and caused problems and was not a new problem. (see Enclosure 5 and 6.) TU Electric management inferred that technical and QA controls were comprehensive and the deletion of QA requirements had no effeet on the outcome. This apparently was not the case based on NRC findings. (See Enclosure 7.) TU Electric management stated that project uniqueness 2 contributed to the deficiency. This is no defense if true as many unique activities must be controlled, for example, setting the vessel at a one unit site is unique in that it occurs once. This does not excuse deficiencies and damage and would not be considered an extenuating circumstance. (See Enclosure 8.) I believe that the first three examples alone would be sufficient l grounds for reconsidering the enforcement (EA-310) for a higher severity level. The other exampler. show that a pattern existed, that is, TU Electric staff responded to the highest management request for information to discredit the findings. I believe the attitude displayed in response to the NRC findings is a more serious problem than the SWS deficiencies that were identified. Accordingly, I recommend that EA-310 be considered for a higher severity level. /A7 7 H. S. Phillips, Senior Resident Inspector for Inspection Programs l Comanche Peak Project Division i office of Huclear Reactor Regulation Enclosures I Details of Incomplete Inaccurate Information cc R. F. Warnick, NRR _ H. H. 1,1vermorea NRR
.s s ENCLOSURE 1 In May 1988, the NRC identified potential violations &nd made TU Electric aware that the NRC did not think that the appropriate QA/QC and technical controls were applied to the SWS coating removal and TU Electric middle management _(engineering, project, took little or no action in response to the NRC, but maintained project. that they were confident that the project and QA controls were QA) The NRC received feedback from meetings entirely adequate. conducted by TU Electric that construction management recogn fact that controls were inadequate and asked that the project stopped. well and refused to listen. i TU Electric discovered a 1/2-inch hole caused by a on July 29, 1988, lack of QA/QC and technical controls applied to the sandblasting Subsequently, (spinblasting) of the 10-inch SWS piping. As eighty-eight other defects were found in 650 feet of the piping. TO Electric had done little or nothing to correct the g s I defenses and the NRC exit for inspectionThe defect was found on Friday, July 29, was only three days away. 1988, and was reported to the NRC on August 1,1988, (one day before 1 l the exit). On August 2, 1988, the NRC summarized the findings that had been identified during the three month period including the most recentThis info the hole in the pipe. development, the TU Electric representative who routinely provided thein When Mr. Counsil learned of the NRC findings, he contacted Mr. exit. Mr. Part10w, NRC Headquarters office of Special Projects Mr. Counsil informed the NRC inspector of Mr. Counsil's protest. i protested to Mr. Partlow because he thought there was an agreement He said the NRC had agreed between hLm and NRC site supervision.that Mr. Phillips, NRC insp He said that the NRC inspector was trying to embarrass TU Electric in front of CASE, the intervenor (the first exit CASE exit. \\) attended after the settlement). The NRC inspector and supervisors The NRC inspector offered to were unaware of any such agreement. delay giving the findings, but supervision directed the inspector to give the findings. After the inspector gave the findings (violations) on the lack of control of work activities on SWS piping, Mr. Counsil challenged the That is, he reiterated that the NRC was not supposed to The inspector stated that the inspector. give the findings per an agreement.
4 i 2 Mr. Counsil was visibly NRC was unaware of any such agreement. angry and turned to two senior managers and said, " load up your guns Several NRC inspectors commented that Mr. Counsil's (There was a virtual repeat at the on this one." behavior was very inappropriate. next exit with operations personnel on another violation.) NRC inspectors received feedback that gave further insight about About midway through the coating removal project, what happened. construction management recognized the lack of controls and recommended stopping work until adequate controls were put in place. Engineering and the project management basically told these managers to sit down and be quiet as they were running the show and had Af ter the damaged piping was found, a everything under control. pre-exit meeting was held and the same managers reiterated their . concerns about the lack of controls they had been concerned about These and.now the same ones had been identified by the NRC. managers suggested that TU Electric should simply admit The project manager maintained that the QA and was adequate. technical controls were applied, but testing simply was not Mr. Counsil decided to listen to the project correctly modeled.At the post exit meeting Mr. Counsil was described as These demonstrations in front of manager. highly emotional and was livid. his staff let his staf f know he wanted to discredit the NRC findings. The Enforcement Conference handout did the job of discrediting the NRC findings by providing incomplete and inaccurate information. The project manager provided a major portion of the input for the In discussions with this manager (whose enforcement conference. it was evident that he believed nuclear experience was limited), they had imposed all necessary controls and had just not foreseen With this belief, he could provide the test modeling problem.It appears that other managers provided Mr. inaccurate information. Counsil with the information to discredit the NRC findings byThe wording in accenting the positive and leaving out the negative. the Enforcement Handout is worded to the legal limit, that is, it is true in part, but not in the whole. I have no evidence that there was intent to deceive the NRC, but it appears that the highest management caused the staf f to skew the information. Without accurate and complete information, the NRC understandably could not adequately evaluate the enforcament matters under Accordingly, the severity level was reduced from ) consideration. The previous enforcement needs to be Level III to Level IV.In addition, the failure to provide accurate and reconsidered. complete information is really more serious than the SWs deficiencies that were identified. .i +..w w-w
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j j 9 i A ENCLOSVRE 2 TU Electric.did not provide information at the Enforcement conference that was later found in TU Electric's memorandum NE 22156. The information would have provided six examples of deficient Code'V procurements for services (work) on safety-related e' components in addition to service water. TU Electric's finding in 4 - response to TXX-89070 dated February 8, 1988, stated that the inspection and surveillance reports associated with the six code V procurements for services-showed that the requisitioned work was satisfactorily completed, but did not discuss deficiencias in memorandum NE 22156. An NRC inspection determined that TV Electric's review of inspection and surveillance reports alone and limited work records would not address the QA. program deficiencies or assure that work was successfully completed.- As a minimum procedures, work, and records should have been reviewed. In addition, one could 2rgue that such documents existed for SWs activities but despite this damage occurred because QA requirements were not established, procedures were inadequate, inspection was inadequate, and nonconformances were not identified and documented. The following are the inspection findings concerning the six services provided. Chemical Cleanino of CCWHXs TU Electric Surveillance Activity Report 87-022 and Memorandum TCP-87027 indicated that overall chemical cleaning process for Train A (Units 1 and 2) was not appropriately controlled. These deficiencies were not documented in. deficiency reports and evaluated to assure correction before cleaning Train B (several months later). Inspection and surveillances concluded that vendor chemical procedures were adequate when they were not. No documented evidence was provided to show that vendor personnel were appropriately trained to follow TV Electrie's QA program.- There were no inspection reports for the chemical cleaning process. Surveillance checklists were generic and did not adequately and l l specifically address process controls. The conclusions for different checklist items were conflicting. l
.e 2 Cutting CCWRX Tube Ends 5720 tube cuts were made for 2 CCWHXs, howevea, only 25. vereNo inspected to assure the cut met dimensional requirements. v in process inspection controls for the cutting process was described. DcA 25192, Revision 0, required 1/8 inch minimum radius; however, this was not inspected. The surveillance checklist and evaluation of this process did not address the above issues. The survoillance summary contained a comment that the vendor lacked discipline, tools, and experience probably should have been a finding. Coatino of CCWHXs Surveillance SR-86-007 concluded that the surface preparation The was acceptable based on inspection report IR-86-0289. inspection of surface was either not done or if done, it was not documented in IR-86-0289. Inspection of areas, where spark testing was not possible, were not inspected or documented. There is no evidence that repair areas were repaired and inspected to SPECO Bulletin 35. The final protective coating was inspected; however, other coats were not inspected to assure proper application. Curing time and temperature was not confirmed by TU Electric inspection. There was no evidence that vendor measuring and test equipment was calibrated. The surveillance was based on a generic checklist that appeared to be inadequate, as applied. Measurement of Steam Generator Norries The work on the steam generators was in progress before QA was aware the vendor was onsite. QA discovered the work was in progress and performed surveillance CSR-87-003. The surveillance concluded that QA did not know about special requirements until after the fact. The procedures, tools, and training was not certified by QA l prior to the beginning of work as required by { Procedure ECE 6.11.
-t ENCLOSURE 3 TU Electric stated during the enforcement conference, in part, that "Id)amage did not occur following modifications to spinblaster." " Pipe Damage Limited To Small Portion of One Train - Not Safety significant." " Process Control Adequate Based on Successful-Implementation After Modification." contrary to the above, my inspection determined that damage did occur after modifications to the spinblaster. Shortly after damage was found in Train A of the SWS in July 1988, the NRC inspector specifically asked whether damage occurred on Train B after the modifications and informal information received from engineers indicated damage occurred in Train B. In March 1989, three NRC inspectors performed a field ~ inspection to view video tapes of Train B after they were reinspected for damage. - Engineering Report ER-ME-19, Revision 0, stated that a reinspection of the tapes was performed by the applicant for 10-Inch piping using'high resolution monitors. The NRC requested that this inspection process be duplicated so the NRC could observe the inspection methodology. The NRC was interested in the inspection of both the corrosion defects and spinblaster damage. The following was found by the NRC: Defects caused by the spinblaster were observed in Train B (Spool SW-1-SB-7-14A-8 frame 1484). The misidentification of video tapes of Train A and Train B 10-inch piping occurred during the process of video taping. This was corrected and the TU Electric representative assured the NRC that they were looking at the correct tape. He also agreed that the damage looked like spinblaster marks. Standards or examples of the damaged piping for comparing observed defects to known defects (as seen in tapes of known damaged piping) were not available for simultaneous viewing. Video tapes were made at an angle instead of perpendicular to the surface. The view was distorted and shadows made it difficult if not impossible to qualitatively evaluate the depth of corrosion defects and spinblaster damage. The wheels on the carriage that traveled through the piping left track marks. At least one pile of sand was observed and it was evident that the pipe surface under the sand was not inspectable. All of these conditions hampered the inspection of the 10-inch piping. Note: The NRC was informed that a different camera will be used for Unit 2 and will eliminate the above problems. If the new camera were used for Unit 1 it could show that all defects were identified, or, alternatively, the old and new camera could be used for a section of piping and then the disposition
J r 1 i 2 could be independently evaluated and then compared to judge the adequacy of inspection in Unit 1 to detect minimum design stress wall thickness. A comparison could prove the process in Unit I was valid. Eighty-four 10-inch spool pieces'(each approximately 20 feet long) were removed and cleaned in the yard. These pieces were visually inspected by TU Electric for defects by viewing the inside surface of the piping from the and of the piping. I do e not.believe corrosion defects could be identified by such visual examination.except for the surfaces.near the pipe ends. .In addition the engineering report stated that two defects were not measured because they.were inaccessible. ~1 l. L I 1 k l l l. l
.t ENCLOSURE 4 TU Electric Enforcement Conference Document stated that the spinblaster ". . damage did not affect the integrity or the functioning of the single train affected, nor other equipment, and was not safety significant." Contrary to the above, 650 feet of piping contained significant damage and some of the piping had to be replaced-as a result of spinblaster damage.- The average pipe wall thickness'before coating removal was 0.390 inches but was reduced in various areas. Approximately 80 spinblaster marks were identified by TU Electric after the hole in the piping was identified including 8 that were greater than.100 inches deep and 4 where projected corrosion lifetime was less that 20 years. One mark was.307 inches deep. And several lengths of pipe were replaced. The integrity of the piping was obviously affected. Given the breakdown.in part of the QA program for SWS coating removal, this made the construction deficiency, as defined in 50.55(e) was significant. The additional six Code V services that were deficient are added support that the deficiency was significant but was not considered significant. It also met the definition or criteria of 10 CFR 50.55(e) because the damaged piping required extensive evaluation or repair.
e' 1 i ? ENCLOSURE 5 TU Electric Enforcement Conference Document states, in part, . ASME Applicability Not Clear". " Contributing causes: This statement was inaccurate. The ASME Code section XI does not allow metal removal without being under the auspices of the authorized nuclear inspector and under code control. Obviously sandblasting can remove too much metal and violate the. code. 'In addition, page 5.of Appendix H of TU-Electric Specification 2323-MS-100 states, in part, " Note: Under ASME XI any metal removal is considered a repair, even though that activity may have been considered rework when working under 7S70C III (i.e., removal of an 4 arc strike is an ASME XI repair even if minimum wall is not violated)." obviously sandblasting can-cause more severe damage than are strikes and must be controlled in accordance with ASME XI Code. The March 14, 1988 TU Electric Meeting Notes document a meeting between O. B. Cannon Company and TU Electric. It appears from these notes that sandblasting and metal removal was recognized as an activity that could adversely affect ASME Class 3 components and should have been controlled as such.. Interview with personnel L showed that some TU Electric managers wanted the process stopped. Construction management challenged this process in mid-project and -wanted to stop work to gain control. Engineering knew at the beginning of the project-that the blaster stalled and may have violated ASME Section XI, but did not test the areas where the stall occurred. v.-
l H 4 M s ENCLOSURE 6 g Enforcement Conference Document states, in part, . Work To Occur At safety /Nonsafety Interface."" Contributing causes: and the EDG fuel oil tanks.Three NRC inspections eviewed the coating issues concerning the SWS-It was clear that the concept of nonsafety-related parts within or adjacent to safety-relat i" plant construction. components is a principle-that should have-been established be requirement that coating activities affecting the quality ofTU E p components must be controlled. The NRC inspector found that safety-related components bas existed for a long time resolution. The following examples support this conclusion: SWS piping in'the field without Appendix B QA/QC Subsequently this was discovered but these areas were not extensively and thoroughly inspected and evaluated. the Stone and Webster Engineering Corporation (SWEC) corrosion In 1988, report stated that the greatest piping occurred in these areas. damage to the coating and piping degradation and finally coating removal damage. In 1980, a site engineer questioned the coating procured ano applied with QA/QC controls. downgrade the specification to read that coating was notThe correc safety-related instead of evaluating the effects of a lack of proper QA/QC controls could have on safety-related components. Page 10 of TU Electric Engineering Report ER-ME-19, Revision 0 september 21, 1988, concluded that the action taken by TU Electric and Gibbs and Hill, Inc., was adequate at the time given the information available. I: The NRC determined that the TV Electric's assessment of thi corrective action was inadequate. was well known and information was available that theIn the coating indu wsuld probably result in nonuniform coating and acc corrosion and/or sheet mode failure of the coating. two subsequent opportunities (INPO SER 68-83 and IE In 1983 Notice 85-24) occurred to identify and correct the QA/QC and
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2 degrading coating and piping deficiencies,-but two additional-
- inadeguate evaluations occurred.
A similar example of problems caused by the confusion over safety related versus nonsafety-related work is discussed in paragraph 8 of NRC Inspection Report 50-445/89-23: 50-446/89-23^, application and removal of~ coatings from diesel generator fuel oil tanks. one engineer: recognized the problem with diesel storage tankIn 1983, coatings and revised this specification to read safety related: however, this corrective action was reversed in 1985. As a part of the corrective action concerning SWS deficiencies, TU Electric failed to recognize the earlier deficiencies and the root causes. significant and not reportable.This 50.55(e) deficiency was also considered not g__.
