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Miscellaneous Press Releases Ultra Deepwater Oil Spill NEWS RELEASES 2010 0612—Press and Journal---Macondo. Mortara. Gullfaks C — unacceptable. 3 pages htip:Henergy pressandioumal co uk/Article aspx/2025770/?UserKey&UserKey N 10 0727—BOE—Deep water is not the problem. 3 pages htty •//budsoffshoreenergy. wordpress. com/2010/07/27/deep-water-is-not-the-problem/ 2010 07—Offshore L-n-ineer—Fitzsimmons, Macondo and other titanic struggles. 4 pages http://www oilonline com/default asp?id=267&nid=2029&name=Macondo+and+other+ti tanic+struggles 2010 0816—Maritime Lawyer News. TO withheld internal report, 3 pages http://www.offshoreiniuries.comlblop,/l 268/transocean-withheld-intemal-report-that- proved-fatal-for-deepwater-horizon- 11 / 2010 0816—NYT, Another close call, TO changed Rules. 3 pages htti)://www.nylimes.com/2010/08/17/us/I 7transocean.html 2010 08---Offshore Engineer —Palmer, Chernobyl offshore?, 2 pages http://www.oilonline.com/default.asp?id=259&nid=l 8509&name=Chemobyl+offshore% 3F 2010 0929—FF—NeNv release to reflect legacy from spill. 2 pages http://fuelfix.com/blog/2010/09/30/new-drilling safety -rules -will -reflect -legacy -of -spill/ 2010 0930—BOE—Washington Post—Aehenbach. Freak accident or frontier enterprise'?, 4 pages http//www washingtonpost com/wt)dyn/content/article/2010/09/29/AR2010092906587.h tml? sid=ST2010092907824 2010 1004—BOE—Marcellus Guiding Principles. 2 pages htip://marcelluscoalition org/n-content/uploads/2010/09/Guiding-Principles-Poster- Final.pdf 2010 1004—OGJ—Alaska offshore plans should reflect conditions there. panel told, 4 pages http•//www ogi com/index/article-display articles.oil-gas-ioumal.volume-108.issue- 38.general-interest.alaska-offshore-plans-should- • reflect.OP 129867.dcmp=rss.pape= l .html 2010 1004—OGJ—US agencies treated spill as catastrophe fi-on) outset, panel told, 6 pages hM://www.oizi.com/index/article-diMlay/4206631374/articles/oil- as-loumal/jzeneral- interest-2/2010/09/us-aeg ncies treated.html 2010 1007—E&P—DNV to investigate the Deepwater Horizon blowout prey enter. 1 page http•//www epmag com/Offshore/Deepwater-Horizon-Incident/October/item69537.y 2010 1008—WSJ—Doubts raised by BP Study, Some Experts see a legal motive in internal investigation of gulf oil disaster, 1 page http•//online wsj com/article/SBI0001424052748704011904575538291955688582.html 2010 1011—WSJ—Inspectors rarely surprised oil rigs, 3 pages http•//online wsi.com/article/SBI0001424052748703358504575544294191404032.html 2010 1012—DOI-- Salazar: Deepwater Drilling may resume for operators who clear higher bar for safety, environmental protection, 6 pages http//www doi gov/news/Xressreleases/Salazar-Deepwater-Drilling-May-Resume-for- Operators-W ho-Clear-Higher-Bar-for-Safety-Environmental-Protection. cfm 2010 1025--ADN-LAT---US looks at UK plan on drilling regulation. 1 page http•//articles latimes com/2010/oct/24/nation/la-na-oil-spill-reform-20101024 2010 1028—Business Wire--Halliburton Comments on National Commission Cement Testing. 5 pages h!tp:Hwww halliburton cop /public/news/pubsdatA/press release/2010/comnws 102810.h tml 2010_1028—NYT-- Panel Says Firms Knew of Cement Flaws Before Spill, 4 pages htti)://www.n3jimes.com/2010/10/29/us/29Viil.htm]? r=1&ref=business 2010 10—Offshore—Ball. More information on Macondo. 1 page http•//www offshore -map com/index/article-display.articles.offshore.volume-70.issue- l0.departments.drilling- production.drilling- production OP129867.dcmp=rss.page=l.html • Page 7 of 10 Last update: August 03, 2011 2010 10--Offshore--'fop. bottom kill prospects leave Macondo just a nasty memory. 3 page • htip://www.offshore-mag.com/index/article- display/5260064721 /articles/offshore/volume-70/issue-10/Deepwater-Horizon- Incident/top-bottom-kill-prospects-leave-macondo-just-a-nasty-memory 2010 1 103—World Oil --Pritchard.. et al. Drilling I-]azzard Management -Part 2, 8 pages http•//www worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment- october-2010.htm1 2010 1103—Rocky Mountain Mineral Law Newsletter. 3 pages No link available as of 7i26�2011. 2010 1110—AP via Yahoo! News —Report: White House altered drilling safety report. 1 page http •//www.themonitor.com/articles/report-44363-drilling-moratorium.html 2010 1 11 1—AP \ is Yahoo! News —White House edits stain its reliance on science, 3 pages http://www.boston.com/business/articles/2010/11/10/rei)ort white house altered drilling safety report/ 2010 1 117—OG.1—National scientific academies criticize 1\4acoildo well procedures. 3 pages http//www opi com/index/article-display articles.oil-gas-ioumal.volume-108.issue- 44. general -interest. national -scientific -academies- criticize.OP 129867.dcmp=rss.page=l .html 2010 1 124--Media Release: Final report on the 1\-1ontara Commission of inquiry released. 2 pages http•//minister ret gov.au/MediaCentre/MediaReleases/Pages/FinalReportoftheMontaraC ommissionoflnguiryReleased. aspx 2010 1 1—Offshore En,,ineer—Kropla. Ne\�' drilling regs challenge. and sonletinles confound, 2 pages No link available as of 7 2(r201 1. 2010 1 1--0ffshore En-ineer—McCulley and Pallanich. Containment capability in the cross -hairs. 1 page No link available as of 7/26,2011. 2010 1 I-- Offshore Engineer—Fitzsinnllons. Macondo-the unfolding aftermath. 3 pages No link available as of 7/26 201 1. • 2011 1 1--Offshore Engineer —Waddell, et al. Expanding well desi,!n, 3 pa"es No link available as of 7i26/201 1. 2010 1 1--2010 Canada US Northern Oil and Gas Research Forum. 48 pages 2010_1208—AP-ADN—BP says Gulf well shutdown was delayed. 3 pages htty://www adn.com/2010/12/08/1595014/bp-says-gulf-well-shutdown-was.html 2010 1208--HC---Hearing focuses oil well mud work. 2 pages http•//fuelfx com/blog/2010/12/08/houston-spill-hearing-focuses-on-drilling-mud-work/ 2011 0103—Telegraph—No UK Moratorium. 4 pages h"://www telegraph co uk/earth/earthnews/8236144/MPs-give-backing-to-deep-water- drilling-off-UK.html 1011 0106—Reuters--Exxon CEO disputes panel finding on BP spill cause. 1 page http•//www reuters com/article/2011/01/06/exxon-spill-idUSN0612733520110106 20 11 0107—WP—In over their heads. ] page http: //www. washingtoLipost. com/wo- dyn/content/article/2011 /01 /06/AR2011010606026.htm1 2011 Oil 1—Press Release—Halliburton comments on National report. 2 pages http://www.halliburton.com/public/news./pubsdatq/press release/2011/corpnws 0111201 I . htm]? SRC=National C o mm 2O i 1 01 12--OG.1--Sep oral inmiediate causes contributed to 1\9acondo blowout. 4 pages httg://www ogi com/index/article-display articles.oil-gas ioumal.drillinp-production- 2 20100 O1 several-immediate.OP129867.dcmp=rss.page=l.htmI 201 1 0117--FT--BP is a guide for modern executives. 2 pages http•//uk finance yahoo.com/newsBP-guide-modern-executives-ftimes- 90232953.html?x=0&.v=1 ')Oil 0130—ADN--UAA chancellor reflects on experience with Gulf oil spill. 4 pages http://www adn com/2011/01/30/1675582/alaskas-ulmer-reflects-on- e_xperience.html#ixzzl CdJBrgia Page 8 of 10 Last update: August 03, 2011 2011 01—Offshore Engineer—Thorogood. Macondo: the human factors, 2 pages • http•//www oilonline com/default asp?id=259&nid=18165&name=Macondo%3A+the+h uman+factors 2011 0201—WSJ—BP's safety drive faces rough road. 7 pages http•//online wsi.com/article/SB]0001424052748704515904576075992850313426.html? mod=WSJ Energy leftHeadlines 2011 0217—The Lookout, via Yahoo Nees —BP slammed again by spill commission. 2 pages htlp•//beta news.yahoo.com/blogs/lookout/bp-slammed-again-spill-commission- complains-feinbergpayouts-20110217-134505-580.htm1 2011_0220—BOE—PSA reviewing Macondo. 6 pages http•//budsoffshoreenergv wordpress.com/2011/02/20/vsa-reviewing-macondo/ 201 1_02—World Oil—Lukosavich. Innovative thinkers. Lessons learned from Montara. Macondo and beyond,] page No link available as of 7/27/201 1. 2011 0322—Dow Jones Newswire --UK Govt: Deepwater Oil Drilling Safety Rules Fit for Purpose, 1 page http://oil-and-gas-post blogspot com/2011/03/uk-govt-deepwater-oil-drilling- safety.html#links 2011 0328—FT. Blowout preventers are no guarantee against disaster. 2 pages h"://bloys.ft.com/energy-source/2011/03/28/blOwOut Rreventers-are-no-Quarantee- against-disaster/#axzz 1 TLSoIgOr 201 1 03— Offshore Engineer-- Fitzsimmons. Deep Water, The gulf oil disaster and the future of offshore Drilling, Macondo and the Presidential Commission, 9 pages http//www oilonline.com/default.asp?id=259&nid=19064&name=Macondo+and+the+Pr esidential+Commission 2011 03—Offshore Engineer --Letter Response from UK HSE to lan Fitzsimmons column. 1 page hLp•//www hse og v uk/press/record/2011/offshoreengineer220311.htm • 2011 03--Offshore Engineer—Statoil admits 'clialogue' doubts over Gullfaks C near miss. 2 pages http•//www oilonline com/default asp?id=259&nid=18709&name=Statoil+admits+%27di alogue%27+doubts+over+Gullfaks+C+near+miss "Oil 0412—Reuters—Government NN,ei�ahs more drilling contractor oversiglit, 2 pages http•//www reuters.com/article/2011/04/12/us-usa-oil-spill-idUSTRE73B7KS20110412 201 1_0417--PN—Prevention the best cure. 3 pages htti)://www.yetroleumnews.com/i)ntruncate/100046473.shtml 2011 04—Offshore Engineer —Rielly. Safety case may be in store for US. 2 pages http•//www oilonline com/default asp?id=259&nid=19079&name=Safety+case+may+be +in+store+for+US 2011 0503—FUe1Fix --Bromwich: Feds will regulate offshore contractors. 1 page http://fuelfix.com/blog/2011/05/02/bromwich-at-otc-201 I -feds-will-regulate-offshore- contractors/ 201 1_0506--BOE—PSA adds N alue. Magne Ognedal. interview January 2010, 10 pages http'//budsoffshoreenergy wordpress com/2011/05/06/psa-adds-substantial-value-at-a- relatively-low-cost/ 2011 0515—PN—A risky business, 4 pages. ht!p://www.petroleumnews.com/t)ntruncate/271763596.shtml 2011 05---Offshore Engineer —Light. Independent and competent: Is it time to raise the bar?, 2 pagers htip•//www oilonline com/default asp?id=259&nid=19166&name=Independent+and+co mpetent%3 A+is+it+time+to+raise+the+bar%3 F 2011 05--Offshore Engineer—Thorogood, Looking bevond the -human error' label, 3 pages htip://www.oilonline.com/default.aspiid=259&nid= 1 9164&name=LooIjinP,+beYond+the +%E2%80%98human+error%E2%80%99+label 2011 0624—Fue1Fix--BP. Transocean spar over Mho gets BOP. 2 pages http://fuelfix com/blog/2011/06/24/bR-transocean-spar-over-who-gets-blowout-preventer/ "Oil 0629—World Oil—Transocean releases investigation report on causes of Macondo incident. 3 pages ht!p://www.reuters.com/article/2011/06/22/idUS I 10092+22-Jun-201 I +HUG20110622 Page 9 of 10 Last update: August 03, 2011 1011 06—Offshore Engineer--Nlculley. Macondo under the microscope, 4 pages • http://www.oilonline.com/default.asp?id=259&nid= 19261 &name=Macondo+under+the+ microscope 201 l 072]—FF—Steffy: Reforms at BP fall short, 2 pages http:/Muelfix.com/blog/2011 /07/21 /steffy-reforms-at-bp-fall-short/ 2011 0722—FF—Feds' oil spill probe delayed again. I page htip:Hfuelfix com/blog/2011/07/22/feds-oil-spill-probe-delayed—aaagain/ 1011 0723—FF—Feds' offshore po\vers cover contractors, 2 pages http•//fuelfix.com/blog/2011 /07/23/feds-offshore-powers-cover-contractors/ 2011 0729—Reuters—Air France crash probe finds pilots ignored warnings. 3 pages. http •//uk.news.yahoo.com/air-fiance-crash-probe-finds-pilots-i¢nored-warnings- 115001901.html. with accompanying BOE bloc entry, I page. htty://budsoffshoreenergy wordpress com/2011/07/29/air-fiance-crash-and-well-control/ 2011 07—Offshore Engineer—Transocean's Macondo report pins blame on BP. ] page http://www oilonline com/default asp?id=259&nid=19435&name=Transocean%E2%80 %99s+Macondo+report+pins+blame+on+BP 1011 07—Offshore Engineer —Fitzsimmons. Macondo: the BOP's story, 7 pages htip://www oilonline com/default asp?id=259&nid=19454&name=Macondo%3A+the+B OP%E2%80%99s+story r -I L- J Page 10 of 10 Last update: August 03, 2011 0 • Macondo: the BOP's story The DeepwaterHorizon's blowout preventer was a victim of the Macondo disaster, not the perpetrator. So says consultant Ian Filzsimmons in his latest think piece for OEwhich takes issue with some of the findings of DNV's forensic study of the recovered BOP and looks at ways in which BOP/LRMP stackup configuration and controls could be improved in future. The events surrounding the Macondo disaster have been made available to the public through BP's Accident Investigation report prepared by BP (OE November 2010) and the US National Commission report to President Obama (OE March 2011). Both reports were unable to determine the reasons for the apparent failure of the BOP to seal the well. It was obvious that it would be necessary to retrieve - DET NORSKE VERFFAS the BOP and LMRP for internal inspection in order to resolve this issue. Prior to the Macondo disaster, the subsea BOP was regarded as the ultimate bulwark against loss of well control. Its apparent failure at Macondo was a revelation to the offshore drilling industry. Faced with this major issue, BOEMRE commissioned DNV to perform an onshore forensic examination of the Deepwater Horizon BOP stack -up, after it had been recovered. DNV were Floe) Report t« UNITED STATES I)FP.4RP/FKT OF THE INn RIOR also directed to establish the cause of the apparent failure of the BOP to respond to the blowout. =_ —�=- That report (in two volumes) was issued on 20 March 2011 and has received a mixed response from the offshore industry. It has to be stated from the outset that it was always going to be a difficult task for DNV - or indeed any other independent verification body - to execute. The offshore industry and the general public were looking for an obvious, single point failure, which could be easily explained and put right. DNV thought that it had delivered that expectation - others were not convinced. It is one thing to postulate a theory, but until the predictions of a theory have been tested and proven, it remains just a theory. And that is the problem with the DNV report. It has drawn a deterministic conclusion without any demonstrable proof. In fact, it is still a work in progress by its own admission, Author's note: At the time of writing, I am advised that thejnal • Macondo report from BOEMRE is due on 27 July. I hope it has something constructive to say. And something far more constructive, one must hope, than the vacuous, hapless remarks offered by the UK's Health & Safety Executive in its letter ('Mailbag', OE April) responding to my previous Macondo piece. 'BOPs are designed and qualified to prevent blowouts, not a volcanic eruption that has already been in full swing for 15 minutes.' as Section &2. Recommendations for Further Testing clearly demonstrates. The BOP from the ill-fated Deepwater Horizon was recovered from the Macondo subsea wellhead on 5 September 2010. It emerged slowly from the sea almost as if ashamed to face the world. Heaped with opprobrium, this gentle giant and its LMRP were separated and transported to the NASA Michoud West Dock Test Site, Louisiana, where they arrived and were offloaded on 3 October 2010. No detailed record has been published that accounts for the daily status of the BOP/LMRP during the four weeks described above. Anecdotal evidence described at the 4 April 2011 meeting of the BOMRE committee confirms that the BOP rams were functioned during this period. It is also public knowledge that subsea ROV activities had altered the status of many key BOP functions after the blowout and prior to 5 May 2011 when all BOP/ROV intervention activities ceased. It can be stated with certainty, therefore, that when the BOP arrived at the test site on 3 October, its status/condition did not reflect that which pertained at the time of the first explosion that occurred on Deepwater Horizon at 21:49 on 20 April 2010. In fairness to DNV, it has to be said that nobody expected the internal photographic evidence to reveal such severe erosion of drill pipe and rams, and the total absence of elastomeric seals, which are obligatory for the safe operation of the BOP. It appears that much critical evidence had been washed away by the erupting, aggressive well fluids, including metallic drilling debris and reservoir sandstone/ minerals. This horrendous, aggressive erosion lasted from the start of the blowout on 20 April 2010 until the well stopped flowing through the BOP after the well had been plugged on 19 September 2010. Five months of aggressive grit blasting had made an already difficult forensic examination even more so. The evidence of compacted mineral debris found in the rams, cavities and drill pipe further confirms the ferocity of the blowout, which has been likened by one witness as 'a 500 ton freight train hitting the rig floor', and by another as `a jet engine's worth of gas coming out of the rotary'- and it was taking the evidence of the cause of the disaster with it. But one inevitable and unavoidable fact remains - neither the BOP nor the annular preventers in the LMRP sealed the well, regardless of the best efforts made to control the blowout between 20 April and 5 May 2010. Even Sherlock Holmes would have had difficulty cracking this case. For DNV, awarded the investigation that nobody else wanted, it may well have reawakened memories of the Alexander Kjelland disaster which claimed 123 lives in the Norwegian sector of the North Sea back in March 1980. MMS The US Minerals Management Service (MMS) became a casualty of the Macondo disaster. It was roundly criticised by the National Commission and completely reorganised, http://oe.oiIon11ne.cam OFFSHORE ENGINEER j july 2011 43 z CD z 0 with BOEMRE established to take responsibility for offshore activities. Some good people worked for MMS. Long before Macondo, they were unhappy about subsea BOP shear ram capabilities and operational failings. In 2004, MMS commissioned West Engineering Services, an engineering house with a well deserved, worldwide reputation for excellence, to investigate its concerns. West specialises in offshore drilling and rig activities for both engineering and operational support activities offshore. West's report is best summarised by quoting directly from the document, starting with the Executive Summary: `West was commissioned by the US Minerals Management Service to perform the Shear Rams Capabilities Study. The main goal of the study was to answer the question — Can a rig's blowout preventer (BOP) equipment shear the pipe to be used in a given drilling program at the most demanding condition to be expected, and at what pressure? Shear rams may be a drilling operations' last line of defensefor safety and environmental protection.' `Code of Federal Regulations, Title 30 Mineral Resources Chapter II... asks in 250.416 (e): What must I include in the diverter and BOP descriptions? And the answer is stated as: Information that shows the blind -shear rams installed in the BOP stack (both surface and subsea stacks) are capable of shearing the drill pipe in the hole under maximum anticipated surface pressures. Therefore, an operator is responsible to assure the BOP rams will reliably shear the drill pipe in the particular operational conditions.' There can be little doubt that six years before the Macondo disaster, MMS were worried about blind shear rams. But it should be noted there is no mention of shearing tool joints. Rather than go into the full details of the report (www.westengineering.com), I will again quote from page 3-1, par 3.2, Understanding the Shear Function: 'The well control function of last resort is to shear pipe and secure the well with the sealing shear ram. As a result, failure to shear when executing thisfinal option would be expected to result in a major and/or environmental event. Improved strength in drill pipe, combined with larger and heavier and heavier sizes resultingfrom deeper drilling, adversely affects the ability of a given ram BOP to successfully shear and seal the pipe in use. West is currently aware of several failures to shear when conducting shear tests using the drill pipe that was to be used in the well. As stated