0 ENCLOSURE 7 The Enforcement Conference Document stated that deletion of the QA L responsibilities from the requisition (6R-350338) did not represent l-a reduction in the level of quality and that the QA program was L' still required. Also, the Enforcement Conference document stated that the deleted QA requirements were replaced by QA surveillances and that verification' activities were assigned to engineering. Therefore, TU Electric stated no violation occurred. The NRC inspector found that the surveillances were almost b-meaningless because the procedures were inadequate. The Stone and Webster Engineering and Ebasco coating engineers were responsible for the coating removal work. They thought all of the activities were nonsafety related. The deletion of quality requirements from the purchase requisition removed the quality organization from the spinblaster testing activities.- This decision to delete the requirement for the quality organization to witness the test was very important because test and results were later found inadequate. The test determined parameters for controlling the spinblast process. In reality quality organization did not object because they viewed the operation on the whole as a nonsafety-related activity and performed little or no inspection of the critical characteristics. For example, the Engineering Report (ER-NE-19) indicated that the quality organization was not at a mobilization meeting on April 6, 1988. Procedure EC 6.11 required the QA department representative to certify that procedures were approved, training had been given on owner / contractor procedures, and appropriate-contractor supplied materials and/or special tools had ~ been received. Later TU Electric QA surveillance personnel wrote a deficiency report (C-88-03361) because QA did not attend the meeting and certify the activities were completed. Instead of finding QA at fault for not certifying the required activities, the disposition of the deficiency found the procedure at fault and the only action needed was to revise the procedure. If QA had been at this meeting the QA/QC deficiencies concerning service water may have been identified before coating removal began. ma TU Electric's argument gives the impression that a one time work activity should be an excuse for not applying QA/QC and technical controls. Every utility is expected to consider and Imaster the concept of the impact of nonsafety-related activities on safety-related systems before the construction permit is issued. For example, the two over one concept is essential to the design of piping. Adjacent nonsafety work must not damage the steam generator. The vessel is only set one time. This is the reason that controls must be developed to perform the activity correctly the first time. The above argument is misleading. {
2 The Enforcement Conference Document and ER-ME-19 gave the impression that the quality assurance organization performed meaningful QA surveillances when in reality five surveillances performed using a checklist based on p:ocedures that did not contain the necessary parameters to control the sandblast /spinblast process. The surveillances only verified if coating was ramoved (a nonsafety function). Manufacturer's minimum specified wall thickness of sws piping and other meaningful characteristics were not checked. At meeting May-July meetings, a TU Electric QC supervisor and SWEC/Ebasco engineering thought the NRC inspectors were strange for thinking that the sandblasting was safety-related and argued that metal removal by sandblasting was not safety related. Page 34 of the engineering report indicates that QA became involved with wall thickness measurements in June 1988 but the report fails to state that this was in reaction to the NRC inspection concerns and was well af ter damage had occurred. The QA organization was not involved with the problems that occurred with the spinblaster when the vendor first encountered process control problems. As a result no deficiency report or corrective action request was made. The engineering report (ER-ME-19) stated that the problems encountered early should have warranted a stop work order but one was not issued. The spinblaster problems resulted in retesting the spinblaster to determine the necessary modifications but again the quality organization was not involved. The NRC inspector also found that TU Electric never audited any Code V procurements for vendor services even though the NRC surfaced deficiencies early in the SwS process. No audit was performed after problems were evident.
'? 9 v b ENCLOSURE 8 k TV Electric Enforcement Conference Document states, in part, " Contributing Causes: Coating Removal was Unique Task... Process Not Previously Employed / Development Work Needed." L Contrary to the above the sandblasting /spinblasting process is an old manufacturing / construction process that is not unique. The process can be controlled provided process parameters are specified and followed. The TU Electric test failed to establish parameters and did not duplicate environmental conditions. Even the parameters (blast material / site, air pressure, blasting rate, and process hold t L points) that were developed by TV Electric were not incorporated into procedures. Quality assurance was not at the critical TU Electric mobilization meeting and was insufficiently involved to monitor and inspect in-process work to prevent wall thinning. In fact, QA did no inspection monitoring or testing in April and May for wall thinning. Until such controls are implemented, the claim that uniqueness caused the damage is without foundation. I tr mi s M ~
1 a;p j[g\\. e UNITED STATES. = - t NUCLEAR REGULATORY COMMISSION LI wasmwcTow,0. c. roess d, k j p In Reply' Refer Tot. Docketsr 50-445/89-23 50-446/89-23 Mr. W. J. Cahill-- i Executive-Vice President J .TU Electric- -400 Ncrth olive Street,' Lock Box 81 Dallas, Texas-75201-1
Dear Mr.Cahill:
t This refers to the inspection conducted by Mr. H. S. PhillipsLduring- -the period April.5 through May 2, 1989, of activities authorized by: NRC Construction Permits CPPR-126 and CPPR-127 for the Comanche Peak steam Electric Station, Units 1 and 2, and to the discussion of-our findings with Mr. H. D. Bruner and other members of your. staff at the conclusion of the inspection. The enclosed ceny of our inspection' report identifies areas examined during.the inspection. Within these areas, the inspection consisted of selective examination of procedures and representative records, interviews with personnel, and observations by the' inspector. During this inspection, it was found that certain of your activities. were'in violation of NRC requirements.. The apparent violation is being reviewed for. appropriate enforcement action. An enforcement conference-to discuss the findings will be scheduled'. Following the enforcement: conference-you will be notified of the resolution-of these findings. . In = accordance.with 10 CFR 2.790- of the Comission's regulations, a copy of-this letter and the enclosed report will be placed in the NRC Public Document Room. f I o
f j m j i E J. Cahill~ '2 l 'should,you have any-questions concerning this inspection, we will be pleased to. discuss them with you. Sincerely,. 9 C. I.' Grimes, Director Comanche Peak Project Division office of Nuclear Reactor Regulation-
Enclosure:
Inspection Report'30-445/89-23; 50-446/89-23 cc w/ enclosure - s See next page 5 4 h
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.. - _. - ~. _L 1 q o W. J..Cahill ec w/ enclosure Roger D. Walker TU Electric Manager, Nuclear Licensing c/o Bethesda Licensing TU Electric 3 Metro Center, suite 610 Skyway Tower Bethesda,-Maryland 20814~ 400 North Olive Street, L.B. 81 Dallas, TX 75201 E. F. Ottney P. O. Box 1777 Juanita Ellis Glen Rose, Texas 76043 President - CASE 1426 South Polk Street Joseph F. Fulbright Dallas, TX 75224 Fulbright & Jaworski 1301 McKinney Street Susan M. Theisen Houston, Texas 77010 Assistant Attorney General Environmental Protection Division George A. Parker, Chairman H P.O.' Box 12548, Capitol Station Public Utility Committee Austin, TX 78711-1548 Senior Citizens Alliance of Tarrant. County, Inc. GDS Associates, Inc. 6048 Wonder Drive l~ .1850 Parkway Place, Suite 720 Fort Worth, Texas 76133 L Marietta, GA 30067-8237 Jack R. Newman, Esq. Lanny A. Sinkin Newman & Holtzinger, P.C. Christic Institute Suite 1000 l 1324 N. Capitol Street 1615 L. Street N.W. Washington, DC 20002 Washington, D.C. 20036 Ms. Billie Pirner Garde, Esq. Garde Law Office 104 East Wisconsin Avenue Appleton, WI 54911 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 1000 Arlington, Texas 76011 l William A. Burchette, Esq. Counsel for Tex-La Electric Cooperative of Texas i Heron, Burchette, Ruckert & Rothwell 1025 Thomas Jefferson St., NW Washington, DC 20007 l l i I A.---
o.: (,l.' ^ . 50-445/ 89-23 ; $0-446/89 - 23 s l; DISTRIBUTION: ? Docket. Files (50-445/446) NRC PDR LPDR CPPD-LA. <CPPD Reading;(HQ) ADSP-Reading s . site Reading. File'
- R. Warnick
- J. Wiebe
- H. Livermore
- MIS System, RIV
- RSTS Operator, RIV 3
RPB, RIV RIV Docket File
- L.'Shea, ARM /LFMB J. Taylor
} C.. Grimes P. McKee s J. Lyons J. H.= Wilson. i M. Malloy. i J. Moore, OGC-WF-M. Fields. J. Gilliland, RIV t 'I D.'Crutchfield E. Jordan a B. Grimes .B.. Hayes
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t j i < = '*: .g y w ^ l In Reply Refer To l -Dockets:- 50-445/89-23 50-446/89 I )
- Mr'. W. J.:Cahill Executive Vice President
-TU Electric. 400 North Olive Street, Lock Box 81 l- -Dallas, Texas-75201
Dear Mr. Cahll,
l: insis refers to the inspection conducted by Mr. H. S. Phillips during- .the period! April 5 through May 2, 1989, of activities authorized-by 'NRC Construction Permits CPPR-126 and CPPR-127 for the Comanche Peak Steam: Electric Station, Units 1 and.2, and to the discussion of our findings with1Mr. H. D. Bruner and other members of your staff at ) 'the conclusion of.the inspection. The enclosed copy of our inspection report identifies areas examined j during the inspection. Within these areas, the inspection consisted of-selective examination of procedures-and representative records, interviews'with personnel, and observations by the inspector. During this. inspection, it was found that certain of'your activities were 1n violation of NRC requirements. ~ The apparent violation is; Lbeing reviewed for appropriate-enforcement action.- An enforcement conference to discuss'the findings will be scheduled. Following the t enforcement conference you will be notified of the resolution ~of'
- these, findings.
In-accordance with 10 CFR 2.790 of the Commission's regulations, a I copy of this letter and the enclosed report will be placed in-the NRC Public Document Room. L SRI:IP:CPPD:NRR IP:CPPD:NRR AD:IP:CPPD:NRR D:CPPD:NRR SPhillip HLivermore RWarnick CGrimes 7//o/89 7/ /82 7/ /89 7/ /89
.c 1: .~ 1 W. J. Cahill' 2 Should you have.any questions concerning this inspection, we will be pleased to discuss them with you. Sincerely, C. I. Grimes, Director Comanche Peak Project Division' office of Nuclear Reactor Regulation
Enclosure:
Inspection Report 50-445/89-23; 50-446/89-23 cc w/ enclosure: See next page a \\ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - " - ~ ~ ^ ' ^ - ~ ~ ~ ~ ~ ~ ~
Eg-K L. t I h U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION L NRC Inspection Report: 50-445/89-23 Permits: CPPR-126. I 50-446/89-23 CPPR-127 Dockets: 50-445 50-446 Category: A2 Construction Permit l Expiration Dates: I -Unit 1: August 1, 1991 1 Unit 2: August 1, 1992 1 Applicant: TU Electric Skyway Tower 400~ North Olive Street Lock Box 81 Dallas, Texas-75201 Facility Name: Comanche Peak Steam Electric Station (CPSES), Units 1 & 2 Inspection At: Comanche Peak Site, Glen Rose, Texas Inspection conducted: April 5 through May 2, 1989 e Inspector: I E. S. Phillips, Senior Resident Inspector Date Construction l l Reviewed by: H. H. Livermore, Lead Senior Inspector Date O
i 2 Inspection Summary: Inspection conducted: April 5 throuch May 2. 1989 (Report 50-445/89-23; 50-446/89-23) I Areas Inspected: Unannounced,: resident safety inspection included: .(1) exit meeting with management,-(2) applicant action on previous L findings, (3) follow-up on violations,.(4) evaluation of corrective L action on' enforcement,.(5) review of component cooling water heat exchanger work, (6) repair of diesel generator heat exchangers, (7) vendor services to measure steam generator nozzles,'and- -(8) application / removal of coatings from diesel generator. tanks.- L Results: Within the areas inspected, one apparent violation was identified:- failure to provide accurate and complete information relative to corrective action concerning Enforcement Action EA 88-310, paragraph 4.b; and additional examples of violations similar to those identified in EA 88-310, paragraphs 5, 6, 7, and 8. An enforcement conference will be scheduled to discuss these findings. r I.
7 \\ / 3 6" DETAILS I 1. Persons Contacted 'R. W. Ackley, Jr., Director, CECO
- G. K. Afflerbach, ASM Startup, TU Electric
- M. Axelrad,.Newman and Holtzinger
- J. L.-Barker,' Manager,' Engineering Assurance, TU Electric
- D. P. Barry, Senior Manager, Engineering, Stone and Webster Engineering Corporation.(SWEC)
,i
- J. W. Beck, Vice President, Nuclear Engineering, TU Electric
- 0. Bhatty, Issue Interface Coordinator, TU Electric
'M. R. Blevins, Manager, Technical Support, TU Electric
- H. D. Bruner, Senior Vice President, TU Electric
- J. H. Buck, Senior Review Team, IAG
'J. T.-Conly, APE-Licensing, SWEC
- R.~J. Daly, Manager, Startup, TU Electric L
- J. W.-Donahue, Operations Manager, TU Electric I
- D. E. Deviney, Deputy Director, Quality Assurance (QA),
TU Electric-
- D. M. Ehat, Consultant, TU Electric
'J. C. Finneran, Jr., Manager, Civil Engineering, TU Electric l
- C A. Fonseca, Deputy Director, CECO
- W. G. Guldemond, Manager of Site Licensing, TU Electric I
- P. E. Halstead, QC Manager, TU Electric
- T. L. Heatherly, Licensing Compliance Engineer, TU Electric
- C B. Hogg, Engineering Manager, TU Electric
- T.
A.-Hope, Licensing, TU' Electric
- A. Husain, Director, Reactor Engineering, TU Electric
- R. T. Jenkins, Manager, Mechanical Engineering, TU Electric
'J. J. Kelley, Manager, Plant Operations, TU Electric
- 0. W. Lowe, Director of Engineering, TU Electric
- F. W. Madden, Mechanical-Engineering Manager, TU Electric
- D. M. McAfee, Manager, QA, TU Electric
- S. G. McDee, NRC Interface, 1NJ Electric
- J. W. Muffett, Manager of Engineering, TU Electric
- E. F. Ottney, Program Manager, CASE
- S. S. Palmer,. Project Manager, TU Electric
- P. W. Pellette, Operations, TU Electric
- D. M. Reynerson, Director of Construction, TU Electric
- A. H. Saunders, EA Evaluations Manager, TU Electric
- A. B. Scott,'Vice President, Nuclear Operations, TU Electric
- B. J. Sewell, TU Materials Coordinator Manager, TU Electric
- J. C. Smith, Plant Operations Staff, TU Electric
- R. L. Spence, TU/QA Senior Advisor, TU Electric
- M. D. Skaggs, CPE, Mechanical, TU Electric
- P. B. Stevens, Manager, Electrical Engineering, TU Electric
'J. F. Streeter, Director, QA, TU Electric
- C. L. Terry, Unit 1 Project Manager, TU Electric
- M. A. Thero, CASE Intern
~,3 .h 4 W L. Thero, QTC Consultant to CASE
- 0.
- T. G. Tyler, Director of Projects, TU Electric
- R. D. Walker, Manager of Nuclear Licensing, TU Electric
- R. G. Withrow, EA Systems Manager, TU Electric The NRC inspectors also= interviewed other applicant employees during this inspection period.
- Denotes personnel present at the May 2, 1989, exit meeting.
2. Applicant Action on previous Inspection Findinos (92701) (closed) Open Item (445/8908-0-01): The documentation a. file relating to the auxiliary feedwater motor fans being L installed' backwards contained two nonconformance reports (NCRs) not previously reviewed-by the NRC. The NCRs described arcing between.the fans and brass rings on the rotor winding. The arcing was attributed to the condition of having reversed fans. The W analysis concluded that the reversed fans would not cause motor failure or reduce i the level of safety during operations. The NRC questioned whether the W analysis included the NCR conditions. During this inspection, TU Electric met with the NRC and presented additional information. That is, W reevaluated L the NCR conditions in connection with the fan reversal issue and concluded that their original analysis was not impacted by these NCRs. This item is closed. y Note: In NRC Inspection Report 50-445/89-08; 50-446/89-08 the tracking number for this item contained.a typographical error. The number shown above- -(445/8908-0-01) corrects the number error (445/8808-0-01). 1 b. (closed) open Item (445/8908-o-03): No NCR was available L on stripped threads in bearing holes for an auxiliary R feedwater_(AFW) motor. The NRC inspector confirmed that operations / maintenance had issued NCR 88-03638, Revision 0. This item is closed. l1 c. (Closed) Open Item.(445/8908-0-04): QC did not verify temperature control during the welding on the AFW rotor bar assembly. The maintenance instruction stated that extreme caution must be taken not to concentrate an excessive amount of heat on the rotor bar assembly. The NRC inspector was concerned that QC had not verified that the instruction was followed. TU Electric met with the NRC to provide information about this concern. 'The NRC inspector asked what type of material was used and what heat input controls were
9 a [ 5 necessary. TU Electric did not have a welding engineer present,1so a-subsequent meeting had to be arranged. During that subsequent meeting TU Electric-revealed that l: an electrical engineer had inserted the caution about heat-l input. The welding specialist identified the material as ' a low carbon steel and provided information about the --energy input. The NRC inspector has no further questions. This item is closed. d. (open). Unresolved Item (445/8908-U-02)t-TU Electric maintenance personnel substituted Grade 5 carbon steel-bolts for the' silicone bronze bolts that secured AFW fans in the motors. The NRC inspector learned that a W field representative.had directed-this material change Secause past experience had shown that the silicone bronte bolts -were cracking and failing because of fatigue. The NRC inspector stated.that this material change was improperly authorized unless an engineering change had authorized the change. The inspector also questioned if this was a weakness in the maintenance program. During this' inspection, TU Electric met with the NRC and made a presentation on this subject. They admitted that the material change was not authorized. They were unable to find the W field representative as he was a consultant and performed this work for W. TU Electric submitted a large amount of material on this subject. The NRC-inspector considers this to be a potential violation; however, this item will remain unresolved pending the completion of the NRC evaluation. 3.- Follow-up on Violations (92702) 1 (open) violation (445/8847-V-Ola): Failure to establish a. QA and technical requirements in procurement documents for coating removal from service water system (SWS) piping. b. (open) Violation (445/8847-V-Olb): Failure to establish adequate controls for the coating removal-process. (open) Violation (445/8847-V-01c): Failure to provide c. adequate QA/QC procedures for the coating removal process. d. (open) Violation (445/8847-V-Old): Failure to take corrective action relative to coating problems and coating
- removal, The above violations were douemented as Enforcement Action (EA) 88-310 in an NRC letter to TU Electric dated January 9, 1989.