in a mini shear study recently done for the MMS, only three recent newbuild rigs out of 14 were found able to shear pipe at their maximum rated water depths. Only half of the operators accepting a newbuild rig chose to require a shear ram test during commissioning or acceptance. This grim snapshot illustrates the lack of preparedness in the industry to shear and seal a well with the last line of defense against a blowout.' In the final paragraph of 3.2 we find the following: 'Unfortunately, not all operators and drilling contractors are aware of the limitations of the equipment they are using. This study examines existing shear data and inconsistencies in an attempt to better understand the likelihood that the rams will function as expected when activated.' The foregoing report is dated September 2004 and readers will draw their own conclusions. West and the MMS had given ,' operators and drilling contractors alike fair warning about the risks and operational security of BOP shear rams. Tuesday 20 April 2010 At 20:00 and following a failed, but presumed successful, Middk Lowey Pon Side 1wr mtaz it Ram = Ram iabtc hcs negative pressure test, the Deepwater Horizon drill crew began displacing heavy mud from the well bore by circulating it with lighter seawater. The tragedy was under way, because hydrocarbons had already entered the wellbore by this time, as a review of the evidence of the failed negative pressure test clearly demonstrates. At 21:00, drill pipe pressure (at the drill floor) started rising when it should have been falling. Nobody tried to explain why the pressure was increasing while the pump rate was not. The kick was under way, but nobody noticed. Had they done so, they could have shut-in the well and averted a major disaster. At 21:41, mud overflowed onto the drill floor. Witness accounts suggest that soon after, a crew member activated the upper annular preventer. It was slow to close, but it did not seal. At 21:46, rapidly rising drill pipe pressure readings suggest that someone activated the upper VBR. But it did not seal. At 21:49, the first explosion occurred, followed immediately by a second explosion. At 21:56, the Master of the Deepwater Horizon announced the activation of the EDS. It was a futile gesture. By this time, the two BOP MUX control cables and the hydraulic umbilical had already been severed by the explosion. This complete loss of communication with the Deepwater Horizon should have activated the BOP/AMF `deadman'. It did not. Both control pods were defective and could not respond. Deepwater Horizon went to her grave in 5000ft of water at 10:22 on Thursday 22 April 2010, taking 11 men with her. ROV intervention to try to shut-in the BOP began at 18:00 on 21 April and lasted until 5 May. It is possible that, after the 44 OFFSHORE ENGINEER I july 2011 htip://oo.oilonline.com 0 • • autoshear hydro mechanical rod had been sheared by ROV on 22 April, the BSRs became partially closed. But in spite of repeated, ongoing attempts to close the BSRs, the well continued to flow. BOP configuration The complete stack up of the Deepwater Horizon blowout preventer is about 60ft high and weighs about 400t. It is illustrated in the DNV report and reproduced left. The upper section of the stack up is described as the Lower Marine Riser Package (LMRP) and contains the BOP connector, two annular preventers, flex joint, and two electrohydraulic control pods. The annular preventer comprises a high pressure body that contains a large elastomeric doughnut. This doughnut can be forced/squeezed by internal hydraulic rams to seal around the internal drill pipe and thereby seal the LMRP annulus. It is normally regarded as the first piece of equipment to be activated in any well control event. The lower section of the stack -up comprises the BOP. It contains the upper Blind Shear Ram (BSR) and a Casing shear Ram (CSR). The BSR can shear and seal drill pipe, but cannot shear and seal tool joints under normal conditions. The CSR can shear tool joints and large casings, but cannot pressure seal the BOP bore. Beneath the CSR are three Variable Bore Rams (VBRs) with internal adjustable elastomeric seals. These rams can close around variable diameter drill pipe and tool joints and seal the BOP annulus. It should be noted that, apart from the CSR, all the rams and preventers depend on elastomeric seals for their sealing integrity. All the rams and annular preventers are operated by hydraulic power supplied from the surface rig and distributed by the control pods. The BOP was supplied by Cameron and is about ten years old. If it has an Achilles heel, it is the inability of the BSRs to shear and seal tool joints. However, this issue can be overcome operationally by the driller locating the tool joints distant from the BSR when the BSR needs activation. This operational determination of the tool joint location when passing through the BOP bore is normal practice, and works well under controlled situations. Such was not the case for the Macondo disaster BOP stripping The annular preventer comprises a large, one-piece rubber doughnut, which can be forced/squeezed by hydraulically activated metallic rams onto the drill pipe, and tool joints. It can cope with large variations in pipe OD. This enables drill pipe and tool joints to be 'stripped' (pulled) through the doughnut, while still providing well control. Two such annular preventers were located on the LMRP. The Variable Bore Rams in the BOP have a similar capability, except a pair of (split) rams is required to seal around the drillpipe/tool joint external perimeter to "close the BOP annulus. It has to be said at the outset, that stripping drill pipe and tool joint through an annular preventer is not good practice when executing well control issues. It may be expedient, but it is not desirable. The OD of a typical tool joint for 5.5inOD drill pipe is about 7.5in. The transition comprises a sloping shoulder. Pulling the tool joint through an annular preventer obviously damages/impairs the internal elastomeric doughnut. To offset this abrasion and degradation, it is common practice to bleed off pressure in the annular preventer so as to ease the passage of the tool joint through the doughnut. It is a subjective and therefore risky operation. It is neither controlled nor deterministic and it should be avoided. A look at the Macondo BP Accident Report (page 22) confirms Mud Pump Pressure Relief Value e.nwie or Nowt Mow k__F1_— SOP Pn o..roore re.. H CMnVYw MC�V» «, ca u—P , . ® a.�s.wwcr.rm .wu that stripping had already been used during an earlier well control event. The record for 5 and 6 March states: 'Stripped drill Dine through under annular Dreventer from 17.146ft-to 14 937ft, while addressing wellbore losses'. Some 45-55 tool joints had been stripped through the upper annular doughnut during a well control procedure. But much more was to follow. After the first explosion, all rig power was lost, and all Sperry Sun real-time data transmission ceased. Without any power, the DP system was disabled, and Deepwater Horizon began to move off station. But although Deepwater Horizon was drifting, she was still tethered to the LP drilling riser, which was suspended by constant tension winches located on the rig. In addition, and to compensate for relative heave motion between the fixed LP riser and the topside drilling facilities, a slip joint is provided which connects the LP riser to the drill floor underside diverter pipe work. The slip joint behaves like a telescope and similarly has a finite travel range before coming up against predetermined mechanical/structural stops. In parallel, the drillpipe being used to circulate mud from the LP riser was suspended from the motion compensated top drive assembly in order to maintain a constant depth for the tip of the drillpipe. The top of the drillpipe above the drill floor was connected to an internal blowout preventer (IBOP). The various reports do not contain details of the IBOP configuration, but I guess a dual valve isolation block and connecting flowspool were used. The flowspool would be suspended from above by the topdrive assembly, and laterally connected by flexible hose to the HP WI/mud pumps, as shown in the figure above reproduced from the BP Accident Report. A witness report carried in the BP report, observed that after the explosion 'the top drive fell about 26ft onto the drill floor'. We can assume that about 8000ft of drill pipe went with it. The exact status of the upper VBR and both annular preventers at that time is not clear from the reports, but it is most likely that the upper annular had been partially closed, and drillpipe was stripping down through it - uncontrolled. A passing tool joint in freefall would have caused considerable damage to the rubber doughnut. As the rig drifted off station, the drillpipe suspended by the collapsed topdrive on the rig floor was stripped upwards through the annular preventer again. The constant tension winches supporting the LP riser from the main deck began to pay out and the slip joint began to expand. The slip joint came to the end of its travel and the LP drilling riser became a mooring line for the Deepwater Horizon. When the condition of the upper annular preventer was http://oe.oiIonIine.cam OFFSHORE ENGINEER I july 2011 45 z 0 Z' C E • g}P Corod PaM �7 .._ f4.lon u4cunwbi� \,,LWtP Nu GOE4 StlVP+VEMEl—i M I H,IXL[ Cwln 1 IY� Aminib• '� ebgd 9rr Panv j <� C�lNony 5ey"q� tv- Lwr Svu Note VD4 ♦ccv earie �o.n,iedi VBR WP 11—g—V M.W ft M W GOwN MalloW OW N~ Buick HOT 7HPSR Wwnea� EDS A F.R' Aim Dlote Mft4hW - discovered by DNV during their forensic examination. no doughnut was present —just the tortured remains of the steel fingers that were used to squeeze the doughnut in happier times. But no sign of a tool joint. BOP control system The schematic above, reproduced from BP's Deepwater Horizon investigation, shows the BOP control system and the BOP stack illustrates the umbilical, SCM and accumulator arrangements. The autoshear rod can be seen beneath the yellow control pod. It is a hydro -mechanical arrangement whereby retraction of the LMRP releases HP hydraulic fluid to the BSRs. In the aftermath of the disaster it was eventually sheared by ROV intervention, thereby simulating release of the LMRP. It is thought this activity partially closed the BSRs. But by that time, the elastomeric seals had been blasted away and the BSRs. VBRs and annular preventers were no longer sealing. The arrangement of the two surface MUX cables and the hydraulic umbilical can be seen in the graphic below, reproduced from the BP Accident Investigation report. One cable is provided for each control pod (SCM), and each SCM duplicates control of all BOP/LMRP functions. A single umbilical supplies hydraulic power to each SCM for distribution to the BOP/LMRP functions. The foregoing arrangements therefore comprise a fully redundant control system. It is immediately obvious that the first explosion would have severed both MUX cables and the hydraulic umbilical, thereby rendering the subsea control system inoperable. This meant that activation of the BOP subsea emergency control system would become totally dependent on power supplied by the battery packs in each control pod, and the subsea accumulators. Fully functioning control pods would also be required. Unfortunately the emergency systems did not activate because the SCMs were faulty and inoperable, as was subsequently discovered and determined. The figure reproduced above (from the BP Accident Investigation report) is a simplified schematic of the AMF (Automatic Mode Failure) control system. The blue pod was inoperable because both battery packs had failed, rendering solenoid valve 103B unable to discharge to the BSRs. The yellow pod was also inoperable because the 27V battery pack suffered low voltage and solenoid valve 103Y had failed. As such, it was also unable to discharge to the BSRs. BOP operation The normal operation of the BOP faced with a well kick is by manual intervention from the well control panel on the rig. In the first instance, the annulus between the drill pipe and the BOP is sealed by closing the annular preventer above the BSR, and the VBR immediately beneath it. In a parallel activity, the IBOP located on top of the drill pipe head is closed. The IBOP typically comprises isolation valves in a flowhead/topside test tree type configuration. The flowspool/ STT is connected to the HP mud pumps by a flexible pipe. Once the kick has been arrested, the way is then clear to stabilise the well by circulating down the drill pipe with mud/ brine and returning it to the surface through the HP kill/choke lines on the BOP. In addition to manual control of the BOP, further progression to emergency modes of well control are available and are illustrated by the figure reproduced above right from the BP Accident Investigation report. (a) BSR closure The first step to emergency mode of BOP operation (if necessary) requires activation of the BSRs to shear the drill pipe and seal the well bore. The reader will note that the foregoing manual activation of the annular preventer and the VBR has centralised the drill pipe through the BSRs. In the event that a tool joint is located between the BSR blades and they will not close/shear, the blades are retracted and the tool joint is stripped upwards through the upper annular. The BSRs are then reactivated and the drill pipe sheared. The BOP bore has been sealed. As an alternative, and if super shear rams have been included within the BOP configuration, the BSR blades are retracted and the CSRs activated to shear the tool joint. The tool joint is then stripped through the upper annular preventer and the BSRs reactivated — if so required. The BOP bore has been sealed. The foregoing is normal procedure after the early detection of a well kick. The seals in the BSRs, VBRs and the annular preventer will not be exposed to well fluids — they will see only brine and/ or drilling mud. The kick can be prevented. `rV OFFSHORE ENGINEER I july 2011 http://oe.oilonline.com • • O Hazard Normal MoAe d WNI Con401 Emergency 6bM of WV * COn101 C—W ox 0—HJo. 1=i w F RM Apo Rp✓ `�{ w nD 6yrJer./y�A pne;:ss l:A EO: ' AW E.P-- "IS SMA. SPIN The foregoing is not intended to arrest a blowout already in progress, as indeed was the case when the Macondo volcano erupted uncontrollably at the drill floor. The well fluid blowout undoubtedly contained reservoir sandstone and cement particles, exposing the elastomeric seals to aggressive and unstoppable erosion. And that is exactly what happened. (b) Emergency disconnect system (EDS) The EDS function is initiated manually from the control panel on the rig. It is initiated in the event of DP failure, whereby the rig cannot keep station. The EDS is intended to disconnect the LMRP from the BOP and in so doing activate the BSRs via the autoshear hydro - mechanical interface connection. The EDS cannot work without at least one MUX cable and the hydraulic umbilical from the rig being intact. (c) Automatic mode function (ANIF) This system automatically activates the BSRs when all communication and hydraulic power through the rig umbilicals has been lost (as was the case with the Deepwater Horizon. Activation requires a fully operational control pod, fully charged batteries, and fully charged accumulators. (d) ROV intervention The foregoing systems can be overridden by ROV intervention. In the case of Macondo, ROV intervention successfully activated the EDS by cutting through the autoshear rod that interfaces the BOP and the LMRP, thereby simulating the EDS described above. But repeated ROV intervention between 21 April and 5 May failed to stem the flow of the well, although the BSRs may have been partially activated during this period. The wreck site Judging by photographic evidence, we can say that even after the first explosion, the fire ball inferno was emerging from the deck(s) of the Deepwater Horizon - not from the sea surface. From this we can assume that the LP riser was still attached to the Deepwater Horizon constant tension winches. The wreck of the Deepwater Horizon lies about 400m north and 150m west from the Macondo wellhead on a heading of 322' The hull lies on the seafloor upside down, the underside of her pontoons facing upwards. She is submerged in deep mud that has buried her deck, derrick and drilling facilities. The figure below, reproduced from the US Coast Guard report, illustrates her unhappy and immodest grave. Although Deepwater Horizon was stationed by DP thrusters, their loss soon after the explosion left her free to drift. However, she did in fact have an 'anchor'- the LP drilling riser. It was suspended from Deepwater Horizon with constant tension winches to generate tensile stress at the base of the riser where it joined the flex -joint LMRP. Being constant tension winches, they would be able to cope with vessel heave and drift within normal operational limits. The LP riser is connected to the underside of the drill floor with an LP telescoping slip joint that compensates for differential movement between the top of the LP riser and the underside drill floor/diverter system. The slip joint does not have unlimited travel - probably not more than 15m in total (±7.5m from neutral). When it comes to the end of that travel with mechanical/structural stops around the sliding rim interface, the LP drilling riser becomes a `mooring line'. An eyewitness account states that he saw the topdrive 'block' fall to the drill floor - about 30ft - before he escaped from the Deepwater Horizon. We have to assume that the entire length of internal drill pipe was then suspended from the drill floor rotary. As a result, the internal drill pipe moved vertically downwards with respect to the subsea BOP, stripping through the upper annular preventer, which we are told was 'closed' at the time. A witness observed and reported that, as the Deepwater Horizon turned turtle before beginning the descent to her grave, the riser parted from her. We can assume that the internal drill pipe must then have fallen downwards with respect to the subsea BOP again. From the foregoing, we have to assume that this final event initiated the collapse and buckling of the LP riser above the LMRP flex joint. The drill pipe so released may well have fallen back into the well before being arrested, either by the buckling of the LP riser, or by the intervention of a tool joint becoming stuck in a BOP component, such as a VBR. DNV report Few would have wished to participate in the forensic examination of the Deepwater Horizon/Macondo BOP. Fewer still would have wished to draw any deterministic reason for the apparent failure of the BOP, particularly since there is no guarantee that the received condition of the BOP/LMRP at the Michoud facility bears any relation to its condition at the time of the blowout. Careful reading of the DNV report will reveal that the BOP became a victim of the Macondo disaster, not the perpetrator. If my car cannot start because I have allowed the battery to go flat, I am at fault - not the car. If I cannot drive my car because it has a flat tyre - that is also not the fault of the car. And if my engine refuses to start because it does not have any fuel, I am at fault because I have failed to refill - that again is not the fault of the car. An obvious point, but I will risk offering one further amplification: BOPS are designed and qualified to prevent blowouts, not a volcanic eruption that has already been in full swing for 15 minutes. Photographic evidence from the DNV report vividly demonstrates the terrible damage inflicted on the BOP rams and elastomeric seals by erupting well fluids, sandstone rocks, drilling debris, and cement fragments. The report also concluded that when the BOP ram stems were tested by direct activation from a hydraulic source, they all closed and opened correctly in a timely fashion. Faults, both electronic and hydraulic, were found throughout the BOP control system when it was examined and tested. When the faulty pieces of equipment were replaced, the EDS and AMF systems were tested satisfactorily, as was the autoshear system. > overleaf http://oe.oiIon line .corn OFFSHORE ENGINEER I july 2011 47 a mM 3M bw. g. 2—yM. .......... atW .......