TU Electric's response to the violations is discussed below in paragraph 4. L m3. - v-w -,a +
~ ' _. 6 4. Evaluation of TU Electric Corrective Action on Enforcement-(35065, 49063, 49065, 92702) a.
Background
NRC. Inspection Report (50-445/88-34; 50-446/88-30 for May.1988). identifies open items concerning the' removal of Plasite 7122 from SWS and potential wall thinning.by sandblasting. NRC Inspection Report 50-445/88-47; 50-446/88-42 was issued on September 2, 1988, and identified one apparent violation (breakdown in the QA program relative:to the removal of the protective liner from L the SWS piping). On September 13, 1988, TJ Electric responded to the findings at a public meeting on site. On November 9, 1988, the NRC held an Enforcement Conference at the NRC's Rockville, Maryland, office. TU Electric made a presentation and provided a handout. The handout was-attached to NRC Notice of violation 50-445/88-47; 50-446/88-42 dated January 9, 1989. The handout stated that problems in the L implementation of QA program requirements occurred but were isolated and were not significant. The-handout also stated that corrective actions were completed and included (1) evaluating / replacing worst i damaged piping, (2) evaluated other spinblast indications with satisfactory results, (3) performed i critical self-evaluation, (4) reviewed.other code V services (other than SWS) procuraments with satisfactory results, and (5) reviewed previous CPSES enforcement action and'found no precursor events. On January 9, 1989, NRC issued the NOV for NRC Inspection Report 50-445/88-47; 50-446/88-42. It i L stated that after careful review of information, the L NRC decided that four Severity Level IV violations k were appropriate instead.of the one Severity Level T III that was initially considered. It also stated that the NRC was concerned that once it was recognized that the coating removal process needed to be modified, adequate measures were not taken to inspect for damage caused by early process problems. l The NRC letter stated that if the violations were not fully corrected they may lead to more significant concerns. On February 8, 1989, TU Electric issued their response-(TXX-89070) with one attachment to the NRC.
u., n- ~ 3 !( .c 7 .l Incomplete an'd "nadequate Information Provided Concernino-b. concernino EA 80-310 The NRC-inspector reviewed the TV Electric Enforcement Document which was docketed with the NRC Enforcement
- Action'EA 88-310 and~ Notice of Violation 50-445/88-47,
~50-446/88-42. TU Electric Response TXX-89070 to the enforcement action was.also reviewed.- These documents -provided TU Electric's overall response. At the b Enforcement l Conference information was.provided to the NRC which advocated a reduction in the proposed severity: level L from Level-III-to Level IV and V. During-the enforcement L conference TU Electric made several statements, some of a which are discussed below, to show that QA/QC deficiencies I t identified-by the NRC were not program breakdowns and, therefore, were not significant. The NRC inspector.found l that specific information related to the results of TV-l- Electric's review of other Code V procured services was not included in the information provided to the NRC. ~ Thus, the information provided by,TU Electric concerning-the enforcement action was' incomplete and apparently. ' inaccurate. Further, the-inspector believes that other information provided by TU~ Electric during the enforcement conference was misleading and misrepresented the a deficiencias encountered during the SWS coating removal project. i NRC Regulation-10 CFR Part 50.9 requires the applicant / licensee to provide accurate, complete, and significant-information to the NRC. -(l) TU Electric-stated during the enforcement conference that they had "[r]eviewed other code V services activities with satisfactory Results." contrary to the above, the NRC inspector determined-that TU Electric failed to provide significant information concerning the results of their review of six code V service procurements which would have shown that these code V procurements for services were.not satisfactory. These deficiencies are () described in TV Electric memorandum NE 22156 dated September 30, 1988. That memorandum indicated that there were deficiencies in the six code V servics procurements. These deficiencies were similar to the Code V procurement for service water system piping coating removal. Further, this information was not provided to the NRC in the meeting on September 13, 1988, in TU Electric Engineering Report ER-ME-19, Revision 0, or in the TU Electric Enforcement Conference Document handout.
[ j o 20, ) 8 d r. The deficiencies documented'in Memorandum NE-22156 were:- 1 Except.for two purchase orders for vendor. L services (661-74340 and 661-74038), the j procurement documents did not clearly define the. i relationship between the organizations involved-and the TU Electric QA Program. None.of'the procurements1(requicitions'or purchase orders) addressed the identification and disposition of nonconforming conditions. Verification Plans (engineering and QC inspection points) for each requisition lacked' detail. H Work on the component cooling water heat-exchangers should have fallen under the auspices of ASME Section XI. Work on the steam generators was performed before the purchase order was approved. The procurement documents in general were of similar quality to those associated with Service L Water coating removal, b (2) TU Electric's response to FA 88-310 (TXX-89070 dated February 9, 1989), stated in part that "six previous Code V services.procurements were identified. i review of the associated inspection and surveillance reports showed that the requisitioned work was successfully completed and documented." Contrary to the above, the NRC' inspector interviewed the TU Electric representative who coordinated the response to these deficiencies. The NRC inspector questioned the apparent contridiction between the response (TXX-89070) and the internal memorandum (NE-22156). TU Electric responded that the inspection and surveillance reports showed that the \\. work was successfully completed and documented. When J asked if QA records were reviewed, the TU Electric representative responded that they had not. Subsequently, during a meeting on May 1, 1989, TU Electric pointed out that procurement documents and some work orders had been reviewed, while reviewing project files.
. l: t 9 TU Electric.had.not performed an adequ. ate review of-the other Code V service procurements to support the conclusions they presented. In addition, during the course of the review of this material, the inspector identified additional deficiencies associated with the subject procurement, as described in more detail in paragraphs 5 and 7. (3) TU Electric stated during the enforcement conference, in part, that "[dlamage did not occur following modifications to spinblaster." Contrary to the above, the NRC determined that damage occurred during coating removal of Train B after modifications were made to the spinblaster after damage was found in Train A of the SWS in July 1988. In March 1989, three NRC inspectors performed a field inspection to view video tapes of Train B after coating removal. Defects caused by the spinblaster were observed in Train B (Spool SW-1-SB-7-14A-8 frame 1484). Although the video' tapes of Train A and Train B had been misidentified during the video review, blasting marks on the Train B piping were confirmed by the inspectors. The TU Electric coating specialist was present when the NRC viewed Train B tapes and the NRC pointed to the marks that were apparently made by the spinblaster. Wnen directly asked if they appeared to be spinblaster marks, he agreed that they appeared to be spinblaster marks. The three items described above are apparent violations of 10 CFR Part 50.9 (445/8923-V-01; 446/8923-V-01). 5. Review of Comoonent Coolina Water Heat Exchancer Work (50073, 50075) During NRC Inspection Report 50-445/89-16; 50-446/89-16, the NRC inspector performed a follow-up inspection to verify the described'in TXX-89070. corrective actions taken for code V service procuraments, Records at the procurement vault, construction QA records vault, and the QA Records Center were reviewed. The QA Records Center personnel provided the NRC inspector with a computer run which listed all QA records available for the component cooling water (CCW) heat exchangers. for work on the CCW heat exchangers.)(one of the previous six code V pro Records for CP1-CCAHHX-02 were selected for review. About March the NRC inspector met with TU Electric to discuss the results29, 1989, of the NRC review. TU Electric was informed that the available \\
c ) 10 records were insufficient to demonstrate that-the work activities were properly controlled, conducted, and documented j as stated in TXX-89070 and TU Memorandum NE-22156., TU Electric was provided specific questions regarding how the criteria of 10 CFR 50, Appendix B, were implemented. TU_ Electric was asked to provide additional records to demonstrate implementation of the criteria necessary to control work. TU Electric was unable to locate or produce additional QA records before the exit meeting on April 4, 1989, and the inspection was not completed. During this inspection period, the NRC inspector completed the inspection discussed in the previous paragraph. TU Electric- -never provided answers to the questions concerning which 7 criteria were applicable for each procurement and how they complied with those criteria. _As a result, the NRC ins performed a comprehensive review to obtain the answers.pector i During March and April 1989, procurement documents, work procedures, inspection reports, QA contractor surveillance reports, startup work authorizations, work orders, correspondence, and miscellaneous records were reviewed to evaluate how work was done,_ inspected, and documented by TU Electric to'show that the QA program was implemented in accordance with 10'CFR.50, Appendix B, QA requirements. The NRC inspector found that the QA program was not adequately implemented for four Code V procurements for vendor services for work on the Unit-1 and 2 CCW heat exchangers. Multiple examples of inadequacies-and program deficiencies similar to those identified for SWS coating removal were identified. The NRC met with TU Electric on April 28, 1989, and provided the findings similar to those that were provided in March 1989; that is, the QA program was not adequately implemented. On May 1, 1989, TU Electric requested another meeting during which they concluded that the program for procured services was adequate and was appropriately implemented except for the specification issues and the contract for steam generators which was marked nonsafety. However, the NRC inspector identified deficiencies in these activities, as follows: Chemical Cleanino of CCW Heat Exchancers a. In 1985, serious corrosion problems were identified inside the CCW heat exchangers (Problem Report 85-302). Several actions were taken to correct these problems and one action in the process involved chemical cleaning Requisitions 6R-282724 and 6R-340403 were process.ed and respective Purchase Orders 661-74038 and 661-74340 were issued to Haliburton Industrial Services Division (HISD).
- m
'O e 11 1 Procurement The NRC inspector identified the following deficiencies j with the code V-procurement for chemical cleaning the CCW heat exchangers: -(1) contracts did not reference or - discuss-the fact-that vendors'would be required to comply A with TU Electric's QA program which implements 10 CFR, . Appendix:B,=-QA Program, and 10 CFR Part 21, defect i reporting. requirements; (2) the requisitions and contracts f did-not address the trair.ing of. vendor personnel (who must help implement TU Electric's QA programs since-the vendor P 'has no Appendix B QA and 10 CFR Part 21 program);- (3) technical and QA requirements were not explicitly defined; (4) activities concerning ASME components were not done under the auspices of ASME XI; (5) verification and inspection plans-lacked specific requirements as they generally stated: "QA shall monitor the vendor's work", and (6) vendor work plans and procedures were inadequate. Project Plan and Procedures The Ndt inspector reviewed the plan and procedure that were used for chemical cleaning and found that the same plan and procedure were used for both purchase orders referenced above for work performed in February and May 1987. Project Plan for Chemical Cleaning CCW HX CP1, CP2-CCAHHX-01 and -02, Revision 0, did not adequately describe the QA and technical requirements needed to control the process. The plan failed to: Describe the purpose of fiberoptic inspections, Describe the criteria for determining when the metal surface was clean and corrosion products were removed, and Describe the criteria for and the hydrolating/ flex lining operation. After the chemical cleaning was completed in February 1987 such criteria were discussed in TU Electric Maintenance 4 y Engineering Evaluation (MEE) No. 88-003 dated January 13, 1988, but were not factored into the plan before the second job. The evaluation state'3 that the comparison of fiberoptic videos of tubes before and after flex lancing { would be compared with a second video recorded after consistently low copper concentration was reached during chemical cleaning. It further stated, "A comparison of the before and after videos would be the final determination of adequate tube cleanliness." These actions were not accomplished.
i ~.. 12 Heat Exchangers," Revision 2, was inadequate in Jollowing respects. The chemical cleaning (vendor) procedurs did not contain information such as a reference section, purpose, sco instruction,pe, responsibility, definition, or records. procedures for cleaning the diesel fuel / lube oil (See TU E piping for an example of a good procedure.) The vendor procedure does not describe or reference the ASTM standard which governed chemical testing to assure proper chemical concentration. The vender procedure does not describe how the blended solution was to be mixed. ( i-The vender procedure does not describe the mixing of nitrogen gas with the foam solution. Also, there was no description of how much heat should be added at step 2 prior to adding the nitrogen (which iL 1 referenced in Note 1). i Step 6 of the vendor procedure did not describe where samples were to be taken nor how to ensure a representative sample. Step 8 requires an inspection of the CCWHX tubes to determine the degree of scale removal, but does not specify the method or any specific criteria. p Step 9 should read: steps 7-9. " repeat steps 5-9" instead of t t Step 10 states, in part, "that once inspection L reveals the desired degree of scale removal," but L gives no description of the desired surface condition L or criteria for inspecting. This step did not incorporate the criteria described in Maintenance Engineering Evaluation (MEE) 88-003. Step 11 does not specify the quality of the water. Step 13 does not describe specific mixing instructions for the soda ash and sodium tolyotriazole (500 ppm). The procedure did not describe the Haliburton data such as type of operation, timeoperator's log nor a chemical concentration, and pressure., temperature, There were no
~ 1 13 Haliburton signatures on the data forms to authenticate the data, only the TU Electric Project Manager signed Haliburton's log. However, the project manager did not perform the steps or operations and was not always present to verify each 1 1 aspect of the operation. The vendor procedure (Attachment 1 to Work order CP7-2347) had no TU Electric approval on it. The vender procedure did not address the calibration of the gauges and other measuring devices used for l process control. Pressure and temperature were at least two parameters which should have required naasuring equipment and calibration. TU Electric memorandum TCP-87027 described this deficiency after the first job, but no nonconformance report or corrective action request was evident. y Note: The project manager's log for the second job indicated,that TU Electric took measurements, but there is no record of these measurements. It was also indicated that the project manager was issued calibrated measuring and test devices that did not work. In discussions with the project manager, it was determined that the vendor's equipment had gauges i that were not under an approved calibration program (Appenaix B requirement). Finally, the tegperature as geasured by the project manager was 117 l F versus 122 F as measured by site chemistry. No deficiency report was issued to document and evaluate this deficiency. The procedure did not address acid spills. The procedure did not address passivation after cleaning. i supoort procedures - The NRC inspector found that a number of other work activities were required to support the chemical cleaning process. Specifically, three work L activities were an integral part of the cleaning process: (1) fiberoptic examination, (2) flex lancin hydrolazing, and (3) addy current testing. g or Procedures to control these activities were not referenced in the chemical cleaning procedure. Work order C870000585 contained a revision to require Hydro Nuclear Company to flexlance the tube side of the heat exchanger, not to exceed 10,000 lbs pressure. Since no procedure was found, it is not clear if quality was sufficiently involved to verify and document this work!. 1 --- --------------- - ~~ ~ ~~~ ~ ~
e 14 other TU Electric activities concerned the fiberoptic exandnation and hydrolating performed by Hydro Nuclear. It is unclear if the flex 1&ncing and hydrolating was the same operation. Finally, eddy current testing was performed, but was not discussed in the Project Plan or cleaning procedures. Documented evidence of controls for j these activities were not provided to the NRC. ] Control of Work Activities - The subject purchase orders resulted in the chemical cleaning of Unit 1 and 2 CCW heat exchangers. The first work occurred in February 1987 i under Purchase Order 661 74340. During the first cleaning job in February 1987, the vendor experienced a number of i problems as described in TU Electric office Memorandum TCP-87027: nonuniform distribution of. chemical J cleaner (which prolonged the cleaning process), flow rate considerably below estimated flow rate of 24 gym, quality of chemical foam inconsistent; gas flow meter was not calibrated for expected flow rater long interruptions occurred while foaming; nottles were not the correct type for most effective cleaning; nozzles plugged up several times; defoamer equipment was inadequate to deliver the I chemicals and caused interruptions; and the vendor had insufficient manpower for the task causing TU Electric to supplement the vendor's work force. The memorandum concluded by recommending a penalty for poor performance. This memorandum appears to be in contrast to TU Electric contractor surveillance Report CSR-87-002 which concludes t that contractor performance was satisfactory (except when the vender removed a red danger tag without authorization). + Although the chemical cleaning job for Unit 1 and 2 CCWHXS, Train B, (performed in May 1987) was better than Unit 1 and 2 CCWHXs, Train t., the NRC inspector determined that no deficiency /nonconformance report or corrective action request was generated to identify, evaluate, l disposition, and correct the following deficiencies. Also, the causes of these deficiencies were not identified. The process problems discussed in Memorandum TCP-8702'l and surveillance summary 87-022 were not documented in deficiency reports and evaluated to determine if the requirements were adequate. The QA and technical requirements were identical for both reguisitions and purchase orders. Considering the problems discussed in the memo and summary 87-022 chemical cleaning of CCWHXs, it should have been evident that the requirements were either inadequate or the vendor was not meeting the requirements.