— 141 i JM31 K1 tit , �aie 2A4 —110 � .._ _. M WA UYI iS�9 Y 0 Y 14 Uzi rase MelncuenV _...- _ 7--------.--- Ur.w�11� A The figure shown above, reproduced from the DNV report, is a schematic indicating the positions from which drill pipe was recovered from within the BOP, LMRP, and the buckled length of the drilling riser. When Drill Pipe Item 148 was recovered from within the BOP (it was lodged between the CSR and the lower VBR), it was found to be packed with debris'and would not become dislodged'. Furthermore: 'The Upper and Middle VBRs had to be retracted and removed in order to secure a safe hold on the drill pipe segment. There was a significant amount of cementitious material in the wellbore between the Upper and Middle VBRs that had to be chiselled out and removed by hand before the Middle VBRs could be retracted.' I know of no BOP qualified to shear drill pine filled with cement debris so compacted that it has to be manually chiselled out of the wellbore and drill nine! Strangely, having identified this as part of its forensic remit, DNV chose not to consider it when forming its postulation of the failure mechanism. What is `considered' to have happened The forensic examination and testing by DNV was comprehensive - especially when considering the uncertainties it faced at the time. Unfortunately it failed badly when it came to postulating the reason for the failure of the BSRs. A further setback was delivered at a public hearing when Cameron demonstrated that the failure mode postulated by DNV could not have existed in practice. DNV postulated that at least 3000ft of drill pipe had been uplifted by the force of the blowout and a tool joint became • lodged in the upper annular preventer. Subjected to extreme dynamic forces (presumably compressive), and restrained laterally by the VBR, the drill pipe buckled and in so doing went off-centre before lodging against the bore of the LMRP/BOP. Q DNV claimed that, because the BSR blades did not intersect 48 OFFSHORE ENGINEER I july 2011 the entire extent of the BOP wellbore, the drill pipe could not have sheared in this extreme location. As such, the drillpipe was pinched by the ram blocks so that the blade could not close to complete the shearing process. DNV heralded the inability of the BSRs to intersect the entire BOP bore as though it were some new discovery. Far from it. This is an acknowledged consequence of having elastomeric, perimeter seals around the ram blocks and it is managed operationally by first closing the annular preventer above the BSR, and then the upper VBR immediately below it. The drill pipe is now centralised and ready to be sheared - as was the case with the Macondo BOP. Further flaws appeared in the DNV postulation, for example: • No explanation was given for the cause of the extreme dynamic force that supposedly lifted 3000ft of drill pipe until its topmost tool joint lodged in the upper annular preventer. If the 'blocked' section of pipe referred to earlier had been subjected to a pressure of 5000 psi at the blockage underside, it would have been balanced by the static weight of the suspended drill pipe. • The model employed to generate the buckling mechanism calls for the tool joint to be fixed vertically by the annular preventer, but free to rotate. At the upper VBR, the drill pipe was considered to be restrained laterally, but free to move vertically. Any column buckling mechanism requires the reaction planes to be fixed vertically. This clearly does not apply to the DNV postulation. Furthermore, the upper annular preventer was in no condition to act as a fixed plane of any description. And neither was the VBR. • Cameron made the point that the buckling scenario could not have arisen because the location of the pipe segments discovered in the BOP/LMRP did not fit with the postulation. DNV was forced to concede the point. • Cameron also pointed out that the forensic examination of drill pipe recovered from the BOP/LMRP did not find any evidence of a buckled drill pipe - or anything remotely like it. Although DNV/BOEMRE did test the closure times and activation pressures for the BOP rams, they did not actually replace the damaged blades and attempt to shear drill pipe. That was a major omission in this forensic exercise. They might then have filled the drill pipe with compacted, lean concrete and repeated the shearing exercise. But they did not. Did determining the truth perhaps take second place to meeting a tight deadline on this occasion? Postulation is just that. It is a suggestion made in the absence of hard facts. To support the postulation, BOEMRE and DNV should have run tests to see if they could recreate the event they had described, before announcing it to the world. Indeed, examination of the DNV report reveals that is just what they recommended for future work. What `actually' happened As has been discussed in earlier OE articles over the past year, the Macondo disaster was manmade and it is the human element that has to be improved. But this piece is about the BOP, a gentle giant summoned to do the impossible but shackled at every turn it seems. Here, in my view, is what actually happened to it: • The upper annular preventer had been severely damaged by stripping out 2000ft of drill pipe during a previous, major well control exercise. • Further uncontrolled stripping occurred as a result of the explosion and the Deepwater Horizon moving off station and sinking. • The EDS was activated by the drill crew a full 15 minutes after a full-blown volcanic blowout erupted from the drill floor (and seven minutes after the two explosions). No BOP had ever been qualified to operate after such a blowout; it was being asked to operate outside its operational parameters and capability. hitp://oe.oiIonIine.co m • • • • The erupting well fluids contained metallic drilling debris, reservoir sandstone, cement chippings and marbles. The ram blocks, blades, and elastomeric seals had not been qualified for such awful service conditions. Photographs in the DNV report reveal the horrific erosion to which the BOP/LMRP internals had been subjected; there was absolutely no chance of them sealing in the face of such an assault. The elastomeric seals were powerless to resist; their destruction would have been instantaneous. Without them, the BOP could not possibly have sealed the wellbore. • The explosion and subsequent inferno ripped out the two surface MUX cables and the surface hydraulic umbilical. It is likely too that their disintegration was instantaneous. • With the loss of the cables and umbilical, the EDS had been deactivated. The LMRP could not be retracted, and without that, the autoshear system (to the BSRs) could not be activated. • Loss of all contact with the surface facilities should have activated the self-sufficient AMF system. But this did not happen due to the poor state of repair and maintenance of each control pod. Subsequent onshore forensic testing on the repaired/refurbished AMF system demonstrated the operational veracity of system as designed. 0 It is possible that the drill pipe running through the BOP/ LMRP had been filled with compacted debris, thereby exceeding the capability of the blade to shear it cleanly. • By the time ROV intervention was activated, it is probable that the shear blades were so disfigured and eroded that they were unable to shear drill pipe in the specified time. Inspection of the recovered sheared drill pipe does not reflect the general squashed -lips and fold -over configuration that is usually found with sheared drill pipe. Shutting the stable door This tragedy will undoubtedly emphasise the need for better training of drilling crew personnel (including annual, compulsory simulator training), and rigorous maintenance of BOP systems. But just as important is a review of the BOP that became a victim of the Macondo disaster, not the perpetrator. From the outset, I have to make the following points: • Had the Macondo well been safely executed, the BOP/LMRP configuration would have been adequate for the well control purpose. • Had the BOP control system been correctly maintained, its configuration would have been adequate for the purpose. • Had the drill crew not delayed activation of the EDS by 15 minutes (after the mud surfaced on the drill floor), the blowout could probably have been managed • Had the drill crew maintained the diverter route to open sea, it may have averted the explosion. It would certainly have given them more time to escape. But it does occur to me that the industry needs to adopt a safer BOP stack -up configuration. Things that went disastrously wrong here could still have been controlled with a revised BOP configuration along the following lines. If there is an Achilles heel in current BOP stack -ups, it is the inability of the BSRs to shear tool joints. Tool joint locations are usually measured and determined from the drill floor so as to avoid any conflict with the BSRs. In a controlled situation this works well; in an uncontrollable situation, it does not. The inclusion of a second set of BSRs within the BOP would resolve this issue. The use of twin MUX cables and twin control pods appears to reflect the prerequisite for a secure system since, on the face of it, this would seem to remove the possibility of a major single point failure. Unfortunately it does contain the possibility of a single point failure represented by the integrity of the drilling riser. When that is lost, so is the operation of the control system We have also seen that gathering both cables and the hydraulic umbilical to a single location around the drilling riser exposes them all to the same risk of fire and explosion and loss of the drilling riser. If both MUX cables and the hydraulic umbilical are lost, as was the case, we are then dependent on the self- standing AFM system to function - which did not happen because both control modules were inoperable due to either poor maintenance or in-service failures A separate direct hydraulic umbilical is required to control the BOP/LMRP safety critical functions (BSRs. autoshear. LMRP disconnection etc), and it should be run from a separate, stand-off support vessel. Failing that, the direct hydraulic umbilical could be run as far away from the drilling riser as possible, and at an extreme, safe location on the rig. If there is room for improvement in respect of the BOP stack - up used on the Deepwater Horizon, it is the use of two annular preventers located on the LMRP. I appreciate this arrangement optimises the height of the individual BOP/LMRP components, but it does separate the BSRs from the first annular preventer by inclusion of the BOP connector. In order to allay any doubt about off-centre drill pipe through the BSRs. the lower annular preventer should be located on the BOP immediately above the BSRs. This is well established, operational drilling practice and should be maintained as such. The connection of the drilling riser to the LMRP is flanged. Macondo has demonstrated that in respect of a collapsed drilling riser, and to facilitate any emergency well capping equipment, the flanged connection should be replaced by a more efficient, quick disconnection system. The flanged connection should be replaced by an hydraulic connector, also under the secondary control of the direct hydraulic umbilical standby. It may sound fanciful, but I wonder it is possible to instrument a BOP to give warning to the driller that a potential blow out is on its way? This would be particularly valuable when dealing with deepwater risers. Subsea xmas trees are routinely equipped with non -intrusive sand detectors and multiphase flowmeters. It may be possible to extrapolate this technology to enable the driller to `hear' the blowout at an early stage, rather then being dependent on measuring mud returns (which did not happen during the Macondo blowout). A ioint industry study should be established to investigate of possibility of providing enhanced BOP instrumentation to give early warning of an erupting blowout. Finally, if something could be done to improve the performance and durability of the raw elastomeric seals used in BOPs it would be a major improvement. DNV also commented on this consideration and it is definitely worthy of serious consideration. Would metal tipped/faced elastomeric seals - similar to those used for XT/wellhead applications - be a possible solution? The kind of measures listed here would represent a very small investment when compared with the reported $20 billion cost of the Macondo disaster. More importantly they would have improved the survival chances of the Deepwater Horizon and the 11 crew members who perished, and might even help cut the risk of a Macondo-like tragedy ever happening again. CIE © Ian Fitzsimmons, June 2011 Ian Fitzsimmons, a regular contributor to OE, is an independent consultant with more than 30 years' offshore industry experience. He has worked for major operators around the world and major subsea hardware/drilling equipment contractors, and has extensive due diligence and expert witness experience. He was chief engineer for RJ Brown & Associates in London. The views expressed in this article are the author's own and do not and the ESD system. http:floe.oilonIine.com necessarily reflect OEs position. OFFSHORE ENGINEER I july 2011 49 • • OEs analysis of current rig market data is updated monthly using statistics provided by Rigzone.com Rig market Worldwide utilization for the mobile offshore drilling fleet continues to track within a 69-72% range overall. Jackup utilization continues to lag the overall average but has held steady at 67-68% for the past three months. Recent tendering activity is supportive of a modest gain in jackup utilization over the summer and fall months. Global drillship utilization is a comfortable 80%. Orders for new drillships continue to trickle in, implying even greater demand in future years. Semisub utilization has been flat for the past five months at 78%. As the jackup fleet has the widest room for improvement, stronger demand for shallow water rigs will likely push the overall utilization average higher in the upcoming months. Looking specifically at Southeast Asia, judging the state of the market based on utilization is tricky because even though the number of contracted rigs has grown over the past twelve months, the marketed fleet has expanded at a faster pace. Thus, overall utilization is down even though the number of rigs working has improved. In contrast to other regions, jackup utilization is the strongest of the three types of rigs at 72%. This compares to overall utilization for the 93 marketed rigs that comprise the Southeast Asian fleet which are trending around 60% in any given month. Semisubs posting low 30% utilization levels are the root of the overall weak figure. Drillships in Southeast Asia are working approximately 60% of the time over the past 12 months. Worldwide rig utilization 1W`d 95°b 90% n s ip 85% emi 80% 75% _- 70% us% Jackup 60% -- Southeast Asia rtg utilization ro% a0% 2D% Transocean's Macondo report pins blame on BP n internal Transocean investigation into the explosion and loss of the Deepwater Horizon found that the tragedy was the result of `compromised' well integrity due to a series of well design, construction and temporary abandonment decisions made by operator BP, Transocean said 22 June. The Transocean investigation, launched shortly after the 20 April 2010 blowout at the Macondo well in the deepwater Gulf of Mexico's Mississippi Canyon block 252, blamed the disaster on 'a succession of interrelated' decisions by BP that increased the risk of a blowout. 'The decisions, many made by the operator, BP, in the two weeks leading up to the incident, were driven by BP's knowledge that the geological window for safe drilling was becoming increasingly narrow,' Transocean said. 'Specifically, BP was concerned that downhole pressure — whether exerted by heavy drilling mud used to maintain well control or by pumping cement to seal the well — would exceed the fracture gradient and result in fluid losses to the formation, thus costing money and jeopardizing future production of oil.' Transocean accused BP of failing to properly assess, manage and communicate risks to Macondo contractors. The company said drill crews were not properly informed about problems with tests measuring the integrity of the cement slurry used to plug the well and that BP ran through a 'series of last-minute alterations' to the temporary abandonment plan before settling on a method that did not have the required approval of federal regulators. Despite lost circulation events and kicks while drilling the Macondo well in 5000ft water depths, Transocean said BP proceeded with its original plan to cement a long -string casing rather than alter the casing design to reduce the risk of a well control incident. 'The resulting cement program was of minimal quantity, left little margin for error, and was not tested adequately before or after the cementing operation. Further, the integrity of the cement may have been compromised by contamination, instability and an inadequate number of devices used to center the casing in the wellbore,' Transocean said. BF and Halliburton, which provided cementing services, 'did not adequately test the cement slurry program, despite the inherent complexity, difficulties and risks associated with the design and implementation of the program and some test data showing that the cement would not be stable', Transocean said. The blowout and fire aboard the Deepwater Horizon rig killed 11 workers and poured an estimated 4.9 million barrels of oil into the Gulf of Mexico. Transocean said it was not clear why the drill crew did not detect a pressure anomaly until shortly before the explosion, but that the crew undertook appropriate well control actions once the influx of hydrocarbons had been identified. The well's blowout preventer had been properly maintained, Transocean said, but was overcome by'extreme dynamic flow' that caused the drill pipe to bow inside the BOP, preventing the shear rams from completely closing — a conclusion also reached by a recent Det Norske Veritas forensic examination of the device. 'The loss of evidence with the rig and the unavailability of certain witnesses limited the investigation and analysis in some areas,' Transocean said. 'The team used its cumulative years of experience but did not speculate in the absence of evidence. The report of the team does not represent the legal position of Transocean, nor does it attempt to assign legal responsibility or fault.' The results of an internal investigation by BP released last September sought to spread blame more widely, attributing the disaster to 'a complex and interlinked series of mechanical failures, human judgments, engineering design, operational implementation and team interfaces.' A federal joint investigation team is set to release a final report on the Macondo disaster by 27 July. RM 20 OFFSHORE ENGINEER j july 2011 http://oe.oiIonIine.D0m r� u Bud's Offshore Energy (BOE) Air France crash and well control July 29, 2011 by otfshoreenergy We have posted several articles about the tragic Air France 447 crash in the Atlantic, and commented on parallels between aircraft safety and well control, most notably the instrumentation, data monitoring, and crew response aspects. Our friend and frequent contributor, JL Daeschler, has been closely following the 447 investigation. He forwarded this very ineteresting_article which identifies behavior that has also been noted in well control incidents. This quote is particularly telling: Aviation experts, however, said the evidence so far left little room for doubt the pilots failed to react correctly. "It seems obvious the crew didn't recognise the situation they were in, for whatever reason, and more training could have helped," said Paul Hayes, safety director at UK consultancy Ascend Aviation. 