15 The chemical cleaning process deficiencies documented in Memo TCP-87027 were nonuniform distribution of chemical cleaner, inadequately measured flow rate, chemical mixing inconsistency, process interruptions, inadequate equipment, and inadequate manpower, were not documented as deficiencies and formally evaluated to assure correction before the award of the second contract for chemically cleaning CCWRXs for Train B and before work was completed on the second chemical cleaning job. TU Electric memorandum TIM-870301 estimated a loss of 0.01 mils of metal surface except for areas where activo pits were and the loss there was estimated to be 0.2 mils of metal. Since the CCW heat exchanger is an ASME, Class 3 component, the deficiencies in memorandum TCP-87027 should have been formally documented, evaluated, and dispositioned to assure the process did not result ir. excessive metal attack, especially in active pits. After the chemical cleaning was completed (per the procedure), two hours worth of chemicals were left over. Rather than waste these chemicals, one hour of additional cleaning was added to each heat exchanger. This action was taken without obtaining authorisation to change the process procedure. NOTE: On May 1, 1989, TU Electric stated that the process was not continued on the basis of chemicals left over, but acknowledged the log stated that. The NRC inspector is of the opinion that additional chemical use should have been based on inspection criteria to determine if the surface was cleaned. A projects summary (Theimer 6-18-87) listed ten comments / recommendations based on the second chemical cleaning job in May 1987. These comments are further indication that the chemical cleaning and support procedures were not well developed to achieve an integrated approach which would assure the work was properly controlled. The main comments discussed deficiencies in these areast. (1) organisational . interfaces, (2) acceptance criteria to avoid jg unnecessary attack, (3) chemical and point indication, (4) sample not taken from main tank supply, (5) PH sampling locations, (6) passivation, and (7) timely chemical analysis. The objective and acceptance criteria were not described in the vendor procedure, but this memo stated, "The acceptance criteria (sic) is a visibly clean heat exchanger tube surface without unnecessary base metal attack." This criteria should have been established in February 1987. One important comment on a support activity 4
~ s 16 concerned TU Electric cualyses of chemicals and corrosion product (for copper) versus the vendor's analyses. The comment suggested a time lag had occurred betwesn the vendor's analyses and TU Electric's chemical analyses. Also, it recommended agreement of + 20% between values. This suggested a large difference had occurred and after the fact corralation was made. Since these analyses control the rate of attack and aler.g with visual i inspection, indicate the process and point, this should have been documented as a deficiency. OA surveillance and Inspection - The NRC inspector reviewed QA surveillance Reports CSR-87-002 dated March 2, 1987, and backup files for the first chemical cleaning of the CCWHXs. The checklist for CSR-87-002 included 11 attributes, 4 of which were marked not applicable. The i I NRC inspector determined that: Item 1 checklist characteristic was marked satisfactory and required verification of contractor prepared procedures reviewed and approved by appropriate "TUGC0" personnel prior to use. No signatures for review and approval were on the procedure. Rather, the surv=111ance report stated that approval was accomplished by attaching the i chemical cleaning procedure to the Plant Operation l organization's work order. l Item 2 checklist characteristic was marked satisfactory and it required the verification that contractor prepared procedures for special process were qualified in accordance with industry standards while Item 5 addressed contractor personnel performing special processes. This characteristic and finding for Item 2 is contradicted by Item 5. That is, Item 5 was marked not applicable. As both address special processes, they are either both L applicable or not applicable. Item 3 checklist characteristic was marked satisfactory and required verification that contractor personnel performed in accordance with procedures. This finding does not reflect and is in opposition to process deficiencies that were identified in TU Electric Memorandum TCP-87027. Since the procedure was not properly reviewed, l approved, and contained shortcomings, the finding for this characteristic was of questionable value. Item 4 checklist characteristic was marked satisfactory. The comment indicated the vendor
I 17 i completed documentation as specified in the purchase i order. This finding is contradictory as no such documentation requirement was in the purchase order. (see TU Electric Memo NE 22156). / 1 Item 7 checklist characteristic was marked not i applicable. The checklist characteristic required ~ TU Electric to verify that safety-related material suppliwd met CPSES requirements and material 1 certifications. The vendor furnished chemicals which should have been checked er verified when received. The surveillance could have verified that appropriate chemical grade materials were received before use. ) TU Electric Procedure EC 6.11 requires engineering, ) i construction, and QA to certify that all contractor supplied material, and/or special tools be received by the TU Electric QA warehouse and accepted by QA. There was no reference to the " Contractor Work Release Authorization Form" which is required by EC 6.11. Item 9 checklist characteristic was marked not applicable. Item 9 required the verification of L contractor supplied measuring and test equipment. The comment on this item stated that, ". .. our chemical dept. provided cal, equip. This statement shows thnt equipment furnished by l TU Electric should have been verificd as a part of the surveillance because TU Electric assumed all QA responsibility. indicated that vendor furnished eIn addition, the project manager which helped control the process.quipment had gauges The surveillance should have addressed the calibrat, ion or lack thereof. Item 10 checklist characteristic was marked satisfactory. Item 10 stated: " Chemistry provide periodic oversight of process & take samples to test for Fe & citric acid concentration." This was followed by a comment " incorrect requirement. checked for copper & nickel " The procedure 1 misstated which test should have been performed. g satisfactory finding was contradicted by the negative The finding. Item 11 checklist characteristic was marked satisfactory. In this case an attribute was added to verify that passivation was done after cleaning and before the domineralized water flush. As this chemical passivation operation was not in the procedure, the source of the characteristic is not clear. If no procedure was established, this se
l i i 18 i \\ characteristic should have been marked unsatisfactory and a deficiency written because it was not an approved step in the procedure. The NRO inspector also reviewed surveillance Activities l Summary (SAS) 87-022 which was referenced by CRS-87-002. The NRC inspector did not find the surveillance Activity Summary in the QA records. It was furnished in a personal file and was not signed by the Quality Surveillance supervisor. and appeared to contradict the surveillance report.This sunna The summary indicated that the overall chemical cleaning process was not appropriately controlled as analyses of copper concentrations indicated an unstable condition, verbal agreements allowed acceptance because of cost considerations, discrepancies between times (that chemical foam was stopped) were recorded by project manager and 3 Haliburton data sheets, no chemical analysis during approximately two hours of continued cleaning, samples were not taken and analyzed, pH values for annoniated solutions were not adjusted for temperature sample location was improper, and large differences, between TU Electric and the vendor's chemical analyses results. This surveillance summary concluded that only two of five findings were deficiencies and reports were written. The NRC believes the three remaining findings should have been documented as deficiencies. 87-022 stated that the chemical cleaning process isFinally, surveillance defined as a special process in paragraph 5.2.18 of ANSI N18.7 while CRS-87-002 stated it was not a special process. The summary of 87-022 stated that inconsistent in-process controls coupled with " cost-effective" decisions in Train B cleaning activities may have a detrimental effect on the heat exchangers at a later time. There is no evidence that the potentially detrimental effcet discussed in this report was ever formally + addressed in a deficiency report. The NRC 7 co e 3 vi nt seco d cleaning operation by Haliburton. c c this surveillance was about the same as CSR ality of f Based on the available documentation that was reviewed, the NRC inspector believes the QA surveillances were not completely adequate. In addition, all deficiencies identified in surveillance activity summary SAS 87-022 were not documented in a deficiency report to assure evaluation, disposition, and corrective action. The NRC inspector reviewed the records and files, but found no inspection reports for chemical cleaning. Work
4 19 \\ order C870000585 indicated that QC would be involved, but no inspection report was required. The work order stated that QC shall provide personnel and equipment to perform fiberoptic examination, but no inspection report was 1 required. b. Cuttino Heat Exchancer Tutt Ends i A Code V procurement for this service resulted in issuing Requisition R-49642 dated August 18, 1986, and Purchase Order CPF-13593-5. The purchase order was issued to Perflex Services. This work was a prerequisite to recoating of the heat exchanger. The work involved cutting 5720 tube ends to lie flush with the tubesheet, grinding rough surfaces, preparing ends for coating and t removing brass plugs. Such preparation was necessary te obtain a quality coating to protect the surface from i corrosion. Procurement - The NRC inspector reviewed the procurement files and found that the Code V procurement deficiencies described in TU Electric Memorandum NE 22156 generally applied to this procurement. Proiect Plan and Procedures - The NRC inspector determined that the work activity (cutt!,ng heat exchanger tube ends) was not part of a project plan such as STA-TP-87-3 which described a plan for cleaning the CCW heat exchanger. No individual project plan was found. Perflex Services Procedure CPF 13593-S, Revision 2, dated l September 4, 1986, was approved by Stone and Webster Engineering Corporation who was project manager for this L job. The procedure submitted by Perflex was a one page procedure which did not: Describe how the vendor's personnel would interface l with various organisations such as SWEC Brown and l Root, Inc., TU Electric Construction, an,d Operations. L Describe the inspection to be performed by Perflex Services personnel and or the personnel qualifications. l Describe criteria for rough grinding tubes after being cut or specify a surface finish or generally state that burrs, rough edges, and other defects be removed. Describe the steps to meet DCA 25192, Revision 0, which required that sharp outside corners be 1/8-inch radius (minimum) and inside corners be welded (ASME ~
i 1 i \\ 20 i Section III, Division ND) to build up to this radius, i Revision 4 of the DCA specified the radius i requirement, but this should have been addressed in the subject pr sharp corners.ocedure unless the cutting caused no l NOTER Interviews with the project manager did not t clear up this matter and no answer was provided specific to whether welding occurred or not. However, the QC inspector stated that welding did not occur. In,gnaction of Work Activities Inspection of the tube cuts and removal was. documented in TU Electric Inspection Report 86-0289. CCWHX tubes were inspected for one CCWHX.However, only 25 The purchase but Form THE-PR-3.2 indicated two CCWHXs. order stated It appears that the balance of the tubes, about 5670, were not inspected or were inspected by Perflex Services (who had no QA/QC program responsibilities in the contract). Such inspections should have been made by inspectors certified to ANSI N45.2.6. It appears that the inspection characteristic of 0.030 inchea maximum protrusion was no verified by direct measurement with a go or no-go gauge.t The vendor's procedure did not indicate how in-process work was monitored and no in-process inspection procedure was evident. No documentation was provided by the applicant to verify the inspection for minimum radius of i 1/8-inch per DCA 25192, Revision 4. l DA Surveillance - The NRC inspector reviewed 1 Surveillance CSR-86-004. The checklist was the same as l others reviewed and it appears to be a generic checklist. Similar to previous surveiAlances, a large number (half) l of the characteristics were marked not applicable. The summary of this surveillance-was not com vendor regarding the lack of discipline,plimentary to the experience. tools, and Apolication of Eooxy Coatino to CCW Heat Exchancer c. Requisition 48370 dated July 10, 1986, and Purchase Order CPF-13597-S dated August 26, 1986, were issued to Specialties Engineering Corporation (SPECO). procurement - The NRC inspector determined that the general comments in TU Electric Memorandum HE-22156 applied to this procurament. l t ..... ~
21 Project Plan and Procedures - The NRC inspector reviewed the plan and procedures. These were more detailed and technically comprehensive than other vendor plans and procedures. Work procedures (Attachment A, B, C, D, and E to SPECO letter FR-48370) described surface preparation, coating of channels, heads, tube sheets, and tube ends.. l However, these procedures were not dated and no signatures for review and approval were on the procedures. one procedure required the applicator to visually inspect the coated area where spark testing was not possible, a practice that is generally not acceptable because an individual should not final inspect his own work. There is no indication that the TU Electric inspector inspected areas where a spark test was not possible.
- Also, Specialties Engineering Bulletins dated December 14, 1978, for repairs were not described in the procedure and were not in the onsite records.
Inspection and Test - The NRC inspector reviewed TU Electric Inspection Report 86-0289 and determined that: The inspection of the coating only addressed the l inspection of the final dry film thickness. such a final inspection would not assure that the epoxy was ~ i applied as required by Attachment B, " Coating Application Procedures for Channels Heads." Attachment B procedure required three coat applications and thickness was supposed to be controlled during each application. After after the figal (third) coat it was to be cured l forlghoursat70Fambienttemperatureor24 hours at 60 F ambient. Inspections of these characteristics, if performed, were not documented on the inspection report. No characteristic was included in the inspection report for repairs for SPECO Bulletin 35. The procedure (Attachment B) required measurements using a Bacharach Sling psycrometer and a Pacific Transducer Company surface thermometer. No TU Electric inspection showed that the vendor's equipment was calibrated. The inspection report had no characteristics to require inspection of the surface preparation or procedures (Attachments A and E). OA surveillance - The NRC inspector reviewed Contractor i surveillance Report SR-86-007 and the attached checklist.
\\ 1 22 The checklist contained 12 characteristics to be verified. The generic checklist had been modified to add characteristics to verify surface preparation, spark test, and 6 inches of tubes coated. All three were marked satisfactory. The basis of the satisfactory was a reference to Inspection Report IR-86-0289 and the inspection of surface preparation. However, the inspection of the surface was not in inspection report IR-86-0289. Three characteristics on the checklist, including calibration, were marked not applicable. This decision appears questionable considering vender personnel were inspecting with equipment that may or may not have been in the site calibration program. The surveillance was I insufficient to fill the inspection gaps described in the paragraph above. 6. Repair of Diesel Generators Heat Exchancers (50073. 50075) The NRC inspector learned that diesel generator jacket water heat exchangers were examined. Corrosion was found and Design Change Authorization (DCA) 21981, Revision 6, required repair, corrosion removal, and recoating. This involved removing the + existing rubber liner, inspecting surfaces to be coated with Belzona ceramic s-metal, welding to build up corroded areas l (ASME III work), sandblasting in preparation for coating L application, and coating application.- The NRC inspector evaluated selected areas where the above work was done. The surveillances, quality of the procurement, inspection, QA E and corrective action concerning Requisition 6R-345080 and Purchase Order CPF-14220-S to s Haliburton for the above work were similar to SWS and CCW work activities. The NRC determined that similar deficiencies existed with respect to the QA program implementation as l described above in paragraph 5 above. One exception was the procedures developed by TV Electric startup. They were a good example of how other procedures should have been developed and implemented to assure proper controls for work activities. 7. Vendor Services to Measure Steam Generator Nozzles (50073. 50075) l Procurement - The NRC inspector reviewed requisition 6R-356251 l dated July 15, 1988. The requisition does not make clear whether this was a safety or nonsafety-related activity. Including the SWS requisition, three of seven code V requisitions evidenced such confusion. Had TU Electric QA adequately audited the code V procurements, this trend may have been identified and the problems associated with these procurements could have been identified and corrected. There
o t i 23 i is no indication that adequate audits of the Code V procurements were ever performed. A purchase order (661-74054) dated January 16, 1987, was issued to Nuclear Services, Inc. Sixteen nozzles on eight steam generators were to be measured and visually inspected to determine each nozzle diameter and radius, height of flange ring to nozzle and location of the 3/4 - 10 UNC tapped holes. This was necessary in order for TU Electric to procure nottle dams to be used inside steam generators to temporarily isolate the steam generator primary channel head from the refueling pool and permit refueling and testing or repair of the steam generators to occur simultaneously. In July 1988, requisition 356251 was issued to purchase the nottle dams from Nuclear Energy Services. The requisition was marked Code N which meant that no 10 CFR 50, Appendix B, QA program or 10 CFR 21 requirements were applied. Code N was incorrect because the activity was safety related. Inspection - The work on steam generators was in progress l before QA was aware that Nuclear Energy services was on site. Since this was a code V procurement for services, TU Electric l was required to provide the QA program and assume 10 CFR ( Part 21 responsibility for the vendor. As previously discussed, QA was required to certify that material and tools were received and personnel were trained prior to work (required by EC 6.11). This was not done. By chance, the QA organization discovered the work was in progress and decided to verify access control, surveillance CSR-87-003. No checklist was attached to the surveillance. TU Electric wrote a deficiency report (P87-0135) because the work was completed January 14, 1987, but the contract was not completed and dated until January 16, 1987, and maintenance engineering and QA did not receive it until January 19, 1987. The surveillance concluded that QA did not know about special requirements until after the fact. The NRC inspector found that TU Electric Me=crandum HE-22156 concluded that this was " acceptable" because hardware was not changed. The basis for this conclusion is not evident. The NRC inspector determined that the procedure for measuring and inspecting the nozzles was comprehensive; however, the procedure was not reviewed and approved to incorporate it into the TU Electric document control system and bring it under their QA program. Section 3 of Attachment 1, " Steam Generator i Nozzle Measurement Procedure," stated that Nuclear Energy services would furnish profile gauges and thread gauges to verify location and condition. The procedure did not state that this equipment would be under the TU Electric calibration There was nc QC verification of the calibration of program. this equipment. ,..__.-_m.