0 http://uk.news.yahoo.com/air-france-crash-probe-finds-pilots-ignored-waming_s- 115001901.html Air France crash probe finds pilots ignored warnings REUTERSBy Tim Hepher I Reuters —Fri, Jul 29, 2011 PARIS (Reuters) - Pilots of a doomed Air France jet which crashed into the Atlantic two years ago killing all 228 people onboard ignored stall warnings and appeared to defy the manual, a new crash investigation report showed on Friday. The inquiry by France's BEA air accident investigator into the final minutes of flight AF447 found pilots lacked training to handle the freezing of speed sensors and failed to discuss stall alarms as the Airbus jet plummeted 38,000 feet, slamming into the ocean at 200 km (125 miles) per hour. The BEA issued 10 safety recommendations aimed at avoiding a repeat of the crash, in particular better training for pilots to fly aircraft manually -- a skill industry critics say has been eroded by computerised flight. Though investigators stopped short of explicitly blaming either the crew or the aircraft and its systems, their report confirmed a finding in May that the pilots responded to stall • warnings by doing something that has mystified aviation experts ever since -- pointing the nose up instead of down. An aerodynamic stall -- not to be confused with stalled engines -- occurs when an aircraft's wings are unable to support it and the textbook way of responding is to point the nose downwards to capture air at a better angle. "The situation was salvageable," BEA Director Jean -Paul Troadec told a news conference when asked if the crew could have righted the aircraft after its speed sensors froze. He announced the creation of a panel of experts, including psychologists and aviation experts, to study why the pilots reacted as they did. A final report is due later this year. Friday's interim report, based on detailed study of black boxes recovered from the ocean floor, revealed passengers were not given any warning as pilots struggled to control the plane amid turbulence in the early hours of June 1, 2009. The report stoked simmering tensions between the heavyweights of France's aviation industry, Air France and EADS unit Airbus, over whether the airlines' pilots or faulty flight equipment were most to blame for the disaster. "At this stage, there is no reason to question the crew's technical skills," Air France said • in a statement, blaming the "misleading stopping and starting of the stall warning alarm" for confusing pilots with a blizzard of information. • Aviation experts, however, said the evidence so far left little room for doubt the pilots failed to react correctly. "It seems obvious the crew didn't recognise the situation they were in, for whatever reason, and more training could have helped," said Paul Hayes, safety director at UK consultancy Ascend Aviation. LAWSUITS MAY FOLLOW Airbus, which insists its planes are safe, welcomed the report and said the whole air transport community could benefit from the lessons to be learnt from the crash. The question of who is to blame is of huge importance as both firms face criminal probes in France. Victims' families have laid the foundation for lawsuits on both sides of the Atlantic. During normal computer -assisted flying, Airbus systems are designed to prevent a stall developing even if the pilot errs. But in this case the A330 was being flown manually after the autopilot switched itself off in the wake of a temporary loss of reliable speed data, thought to be caused by ice on the Pitot speed sensors made by French aerospace firm Thales. • The pilots had not been trained on a procedure known as "Unreliable IAS (indicated airspeed)" or on manual aircraft handling at high altitudes, the BEA said in a statement. Black box data suggested a 32-year-old junior pilot flying when the incident began, pulled back on the stick despite a series of stall warnings, including one lasting 54 seconds. A lawyer for some victims' families, however, said the BEA's emphasis on the role of the pilots was "very questionable" and without equipment failure the situation would never arisen. "This is perhaps a way of BEA freeing the firms from their responsibility," Olivier Morrice told Reuters. "Stall, stall" The plane's 52-year-old captain had started a routine rest period when the incident occurred, having left without giving clear operational instructions, the BEA said. By the time he returned to the cockpit a minute and a half into the emergency, the aircraft was unable to calculate its angle and therefore the stall warning had stopped. When the pilots took correct action, the alarms went off again. • • France's SNPL airline pilots' union said this behaviour by the alarm misled the crew. It said the combination of the failure of speed sensors, disconnection of autopilot and breakdown of stalling protection systems was a totally new situation for which the manufacturer had not planned training. "It is not possible to say it was human error. It is too narrow to say it was the fault of the pilots," said Air France Chief Pilot Eric Schramm, adding the crew may have thought they were flying too fast, a situation which would have called for the stick movements they made. Pilots say an Airbus stall warning consists of a synthetic voice crying "stall, stall," an alarm nicknamed the "cavalry charge," and a red master warning light on the instrument panel. The BEA report proposed adding an extra instrument to reinforce audible stall alerts and called for black boxes to record a video image of what pilots see on the computer screens that nowadays replace a forest of dials, although unions fear this could be misused. (Additional reporting by Daniel Flynn, Yves Clarisse, Patrick Vignal and Alexandria Sage; Editing by Sophie Hares) • ��l 0 f UeVINIX Feds' offshore powers cover contractors http://fuel fix.com/blog/2011 /07/23/feds-offshore-powers-cover-contractors/ For decades, the U.S. agency that polices offshore drilling has had a laser -like focus on the companies searching for oil and gas in federal waters. But now under the leadership of a former federal prosecutor, the agency is expanding its regulatory reach beyond oil and gas companies to the drilling rig owners, service firms and other contractors that work for operators. "No one operating on the outer continental shelf should be immune," argues Michael Bromwich, the head of the federal Bureau of Ocean Energy Management, Regulation and Enforcement. And, Bromwich adds, it would be irresponsible for the government to turn its back on any "egregious" behavior offshore, just because it's by a rig owner, cement contractor or any other service firm. Bromwich insists that a new legal interpretation of the ocean energy bureau's authority confirms that the • agency can pursue fines and other civil penalties against offshore contractors that behave badly — even though he stresses that the chief focus will remain on operators. Last year's Gulf oil spill put a new focus on the way the oil and gas industry is regulated, especially after a presidential commission said the disaster was evidence of systemic problems and poor communication among the broad cast of characters involved in the project. At the very top of the chain was BP, the primary offshore operator who held the lease on which its failed Macondo well was drilled. Other companies also were involved — including Transocean, which owned the Deepwater Horizon rig working on the job, and Halliburton, which applied cement barriers at the well site. Bromwich said the spill revealed holes in the bureau's traditional approach to enforcement because, no matter what or who caused last year's disaster, the agency generally would be limited to holding the primary operator — BP — responsible. Even so, the agency's traditional focus on operators does not bar BP from suing its contractors independently. It also doesn't block the Justice Department from pursuing criminal or civil claims against others involved in an offshore accident — just as is happening now in a federal district court in New Orleans. Bromwich also was frustrated earlier this year after he unsuccessfully pressed Transocean to help ensure that two of its employees would testify before a federal probe of the spill. "This served to underscore the sense that Transocean — and other contractors and subcontractors — were acting as though they had no regulatory obligations," Bromwich said. By upending a longstanding practice of making offshore operators solely responsible for accidents that happen under their watch, contractors say the change casts doubt on their legal liability and the risk their insurers take on. 0 • "It's not well defined, so insurance companies are unsure how to insure for it and what kind of premiums (to charge)," said Randall Luthi, head of the National Ocean Industries Association. "We in industry always feel that it's important that you tell the regulated what you're going to expect from them, and how you are going to regulate them," Luthi said. "But those details apparently are lacking." Brian Petty, the executive vice president of government affairs for the International Association of Drilling Contractors, said Bromwich is overturning a system has been "settled" for decades. Any move to shuffle the system and create "an opening for government action without any parameters" is unsettling, Petty said. "This gives us huge indigestion." He added that the insurance calculations and threat of unlimited risk could discourage some rig owners from operating in U.S. waters. "In this robust global drilling market, drilling contractors will have to assess whether they want to take on the possibility of that exposure," Petty said. Facing a backlash from some Gulf Coast lawmakers on Capitol Hill, Bromwich has appeared to scale back plans that initially seemed much more ambitious. When he first announced the plan at the Offshore Technology Conference in Houston this May, Bromwich stressed that the ocean energy bureau has "broad legal authority over all activities relating to offshore leases, whether it is engaged in by lessees, operators or contractors." "We can exercise such authority as we deem appropriate," he added, in a room filled with representatives from the very contractors he was targeting. • But after testifying before the House Natural Resources Committee on July 15, Bromwich told reporters that the change wasn't going to be "a revolution" or "the new dominant strain in our regulation." And he made clear that his agency does not plan to issue new regulations targeting offshore operators. Not everyone is assuaged. The House is set to debate a government spending bill next week that would bar the ocean energy bureau from using federal dollars to go after contractors unless it explained its authority to Congress. Although the provision stops short of an outright ban, it is a signal that lawmakers intend to keep a close watch on the issue. One of them is Rep. Jeff Landry, R-La., who argues that the ocean energy bureau's move creates too much uncertainty. "It's going to create a very crowded chain of command when it comes to incidents in the oil and gas industry," Landry said. Landry insisted that companies that perform badly already pay a price in the free market. "If you do a bad job, you're going to go out of business," Landry said, adding that companies face a bigger, ,'more onerous" penalty in the free market — "more than anything the government can do." • http://fuelfix.com/blog/2011/07/22/feds-oil-spill-probe-delayed-again/ Feds' oil spill probe delayed again Posted on July 22, 2011 at 10:25 am by Jennifer Dlouhy in Gulf Oil Disaster; Interior Department 0 The government's chief investigation into last year's Deepwater Horizon disaster will not be complete by a July 27 deadline, officials confirmed today. • The probe by the U.S. Coast Guard and the Interior Department has already received two extensions, partly because of delays in testing emergency equipment that failed to stop the Gulf oil spill. In February, the government said it was aiming to issue the report by July 27. Joint investigation team members now are putting the final touches on a report summarizing their conclusions about what led to the lethal explosion of the Deepwater Horizon rig in April 2010. "To ensure that all evidence is properly weighed and considered, the JIT is taking additional time to finalize the report," said Eileen Angelico, a spokeswoman for the joint investigation team. "The team is in the final stages of completing its report and expects to release it in the near future." Although it is not clear when the government will issue its findings, Angelico stressed that the group "is working diligently to complete its report." The Coast Guard and Interior Department probe is one of several investigations of the Deepwater Horizon disaster, including a few that are still ongoing. The National Academy of Engineering and the Chemical Safety Board are still investigating. A presidential commission investigating the spill concluded in January that the disaster revealed "systemic" failures by the offshore drilling industry and federal regulators. 0 http://fuelfix.com/blog/2011/07/21 /steffy-reforms-at-bp-fall-short/ fuevrix Steffy: "Reforms at BP fall short" 0 The mobile offshore drilling unit Development Driller III at the Deepwater Horizon site on May 7, 2010. (U.S. Coast Guard file photo) BP's strategy for returning to the Gulf of Mexico is going according to plan. Getting back in the Gulf has been the company's focus almost from the moment the burning wreckage of the Deepwater Horizon slipped below the water's surface, and everything it has done during the past year has been designed to make it possible. Last week, the company took another step. Less than a year after its disastrous Macondo well was capped, it sent a letter to the Bureau of Ocean Energy Management, Regulation and Enforcement outlining a series of voluntary performance standards that BP hopes will prove that it's changed its ways since unleashing the worst oil spill in U.S. waters. Technically, of course, BP has been back in the Gulf for months. As I wrote in March, it's the majority owner of the well that got the first new drilling permit since the disaster, but BP isn't the operator. Now, the company is itching to run its own projects again. Its voluntary standards, though, are an underwhelming response to more than a decade of operational and maintenance failings marked by more than two dozen worker deaths and scores of debilitating injuries. Despite BP's repeated promises to change, it hasn't. And the voluntary standards it now offers in hopes of unlocking its lucrative prospects in the Gulf are tinged with a chillingly familiar sense of deja vu. In the past year, BP has worked diligently to cast the accident as an industry problem, as something that grew not out of its own culture and poor oversight, but something that could have happened to any drilling company. 0 • Its new standards include a second set of blind shear rams to help seal a well if a problem arises, improved testing of blowout preventers, better review of cement tests and an enhanced spill response program. Calculated steps These are all good steps, and, like everything else BP does, they are carefully calculated. They are things that all companies operating in the Gulf should consider after the Macondo disaster. They also are largely directed outwardly — watching over the cement formulas and blowout preventers designed by others, for example. The procedures, though, aren't all that stringent. Some of them BP already has to follow in other countries in which it operates. Yet for all its talk of a companywide focus on safety, BP isn't applying its new standards to all the company's operations. It letter referred merely to its Gulf operations. That's reminiscent of the aftermath of the Texas City refinery explosion, when BP chose to apply the recommendations of an independent investigator only to its U.S. refining operations, not to other aspects of the company. More change needed What's missing is the same thing that always seems to get overlooked when BP is mopping up after one of its operating failures — a restructuring of its internal decision -making and oversight. What's more, some of the "new" procedures are things that BP had claimed to be doing as far back as 2009. That's when the head of its Gulf operations told Congress about new technologies it had supposedly adopted, such as real-time well -control techniques, an action the company now says it implemented after the Macondo accident. isOnce again, it seems, BP's actions are years behind its words. Even as it was preparing to send its letter last week, a BP -operated platform in the North Sea off Norway erupted in flames in what the company itself described as a "serious incident." Then, just days later, BP experienced yet another pipeline leak in Alaska during a maintenance operation, causing a release of methanol and oily water. By themselves, these incidents might not say much about a company's ability to drill safely. But with BP, the pattern is all too familiar. So are the repeated promises, issued by the past three CEOs, that it will change how it operates. It hasn't yet. Nor has it offered any convincing evidence that it will. Loren Steffi, is the Chronicle's business columnist. His commentary appears Sundays, Wednesdays and Fridays. Contact him at loren.siefr,la;chron.com. His blog is at http://blogs.chron.com/lorensteffj-. Follow hint on Twitter at t witter. com/lsteffy. 0 • • • anaivsis Macondo under the microscope The US Coast Guard in April released a report on its investigation into BP's DeepwaterHorizon disaster, just weeks after DNV delivered the results of its forensic examination of the Macondo blowout preventer. Both will inform the Joint Investigation Team's final report, due 27 July. Russell McCulley reports on the information —and the reaction — so far. he final report from Det Norske Veritas Columbus (DNV), delivered to the US Bureau of Ocean Energy Management, Regulation & Enforcement (BOEMRE) and US Coast Guard 23 March, concluded that a portion of buckled drill pipe prevented the Macondo BOP's blind shear rams from completely closing. DNV investigators said flow pressures from the deepwater well forced a portion of the pipe between the upper annular and upper variable bore rams to bend; at the point where the BOP's blind shear rams were Blowout containment goes global designed to sever the pipe and seal off flow, the pipe was off - center, preventing the rams from fully activating (OE April). At an early April Joint Investigation Team hearing, David McWhorter — VP of engineering & quality for drilling services at Cameron, manufacturer of the BOP — said the DNV report'excluded or ignored' possible alternative causes for the device's failure, including the possibility that 'a finicky solenoid valve' and insufficient hydraulic pressure could have led to a partial or underpowered Nine major oil & gas companies have launched a project designed to improve the industry's ability to respond internationally to a subsea well blowout and spill. The companies —BG Group, BP, Chevron, ConocoPhillips, 6aonMobil, Petrobras, Shell, Statoil and Total — have signed an interim joint development agreement to create the Subsea Well Response Project and appointed former Shell VP Keith Lewis to manage the effort. The companies said the SWRP will design a'capping toolbox for shutting in wells, create hardware for subsea injection of dispersant and assess the feasibility and need closure of the shear ram. 