i 1 24 The NRC inspector determined that on December 1987 design modification request (87-1-237C) was issued to drill an dans when needed. Measurements and inspections to implement these proposed modifications and inspections were safety related. 8. Aoplication/ Removal of Coatinos from Diesel Generator Tanks (51053) NRC inspectors met with TU Electric in September 1988 and pointed out the similarity between deficiencies in the diesel generator fuel oil tank coating removal and service water system coating removal. be similar because the procurement code was different.TO Electric d documented belowsinspector believes the same lack of QA/QC controls ex 'The NRC t L o Initial coating requirements for the diesel fuel oil a. storage tanks were defined in the tank specification (2323-MS67A); documentation of the coatingthis document did not require inspectio design change authorization (process. In May 1979, a 2 DCA 4665) was issued implementing the provisions of Specification 2323-AS-31 which included requirements for safety-related.. procedures, inspection, and documentation for protective coating work. In January 1983, the project recognized that the required documentation was lost and an NCR (C-83-00223) was generated. It was dispositioned "use-as-is" on the basis l-failure could be offset by alternate means of filling t day tanks. In August of 1983, blistering of the coating was noted in one of the tanks and an NCR (C-83-021615) was written and dispositioned "use-as-is" on the basis of insufficient blistering to warrant repair. In mid-1985, the safety-related coatings Specification (2323-AS-31) was reclassified to "Non-Safety Related". In 1986, during the cleaning of the Unit 2 diesel fuel oil storage tanks in preparation for startup testing, a band of rust spots approximately two (2) feet in width was observed in the Train A tank. DCA 4665 classified the coatings work as a safety-related activity, but the declassification of the Specification (2323-AS-31) removed the technical basis for implementing a repair of the safety-related coatings. versus non-safety for coatings and similar activitiesThis distinctio requires resolution by TU Electric prior to initiating repairs on the Unit 2 tank and investigation of the Unit 1 tank coatings. l TU Electric letter (TXX-6461) concluded
== r 4-v7 w m www ww,-#r- ~+- r-w y--,ve-----e-- t k--weg
i { 1 25 i that the coating was not safety-related and the walls were thick enough to withstand corrosion for the 40 year design
- life, b.
The NRC inspector reviewed the background of the issues and records for the above activities and determined the followingt Similar to the service water coating, Gibbs and Hill 1 failed to recognise that the procurement / application of coating is safety-related even though the coating ) may be nonsafety related. failed and the tanks were attacked by corrosion.The coating subs The initial corrective action (DCA-4665 dated 1979) attempted to correct the QA program deficiency by t changing the specification (2323-AS-31) to require i' such controls. However, this action was reversed in mid-1985 by reclassification to nonsafety-related. 4 This reversal was incorrect because it did not recognire the adverse effects the uncontrolled work activity could have on the safety-related fuel oil tanks.- 1 On September 4, 1986, TU Electric reported in a 10 CFR 50.55(e) report that the fuel oil tanks that were coated without QA/DC controls were acceptable l and the first reclassification to safety-related was incorrect. l Therefore, no QA/QC controls were needed. It was also concluded that since it was unlikely that fuel lines would become clogged with coating (if it failed), this item was not reportable. The final response (TXX-6461) dated May 22, 1987, failed to assure corrective action as follows: (1) Failed to consider the fact that activities affecting the quality of components must be controlled even though the purpose of the i coating is considered nonsafety related. I (2) Failed to address the fact that the coating material was not known for sure, but assumed it was AMERCOAT 395. (3) [ Failed to address the loss of the documentation of the type of coating and how it was applied. TU Electrib failed to address the similarity between diesel generator and service water coating damage in the Enforcement Conference Document. Both involved the lack of QA/QC controls for coating procurement application, coating degradation, and corrosion of I
- 3 26 components.
The NRC had pointed.out the similarity before the Enforcement conference. I The removal of the coating from ASME tanks should have come under ASME XI for Unit 1 tanks. There was no indication that ASME XI was considered. I The NRC inspector found that TU Electric failed to take c. s adequate corrective action as follows: i (1) The specification does not specifically address the controls of activities affecting the quality of the fuel oil tanks. (2) TU Electric did riot address why the documentation was lost. (3) TV Electric did not specifically address the lack of ASME XI involvement. j The above work on the diesel fuel oil tanks was not a service procured under code V, but the work was performed on site by a contractor. However, the similarity existed i between work on the service water system and work previously done on the component cooling water, diesel generators, and steam generators, that is, the question about whether the procurement and application of coating were safety-related. Other similarities were that work was not done under ASME XI auspices, and documentation was l not readily retrievable. l 9. Exit Meetina (30703) An exit meeting was conducted May 2, 1989, with the applicant's representatives identified in paragraph 1 of this report. No written material was provided to the applicant by the inspectors during this reporting period. The applicant did not identify as proprietary any of the materials provided to or l reviewed by the inspectors during this inspection. During this meeting, the NRC inspectors summarized the scope and findings i of the inspection. l 1
l IllSPECTION PLAN FOR COMANCHE PEAK OPERATIONAL READIN ASSESSMENT (ORAT) INSPECTION 4 1. C'bjective This inspection is ;eing performed in accordance with draft Inspection Proce-dure IP 93606 " Operational Readiness Assessawnt Team Inspections," which is included as Attachment 1. The objective of this inspection is to provide a 1 major input and basis for a NRC determin6 tion of the startup readiness of the Comanche Feak Steam Electric Station (CPSES). 1 Operational readiness assess-ocnts are required before issuance of the low-power license, and before issuance of the full power license or during power escalation. The major focus well before fuel loading and initial criticality.of the inspection will b control construction completion, procedural use and work assignments shouldIn have been phased out or merged with operational control programs. tion will also em The inspec. action programs; phastae the effectiveness of management oversight, corrective root cause analysis, and the readiness to support operations. At the conclusien of the inspection we will provide a recomendation on whether the applicant can safely proceed to fuel loading and low power testing.
- 11. _ Background The Comanche Peak Steam Electric Station (CPSES) Units 1 and 2 are owned by Texas Utilities Electric Company (TV Electric, a subsidiary of Texas Utilities Company (TUCo), Texas Municipal Power Agency ()TMPA), and Tex-La Elec Cooperative of Texas, Inc. (Tex-La). TMPA is in the process of transferring their ownership interest to TU Electric and Tex La is transferring their ownership to TU Electric in the near future.
tric, which has been cesignated Agent for CPSES bThe lead applicant is TU Elec-facility is a standard 1160 MW Westinghouse four y the owner-appitcants. The loop pressurized water reactor with a steel lined, reinforced concrete containment. The units are locateo in Glen Rose, Texas, approximately 40 southwest of Fort Worth, Texas. The applicant received a Construction Permit in December 1974 and had essen-tially cospleted construction and preoperational testing and turned the systems over to operational control in 1984. The original architect-engineer was Gibbs i and Hill; however, they were replaced by Stone and Webster after 1985. Ebasco and Impe11 have also provided engineering support since 1985. In 1982 numerous adverse allegations were received, most of which concerned construction adequacy and quality assurance. These issues have been subsequently referred j to as the *Walsh Doyle* issues. In 1983 an NRC Construction Appraisal Team confirmed these allegations and the ASLB determined that TU Electric was not in t accordance with Appendix B of 10 CFR 50. TheOfficeofNuclearReactorRegulation(NRR)assem6ledaTechnicalReview Team (TRT)onsitein1984. The TRT included 50 technical experts from the NRC, national laboratories, and consulting organizations. The TRT spent four months investigating the allegatioris and documented their findings in five SupplementalsufetyEvaluationReports(SERs). In addition, nueerous concerns about the design and construction of the plant evolved through contentions before the NRC s Atomic Safety Licensing Board (ASLB) and the Comanche Peak Indepencent Assessment Program review conducted by Cygna Energy Services. 3
4 In response to the concerns, the applicant implemented the Comanche Peak Response Team (CPRT) in 1984 to address a11 relevant issues, existing and future. This program involved a re-verification of the design and re inspection of the construction of selected engineering disciplines. ther design review was initiated. In 1985 fied TU Electric developed the Corrective Action Program (CAP) in 19 require a complete design re verification; hardware validation, including hardware re-inspection and modifications; and design and "as-built" reconcilia-tion in a broad number of areas. The development and implemantation of the CAP i for desi n and construction deficiencies typifies the aggressive and thorough 5 approach that TU Electric management has applied to safety issues This attitude is regularly demonstrated by TV Electric managers, severa. i former NRC employees, but not always by the working staff. l of whom are In 1987 the NRC Office of Special Projects hensive,and timely resolution of complex regu(OSP) was formed to ensure compre. latory concerns with a strength-ened and integrated staff organization and direct lines of management responsibility and authority and appropriate high-level direction. was incorporated into the Office of Nuclear Reactor Regulation (NRR) in Janu This Office 1909 as the Associate Directorship of Special Projects and retains responsibility for all Itcensing and inspection activities, i l There has only been one recent escalated enforcement case completed. February 1989, the staff cited TU Electric with a Level III Violation for In failure to submit a timely application for extension of the Unit 1 construction permit. The applicant had inadvertently allowed the original permit to expire. There have been slightly over 1000 allegations received by the staff concern Comanche Peak. All of the alle been closed. Of the remaining,gations received prior to formation of OSP have approximately 13 remain open. in Jul (i.e.,y 1988, TU Electric reached an agreement with the remaining intervenor 9 Citizens Associated for Sound Energy) and the ASLB hearings were dismissed. As a result, Ms. Juanita Ellis, became a member of the Opera Review Committee and TU Electric compensated CASE for previous expenses.tions August 1988, a new group, the Citizens for Fair Utility Regulation (CFUR), and In an individual, Mr. Joseph Macktal, are attempting to gain status as intervenors. The extensive corrective action effort to correct the numerous design and construction deficiencies has been underway at CPSES over the past several This program has resulted in a significant number of modifications to years. bring the plants into conformance with NRC requirements. In March 1988 the applicant temporarily suspended work on Unit 2 to concentrate resources,on Unit I completion. The applicant is currently nearing completion of the } corrective actions and has committed to re perform greater than 90 percent of the preoperational tests as the Prestart Test Program. (HFT) and integrated leak rate testing on Unit 1 was completed in July (Unit 1 H previously underwent NFT in 1985). The appitcant has comitted to begin a two-week o following completion of construction and testing.perational readiness period The project status report time" on October 2,1989. currently shows a fuel load readiness date and the beg The applicant is running about two-weeks behind 2
i i curing the second week of our inspection. schedule; therefore, the ea 111. Inspection Plan A. Objectives The inspection has three major objectives: 1 (1) Indepencently assess the Comanche Peak Steam Electric Station (CPSES) power ascension, operations, and operations support prograsenatic and i staffing readiness for operations. (2) Monitor daily activities in the areas of operations, testing, maintenance, t engineering and technical support, and quality assurance in order to assess whether the applicant is ready to operate the facility safely. (3) Evaluate the status of the prestart testing program to determine whether testing has been essentially completed.and that outstanding construction deficiencies will not adversely affect the safe operation of the plant. B._ Scope ~The emphasize of the inspection will be an independent assessment of the effectiveress of management oversight, corrective action programs, root cause analysis, and the readiness to support operations. that the applicant has established an appropriate operating attitude wellThe inspect before fuel loading, t In order to focus the inspection effort we will limit our detailed review of safety related activities, system alignm,ents, material condition, surveillance testing, and operational procedures to the following systems: 41 High Pressure Injection. (2 Decay Heat Removal. Auxiliary Feedwater. Diesel Generators. Station Batteries. This inspection plan has been developed to address the applicant's operational readiness in the six functional areas. of the areas is provided in Appendix A. A detailed evaluation criteria for each Any suggested changes should be provided to the team leader. The functional areas are: ll ) Surveillance and Testi Plant Operations. \\ q /) ng. J l Facility Management Organization. ( ))p Power Ascension Test Program (PATP). ( Maintenance. ( Engineering and Technical Support. C. _ Team Members In order to accomplish this inspection sections -- operations and operational, support.the team will be divided into two The operations section will 3
i J i focus on operations department activities and control room observations and operations support section will focus on the system walkdowns and the opera the tional readiness and support of the remaining departments. Continuous control of the first week onsite). room coverage is anticipated for at least 72-hours (Tue i perform walkdowns of the selectec systems during the same time Sunday (October 22) the entire team will reconvene to setermine the direction On of the remainder of the inspection. The team membert are listed below. 1 Chris A. VanDenburgh - Team Leader - NRR - (301) 492-0965 Dwight D. Chamberlain - Asst. Team Leader - Region IV - (817) 860-8249 s e' W s Operations Section Jay R. Ball - Discipline Lead - NRR - (301) 492-0962 Jackie E. Bess - Region;IV/STP-SRI - (512) 972-2507Si"in 0, ;; Men i { Larry R. Veeder - Prisuta-Beckman Associates, Inc. - 412) 872 9157 Robert L. Lewis - Prisuta-Beckman Associates, Inc. - ((412) 872-9157 BruceW. Deist-ConsultingServices-(301)972-1973 i i _ Operations Support Section Thomas 0.McKernon-DisciplineLead-RegionIV/DRS-(817)860-8153 Donald C. Kosloff - Region !!!/ Davis Besse - (419) 898-2765 Donald A. Beckman - Prisuta-Beckman Associates, Inc. - (412) 872-915a7 Gary G. Rhoads - Prisuta-Beckman Associates, Inc. - (412) 872-9157 Paul E. Harmon - Region II/Sequoyah-RI - (615) 842 8001 D. Team Assignments i The inspection report is required to be issued within 45 days of the end of the inspection. following topics for development and documentation.To simplify the devel These assignments have been made based on sty understanding of each inspector's experience and back-ground and I have attempted to evenly distribute the workload. If an tional topics are identified (either before or during the inspection)y addi-I will make the required changes. These assignments are not final and any questions or suggestions should be identified as soon as possible. An inspection report outline will be provided during the inspection which will be similar to the topics identified in Appendix A. L Operations l Operations Support Ball Shift Professionalism McKernon - Facility Management Procedure Adherance Outstanding Construction Deficiencies Harmon - Post Trip Review Process Kosloff - Power Ascention Program Shift Consnunications Surveillance and Testing Shift Routine / Turnovers HTE Control i i 4
Bess - Operability Determinations Beckman - Maintenance l Response to Annunciators i Off normal Conditions Housekeeping Room and Area Turnovers 5tation Vital Drawings Veeder - Equipment Out-of-Service Rhoads - Engineering & Tech. Support System Status Control & Logs j-LCO Tracking 50.59 Safety Reviews Technical Specifications Lewis - Operating Procedures Johnson - Self-Assessment Program Abnormal Procedures s Event Reporting System Valve Lineups Lessons Learned Programs Deist - Organization & Staffing Staff Stability and Experience Operator Training Attachments 2 and 3 contain background informatios on the facility provided l NRR's Special Project's Division and current organization chart. which will be the model for our inspection report.I have included in addition 50-446/89 30)the inspection report for the Augmented Inspection Team (50 problems with Borg-Warner check valves at Counche Peak.and resultan identified several weaknesses with the operation of the facility.This inspection These concerns were communicated to the applicant and are included as Attachment 4 50-446/89-58 and 50-445/89-43; 50-446/89 43)And finally, I have in concerning the implementation of the emergency plan which identified several problems concerning the knowlege level of the operators. I will be forwarding system descriptions and selected plant procedures after I complete the pre-inspection visit during the first week of October. In the meantime please familiarize yourself with information provided and communicate any sugge,stions for organizing our task directly to me. I V. Inspection Schedule I A. Inspection Preparation Sept. 25 Receive ORAT inspection planner. Oct. 2 Provide comments to team leader by COB. Oct. 10 Receive pre inspection review material. I B. Inspection Oct. 35 Arrival at motel. Oct.16(8:00am) Arrive onsite at Comanche Peak - Badging, entrance and site orientation. Oct. 17-25 Perform system walkdowns, monitor control room activities, review procedures, and conduct interviews. 5
Oct.26(1:00pm) Conduct NRC management briefing and practice applicant exit. Oct.27(8:00am) Conduct exit. C. Inspection Report Preparation Oct.30(8:00am) Arrive at NRC White F1 tnt Offices. Oct. 30 - Nov. 3 1 Entire team complete and approve draft inspection report. Nov. 6 Submit draft inspection report to technical editurs. Nov. 14 Submit draft inspection report to Section Chief. Nov. 21 Submit draft inspection report to Branch Chief. Nov. 29 Submit draft inspection report to Division Director. Dec. 6 Submit approved inspection report to Projects Division. Dec. II Issue ins meeting. pection report 45 days from inspection exit V. Travel Itinerar.y i Reservations for fourteen single rooms at the government rate have been made in Directions to the CPSES are incluced as Attachment 5.my name at the Pleasecall(817) 573-8846 I plan to arrive at the motel on October 10 at approximately 6:00 The entire team will meet on October 16 at 7:00 am in the hotel lobby.pm.I anticipate departing the site on October 27 at approximately noon, therefore your departure reservations should be made accordingly. WewillbeginworkontheinspectionreportontheMonday(October 30) follow-ing the conclusion of the inspection. The entire team will participate in this effort. Please plan on beginning work at the NRC White Flint offices at 6:00 am on October 30. hovember 3 and the inspection report will be issued within 45 days o conclusion of the inspection. Reservations for ten single rooms at the government rate have been made for October 29 - Noves6er 10 under a group reservation (i.e. NRC Group. Van 0enburgh)attheGuestQuartersInnlocatedat7335WIsconsinAvenue, Bethuda, MD, 20814 The motel is within one block of the Bethesda station of I the Metro Red Line. Pleasecall4E4-2900or(301)961-6400 by October 16 to individually confirm and guarantee your reservation. travel itinerary for both trips, including rental cars plans, before COBPlease inform October 10. VI. _ Inspection Routine Normal working hours will be 8:00 AM to 5:00 PM while onsite, including the first Saturday (October 4). All NRC employees should arrange to suspend their 6
Overtime will be approved on a case basis by the team leader. c l Tecm meetings will be held daily at 8:00 ani. All team member's observations will be provided on Appendix 6 in sufficient detail to support their observa-tions anc ccnclusions. following the team meeting.The team leader will meet with the applicant daily observations developed from the previous day's Appendix B forms discussed. The inspection will be effectively over by noon on October 26. team efforts will be devoted to pre All further { the exit meeting with the licensee. paring for the NRC ennagement briefing and The inspection report number is $0-445/89200. NRC personnel should charge their time to the following: Docket Number Inspection Report Number 50-445 89200 InspectionProcedure(IP) 93806 Inspection Procedure Elememt Item of Major Interest (IM1) (IPE) OA 10H1 please contact me at (301) 492-0965 for confirmation of assignments. upon receipt of your review materials and Chris A. VanDenburgh. Team Leader Special Inspection Branch Division of Reactor Inspection and Safeguards Office of Nuclear Reactor Regulation i Attachments: i; )) Comanche Peak Background Information Draft inspection Procedure IP 93806 h Comanche Peak Organizational Chart NRC Concerns Regarding Operations Response to Check Valve Failures Maps to CPSES 7
APPENDIX A OPERATIONAL READINESS A$$ES$ MENT EVALUATION CRI plant Operations Operations organization and staffing Staff stability and_ morale Operating shift professionalismOperations experience and training (including Methods for operability determination Post-trip review Lessons learned (process rootcause) programs Performance of safety evaluations Event reporting Response to annunciators and off-normal conditions . Nuisance alars and indication controls shift routine and turnover Equipment cut-of-service controls System status control and logs Operating and em#sency operating procedures i Procedure adherence Verification of syst6 line ups (including use of local valve position indications) Housekeeping and material control Comunications with other departments Surveill,ance and Testing L Organization and staffing Qualifications and training Interface between operations and startu Completionofprestart(preeperational)ptestingorganizations testing Observations of surveillance performance Technical Specification technical adequacy Technical Specification surveillance LCO tracking and control i Performance of 10 CFR 50.59 safety reviews 1 l Calibration of installed and portable measuring and test equipment i 4 Surveillance procedure review Surveillance training of operators k nagement and quality assurance overview Facility Management Organization Organization and staffing Qualifications and training Management oversight activ< ties and goals ' Applicant's operatiunal readiness assessments (internal and external) Onsite safety review conunittee Les' sons learned from previous new plant operating experience Root cause and corrective action programs A-1 4
- <n 6
.k Power Ascer.sion Test Procram (PATP) FATP organization'and staffing Qualifications and training Approval for plateau changes Quality assurance controls for PATP $taffing prerequisites for testing Program change controls Test status and scheduling 1 Maintenance j Maintenance organization and staffing Qualifications and training Construction deficiency " punch-list" items Maintenance work observation. l Material condition and labeling of systems and components Predictive amintenance programs Post-maintenance testing Work planning and prioritization Parts and material control Engineering and__ Technical Support Engineering organization and staffing Qualifications and training System engineering Vendor manual control Review of generic corsnunications Nodification controls Configuration controls Temporary modifications i e A-2
APPENDIX 8 Subject : t Observation & : Revision : i 4 References : I i i 1 Mcussion: 1 i i r Significance: I Required Ae' tions : B-1
i p b I i t t 6 1 1 ATTACHMENT NO. 1 6 f ( l i b 4 ) i 4 4 ) t ? r Y k t 4
. ~. _ _.. _ _ 3 I POEB INSPECTION PROCEDURE 93806 OPERATIONAL READINESS ASSESSMENT TEAN INSPECTIONS PROGRAM APPLICABILITY: 2514 t 9380E-01 INSPECTION OBJECTIVE The objective of this procedurt, is to provide guidance on conducting Operational Readiness Assessment Team (ORAT) -inspections for new plants. Results from these inspections will provide a major input and basis for a NRC determination of startup readiness. 93806-02 INSPECT!0flREOUIREMENTS 02.01 _ Inspection Plannino. Conduct of Operational Readiness Assessments is full-power license, or during power escalation.requirec before issuanc The inspection schedule and scope are to be tailored to the individual plant circumstances. The plant operations which have not yet been sufficiently reviewed pro ides an outline of the areas that may be covered during assessment of the reaciness for power operation, t 02.02 Plant inspection. The following specific items, in addition to those listed in Attachment 1 should be considered during ORAT inspections: Focus the inspection on safety-significant activities such as fuel a. I loading, reactor startup, heatup/cooldown, and surveillances. Direct observations of activities are preferred and should be supplemented by personnel interviews and document reviews. Systems should be selected for walkdown and inspection on the basis of their potentici to cause challenges to safety systems. (The results of similar unit design or generic probabilistic risk assessment studies should be used, if available. ) b. Evaluate licensee management transitional controls. Construction deficiency " punch" list items transferred to the operations organization for completion are either subject to contractor disposition or are converted to maintenance work order items. These items constitute incomplete construction phase work fnr which management controls are required to ensure readiness for operation. 1-Issue Date: XX/XX/XX-
u Evaluate management oversight of and involvement in daily work and . preparation activities. Review licensee perfomance in conducting preventive maintenance activities and controls over deferred preventive maintenance. L Review the licensee's program for operating experience feedback and c. i verify implementation. implement lessons learned and that research the safety, sig problems that have developed during the startup of similarly designed l plants. Select and review in detail, several operational problems experienced by the licensee,during the preoperational or startup test phase and assess whether the problem was fully reviewed and understood i prior to further testing. NUREG-1275 and applied lessons learned. Determine if the licensee has revie Evaluate whether procedural problems related to operations are being effectively identified arr! expeditiously corrected. d. Examine the licenste's self-assessment capability as it relates to readiness for operatic t, including the root cause analysis process, the corrective action program, and the trending and generic applica-t bility review of self-identified problems. the deficiency reporting system, including thresholds, and evaluateDete i the effectiveness of prioritiration of the identified problems. Review the root cause analysis training program. Assess the involvement of OA and engineering in problem resolution, e. Determine whether operator training, including simulator usage includes beginning of-life core characteristics and system response., Through operator interviews, control room obsersations, and the review of alam response procedures, determine whether shift personnel are prepared to respond to abnormal plant conditions, instrumentation and control setpoint and display anomalies, and the potential for a high number of challenges to safety systems during testing, f. Evaluate whether there is any change in the Que11ty Assurance (OA) program effectiveness due to the differences in the QA organizational interactions with other station departments under operational controls versus what existed when under construction controls. Verify whether program requirements exist for quality arsurance/ quality control (QA/0C) adeouacy. personnel to be present during back shifts, and assess Detemine whether the licensee has implemented an effective Technical g. Specification Appraisal process. Verify that plant procedures accurately reflect the applicable Technical Specification sections. Verify the adequacy of administrative controls to complement startup testing activities under Technical Specification constraints, as opposed to the latitude for " troubleshooting" problems that exist under preoperational testing controls. h. Detemine whether the licensee has implemented an effective program to review and focus attention on balance-of-plant (80P) operations to reduce the frequency and severity of plant transients. Issue Date: XX/XX/XX -t-93806
i X 1.
- Evaluate the adequacy of licensee plans to resolve material and
- personnel access and work control ' problems once the radiclogic controlled areas (RCAs) and protected / vital areas are established, j.
Evaluate the status of control room ~ annunciators alams, and recorders. compensatory measures for those indicatirsns not o k. Evaluate the licensee's program to review and evaluat' the maintenance work e the impact of request backlog on operational readiness, including the collective impact.on safety system availability and operability. Determine if safety-related work is being accom by means other than the written administrative-controls (e.g.,plished tickets").. " shop 1. Review the qualifications and comercial operating experience of key 'i managers and operators and whether organizational responsibilities and interfaces exist to support an operating unit. Determine whether the licensee has staffed the organization to levels which are capable of g successfully operating and supporting the-unit. l' E m. Review the startup test bg schedule and status of completion to ensure report (FSAR) is, or will be, actually performed.that the start If tests are de-leted or modified. ensure that an adequate 10 CFR 50.59 review was i perfonned tnd forwarded to NRC for review. l t n. Review Technical Specification action statements.the method for keeping t L from Ensure that the operators implications.are aware of all action statements in effect and their cumulative i; t Twenty-four-hour inspection coverage of shift operations is necessary at various times during the startup sequence. Such coverage provided during. initial criticality and Other periods of startup testing byis routinely regional / resident personnel Chapter _2514 inspection program.in the conduct of the NRC Inspection Manual L such bt.nefits against the requirement for additional inspection resourc conduct around-the-clock shift coverage.
- 02.03 Menagement Meetings.
Frequent NRC management meetings with licensees are recomended before and after the ORAT in m etion effectiveness of the Operational Reaniness Review ;rocess. to maximize the first few months of initial comercial operation, the NRC should review withThroughout the plant management and staff the root causes of all reportable events and L planned licensee corrective actions at such periodic meetings. L The ORAT exit meeting should emphasize the continuing nature of the NRC readiness review process. 93806-03 INSPECTION GUIDANCE 03.01 General Guidance. Previous NRC evaluations and Office for Analysis and Evaluation of Operational Data (AEOD) studies have shown that effective . management of the transition from construction to operations and of the feedback of operating experience from other plants (and similar plants) can L 93806 Issue Date: XX/XX/XX
L F significantly enhance early performance. This inspection procedure provides . general guidance on = the - scope, content, relevent to the conduct of ORAT inspections. problem areas, and verifications - ORAT inspections will emphasite the effectiveness of managempnt. oversight, corrective action programs, root cause analysis, and the readiness to support operations. The following major points should be assessed: the establish-ment of a basic framework of management programs to support the operation of the unit;.the establishment and implementation of a program to gather and apply lessons learned from industry experience; the ability of the management. team to establish a proper working atmosphere in which-to operate the unit; the involvement of both site and corporate engineering in the operation of the unit; and the depth of QA involvement in plant operations and problems. For new plants it is essential that the licenste identify lessons learned from previous new plant operating experience and communicate these lessons to the senior management of the new plant. New plants that have come.on line have shown significant improvement after establishing effective root cause i analysis and corrective action programs. Effective station goals and actions that result from self-assessment demonstrate the readiness of the plant for plant's safe operation. safe operation and the readiness of its personnel for the con L 1 I 1 However, one comon element supports all Operational Readiness Reviews, including ORAT verification activities, and that is the fundamental need for the establishment of an app ~ropriate operating attitude well before initial criticality, programs that control construction completion should be phased out or merged with operational control programs in order to minimite the confusion associated with duplicate systems of controlling work. The same is i lso true for procedural use and personnel work assignments. a Operational controls should be implemented as early as possible to allow for personnel acclimation and training. It is also important that such operational controls, particularly in the . areas of maintenance and modifications, be consistent with both the original bases of the plant design and the good work practices used during plant construction. The plenning for this inspection is an important element. Selection of the inspection team is a very important function during the planning phase, Operating experience of team members should be a primary consideration for t selection, especially for the control room observations. The use of resident inspectors from similar sites and experienced regional / Nuclear Reactor Regulation inspectors should be emphasized. The inclusion of a licensing examiner may also be. beneficial in evaluating operational readiness. Consideration should also be given to including a team member with expertise in management and organizational theory and/or human factors engineering, if applicable to the inspection scope. on the scope and duration of the inspection.The size of the team will very depending 03.02 Specific Guidance a. Inspection Requirement 02.01. The scheduling of the ORAT inspection shall be based upon the previous licensee experience and operating history as may be applied to the specific plant. An inspection of the first nuclear unit for a utility may require more lead time before the Issue Date: XX/XX/XX 4 g3806
e,c e c
- projected fuel load date than is needed for inspections of subsequen nuclest units.
The timing of the inspection must be well coordinated with other NRC and third party inspection activities,- such as: } (1) Inspection Procedure 94300 status report requirements. ] (2) Issuance of the proof and review copy of the Technical Specifications. (3) Regional Office conduct of' a team inspection for a Technical Specification Review in accordance with Inspection Procedure-71301. (4). Conduct of the INPO Preoperational hsistance visit at the site. t (5) cf the resulting report (s). Conduct of utility self-assessment ac = Prior licensing and plant restart experience indicates that ORAT of the initial license. inspections can be optimally conducted about 3 m In the case of full-power operation for a new
- plant, another evaluation should be conducted 3 to 6 months afte receipt of the full-power license to observe actual operational activities.