'There is a possibility that the shear ram could have been functioned not through the high pressure circuit but through the manifold pressure, which would be 1500psi, and it's possible that if that happened, we wouldn't have near enough hydraulic force pressure — you could not generate enough force Cameron's David McWhorter being sworn in at a Joint Investigation Team hearing in New Orleans. for a spill containment system that could be shared among operators. The group will also'recommend a model for international storage, maintenance and deployment of this equipment,'the release said. The agreement follows a set of recommendations, handed down by the International Association of Oil & Gas Producers' Global Industry Response Group, on how operators should respond to a subsea well control incident like last year's BP Macondo blowout in the Gulf of Mexico. 'SWRP will now work to deliver on these objectives over the course of 2011; Lewis said. 'Designing systems that can be deployed effectively in different regions of the world is an immense challenge but member companies have assigned leading specialists to the task.' Houston's Wild Well Control, a subsidiary of New with that pressure to cut the pipe.' McWhorter, who was on hand to answer questions and offer technical advice when Orleans -based Superior Energy Services, is also preparing to introduce this fall a subsea spill containment system that the company said can be deployed anywhere in the world in a matter of days. The Global Subsea Containment System, designed for use in water depths of up to 15,000ft, will be housed in Aberdeen and deployable by air, Wild Well Control EVP and general manager Bill Mahler said at OTC 2011 in May. The company was heavily involved in the effort last year to cap the Macondo well, which spilled an estimated 5 million barrels of oil into the Gulf of Mexico before it was plugged with a capping stack and oil & gas capture system. Wild Well Control and the SWRP join two other US -based capping systems developed by Helix Energy Solutions and the IOC -funded Marine Well Containment Company. RM Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe.aiIonIine.cam For reprints please contact the Publisher. OFFSHORE ENGINEER j june 2011 13 Deepwater output dip forecast It could be another five years before deepwater Gulf of Mexico oil & gas production recovers from the disruption caused Macondo, according to a new report from Wood Mackenzie. April's Upstream Insight -North America report, released on the first anniversary of the disaster, estimates that the federal moratorium on new drilling permits imposed after Macondo clipped average production in 2010 by some 80,O00boe/d. Deepwater Gulf of Mexico production this year will average 375,OOOboe/d lower than most analysts predicted before the disaster, WoodMac said. The Obama administration lifted the moratorium last October and at the end of February this year BOEMRE issued the first post-Macondo drilling permit to Noble Energy, allowing work to resume at the its Santiago prospect. According to BOEMRE statistics, as of late May the agency had approved 36 permits for 14 unique wells and had 18 applications pending. The agency returned 26 applications to operators, requesting additional information. WoodMac said that permitting levels would likely reach 'a new equilibrium' in mid-2012. 'We assume that extensions to pre-Macondo approval periods will be negligible to overall project timelines. Exploration drilling is expected to strengthen during 2012 and re to healthy levels during 2013,' the report said, countering early fears of a mass exod of rigs from the US Gulf and claims by some'` operators that development costs will rise 1 to 20% as a result of beefed-up regulations. The report notes that four of the seven deepwater rigs to leave the region during the drilling suspension are scheduled to return during 2011, with another four newbuild rigs slated to arrive in the Gulf this year. Day rates are likely to `remain steady in the near -term'. `Much uncertainty remains around potential time extensions to drill a well, but we currently assume that any increases will be negligible to overall project economics,' WoodMac noted. Deepwater production will continue to lag for a few years before new projects help push production beyond pre-Macondo levels in 2016, when WoodMac predicts Gulf of Mexico production will hit a new peak of nearly 2 million boe/d. 'In 2011, we calculate that a staggering 375,OOOboe/d, or 20% of previously estimated production levels, is expected to be pushed back. 'This is difficult for many to accept when energy demand is strong, supply is constrained by the current geopolitical environment and Brent Crude is trading o US$100/bbl.' the forensic examination was under way at NASA's Michoud facility in New Orleans, said a solenoid valve recovered from the Macondo site 'operated intermittently' during tests. 'Also, there were at least a handful of cases during the course of the intervention in which the shear rams were double clutched,' he said. 'In other words, pressure was applied to the BOP and then it was relieved. It was applied and relieved. There were at least a handful of times in which that happened. And that was not considered as a possibility for the wellbore environment that they found when they took the BOP apart. I have questions about that.' In a meeting with reporters during May's Offshore Technology Conference in Houston, BOEMRE director Michael Bromwich acknowledged that 'there were some challenges to the forensic findings'. 'We're still in the process of evaluating both the report and > page 16 )r retransmission. 9 Bromwich: contractors must assume responsibility too Oilfield service companies and contractors could face fines and other punitive measures that traditionally have been the responsibility of the operators they work for, US Bureau of Ocean Energy Management, Regulation & Enforcement director Michael Bromwich said at OTC in Houston last month. The change in policy is a break with the practice of assigning all responsibility for operations to oil company leaseholders, Bromwich said. BOEMRE has 'broad authority' under existing law to pursue actions against service companies and contractors whose operations run afoul of safety or environmental rules, he said. 'I'm not sure how much it's going to change our day-to-day practice,' Bromwich said of the new interpretation of existing law. 'Because it's important that we preserve the principle that operators are fully liable for things that go wrong — not just accidents, but even regulatory violations.' It was not clear what relevance, if any, the new policy will have on the Deepwater Horizon aftermath. Some investigations have accused contractors Halliburton, which carried out cementing operations, and Transocean, the rig owner, with varying degrees of responsibility for the blowout and spill. `Where the behavior of ... contractors is egregious enough; we need to have the ability to move directly through enforcement actions.' Michael Bromwich. BOEMRE Operator BP has so far footed the bulk of the multi -billion dollar cost of the spill response and environmental and economic reparations; in late May BP collected $1 billion from 10% Macondo interest holder MOEX to cover the Mitsui subsidiary's share. Anadarko, which holds 25% interest in Mississippi Canyon block 252, has thus far refused BP's requests for reimbursement. 'Certainly, in at least some cases where the behavior of non -operators — that is, contractors — is egregious enough, we need to have the ability to move directly through enforcement actions, through the assessment of civil fines, and through the other regulatory tools that we have, against non -operators,' Bromwich said. 1 think that's an important principle to have out there so that people know that that's our view of what our power and authority is. It's fairly clear under the law. It was not as clear within the OUR STATE-OF-THE-ART OIL CONDITION MONITORING PROGRAMME HELPS YOU MANAGE YOUR EQUIPMENT MORE EFFECTIVELY AND CONSISTENTLY TO CONTROL COSTS AND MINIMIZE DOWNTIME. Content is copyright protected and provided for personal use only For reprints please contact the Pub agency because of the historical practice of going exclusively against operators.' Bromwich said the agency does not need to issue any new rules governing the on -lease activity of contractors but could release guidelines clarifying the policy if necessary. In the year since the disaster, BOEMRE has issued strict new rules governing deepwater drilling and safety and launched an effort to beef up its regulatory and permitting staff. Bromwich suggested that the new policy toward operator liability would likely have little impact on offshore activity. 'But I think there are at least a small number of cases in which we want to be able to go against the contractors,' he said. 'And I didn't want to be in the position where we were essentially declaring unilateral disarmament with respect to contractors and failing to assert authority that we have under the law.' RV Quick scats OE's at -a -glance guide to New discoveries announced offshore hydrocarbon reserves Depth and key offshore infrastructure range 2008 2009 2010 2011 globally is updated monthly Shallow , 141 106 75 16 using data from leading Deep 0001wil 30 38 24 5 energy analysts Infield Systems Uhradeepo, 22 S2 18 3 (WWW.infield.com). TOW 199 176 117 Note. Opera;ms do not announce discovery dales at the time of discovery, so totals for previous years can continue to change. eserves in the Golden Triangle water depth 2011-15 Water Field Liquid Gas depth numbers reserves reserves (mmbbl) (bcf) Shallow 52 3844.45 20,493.79 Deep 26 3639.50 2460.00 m Ultradeep 28 5279.20 6530.00 Shallow 26 131.10 1384.00 h Deep 32 1982.36 2175.57 Ultradeep 21 1964.25 1930.00 4e$ Shallow 156 3509.51 12,966.15 Q Deep 47 7401.50 5830,00 3 Ultradeep 13 2140.00 1490.00 401 29,891.87 55,259.51 EEER (last month) (41§ ;'.440.53) ,- -._ Floaters: nan1A) Operational 242 Greenfield reserves 2011-15 Under construction/conversion 26 Water Field Liquid Gas Planned/possible 267 depth numbers reserves reserves 533 (635) (mmbbl) (bcf) Fixed platforms: )aSlnWnth) (last recent) Operational 9548 Shallow 1335 74,365.58 649,112 36 Under constructioniconversion 129 (1347) (74,206.7e) (1152 T14) Planned/possible 1541 Deep 168 15,474.86 73,155.84 11,218 n1.1751 (178) (15.797.36) (74.%5.84) Subsea wells: Operational 4083 Uhradeep 68 9423.45 38,050.00 Underdevelopment 407 I lanned/passibl2 4934 1571 99.263.89 760,318.20 9424 Global offshore reserves (mmboe) onstream by water depth zuU9 2010 2011 2012 2013 2014 2015' Shallow water 11,697,32 10,018.14 23,215.65 45,627.00 40,581.70 37,162.67 41,930.64 (bstmonth) (11,69522) (1(1,059.62) (23,13327) (46,422.60) (39,825,84) (37A54.66) (41.632.76) Deep 5013,66 2457.43 2371.42 3286.74 5735.44 10.N.39 6%7.95 (laslmonth) I913.66) (2461.93) (2378111) (3602.15) (5419.69) (10.33090) (7319.08) Itradeep 1042.96 938.06 502.76 1342.98 886.73 6350.52 7049.04 • (l3sltmrFT) (523.92) (1321.82) ('06456` (W.83) (7365.82) Total 17,753.94 13,413.62 26,089.83 50,255.72 47,203.87 53,571.58 55,937.63 All reserves Ilgmes are prove-, probable. Content is copyright protected and provided for pers( 16 OFFSHORE ENGINEER I june 2011 For reprints please cot the criticisms of the report. omissions by Transocean and And we're factoring all that its Deepwater Horizon crew, together as we move forward that had an adverse impact with our investigation. on the ability to prevent 'That's still a work in or limit the magnitude of progress.' the disaster'. The report Bromwich said it was 'too cited 'poor maintenance of early to know' what, if any, electrical equipment that may new BOP requirements may have ignited the explosion, be in store. bypassing of gas alarms 'We've said all along that and automatic shutdown future rule making ... will systems that could prevent an include specific enhancements explosion, and lack of training relating to blowout of personnel on when and preventers,' he said. 'What the how to shut down engines and configuration combination disconnect the MODU from the enhancements of those will well to avoid a gas explosion be will be driven at least in and mitigate the damage from part by what are the final an explosion and fire.' findings emerging from that The Coast Guard also investigation.' charged the Republic of the BOPs are but one element Marshall Islands, the rig's in an overall drilling safety flag state, with 'ineffective' scheme, and not 'failsafe oversight and regulation and devices' that can alone prevent recommended that the USCG another disaster, he said. 'I'm be granted greater oversight of under no illusion: for those foreign -flagged MODUs. who want the risk reduced Transocean released to zero, that's never going to a statement disputing be reached, and I think we portions of the report. 'We need to be pretty clear-eyed strongly disagree with - and and realistic about that. documentary evidence in Even when we issue the next the Coast Guard's possession generation of drilling safety refutes - key findings in this rules, even when we further report,' the driller said. 'The enhance blowout preventers Coast Guard inspected the - if we require double blind Deepwater Horizon just seven shear rams and all sorts months before the Macondo of other enhancements to incident and certified the blowout preventers - we'll rig as being fully compliant never reduce risk to zero. It's with all applicable US and not humanly possible. international marine safety 'But through a combination compliance standards, of enhancements to drilling including those associated safety rules, a mature with fire and gas detection and robust (safety and systems. environmental management 'Further, at the time of system) rule, better the accident the Deepwater containment, better spill Horizon possessed all response, we're going to required valid documents get the risk down to a point verifying compliance with where it's even better than it international and Coast Guard is today. And we're satisfied requirements.' that it's at a point today where A report released in we can appropriately issue January by the Presidential deepwater drilling permits, Commission investigating so long as applicants meet all the Macondo disaster spread of our current requirements blame for the incident among and have containment operator BP, Transocean and capabilities.' Halliburton, the company in charge of the well's cementing Acts and omissions (OE March). The US Coast Guard report Bromwich said the Joint looked beyond the immediate Investigation Team's final mechanical failures that led report could be released to the 20 April 2010 blowout before the 27 July deadline, to find 'numerous systems promising that 'no further deficiencies, and acts and extensions will be granted'. CE ,nal use only - not for reproduction or retransmission. ltact the Publisher. h tt p: //o s. o i I o n I i n e. c o m World Oil Pagel of 3 World Oil= COPYING AND DISTRIBUTING ARE PROHIBITED WITHOUT PERMISSION OF THE PUBLISHER Transocean releases internal investigation report on causes of Macondo incident Transocean Ltd. announced the release of an internal investigation report on the causes of the April 20, 2010, Macondo well incident in the Gulf of Mexico. Following the incident, Transocean commissioned an internal investigation team comprised of experts from relevant technical fields and specialists in accident investigation to gather, review, and analyze the facts and information surrounding the incident to determine its causes. The report concludes that the Macondo incident was the result of a succession of interrelated well design, construction, and temporary abandonment decisions that compromised the integrity of the well and compounded the likelihood of its failure. The decisions, many made by the operator, BP, in the two weeks leading up to the incident, were driven by BP's knowledge that the geological window for safe drilling was becoming increasingly narrow. Specifically, BP was concerned that downhole pressure -- whether exerted by heavy drilling mud used to maintain well control or by pumping cement to seal the well -- would exceed the fracture gradient and result in fluid losses to the formation, thus costing money and jeopardizing future production of oil The Transocean investigation team traced the causes of the Macondo incident to four overarching issues: -- Risk Management and Communication: Evidence indicates that BP failed • to properly assess, manage and communicate risk to its contractors. For example, it did not properly communicate to the drill crew the absence of adequate testing on the cement or the uncertainty surrounding critical tests and procedures used to confirm the integrity of the barriers intended to inhibit the flow of hydrocarbons into the well. It is the view of the investigation team that the actions of the drill crew on April 20, 201o, reflected the crew's understanding that the well had been properly cemented and successfully tested. -- Well Design and Construction: The precipitating cause of the Macondo incident was the failure of the downhole cement to isolate the reservoir, which allowed hydrocarbons to enter the wellbore. Without the failure of the cement barrier, hydrocarbons would not have entered the well or reached the rig. While drilling the Macondo well, BP experienced both lost circulation events and kicks and stopped short of the well's planned total depth because of an increasingly narrow window for safe drilling, specifically a limited margin between the pore pressure and fracture gradients. In the context of these delicate conditions, cementing a long -string casing would increase the risk of exceeding the margin for safe drilling. But rather than adjusting the production casing design to avoid this risk, BP adopted a technically • complex nitrogen foam cement program that allowed it to retain its original casing design. The resulting cement program was of minimal quantity, left little margin for error, and was not tested adequately http://www.worldoil.com/Transocean releases_intemal_investigation_report_on_causes_o... 6/30/2011 World Oil Page 2 of 3 before or after the cementing operation. Further, the integrity of the cement may have been compromised by contamination, instability and an • inadequate number of devices used to center the casing in the wellbore. -- Risk Assessment and Process Safety: Based on the evidence, the investigation team determined that BP failed to properly require or confirm critical cement tests or conduct adequate risk assessments during various operations at Macondo. Halliburton and BP did not adequately test the cement slurry program, despite the inherent complexity, difficulties and risks associated with the design and implementation of the program and some test data showing that the cement would not be stable. BP also failed to assess the risk of the temporary abandonment procedure used at Macondo, generating at least five different temporary abandonment plans for the Macondo well between April 12, 20io and April 20, 20io. After this series of last-minute alterations, BP proceeded with a temporary abandonment plan that created unnecessary risk and did not have the required approval by the MMS. Most significantly, the final plan called for underbalancing the well before conducting a negative pressure test to verify the integrity of the downhole cement or setting a cement plug to act as an additional barrier to flow. it does not appear that BP used risk assessment procedures or prepared Management of Change documents for these decisions or otherwise addressed these risks and • the potential adverse effects on personnel and process safety. -- Operations: -- Negative Pressure Test: The results of the critical negative pressure test were misinterpreted. Post -incident investigation determined that the negative test was inadequately set up because of displacement calculation errors, a':lack of adequate fluid volume monitoring, and a lack of management of change discipline when the well monitoring arrangements were switched during the test. It is now apparent that the negative pressure test results should not have been approved, but no one involved in the negative pressure test recognized the errors. BP approved the negative pressure test results and decided to move forward with temporary abandonment. The well became underbalanced during the final displacement, and hydrocarbons began entering the wellbore through the faulty cement barrier and a float collar that likely failed to convert. None of the individuals monitoring the well, including the Transocean drill crew, initially detected the influx. -- Well Control: With the benefit of hindsight and a thorough • analysis of the data available to the investigation team, several indications of an influx during final displacement operations can be identified. Given the death of the members of the drill crew http://www.worldoil.comITransocean releases internal_investigation_report_on_causes_o... 6/30/2011 World Oil Page 3 of 3 and the loss of the rig and its monitoring systems, it is not known which information the drill crew was monitoring or why the • drill crew did not detect a pressure anomaly until approximately 9:30 p.m. on April 20, 20io. At 9:30 p.m., the drill crew acted to evaluate an anomaly. Upon detecting an influx of hydrocarbon by use of the trip tank, the drill crew undertook well -control activities that were consistent with their training including the activation of various components of the BOP. By the time actions were taken, hydrocarbons had risen above the blowout preventer and into the riser, resulting in a massive release of gas and other L] fluids that overwhelmed the mud gas separator system and released high volumes of gas onto the aft deck of the rig The resulting ignition of this gas cloud was inevita e.Ar io rft 6,a t -- Blowout Preventer (BOP): Forensic evidence from independent post -incident testing by Det Norske Veritas (DNS and evaluation by the Transocean investigation team confirm that the Deepwater Horizon BOP was properly maintained and operated. However, it was overcome by the extreme dynamic flow, the force of which pushed the drill pipe upward, washed or eroded the drill pipe and other rubber and metal elements, and forced the drill pipe to bow within the BOP. This prevented the BOP from completely shearing the drill pipe and sealing the well. -- Alarms, Muster, and Evacuation: In the explosions and fire, the general alarm was activated, and appropriate emergency actions were taken by the Deepwater Horizon marine crew. The 115 personnel who survived the initial blast mustered and evacuated the rig to the offshore supply vessel Damon B. Bankston. The Transocean internal investigation team began its work in the days immediately following the incident. Through an extensive investigation, the team interviewed witnesses, reviewed available information regarding well design and execution, examined well monitoring data that had been transmitted real-time from the rig to BP, consulted industry and technical experts, and evaluated available physical evidence and third -party testing reports. The loss of evidence with the rig and the unavailability of certain witnesses limited the investigation and analysis in some areas. The team used its cumulative years of experience but did not speculate in the absence of evidence. The report of the team does not represent the legal position of Transocean, nor does it attempt to assign legal responsibility or fault. The investigation report and supporting documents are available on the homepage of the Company's website at www.deepwater.com. o6/22/2011 http://www.worldoil.com/Transocean releases_intemal_investigation_report_on_causes_o... 6/30/2011 • BP, Transocean spar over who gets blowout preventer f'"b 6 ur, wile ��,, :.u_3 ; at 11:38 am by Associated Press ,ri Gulf Oil Disaster http://fuelfix.com/bloq/2011 /06/24/bp-transocean-spar-over-who-gets-blowout-preventer/ The blowout preventer pulled from the wreckage at BP's Macondo well is transported to land for testing on Sept. 11, 2010. (Photo: U.S. Coast Guard) Transocean report: BP didn't assess risks properly before blowout `update' • By HARRY R. WEBER Associated Press ATLANTA — BP and Transocean are at odds over who should get possession of a key piece of evidence in the Gulf of Mexico oil spill investigation once additional testinq is complete. Transocean, responsible for maintaining the blowout preventer that failed to stop last year's oil spill, argues it is best equipped to preserve the 300-ton device and it wants it back. But BP told a federal magistrate judge in a letter filed by the court Friday that the blowout preventer shouldn't be qiven to one of the defendants in numerous lawsuits filed over the disaster. It said the qovernment should safequard it at least until the end of a trial set for February related to the lawsuits. The government has said the blowout preventer failed because of a design flaw and a bent piece of pipe. BP, unsatisfied with the analysis, got court approval for additional testinq. The qovernment has said it doesn't expect its conclusions to change, though BP and other companies could use the results of the additional testinq to defend themselves in the lawsuits. The additional testing is wrapping up at a NASA facility in New Orleans, and the court has asked the parties to weiqh in on what should be done with the device. "Transocean has the necessary expertise to transport the BOP to a location of its choosing and is willing to assume the costs associated with the related transportation," Transocean said in a letter to the court. BP argues the blowout preventer should remain in independent hands to ensure its integrity because it is one of the most central pieces of physical evidence in this litigation." • A lawyer for the Justice Department told the court that the government wants to retain the control pods and certain other parts of the blowout preventer, but it doesn't object to the rest of the device beinq returned to Transocean. However, it noted that another government agency, the U.S. Chemical Safety Board, may want • to do additional testing if its own. A ruling was pending. Eleven workers were killed when the Deepwater Horizon rig exploded off Louisiana on April 20, 2010. Some 206 million gallons of oil spewed from a well a mile beneath the sea before it was capped three months later, according to government estimates. BP owned the well and was leasing the rig from Transocean. • N • z 0 z Cl- CD • • `human Problems of the kind encountered by the DeepwaterHorizonand Sedco 711 are not unique and being judgemental with the benefit of hindsight is futile, argues drilling consultant Dr John Thorogood. Pointing out that there is much still to be learned about human error, he calls on the industry to raise its game around operations management. Over recent months several books and articles have been written, or commentaries made about the Deepwater Horizon disaster. They have either trivialised the nature of the well by saying it should have been'relatively simple'111; attempted to 'prove' that the accident was an entirely predictable consequence of the commentator's interpretation of organisational culture"; criticised apparently obvious failings of risk assessment with the wisdom of hindsight","; reduced the complexities of the event to a sound bite, 'a breakdown of management oversight't'J; or simply asserted that the industry has a 'strong' safety culture"]. Together, they create an impression that what happened was an exceptional event, confined to one particular operator and not representative of the industry as a whole. There is, however, another side to this story, namely that what happened may be a predictable consequence of the complexity of the systems that the industry itself has created. With one recent exceptionte], this is a question that the industry has not generally acknowledged and, until it does so, there is no assurance that a similar event will not happen again. All of these critical comments are made with the benefit of knowledge of the outcome. As explained by Woods et al in Behind Human Error0l, this hindsight bias is an inevitable consequence of outcome knowledge. It results in much more severe judgements of the event than would be accorded to a similar event with a less severe outcome. The lack of public reaction and apparent regulatory inaction resulting from an earlier similar incident onboard the Sedco 711 in the North Sea is evidence of this phenomenon. In this instance, disaster was averted because the BOPs operated successfully. It was fortunate that this blowout had not evolved to the same point as on the Deepwater Horizon, because according to the DNV forensic examination of the Horizon BOP"0' all the rams had functioned and were found closed upon disassembly. The authors concluded that the dynamic effects of the fluids in the well caused the pipe to buckle beyond the limits of the ram blades thereby preventing complete closure and sealing of the blind shear rams. A failure to shear and seal combined with an attempt to close rams on fluids flowing at high rates, a situation also not envisaged by the designers of the BOPs, created conditions under which a successful shut-in was probably impossible. To compound the good luck, the difference between 500ft of water and 5000ft ensured that there was little or no hydrocarbon inventory in the Sedco 711 riser to create the risk of an explosion. Quick fixes The commentaries referenced above play into a climate that is ripe for risk denial and yet demands quick fixes. They fail to recognise the complexity of the socio-technological systems that exist in our deepwater drilling operations. The Chief Counsel's Report"" is inevitably biased with hindsight and qualifies its conclusions with regards to the BOP. However, it goes much further than the earlier National Commission Report to the President"" to describe in detail the confusion and conflicts that those involved, both onshore and offshore, faced in the hours before the blowout. The Chief Counsel's Report does not analyse or explain why it was that the crew on the rig made sense of what they saw in a way that convinced them that it was safe to continue displacing the well to seawater. The explanations and accompanying diagrams are couched in simple technical and managerial terms. They make it hard to understand why the rig team didn't see what was apparently staring them in the face. They belie the complexity of the layout of the drill floor and the interplay of personalities, egos and experience. Yet this is precisely what happened and nobody has thus far ventured an explanation as to why. In the closing sentences of Chapter 6, the report agrees that more regulation or inspectors will not solve the problem. However, the report is unwilling to 'open the curtain'tolook behind the label of human error; concluding that it was simply the absence of a culture of leadership responsibility. Again, four months earlier on the Sedco 711, a successful inflow Content is copyright protected and provided for personal use only - not for reproduction or retransmission. 22 OFFSHORE ENGINEER I may 2011 For renrintsnleasecontact the Publisher. http://ae.o11aniine.com • b/ 'epwater Horizn o 0 cident Investigation Report test probably created amongst the crew a sense of absolute bomb -proof security about the well. Under these conditions, it is understandable that they might have overlooked some otherwise unremarkable operational inconsistencies prior to commencing the displacement to seawater. If taken note of, these might have suggested that the formation isolation valve had been damaged and the barrier compromised. Naturally, when faced with unexpected volumetric behaviour of the well during the displacement, such a mindset would inevitably direct the search for explanations in precisely the opposite direction to the one that is now so obvious with hindsight. It is only with the benefit of hindsight when we reflect on the narrowness of the escape do we wonder 'How could they have missed it?' Simply stating that the successful pressure test'blinkered' the crew without any deeper examination of the complexity of the situation over -simplifies and trivialises the incident. Read in conjunction with the Chief Counsel's Report, it is clear that this failure to respond to weak and contradictory signals is not a rare event in our industry. Confirmation is one of the stronger biases influencing decision -making, where operators see what they expect to see and disregard or overlook disconfirming information. It has been implicated in many other major accidents — Challenger, Columbia, Texas City and Gretley, to name but a few. The sharp end The natural reaction of engineers to such events is to regard the operator as the weak link. To avoid future repetition, perceived risk is mitigated with more rules, regulations, procedures and training. Contemporary research shows that the problem is much more complicated and that these remedies are generally ineffective. It is not simply the errors or omissions of the operators at the sharp end that matter. As Woods et all" explain, to a much greater extent, it is the contribution of those at the blunt end of the system that have far rMMacondo greater influence. It is the climate created by the regulators, politicians, media, public, mixed messages from senior management creating goal conflicts — the un between efficiency and safety, and the contradictions that stem from attempts to comply with over -prescriptive or B_ impractical procedures that create the conditions under which human error is almost inevitable. The reason that there are so few catastrophes is the ability ' ------ of the practitioners at the sharp end to reconcile these conflicting demands and avoid the traps set for them. As Reason"a) == - observes, the operators are often the Poolheroes because their adaptations, improvisations or compensations often retrieve troubled systems from the brink a of disaster. Unfortunately, on occasion, sometimes the operators do fail. But it is not an individual failure, but collective and evidence of weakness of the system. In the face of such complexity and in the absence of a detailed enquiry to develop a deeper understanding of the error -producing conditions that exist on our rigs and in our operations, to pretend that a different leadership culture, more risk assessment blessed with second sight, restrictive rules, vigorous regulation, rigorous training and strict certification will solve the problem is naive. Such a position is at variance with our understanding of the nature of human error and the evidence of the events on the Deepwater Horizon and the Sedco 711 reinforces this conclusion. In the short term, doing nothing is not an option and there are some things that the industry could beneficially do. Responding to the analysis presented in the Chief Counsel's Report, and drawing on parallels with established practice, for example the training in controlling emergencies of offshore OIMs and deputies in the UK sector, a useful first step might be to codify and enforce through regulation: 1. Selection, training, assessment and certification for all those in positions of authority and control of wellsite operations both onshore and offshore. Periodic refresher training and recertification should run in parallel with well control certification. 2. Standardised organisation structure, procedures and protocols for controlling operations. 3. Compliance with a practice of detailed planning and associated discipline of adherence to the plan from which deviations are tightly controlled. 4. Standardised operational management of change procedure with clearly defined responsibilities for decision -making. 5. Training in the non -technical skills"' '' such as leadership, teamwork, communication, decision -making, situation awareness and stress management combined with extensive scenario -based exercising. While these actions are a necessary "f 16" 11 first step to consolidate what is, essentially, current best practice, they do not begin to get at the underlying folding aftermat� problem of human error and complex systems. To p = make progress, it might be helpful to concede that we don't fully understand .: �. ;.. how human error works in our environment. Having acknowledged the limitations of our knowledge, we should — -- do the research needed to gain = the necessary insights specific rT1 to human error in the drilling domain. Avoiding the pitfalls Drawing from the experience of other high -hazard industries, such as nuclear, I aviation and chemical, we must apply Content is copyright protected and provided for personal use only - not for reproduction or retransmission. r� http://oe.oiIonIine.com For reprints please contact the Publisher. OFFSHORE ENGINEER I may 2011 `'3 z CD z CD • • do F i 7 a TWA �� A _FLEXIBLE BLADDERS FOR: 01L DISPERSANTS. METHANOL. GLYCOLS. FUEL, LUBRICANTS. HYDRAULIC FLUID, CHEMICAL CLEANING COCKTAILS ETC. ACCUMULATORS • ACTUATORS • BALLAST COMPENSATORS • DAMPERS • DIAPHRAGMS FLOTATION • HYDRAULIC RESERVOIRS FUEL & BATTERY CONTAINMENT • PIPE PLUGS It , 14,1 800-526-5330 Ail1 RAMSCUN U,SAORIFS :..1f+ www.ArL1NC.cvM, IMCA Member Internat,aul Marne Contractor Assomoon w .imca-incxom similar understandings to the pitfalls inherent in our own operations by identifying, training, and assessing the relevant non -technical skills. With the resulting knowledge, we can also train our people to recognise the domain -specific traps that we set for ourselves. We can then ensure that our management systems, risk assessment methods, planning procedures and protocols for operational control are designed with the resilience needed to avoid the pitfalls. This work will take time and there is no time to lose. It is to be hoped that the new US Ocean Energy Safety Advisory Committee to Guide Oil & Gas Regulatory reform recently announced by US Secretary of the Interior Salazar will pick up on this agenda and drive it forward. Inaction will ensure that at some time in the future, history will repeat itself. Hubris leads to nemesis. We must move quickly to get beyond the label of 'human error'. FOIE John Thorogood is an independent consultant after a 34-year career with BP in drilling operations, technology and exploration project management. In 2002-2003 he undertook research with the University of Aberdeen Department of Psychology and published work on drilling teams and decision making and human factors. He is the 2011 recipient of the Society of Petroleum Engineers International Drilling Engineering Award, a former technical director of the SPE and author of more that 40 technical papers and articles on drilling engineering. He has BA and PhD degrees in Engineering from the University of Cambridge. Acknowledgement Margaret Crichton, People Factor Consultant Ltd, provided valuable comments on the draft of this article. References 1. S Reed & A Fitzgerald. In Too Deep, Bloomberg, 2011. 2. L Steffy. Drowning in Oil, McGraw Hill, 2011. 3. I Fitzsimmons. 'Macondo and other Titanic struggles', Offshore Engineer, July 2010. 4. I Fitzsimmons. 'Macondo - the unfolding aftermath', Offshore Engineer, November 2010. 5. I Fitzsimmons. 'Macondo and the Presidential Commission', Offshore Engineer, March 2011. 6. R Tillerson. 'Tillerson blames BP for Gulf spill', Upstream Online, 9 March 2011. 7. M Ralls. 'Industry safety culture is not complacent', Drilling Contractor, March 2011. 8. R Saltiel. 'A new safety language is on the horizon', Drilling Contractor, March 2011. 9. Woods, Dekker, Cook, Johannesen & Sarter. Behind Human Error. 2nd ed, Ashgate, 2010. 10.Det Norske Veritas. Forensic Examination of Deepwater Horizon Blowout Preventer, Report EP030842 for BOEMRE, March 2011. 11.ChiejCounsel's Report. Macondo, the Gulf Oil Disaster. National Commission on the BP Deepwater Horizon Oil Spill & Offshore Drilling, 2011. 