The areas of review should also be based c: of the licensee. ' For example, the inspectice the previous experience in a three. unit station will diff plan for the third unit plan for the station's first unit, er consitai ?bly from the inspection b. Inspection Requirement 02.02. of the o For newly' licensed plants, the status Program (perational preparedness phase of the Preoperational Testing NRC Inspection Manual Chapter 2513 Appendix B) should be problems have been identifiedreviewed to determine which inspections in the areas previously inspected. The NRC Inspection Manual Chapter 2513 Program inspection ' Procedures that are incomplete or that resulted in identification of problems can be utilized to develop areas for review during the operational readiness team inspection. inspection areas, as listed in the NRC Inspection Manual Ch Appendix B: (1) Operations (2) Maintenance (3) Fuel Receipt and Storage ) (4) Fire Protection (5) Surveillance (6) Plant Water Chemistry Controls (7) Radiological Controls 93806 Issue Date: XX/XX/XX
t (C) Security and Safeguards-(g) Quality Assurance - The operations phase inspection program (NRC Inspection Manual Ch 2515) also contains-inspection procedures that can be used to devel_ areas for further review of operational readiness. i inspection functional areas that they support: represent curre t 2 (1) Plant Operations t 42700 Plant Procedures 64704 Fire Protection / Prevention Program 71707 Operational Safety Verification 71710 ESF System Walkdown-1 (?) Maintenance / Surveillance 61700 Surveillance Procedures and Records q 61726 Monthly Surveillance Observation 61725 Surveillance Testing and Calibration Control Program 62700 Maintenance Program implementation 62702-Maintenance Program 62703 Monthly Maintenance Observations 62704 Instrufrent Maintenance 62705 Electrical Maintenance (3) Engineering and Technical Support 37700 Design Design Changes, and Modifications 37701 Facility Modifications -72701 Modification Testing (4) Safety Assessment /Ouality Verification 35701 OA Program - Annual Review 40500 . Evaluation of Licensee Self-Assessment Capability $2720 Corrective Action (5) Security 81XXX Physical Security (81000 series procedures) 81018 Security Plan and Implementing Procedures e-81020 Management Effectiveness - Security Programs y 8107X Access Control (81070 series procedures) 81088 Consunications (6) Emergency Preparedness 82701 Operational Status of the Emergency Preparedness Program .lssue Date: XX/XX/XX 93806
ej (7)' Radi_ation Controls 83750 Occupational Exposure. Shipping, and Transporta tior. B4750 Radioactive Waste Systems; Water Chemistry; l Confime-tory Measurements and Radiological Environmental Monitoring L c. Inspection Reoutrement 02.03.- The scope of the ORAT inspection must i be flexible enough to accommodate both the unique ~ plant design and L the plant inspection histor including systematic assessment of licensee perfomance- ($ ALP). y, steam supply system (NSSS Thus, departures from standard nuclear may provide areas for spe)cific review at a new plant.. designs a L. reviewed _ for planning input and to identify area i. t not be completed before criticality is achieved. Also the results of to understand past problem areas, but alpast NRC team inspection i of licensee corrective action programs. so to review the effectiveness The licensee's responsiveness the licensee's progress toward developing a proper o l and ensuring a hi power operations,gh degree of readiness for conducting criticality and o Just as the scope of any Operational Readiness Review must be r flexible, so must the ORAT inspection be adaptable to changes in direction and emphasis. to. identify any generic problems or concerns that may exist i different inspection. areas, but also to redirect inspection resources away from areas in which no problems are evident. Identification of acceptable areas should be made to allow the inspectors the latitude and time to thoroughly investigate the causes of identified L problems. to the necessary chanThe ORAT inspection should be flexibly structured to ada t the use of perfomanceges in direction and scope that occur through' based inspection techniques. 93806-04 RESOURCE ESTIMATE This inspection is estimated to require 560 direct inspection hours of regional and headquarters resources. Actual inspectio a specific plant may require substantially more or fewer resources,ns at inspection scope. depending on the 93806-05 REFERENCES NUREG-1275. ' Operating Experience Feedback Report - New Plants.* July 1987 NUREG/CR-5153. ' Performance-Based Inspections." June 1988 NRC Inspection Manual Chapters 2513 and 2515 Memorandum, J. Sniezek to Regional Administrators, dated April 23, (NUDOCS 68863/046). 1007 END 93806' Issue Date: XX/XX/XX
i um a imm i, - 4 : Attachment'l CPERATIONAL READINESS REVIEWS 1. Plant Operatiens A. System Status Control and Logs B. Organization and Staffing C. Shift Routine and Turnover. D. Training-E. Response to annunciators and Off-normal Conditions F. _ Housekeeping and Material Condition G. Control Room Decorum H. Reportability Requirements and Implementation I. Communications with Interfacing Departments J. Fitness for Duty Program K. Overtime Controls L. Procedure Adequacy / Adherence Maintenance / Surveillance [ A. Maintenance Management and Organization B. Observation of Work Activities C. Temporary Modifications D. Preventive Maintenance Program E. Failure Trending and Predictive Maintenance ~ F. Post-Maintenance Testing G. Work Planning and Prioritization Processes H. Training 1. Comunications with Interfacing Departments J. Rework identification and Control K. Implementation of T5 Surveillance Requirements L. Observation of Surveillance Activities M. Procedure Adequacy / Adherence - III. Engineering and Technical Support A. Nodification Controls B. Support to Operations and Maintenance C. Configuration Controls D. Interface with ALARA Program E. Licensing Activities and Technical Specifications Management p 1Y. Safety Assessment / Quality Verification A. Management Oversight Activities and Goals B. Self-Assessment Capabilities (PORC, 50RC, 15EG) C. Quality Assurance /Ouality Control Involvement D. Corrective Action Programs E. Post-Trip Review Process F. Operating Experience Feedback G. Independent Verification Policies H. Licensee Readiness Assessment - 93806 Al-1 1ssue Date: XX/XX/XX = - _ _ _ _ _ _ - - - - - - ~ - - ~ - ' ~ ~ ~
i 4Y. Radiation Protecticn A. Health Physics Organization and Staffing B. Radiological Controls C. Effluent /Kaste Controls D. ALARA E. Materials and Contamination Control F. Surveys and Monitoring G. Respiratory Protection F. Training VI. -Security A. Drganization and St&ffing B. Security Plan implementation C. Access Controls D. Alam Response-E. Communications . F. Training V12. Emergency Preparedness A. Emergency Plan.and Implementing Procedures B. Energency F6cilities, Equipment, Instrumentation, and Supplies C. Organization and Management Control D. Training E. Independent Reviews / Audit i Issue Date: XX/XX/XX Al-2, 93806 1..
?y pp, e .:vn, 3 -e_, y J Y 7 1o - )
- 4
) r :ty . -1 ,3 ,f _4 -4 {, . [. - 6. b O E e -ATTACHMENT NO. 2 4-h ~ r v 9 s .'y .t 8 ,I r .c ? ~Y k 5r 3 Y. h i Pw f.. }..
- N cA r
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.? . hMJ p. BACKGROUND INFORMATION ON [0MANCHE PEAK STEAM ELECTRIC STATION (CPSES) l'tility: Texas Utilities Electric Company (97.8% Ownership) (TV Electric / Applicant or Applicants) Location: ) 40 miles SW of Ft. Worth. Texas-Somervell County, Texas Unit 1 Unit 2 Docket No.: 50-445 CP Issued: 12/19/74 50-446 Low Power License: Est. 10/89 12/19/74 Full Power License: Ee% - nt Not Scheduled Initial Criticality: E+ in/e/sq Elec. Energ. 1st Gener: Commercial Operation: Reactor Type: PWR Containment Type: Steel-lined. Same Same Power Levet: reinforced concrete 3411 MWT; 1159 MWE Same Architect / Engineer: Original - Gibbs & Hill Same Current - Reverification and redesign effort by Stone and Webster. Ebasco, NSSS Vender: and Impell Constructor: Westin9 house Some Brown & Root Turbine Supplier: Allis-Chalmers Same i Condenser Cooling Method: Circulating Water System Same-Same Condenser Cooling Water: Squaw Creek Reservoir Same -Licensing Project Manager: (see Projects group below) 1 NRC Responsible Office: Associate Director for Soecial Pro.iects. H0 [ Dennis M. Crutchfield. Associate Director (492-0722) i Comanche Peak Pro.1ect Division. OSP Christopher Grimes, Director (492-3299) n.::::p n e, :;e.;,, :: = e- '/. ?? - !!W, - CPPD Projects: Assistant Director for Pro.iects James Wilson. Assistant Director (492-3306) Melinda Malloy. LPM (492-0738) Mel Fields, LPM (492-0765) r Auwb $ p
w '. ~ . Comanche-Peak Steam Electric Station: ' e CPPD Technical Review: Assistant Director for-Technical Procrams' James Lyons Assistant Director s (492-3305) CPPD Inspections: Assistant Director for Inssection procrams Robert Warnick, Assistant 11 rector (817) 897-1500 CP Site Section Chiefs: Herbert Livermore 817 897-1500 Joel Wiebe 817 897-1500-Senior Resident Inspectors: Sh;rn;; "t:111;^ (0;,;;;.;;1a.) (017) ;^7 1,;^ I'db;;e=J --h " 7-f; (Operations) .(817)897-1500 6 Resident Inspectors: Michael Runyan (C/S) (817) 897-1500 St939nSitter{0g) {817]897-1500 s,,,.,,..... w, Robert Latta (Elec)(817J897-1500 Recion IV. Arlincton TX: Responsib.le for Operator Licensing Activities, Emergency Planr.ing Activities, and Radiation Safety and Safeguards Inspections Robert Martin, Regional Administrator (8-728-8225) 1 l John Montgomery, Deputy Regional Administrator (8-728-8226) !Y , Director Division of Reactor Safety (8-728-8183) A. Bill Beach, Director Division of Radiation Safety and Safeguards (8-728-8248) William Fisher Chief I Nuclear Materials Safety Branch (8-728-8215) Blaine Murray, Chief Reactor Programs Branch (8-728-8126) I Donald Driskill, Director (. Office of Investigations Field Office W (8-728-8110) i ~
Comanche Peak Steam Electric Station'.x 70 Electric Corporate Menacement Personnel (D$11as.- Texas) Jerry S. Farrington, Chaiman of The Board and Chief Executive, Texas Utilities Co. c Erle A. Nye, President. Texas Utilities Co.. 1 [ and Chaiman:and Chief Executive, Texas. Utilities Electric Company William G. Counsil, Vice Chaiman TU Electric L Michael D. Spence President TU Electric Generating Division TU Electric Corporate Management Personne1'(Site) L l' William J. Cahill -Executive Vice President, Nuclear t l. H. D. (Buz) Bruner, Senior Vice President Nuclear Engineering and Operations J -\\ r R. A. Werner, Manager. Safeteam 'TU Electric Management Personnel - Operations (Site) A. B. Scott, Jr., Vice President Nucitar Operations i J. J. Kelley, Jr., Plant Manager J. V. Donahue, Operations B. W. Wieland, Maintenance I G. J. Laughlin, Instrumentation and Controls M. R. Blevins, Plant Support M. J. Riggs, Plant Evaluation I J. S. McMahon, Training T. L. Gosdin, Administrative Services B. T. Lancaster, Plant Services R. Daly, Startup L D. L. Davis, Results Engineering S. L. Ellis, Test D. W. Stonestreet Outage Planning l
- l
_-__ Comanche Peak Steam Electric Station s.- ~ ) Menacement Personnel -'CPSES Nuclear Engineerino/EncineerinQ Construction - wanes n-site) m L. D. Nace, Vice President \\ J. W. Beck, Vice President, Nuclear Engineering-k J. 8. George Vice President,. Support -L. R._D.' Walker, Manager ~ Nuclear Licensing 4 J. F. Streeter, Director Quality Assurance 1 A. Husain Director li Reactor Engineering L
- 0. W. Lowe, Director-Engineering T. G. Tyler,' Director Projects D. M. Reynetson, Director Construction
- 4 W. R. Deatherage, Director Engineering Administration J. W. Muffett, Manager of Engineering (CECO)
J. E. Krechting, Director Technical Interface f Workforce As of April 8.1989: Ornanization Onsite. Total Eng. & Eng. Admin. 2351 2508 Construction 3694 3694 g Projects 604 619 Operations 1686 1700 Nuclear Engineering 739 841 Support Services 275 277 NE0 Administration 26 45 TOTAL 9375 9664
Comanche Peak Steam Electric Station. Reactor Operators SR0s Operating 19 R0s Operating 24 Staff 24 Staff 1 -Total 7 Total 7 IS SR0s and 10 R0s are required to operate Unit 1 Work Shifts 6 Shift Manning Cycle 3 shifts working 1 shift in training 2 shifts extra and off As reflected in current proposed Technical Specifications each shif t will be comprised of the following staff: For one unit operation: ShiftSupervisor(SRO) 1AssistantShiftSupervisor(SRO) 2 Reactor Operators S Auxiliary Operators Shift Technical Advisor (SR0/STA)- For two unit operation: ShiftSupervisor(SRO) 2 Assistant Shift Supervisors (SRO) 4 Reactor Operators 10 Auxiliary Operators Shif t Technical Advisor (SRO/STA) .9
.a.u.., .-..a..n.. F ~,.E 4 r i l Comanche Peak. Steam Electric Station. 6- 'i i Reactor Operator Exams Administered by the Region 3 Date of. Number of s Exam A>plicants Passed Failed 12/21/88' ' 5 iO 1 1 0 I ~ R0 0 0-0 06/06/88 SRO 7 5 2' i s RO 6 3 3 12/15/87 SRO 0 0 .0 R0 5 3 2. l 07/13/87 SRO-8 7 1 R0-4 4 0 a 09/23/86 SRO 5 3 2 RO 7 6 1 i L 04/01/85 SR0 2 2 0 H0 5 4 1 ~i 09/11/84 SRO 5 4 1 i R0 17 8 9 04/03/64 SRO 12 7 5 10 13 8 5 .r 07/18/83 SRO 29 23 6 s R0 10 3 ~7 Totals ~ 136 - 91-45 Recualification Exams Ad' ministered-by the Recion Date of-Number of Exam Applicants Passed Failed 09/23/06 SR0 14 10 4 R0 7 3 4 04/01/85 SR0 7 4 3 RO 3-2 1 - Totals 31 19 12 Next Examination Scheduled for: July 3-7, 1989 Requalification Exams t l Number of Applicants: SRO 8 RO 4 Total 12
- This was a retake exam including the ' Administrative Topics" and " Control Room
- Systems / Facility Walkthrough" sections of the operating exam.
Comanche' Peak Steam Electric Station + A11ecations-(continued) The staff has received 45 allegations since the femation of OSP. As of May 15, 1989, 10 alle;stions. remain open. All of the allegations have been reviewed by the CPPD Allegation Review Comittee to es-tablish the necessary follow-up action required for closecut. All totaled, approximately 130 allegers have reported concerns about Comanche Peak. Emercene.y Preparedness
- t The staff documented its _ review of Revision 8 (FSAR Amendment 48) to the Emergency Plan in $$ER 6 (11/84).
On the basis of a review of the Applicant's Emergency Plan against the (1) Planning Standards of 10 CFR $0.47(b), (2) requirements of Appendix E to 10 CFR 50, and (3) guidance criteria in NUREG-0654. Revision 1 (11/80), " Criteria'for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants (Regulatory Guide 1.101. Revision 2), the staff concluded that the Emergency Plan for CPSES i Units 1 and 2 provides an adequate planning basis for an acceptable state of emergency preparedness and meets the requirements of Appendix E to 10 CFR 50. The Applicant provided Revision 9 to the Emargency Plan in i FSAR Amendment 58 (6/86) and with Revision 10 (8/88), the Plan was separated from the FSAR and will be maintained as an independent report. i The staff's review of the changes to the Plan was completed in February 1989 and affirmed the staff's prior conclusions on the plan's acceptability. p In addition to the Emergency Plan review, the staff completed an appraisal L _(September 6 through October 7, 1983) of the Applicant's implemented emergency preparedness program (Inspection Reports 50-445/83-33 and 50-446/83-17 dated February 8, 1984). Also, the Applicant's performance was observea during a full-participation exercise (December 12-15,1983) with participation by the applicant, the State of Texas, and Hood and Somervell Counties (Inspection Reports 50-445/83-46 and 50-446/83-21 [ dated January 23,1984). l By memorandum dated November 29, 1984 FEMA provided findings based on L the review of the original and revised offsite Emergency Plans and the results of the December 14, 1983 full-participation exercise. FEMA determined that: offsite radiological emergency plans and preparedness for the Comanche Peak Steam Electric Station have been determined to be adequate. Consequently, there is reasonabis assurance that appropriate measures can be taken offsite to protect the health and safety of the public living in the vicinity of the Comanche Peak Steam Electric Station.