12.Report to the President: Deep Water, the Gulf Oil Disaster, National Commission on the BP Deepwater Horizon Oil Spill & Offshore Drilling, January 2011. 13.J Reason. The Human Contribution: Unsafe acts, accidents and heroic recoveries. Ashgate, 2008. 14.Flin, O'Connor, Crichton. Safety at the Sharp End: An introduction to non -technical skills. Ashgate, 2007. 15.Thorogood, Crichton & Henderson. Command Skills for Drilling and Completion Teams. SPE Paper 89901, 2004. 24 OFFSHORE ENGINEER j may12011 na ^_.idea f�onal use only - not for reproduction or retransmission. For reprints please contact the Publisher. http://oe.oiIonIine.com 0 • `With offshore drilling rigs earning $500,000 a day and more, the temptation remains strong to skirt safety and environmental requirements rather than shut down or limit operations for maintenance, or to wait for the appropriate expertise to become available. Third parties are not immune to these pressures. In fact, they are often contracted and paid by the parties for whom the pressure is most acute.' lain Light Independent and competent: is it time to raise the bar? Competence testing, true independent oversight and a stronger focus on the human element are the lessons from Macondo, argues Lloyd's Register energy director Dr lain Light. he offshore industry has just had the dubious distinction of marking the first anniversary of the Macondo well tragedy in the Gulf of Mexico. That event, perhaps more than any other in the history of offshore drilling, was meant to herald in sweeping changes to our industry's safety practices. There has certainly been a lot of recrimination, hand -wringing and well-meaning proposals in the 12 months since the destruction of the Deepwater Horizon. But as the public outrage about the loss of life and unprecedented environmental damage fades with each passing day, we should all ask ourselves: 'Have we learned the lessons?' The findings of the US National Commission on the health of the country's offshore industry in the wake of the Macondo well tragedy made for some pretty stark reading; the words of its co-chairmen, senators Bob Graham and William Reilly, were equally direct (OE last month). Macondo, according to Graham, was a tragedy that'likel would not have happened' if there had been 'the capacity and will to demand world -class safety standards'. Insofar as the Commission recommended an overdue transition to a holistic 'safety -case' risk -management regir - away from the historic prescriptive practices - their effoi were largely applauded and eventually may be seen as the right medicine for an industry that was, apparently, quietly ailing. If the Commission's words are heeded, the importance of having the right kind of technical expertise and more independent oversight - of the operators and the regulators - should grow exponentially in the US and elsewhere. This will present clear commercial opportunities for independent risk -management firms. What was less clear from the report were the qualifications companies will require to be considered 'independent' or 'competent' to perform what are becoming increasingly complex work programmes as the industry moves into more hostile environs in search of the remaining stores of fossil fuels. Clearly, there will be no shortage of 'third -party inspectors' willing to do the work in the US; whether they are competent and truly independent is another question. In the North Sea, the comparative environment most cited by the Commission's Report to the President (OE March), inspectors and their companies are'independent' according to the UK Offshore Installations (Safety Case) Regulations only when their relationship to the asset or system they are inspecting is removed enough 'to ensure that [they] will be objective in discharging [their] function'. Content is copyright protected and provided for person httn://oe oilonline.com For re rints please con The associated guidance issued by the UK HSE makes clear that those carrying out such work should be free from pressures, especially of a financial or operational nature, which could affect sound judgement. It sets clear expectations for managing the potential conflicts of interest for inspectors which arise from: having to meet production targets; hoping to earn promotion or pay rises; incentives such as targets for key -performance indicators, all of which can influence otherwise sound engineering [gement. In fact, some types of work (such as structural ialysis) often require a completely separate ;sessment, using different personnel, modelling )ols and even design methodologies. The Commission clearly identified events in :he run-up to the Macondo tragedy where the inspectors were too close to the commercial end of the business to exercise sound judgement; another layer of qualifications in the US to define'independence' would strengthen the vital role of the third -party assurance agents who have become so critical to most major process industries. Clearly, this would make America's offshore industry safer. With offshore drilling rigs earning $500,000 a day and more, the temptation remains strong to skirt safety and environmental requirements rather than shut down or limit operations for maintenance, or to wait for the appropriate expertise to become available. Third parties are not immune to these pressures. In fact, they are often contracted and paid by the parties for whom the pressure is most acute. Moreover, the technical assurance providers themselves are in a constant struggle to win new work, with the inevitable pressure to lower their prices, which again can impact on the quality and integrity of the services they provide. But, short of creating a monopoly to eliminate competitive pressure (and competitive pricing), there are basic steps that can be taken to ensure that the competence and independence of any industry's assurance providers remains robust. Technical standards and a clear outline of the scope of third - party involvement need to be set and maintained by regulatory authorities, including the requirements for competency of the personnel carrying out the assessments. Any such organisation also should be required to be of sufficient size, with a diverse enough client -base, to ensure that it is not too commercially dependent on any one client or project. >ouerleaf al use only - not for reproduction or retransmission. p tactthePublisher. OFFSHORE ENGINEER I may 2011 27 z CD z O • Scana SCANA CREATES PROGRESS Scana Mar -El AS is a leading manufacturer of electronic remote control systems for propulsion and manoeuvring of vessels The company was founded in 1974, and so far we have delivered a total of nearly 3000 systems world-wide Joystick and position keeping system The Marco-V is an advanced joystick system offering full vessel control from a 3-axis joystick. The system includes features as automatic heading and automatic position keeping. Scana Mar -El AS Storvegen 48, N-3880 Dalen, Norway • TIC +47 35 07 58 00 Fax + 47 35 07 58 01 • E-mail mar-el@scana no • www scana no That said, even the most rigorous qualifications for independence are unlikely to produce the required levels of safety and environmental stewardship unless the assessors are also proven technically competent. The increasingly integrated and complex nature of modern offshore systems and processes requires comprehensive levels of technical understanding and experience; most often one project requires the skills of more than one person. It's a size thing The ability of an independent assurance provider to coordinate input from experts across a number of disciplines is a key to a successful outcome. So, again, the size of the organisation matters. The bar needs to be set high. Every prospective assurance provider should be required to demonstrate having the knowledge, skills, experience and behaviours to be considered competent to perform a role. Strength in one of these areas is not enough. In particular, a technical qualification alone should not be sufficient, particularly since there is growing acceptance that understanding and managing the human element is where the next significant advances in workplace safety will be made. Huge advances have been made in the technical construction of marine and offshore infrastructure - as well as the management systems that support them - in the past two decades. It is now industry consensus that more than 90% of incidents such as Macondo are caused by human failures of one description or another. With equipment and systems increasingly `safe by design', understanding the influence that an organisation's work -place culture has on maintaining and improving safety standards is critical. Employee familiarity with state-of-the-art warning systems is just as important as the ability of the system itself. Just as having the expertise to recognise when an asset is not performing safely means little if company employees lack the courage or management culture to report it. The offshore industry is evolving. Risk levels are rising proportionate to the more dangerous environs we are exploring and the technical complexity of the infrastructure we need. So the qualifications required to provide independent technical assurance far exceed those needed for a one-off assessment of a blowout preventer. To provide effective technical assurance, a company needs a deep knowledge of how people, plant and process interact - and the integrity to exercise clear judgement. t'lE lain Light is group energy director for Lloyd's Register. Based in Aberdeen, he is responsible for developing strategy and ensuring that the group has the right services for an increasingly complex energy sector'. Light lays claim to more than 30 years' experience in 'making the offshore industry a safer place to work' and since joining Lloyd's Register in November 2007-after 16 years with DNV- has guided a number of telling acquisitions, including drilling rig safety and technical assurance services provider ModuSpec and Norwegian technical risk -assessment company Sundpower. Content is copyright protected and provided for personal use only - not for reproduction or retransmission. 28 OFFSHORE ENGINEER j may 2011 For reprints please contact the Publisher. http://oo.ollonline.com r� U http://www.petroleumnews.com/pnads/271763596.shtmi Vol. 16, No. 20 Week of May 15, 2011 Providing coverage of Alaska and northern Canada's oil and gas industry A risky business Print this story I Email it to an associate. Panel discusses how to handle dangers of Arctic offshore oil development Alan Bailey Petroleum News The Deepwater Horizon disaster in the Gulf of Mexico has heightened everyone's consciousness of the risks involved in offshore oil exploration, while also adding a few decibels to the volume of the contentious debate over the advisability or otherwise of searching for oil in the Arctic offshore. And on May 3, in a panel discussion organized by the University of Alaska Anchorage, four people who have been involved in different aspects of industry safety management reflected on how offshore oil and gas risks might be managed in the future. Needs safety system Panel member Fran Ulmer, chair of the U.S. Arctic Research Commission and an erstwhile member of the President Obama's National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, reiterated the general findings of the presidential commission, saying that the Deepwater Horizon, a result of a litany of errors and safety failures by industry, and a corresponding failure of government regulatory oversight, had been both foreseeable and preventable. The lack of an overarching system for protecting against mistakes increased the risks to a catastrophic level, she said. 0 • Pointing out that the U.S. oil industry safety record lags behind that of Europe, Ulmer compared the regulatory regime in Norway with that of the United States. The Norwegians use a safety -case approach that focuses on assessing the safety risks associated with each specific drilling operation, rather than using the prescriptive set of one -size -fits -all safety standards that have become the norm for safety regulation in America, Ulmer said. The problem with the prescriptive approach is that a company that meets all of the regulatory requirements may become complacent about the safety of its operations, Ulmer said. The best system would probably entail some combination of a safety -case approach and the use of some prescriptive regulations, she said. In addition, the Petroleum Safety Authority Norway, the Norwegian government agency tasked with oversight of oil and gas industry safety, is a completely separate organization from those sections of the Norwegian government administration responsible for dealing with oil leasing or oil revenue collection, Ulmer said. Independentageney In its post-Deepwater Horizon internal reorganization, disbanding the old U.S. Minerals Management Service, the agency that came out with a less than stellar reputation after the Gulf of Mexico disaster, the Department of the Interior has split off regulatory oversight • from other oil and gas -related functions, along the lines of the Norwegian model. Panel member Jeffrey Loman, deputy regional director in Alaska of the Bureau of Ocean Energy Management, Regulation and Enforcement, said that he hopes that the new Interior regulatory agency would be both feared and respected by industry. Prior to Deepwater Horizon MMS had come to a belief that it had a gold-plated safety system, a belief that had led to dangerous levels of complacency, Loman said. Equally, industry must never be lulled into a situation where it feels satisfied with its safety protocols — concern with the adequacy of safety arrangements drives out complacency, he said. At the same time, BOEMRE needs to address the concerns of all stakeholders in outer continental shelf oil development, including those people worried about employment and those whose overriding priority is environmental protection, Loman said. The biggest single issue facing society is the decision on what to do about future energy needs, with that decision also being linked to decisions about what to do about global climate change, he said. And even if the United States cuts back on fossil fuel usage as much as possible, the rapidly growing use of cars in India and China will continue to create a huge demand for hydrocarbon -based fuels. Although that compelling near -term demand for fossil fuels can push people into taking risks in the search for new resources, people not involved with the oil industry can tend to overestimate the risks involved in industry activities over which they have no control, Loman said. 0 • Evaluation needed On the other hand, every regulatory agency has to make decisions involving an evaluation of costs, benefits and the likelihood of a successful outcome. Shell's drilling plans for the Arctic outer continental shelf include a comprehensive oil spill response capability. But it is also necessary to realize that during a worst -weather day in the Arctic offshore people will struggle and probably not be able to clean up anything, Loman said. Offshore oil exploration is a risky business. BOEMRE is investigating how to plug any gaps in Arctic spill response capabilities, such as the difficulty of deploying spill responders into the region. Among other things, BOEMRE is analyzing the potential impacts of a very large oil spill in the Chukchi Sea, to fully inform regulatory decision makers, Loman said. The agency is looking under every stone to make sure that industry will do a realistic spill estimate for every well drilled, Loman said. Panel member Cathy Foerster, a commissioner on the Alaska Oil and Gas Conservation Commission, explained how AOGCC oversees drilling safety in Alaska. AOGCC has jurisdiction over oil and gas drilling throughout the state, including in -state waters within • the three-mile limit. All wells require permits, with professional engineers and geologists from AOGCC reviewing individual well plans. The agency also has a robust field inspection program, to ensure compliance with AOGCC regulations and permit stipulations, Foerster said. Changes to a well plan during a drilling operation also require AOGCC approval, she said. There are fines and other penalties for failure to comply with regulations. Test requirements AOGCC requires well blowout preventers to be tested every seven days for an exploration well and every 14 days for a development well. There have been seven well blowouts in Alaska since 1968, all except one resulting from a well hitting a shallow gas zone, and with no blowouts resulting in injury or oil spills, Foerster said. Improvements in seismic data acquisition and improved regulation in recent years have reduced the risks posed by shallow gas, she said. AOGCC has stringent regulations to ensure that operators do not take unacceptable safety risks but, following the Deepwater Horizon disaster, the agency is conducting a comprehensive review of its regulations for offshore and extended reach drilling, Foerster said. AOGCC is fully funded out of industry regulatory cost fees, independent from other state funding, she said. 0 Loman commented on the issue of company size when it comes to capabilities to deal with an offshore incident. Who are you going to let do business in the Arctic, Loman asked. It has to be a company with "tremendous financial viability," he said. Foerster said she feels concerned that some of the smaller companies entering the Alaska oil and gas industry need to progress through a learning curve of how to do business in the state. Ulmer emphasized the importance to offshore safety of encouraging a safety culture for all involved, a theme that panel member Karlene Roberts, director of the Center for Catastrophic Risk Management, University of California, Berkeley, picked up in an overview of the characteristics of what she termed "high -reliability organizations." High reliability organizations High -reliability organizations have exemplary safety records when conducting potentially high -risk activities through, for example, effective process safety auditing; reward systems that do not fall into the trap of rewarding some undesirable behavior; and systems that recognize and address risks, Roberts said. And senior management in these organizations focus on strategic issues. By resisting the temptation to micromanage, these managers ensure that people with the appropriate • expertise can make critical decisions, Roberts said. Roberts cited a major drop in U.S. Navy aviation accident rates over the years and the increasing reliability of U.S. nuclear power stations as two examples of situations where a high -reliability approach to management had yielded demonstrable success, primarily through changes in the way people behave. The Arctic has a whole array of new and rather challenging conditions that have to be considered in the planning and funding of industry and government involvement in exploration of the region, with these challenges requiring the international sharing of best practices and the setting of high standards for doing business, Ulmer said. "Clearly as we move forward in the United States to find more oil and gas in the outer continental shelf, offshore in deeper waters and in frontier areas, it becomes increasingly important for us to concentrate on managing risk and improving safety," she said. Bud's Offshore Energy (BOE) Energy Production, Safety, Pollution Prevention, and More PSA adds substantial value at a relatively low cost May 6, 2011 by offshoreenergy _*P E T R 0 L E U M S T I L S Y N E T PETROLEUM SAFETY AUTHORITY NORWAY Surprisingly, the post-Macondo discussion about regulatory approaches has been largely devoid of value and cost -benefit assessments. While PSA has been praised for Norway's outstanding offshore safety record, little attention has been paid to their relatively low regulatory costs. According to data in the 2010 Annual Report, PSA has 161 employees, and had total • operating expenses of NOK 