Comanche Peak Steam Electrie Station Plant Simulator The simulator was op m tional in 1985 and is Comanche Peak Plant specific. It is located in the Nuclear Operations Support Facility on. site and the vendor is Singer-Link. Systematic Assessment of Licensee Performance ($ALPF The SALP process was suspended in February 1985, because of the TRT and Region IV special attention. The SALP process was resumed by the NRC for the period September 1, 1987 through August 31, 1988.- The final SALP report (see Attachment 3), Inspection Report 50-445/87-40 and 50-446/87-31, was issued on December 9, 1988. Overall, the recent SALP concluded that, while there have been some deficiencies in the complete implementation of Comanche Peak programs TV Electric has established a solid foundation for excellent performance. Escalated Enforcement Actions On February 28, 1989, the staff cited TU Electric with a Level !!! Violation (EA-88-278) for failure.to submit a timely application for extension of the Unit 1 construction permit. No civil penalty was imposed in consideration of the applicant's extensive corrective action programs, the age of the violation, and overall safety sv;nificar.ce of the violation. Investigation /Allecations Status Of In/estigations O! has issued 14 investigation reports, 29 inquiries and 5 assists to Region IV. Areas include welding, QC, electrical, inspections, intimidation, procedures, management NCRs, coatings, pipe hangers, firings, falsification of records, and construction practices. OSP/CPPD has referred 5 requests for investigation to 01, 01 currently has 1 open investigation. Allegations Slightly over 1,000 allegations have been received by the staff on Comanche Peak. The evaluations of the majority of them (approximately 600) were documented by the NRC's Technical Review Team in SSERs 7-11 in the following areas: civil, protective coatings, mechanical. and QA/QC. electrical / testing,ly Approximate 200 allegations-(received after the SSERs mentioned above were issued, but before September 15,1985) in the areas of electrical, + civil, mechanical, and QA/QC have been evaluated and documented. The QA/QC allegations were closed out in inspection reports, and the electrical, civil, and mechanical allegations ~are addressed in SSERs 14-20. ~From September 15, 1985 until the formation of the Office of Special Projects (OSP) in February 1987, Region IV processed cons-truction and QA/QC-related allegations; 14 allegations were received during this time period. All of the allegations received prior to the formation of OSP have been closed.
j [ p Comanche Peak Steam Electric Station - ~- The staff has reviewed the FEMA findings.and determined that they support l the' staff's recomendation that there is.an adequate state of onsite and offsite emergency planning and preparedness for full-power licensing for the Comanche Peak Steam Electric Station. In a subsequent letter dated July 15, 1985. FEMA transmitted its findings and detemination in accordance with the FEMA rule (44 CFR 350). FEMA detemined that:- the Texas'$ tate and local' plans and preparedness for the Comanche H Peak Steam Electric Station are adequate to protect the health and L safety of the public in that there is reasonable assurance that the-L appropriate protective measures.can be taken offsite in the event L of a radiological emergency. The adequacy of the public alert and notification system has also been verified by FEMA in accordance with the criteria in FEMA rule 44 CFR 350; Appendix 3 of NUREG-0654/ FEMAaREP-1 Rev. 1; and the " Standard Guide for the Evaluation of f Alert and Notification Systems for Nuclear Power Plants" (FEMA-43). Further, consistent with the Comission's Statement of Policy regarding arrangements for offsite emergency medical services, the~ Applicant, by letter dated February 20, 1986, confirmed that the Emergency Plans of the-involved offsite responsa jurisdictions contain e' list of medical service facilities. The existence of such a list in the pertinent plans has also been confirmed by FEMA. Further, the Applicant.has comitted to fully comply with the Comission's final response to the Court's remand. The last full-participation exercise was conducted in November 1984. A full-participation emergency exercise is scheduled for July 25-26, 1989. I-In a letter to FEMA dated March 24, 1989 NRC requested FEMA to (1) provide L its evaluation of the upcoming 1989 full-participation exercise. (2) confirm that any revisions to the State and local the effectiveness of those plans, and-(3) plans since 1984 have not degraded confirm that the emergency plans of the involved emergency. response jurisdictions meet current regulatory re-quirements and guidance. Emergency Response Facilities The Appifcant's Emergency Plan and Emergency Response Facilities (ERFs) provide for a Technical Support Center uTSC) which is separate from the Control Room but' located adjacent to and above it. The TSC has the capability to display and transmit data and' data sumaries describing plant status to the Control Room and the Emergency Operations Facility (E0F). There is space in the TSC for management and technical personnel to perform their functions. The radiological habitability of the TSC is the same as the Control Room and comunications are provided between the Control Room, the Operational Support Center (OSC). the E0F, the NRC and other offsite agencies. The use of semi-portable continuous monitoring instrumentation is available to determine dose rate and radioactivity levels in the TSC. The TSC appears to be capable of supporting reactor control functions. evaluating and diagnosing plant conditions, and serving as the main comunications link between the Control Room, the OSC the EOF. and the 4-NRC. The TSC can carry out the EOF functions until the E0F is staffed. ?
Comanche Peak Steam Electric Station -{ Emerceney Response Facilities (continued) The Comanche Peak OSC is presently located in the Maintenance Buildiag-and provides a place where operations support personnel can assemble and - report in an emergency as well as receive instructions from the operating staff. With Revision 10 to the Plan, the OSC-is being relocated to the Radiation Control Access Office; the Maintenance Building will serve as an alternate OSC. The OSC has comunications with the Control Room, the TSC, and the EOF - The EOF is attached to the Nuclear Operations Support Center which is located within 1.2 miles from the Comanche Peak Steam Electric Station and has a Protection Factor of greater than-15. An alternate EOF is provided in Granbury (10 miles). There is space in the EOF for management and technical personnel to perfom their functions. There are communications links between the EOF and the Control Room, the TSC, the OSC, the-NRC, and other offsite agencies. The EOF appears to be capable of coordinating all the Applicant's onsite and offsite activities for reactor emergency situations. In $$ER 3 (3/83) and 6 (11/84)..the staff concluded that the Applicant's i emergency facilities and equipment are adequate to meet the requirements - of 10 CFR 50.47 and Appendix E to 10 CFR 50 on an interim basis, subject to an onsite post-implementation review. This onsite post-implementation review will also be used to determine the adequacy of the final ERFs in accordance with the requirements and procedures given in Supplement 1 of NUREG-0737.- t Sionificant Licensee Accomplishments The development and implementation of the Corrective Action Program (CAP) for design and construction deficiencies typifies the aggressive and thorough approach that TU Electric management applies to safety issues. TU Electric's comitment to excellence is evident in their improvements 'i l to the security systems and emergency preparedness facilities. This comitment is regularly demonstrated by TU Electric managers, several of whom are fonner NRC employees. but not always by the working staff. Plant' Status Schedule g L In March 1989, the Applicant formally announced that the current schedule forUnit1 fuel-loadingis"threemonthsbehind[our]...mid-1989 schedule" ( which was announced in March 1988. Based on current construction activity ) schedules. TU Electric estimates that Unit I will be ready to load fuel in October 1989. Unit 2 construction was suspended in March 1988. TU Electric estimates that the Unit 2 fuel load date will be approximately two years after Unit 1 fuel load. .: 2 -
.-~ t a " Comanche' Peak Steam Electric Station- ' Plant Status (continued) Hearino' Status Comanche Peak has been a heavily contested proceeding since 1981. ~On July-1,1988 the Applicant, intervenor (Citizens Association for Sound Energy), anc the NRC staff filed a Joint Motion for dismissal of the proceedings based on a Joint Stipulation describing the tems of a settlement agreeiaent under which CASE President, Ms. Juanita Ellis, would become a member of the Operations Review Comittee and TU Electric - would compensate whistlehlowers.: The Joint Motion applied to the admitted contentions in both the OL and Unit I construction permit amendment (CPA) proceedings. -At a special prehearing conference on. July 13, 1988, the ASLB issued a Memorandum and Order dismissing the proceedings.- h On August 11, 1988, the Citizens for Fair Utility Regulation (CFUR) filed, with the ASLB, a Request for Hearing and Petition for Leave to i. Intervene in both the OL and CPA proceedings in place of CASE. That t petition was denied by the Comission in CLI-88-12. Mr. Joseph Macktal. filed a motion on December 30, 1988 requesting the Comission to recon-sider CLI-88-12, and CFUR petitioned the U. S. Court of Appeals for the Fifth Circuit in New Orleans on February 15, 1989 to review the decision. 1' On January 19, 1989 Mr. Macktal filed a motion before the U. S. Court of Appeals for the D. C. Circuit to overturn CLI-88-12, which-the Comission has moved that-the Court dismiss. His December 30.-1988 motion was denied by the Comission on April 20,1989(CLI-89-06). AE00 Analysis of-Operational Data N/A NRR Operatinc Reactor Assessment N/A 1 public issues Except for the safety issues associated with the hearings, public sentiment in the Dallas and Fort Worth area, as reflected in newspaper articles, editorials and television news, is principally concerned with the plant's cost increases and the state's energy balance. Attachmeds \\ j 1. Figures lost e SALP ort (In ion Re 50-44 7-40 a 50-44 87-31 daged Oct 1, 88) S
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% n.- 9 fCPSES/FSAR DRAFT Resumes of the key 70 Electric /CPSES personnel-in the following ,c, -order: te,r;. Barnes DRAF1 ~ Sh ut 0,erations Manager y DRAFT. John W." Beck Vice President. Nuclear Engineering-DRAFT Michael R. 81evins Manager of Nuclear Operations Support DRAFT Dudley M.- Soseaan-Chemistry and Environmental Manager
- DRAFT H. D. Bruner Senior Vice President' t
DRAFT -William J. Cahill. Jr. -Executive Vice President. Nuclear
- DRAFT Richard Daly Jr.
Manager Startup DRAFT Doug L. Davis Manager. Technical: Support DRAFT David E. Deviney Deputy Director.' Quality Assurance = DRAFT- -. Joseph W. Donahue Manager. Operations , DRAFT. ~$tephen L. E111s Perforsance and Test Manager ^ DRAFT Joe B. George Vice President. Support ' DRAFT Phillip E. Halstead Manager. Quality Control DRAFT-Chuck Hogg Chief Engineer . DRAFT Ausaf Husain Director Reactor Engineering-DRAFT James J. Kelley, Jr. Plant Manager DRAFT John E. Krochting' Director. Technical Interface DRAFT Sobby T. Lancaster Manager. Plant Support DRAFT G. Jay Laughlin Instrument and Controls Manager ' DRAFT Dwen-W. Lowe Director of Design Engineering and DRAFT Configuration Control DRAFT David R. Moore Manager. Work Control DRAFT James.W. Muffett Manager of Engineering (CECO) DRAFT Robert J. Prince Assistant Radiation Protection t DRAFT Manager-DRAFT Michael J. Riggs Plant Evaluation Manager DRAFT tric J. Schmitt Radiation Protection Manager DRAFT Austin 8. Scott Vice President. Nuclear Operations DRAFT Peter 8. Stevens Manager of Operations Support DRAFT Engineering Group t 13.1A 1 Draft Version l
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[ '%,,. c [ *1 NUCLEAR REGULATORY COMMISSION 5 %- l useoios. o. c. psss ( (f f October 3, 1989 ...+ MEMORANDUM FOR: All NRC Perso mel Involved In Comanche Peak, Unit 1 Licensing Activities i FROH: Christopher 1. Grimes. Director Comanche Peak Project Division Office of Nuclear Reactor Regulation
SUBJECT:
IDENTIFICATION OF COMANCHE PEAK UNIT 1 ISSUES As Comanche Peak Unit 1 nears completion, it is important that all safety-related i concerns, which could have a bearing on satisfactory completion of construction and preparation for plant operation, be addressed. In order to ensure that all such concerns have been identified, we request that all professional staff who have been involved in the Comanche Peak licensing activities notify us if they know of any concerns that are not being tracked by inspection reports Safety Evaluation Reports, or other public records. In a memorandum to the NRR Branch Chiefs, dated August 29, 1989, ! separately req'sested the status of the technical review activ' ties and identification of 4 those issues evolvin0 from the review of the FSAR that Will not be resolved before licensing. Those issues that will be reflected in a forthcoming SER input and/or associated staff positions need not be repeated for this effort, as long as the Comanche Peak projects staff is aware of the status of those issues. The responses to this request may be made by telephone ffTS 492-3299)orin writing-(Mail Stop 7H-17, OWFN). Your response siould fdentify the specific concerns with sufficient details for follow-up action. Previously closed items need not be identified again, unless there is additional inic a tion or a change in the concern that may have an impact on plant licensing. Your cooperation in this effort will be greatly appreciated. Should you have any questions regarding this s'atter, please contact me or Robert Warnick, AssistantDirectorforInspectionPrograms(817-897-1500). S I Chrkstoph yttu) Director . Grimes, Comanche Peak Project Division Office of Nuclear Reactor Regulation b - cc: T. Murle J. Sniezek D. Crutchfield F. Miraglia J. Partlow J. Richardson A. Thacani E. Rossi B. Grines F. Congel egg Q l G y. Enclosure _3
.m / UNITED STATES [",3.e,< NUCLEAR REGULATORY COMMISSION n W A5HING T oN. D. C. 20566 %, [,' october 10, 1989 l AEMORANDUM FOR: All liRC Staff Invc1ved in Inspection Activities Related to Comanche Feak FROM: Dennis H. Crutchfielo, Associate Director for Special Projects Office of Nuclear Reactor Regulation +
SUBJECT:
NRC STAFF DIFFERING PROFESSIONAL OPINION ON C0tiANCHE PEAK In a memorandum to the Chairman dated Octcber 4,1989, an anonymous group identifying thtmselves as 'KRC Staff Inspectors' asserten that the pending SALP report relateo to TU Electric's perfomance in the preparation cf Unit 1 for plant operation is neither accurate nor complete. The memoranoum is critical of both the SALP Board's fir. dings and the qualifications of the Board members to draw conclusions on TU Electric's performance. In order to assure that all cor.cerns related to TU Electric's perfomance i are clearly understood prior to the issuance of the SALP report. I request L that each of you involved in the inspection activities for Comanche Peak review I the enclosed initial SALP report and submit any comments you may have on the Board's findings within 15 days from the date of this memorandum. In commenting on the encloseo report, you may want to review the procedural requirements ano purpose of the SALP, as cascribed in Manual Chapter 0516. You should also note that the enclosed SALP report is considered to be t 'predecisional* and, as such, this draft should not be released or discussed with unauthorized personnel. Your coprnents should be as specific ts possible and be submitted directly to me. They may be submitted Anonymously if you so desire. Depending on the nature of the comments received, further action may be warranted before the report is issued. Should ycu have any questions regarding this matter, please do not hesitate 4 to contact me at FTS 492-0722. Denni chf e ,A oc ate Director for Special Projects Office of Nuclear Reactor Regulation
\\ .o o Multiple Addressees. i 2-October 10, 1989 i i Enclosure l Initial SALP Report i cc w/o enclosure: T. Nurley
- 0. Snierek
'i J. Particw F. Miragita i C. Grines l c 1 l 1 l } { t ? _..,,,..v.
f 'i puseg# ((b e. < , 9, UN!TED STATES yAN7 ( % NUCLE AR REGULATORY COMMISSION % *N *y/,f usmNotoN. D. c. rosss October 10, 1989 l l i MEMORANDUM FOR: Martin Halsch Acting Director Office of the Inspector General FROM: Christopher 1. Grimes. Director Comanche Peak Project Division
SUBJECT:
NRC STAFF DIFFERING PROFESSIONAL OPINION RELATED TO THE CONDUCT OF THE SALP FOR COMANCHE PEAK In the enclosed memorandum to the Chaiman dated October 4,1989, an anonymous group of *NRC Staff Inspectors" asserts that (a) the Comanche Peak Plant is not i ready for fuel loading and (b) the pending SALP report related to TU Electric's perfomance in the preparation of Unit 1 for plant operation is neither accurate nor complete. The memorandum also implies that NRC inspection reports and other documents have been edited to create an untrue impression of the plant. The i meniorandum is critical of both the SALP Board's findings and the qualifications of the Board members to draw conclusions on 70 Electric's performance. Moreover. the meniorandum specifically states that the NRC managers on the SALP Board deliberately excluded infomation so as to give a false impression of the plant. Accordingly, we are forwarding the memorandum for appropriate action. L As a result of this memorandum, we have issued the draft initial SALP report to all professional staff involved in the inspection activities related to Comanche Peak and re days (copy enclosed) quested their conments on the Board's findings within 15 In addition, we are infoming the Commission of the l actions that will be taken to address the issues raised in this memorandum. We have also enclosed for your infomation, a memorandum dated October 3.1989 i which requests that the NRC staff identify any issues that may have been neglected and say have a bearing on the licensing decision for Comanche Peak Unit 1. I JN Q Christopher I. Grimes. Director Comanche Peak Project Division Office of Nuclear Reactor Regulation
Enclosures:
1. Memo to Chaiman dtd.10/4/89 2. Memo to Comanche Peak Staff dtd. 10/10/69 3. Memo to NRC Staff dtd. 10/3/89 h/J/()OI g L .}}