202,762,689 ($US 38.1 million) for 2010. These modest cost and staffing numbers are particularly impressive when the magnitude and complexity of Norwegian offshore operations are considered. In March 2011, Norwegian oil production averaged 2.017 million barrels per day (no. 2 offshore oil producer slightly behind Brazil) and gas production averaged 11.6 billion cubic feet per day (world offshore leader). PSA is also responsible for onshore processing facilities. PSA's costs are relatively modest for the same reason that their regulatory program is successful. They hold companies responsible for managing their operations and conducting inspections. They don't approve every detail of every operation, but focus on ensuring that the company management systems are effectively implemented. They identify risks and insist that industry address them. As Ma ng e Ognedal said in his interview with BOE: Our regulatory philosophy is indeed firmly based on the legislated expectation that those who conduct petroleum activities are responsible for complying with the requirements of our acts and regulations. Furthermore, our regulations require that they employ a management system that systematically probes and ensures such compliance at any time. The approach to achieving this should be risk -based. So, ensuring compliance with rules and regulations is the • operator's job — not ours. • Magne Ognedal Interview with Magne Ognedal, Director General, Petroleum Safety Authority — Norway (Note to readers: This interview has received much attention in the wake of the Macondo blowout in the Gulf of Mexico. Please keep in mind that the interview was conducted in January, 2010, three months prior to the blowout. With that in mind, I think you will find Magne's comments to be particularly insightful.) Magne Ognedal My experience is that you unfortunately often need a major accident or even a disaster to engender political support for streamlining regulatory regimes. Moreover, history shows that major accidents apparently must happen in your own jurisdiction to have such an effect on political support. BOE. We're honored that you have agreed to help us kickoff this offshore energy blog. Magne, you are internationally recognized for your offshore safety and regulatory leadership. Tell us how you got your start. When did you first become interested in • offshore oil and gas operations? What attracted you to a career with NPD (now PSA)? Were there any mentors who inspired you or helped guide your career? • Thanks Bud, let me first say that I'm very pleased to be featured in your blog's maiden interview. Well, when NPD started up in 1973 I was teaching at a ship automation school in Stavanger. A fellow student, who had just signed with the NPD, contacted me and recommended the agency as an excellent place to work. I must admit I was in doubt, since I imagined government offices to be gloomy workplaces covered with dust and what have you, and with mainly stiff-necked bureaucrats hanging around. So, I got an arrangement where I only worked a couple of days a week to try it out first. It turned out to be much more exciting and fun than I could ever imagine, and my employment soon became permanent. I have never regretted that choice! We did not have mentors in those days, since the agency was only a year old and had a fairly young and inexperienced staff. My tasks and responsibilities were so interesting, and finding out for myself about how to adapt (without having a mentor) was quite challenging, inspiring and rewarding. I think I got a good start to my professional career. BOE. For background purposes, can you tell us Norway's current offshore oil and gas production? How many production facilities are there? Approximately how many personnel are on Norwegian offshore facilities at any given time? In 2008 we produced oil and gas for a total production of saleable petroleum of 242.2 • million scm oil equivalents (1.53 billion boe). The petroleum sector's share of GDP was as high as 26%. We have about 75 manned installations, but you should bear in mind that most of these are really huge facilities compared to what you find in many other provinces. Some could (manning -wise and support -wise) even match the number of inhabitants and services provided for onshore villages. About 26,000 personnel work offshore, so approximately 8000-9000 are working on the Norwegian facilities at any given time. BOE. PSA demands excellence from duty holders (operators) and holds them accountable. Is this accountability the core element of your regulatory philosophy? Can you briefly characterize your regulatory philosophy? Interesting question, Bud, which touches upon basic principles for statutory regulation. Our regulatory philosophy is indeed firmly based on the legislated expectation that those who conduct petroleum activities are responsible for complying with the requirements of our acts and regulations. Furthermore, our regulations require that they employ a management system that systematically probes and ensures such compliance at any time. The approach to achieving this should be risk -based. So, ensuring compliance with rules and regulations is the operator's job — not ours. 0 • Now, if that worked to perfection there would probably not be a need for a regulator, but unfortunately this is not so. The role for us as a regulator is to challenge the companies across-the-board. But first and foremost, we must be able to rely on their competence and capacity to fully control all of their activities, and effectively prevent harm to personnel, environmental, and economic values. However, should we find that somebody has been trying to con us, we will definitely take strong action. Being a regulator, our role is to assess that the management systems employed to ensure industry compliance programs are functioning as intended. Well, this was perhaps not a brief elaboration, as you asked for, but it is important for me to get the message across: A regulator must have faith in the industry participants' genuine eagerness and capacity to achieve compliance. If not, the regulatory system will fall apart as distrust otherwise might easily develop between the regulator and industry. This goes both ways, since a regulator should also be trusted by the industry to do the right things. BOE: Norway does not require the submission of safety cases. Is that correct? Any comments on your thinking in that regard? I have often had that particular question posed to me! Many that come to visit us in Stavanger seem to have the idea that if you do not have a Safety Case regime, then you • are not up to scratch as an efficient, contemporary regulator. It is true that we do not require the acceptance of a Safety Case in Norway. We have considered it, but we've concluded that the proper processing of a Safety Case by the regulator is a very resource demanding exercise, which we do not believe adds to safety. Depending on the volume of offshore development activities, a regulator may also find itself swamped with work on processing Safety Cases, which means it's actually the industry activities that control how the regulator should use its resources. And, maybe most importantly: We believe that a regulator's acceptance of a Safety Case inevitably transfers parts of the operator's responsibility to ensure compliance with statutory requirements on to the regulator. Perhaps not really in a legal sense — but morally. That said, we do require that operators do the same risk assessments and describe how they intend to control identified risks similarly to the way they would in a Safety Case regime. Their documented assessments and calculations — or parts of them — must be kept and handed over to us should we require it. BOE: How do regulations and guidelines fit into your regime? When you have specific expectations (e.g. BOP pressure testing procedures and frequencies) do you incorporate them into your regulations? Are alternative procedures allowed if a company can demonstrate that there would be no increased safety risk? Where established procedure do not exist or are ineffective, are the companies responsible for selecting solutions that satisfy PSA? 11 . Many years have passed since we had to admit that writing safe design and operations requirements into our detailed regulations was not the way to go. We realized that the maintenance of detailed regulatory requirements on how to construct safe installations or operate them properly was resource intensive, and that these requirements would sooner or later lag behind best industry practices. Such detailed requirements could even hamper technological development. So, since 1985 we have systematically worked on revising our detailed regulatory specifications. We introduced a new kind of regulatory portfolio with just a few regulations mainly stating what should be accounted for by the duty holders. Our statutory requirements today describe the goals that should be strived for — not how to achieve them. Only where we find it essential will we specify detailed measures that need to be adhered to by duty holders. To provide predictability, our formal regulations are supported by guidelines that also make reference to industry standards. Meanwhile, the industry has done a remarkable and admirable job of developing standards based on best practices. We oversee this development, and if we determine that a new industry standard is fully acceptable, we recommend it as a good tool for the industry to comply with our functional -oriented requirements. Our approach to enforcing the regulatory requirements allows companies to select a solution as long as they can demonstrate its compliance with the goals of the regulations. • Needless to say, this has saved us a lot of resources in developing specific rules and regulations, and also provided for better predictability for all duty holders. BOE: The recent safety record for facilities offshore Norway has been outstanding. From 2002 through 2007, there wasn't a single fatality associated with offshore oil and gas operations in Norwegian waters This is a remarkable achievement for any offshore region, particularly one with high activity levels and harsh conditions! To what do you attribute the success? I think it has been primarily due to the industry's own dedication and hard work to prevent accidents from happening. For a long time, they have had HSE high up on their agenda. In this regard, they have obviously had good reasons for doing that. To adhere to regulatory requirements means they also avoid receiving orders from the regulator, which naturally could severely tarnish their standing. Also, duty holders wish to avoid accidents at all costs, because accidents are costly and often impact their corporate reputation. They might even be severely punished on the stock exchange. A good safety record will also be beneficial for the companies in terms of being awarded new prospecting areas. But, also the regulatory authorities have been a driving force in this development by • initiating efforts to advance technology, organizational issues and tripartite • collaboration. In this connection, our own yearly survey of risk levels in the Norwegian petroleum activities has proven to be very valuable in that it identifies areas where there are negative trends. Such areas need to be addressed by those who are responsible for complying with regulations — and who actually own the problems. So, we regulators normally do not need to develop and introduce new rules to change risk level trends and achieve necessary improvements. BOE. The MMS just started tracking natural cause fatalities at offshore facilities, and the number was higher than expected (10 in 2007, 11 in 2008). Does Norway track natural cause fatalities at your offshore facilities? Any numbers you can share? No, we do not. We do occasionally receive reports on natural cause deaths or on personnel that have fallen seriously ill and therefore been taken to hospital onshore. However, we have no requirements that such incidents should be reported to us. BOE: A related concern is medivac capabilities Does Norway have any guidelines for ensuring prompt medical treatment for injured or ill offshore personnel? We did a review a year or so ago and found there was a considerable higher frequency of medivacs for personnel that had fallen ill and were taken to shore for hospitalization than for work related injured ones. The industry has SAR helicopters stationed at certain installations to facilitate quick evacuation of injured or ill personnel. There is an • industry guideline saying that injured or ill offshore personnel shall — if required — receive lifesaving treatment on board, and that the evacuation of a patient to a hospital onshore should not take longer than 3 hours. BOE: Norway has done a good job of minimizing regulatory overlap and the associated confusion. To what do you attribute this success? The US and other countries have a myriad of agencies involved in regulating offshore facilities. Do you have any suggestions for engendering the political support needed to streamline regulatory regimes? To start with your last question, Bud: My experience is that you unfortunately often need a major accident or even a disaster to engender political support for streamlining regulatory regimes. Moreover, history shows that major accidents apparently must happen in your own jurisdiction to have such an effect on political support. Before 1985, we had 13 different agencies or authorities with self-contained powers and regulations to regulate parts of our offshore activities. Moreover, the Norwegian Maritime Directorate regulated the exploration activities, whereas the NPD regulated development and production activities. Then we experienced two major accidents. First, we had the Ekofisk 2/4 Bravo blowout in 1977. Hydrocarbons were not ignited, but 9000 tons of oil escaped to sea before the well came under control. There were no fatalities nor any injuries. Then we had the • Alexander L. Kielland capsizing in 1980, in which 123 people died. • The Commission investigating the latter disaster strongly criticized our confusing regulatory arrangement with many different regulators and recommended it to be revised. The involved ministries sat down to assess the situation and concluded that a dramatic change should be made. It resulted in a new regulatory regime with only 3 regulators: The NPD was to be responsible for safety in all petroleum activities, the State Pollution Control Agency for the protection of the environment and the Health Directorate for hygiene and health matters. NPD "inherited" all regulations of the former authorities and the first thing we had to do was to revise them and produce just one set of new, modern and goal -setting oriented regulations. BOE: You have assisted many developing nations with their offshore safety programs. Any advice you would like to share with new offshore regulators? Our approach to assisting developing countries has always been to only provide information on our experiences in the development of the Norwegian regulatory regime — what has worked well for us and what has not worked so well. We never recommend or suggest what type of regulatory regime they should choose or how they should run their safety programs in practice. It takes a long time to fully understand the local administrative or cultural specifics of a foreign country, so our policy has always been to leave such fundamental decisions for them to make. We might, however, suggest issues for them to consider. It is my view that all regulators engaged in assisting developing countries should apply the same approach. • BOE. You have also conducted reviews of several established regulatory programs. Any common weaknesses that you would like to highlight? This is true, Bud, and I can assure you I have learned a lot about regulatory regimes and practices by carrying out such reviews, including picking up particulars that have been beneficial to advancing our own regulatory and operational systems. Such peer reviews have no doubt been resource demanding, but also very rewarding and useful to ourselves. I would like to mention three common weaknesses that have often puzzled me: Firstly, the unclear division of the roles of the regulator and the industry participants. Quite often, for example, I have observed that regulators tend to take on roles, which in my mind clearly rest solely with the companies. Secondly, many sets of national acts and regulations appear to include requirements, which are confusingly spelled out, incomprehensible, inconsistent and incomplete. Often you'll find there is a plethora of requirements that do not provide for — or even concern — safety at all. Thirdly, for some reason, regulators often seem to become seriously bogged down in unimportant details in their daily work, whereas the bigger issues might be left unattended. • • May I also add another comment I often have to make, which is based on observations particularly pertaining to the challenges of regulators trying to properly conduct their duties in a federation of states: "I am glad Norway is one Kingdom!" BOE: Offshore regulatory regimes have been shaped by safety tragedies and major spills: the Santa Barbara blowout in the US and the Piper Alpha fire in the UK are 2 of the more prominent examples. Can you comment on the capsizing of the Alexander Kielland, and how that tragic incident influenced Norway's regulatory regime? I said something about that earlier, but let me elaborate: The Alexander L. Kielland, in which 123 good people perished, happened 30 years ago. Nobody in Norway was prepared for a tragedy of this magnitude. I can remember the whole country was in shock. To us at the NPD, it was incomprehensible that such a tragedy could possibly occur. We made a pledge to do all we could do to prevent a catastrophe of such dimensions from ever happening again. This pledge, has among other things, materialized in what I think today is an efficient regulatory regime. We have implemented an effective set of regulations, which among other things provide for a robust design of offshore installations with regard to minimizing major risks and which provide for proper barriers to prevent accidents from happening — or at least mitigate their severity. Along the road we have been greatly supported by our tripartite collaboration, which we have a tradition for mobilizing when developing a better Norway. BOE: In 2004, Norway separated its safety and resource management functions. The UK had done this after Piper Alpha, and Australia recently established a separate offshore safety regulator. Can you comment on the pros and cons of being an independent offshore safety regulator? This is a good example of the influence of the political system of a country on safety regulatory matters. Not that I disagree, but the change made to separate safety and petroleum administrative matters was probably also aimed at reducing political risk. We have had no problems relating to that fact. Our role and mandate has now become much clearer and we have been given all the necessary authority to fulfill our mission. However, it has placed a big responsibility on the PSA. We must ensure we make the right decisions and be able to defend them. For myself, I think our oversight of safety in the petroleum industry has become both better and stronger because of this change. But others shall have to judge that. BOE: From the standpoint of offshore facility safety, what are the major technical or management challenges that most concern you at this time? What currently concerns me the most is also reflected in PSA's four priority areas for • 2010, namely: that the management at all levels of the industry will keep working hard to reduce major accident risk, that the maintenance of technical and operational barriers is 40 prudent, that the industry will work determinedly to prevent undesirable incidents which could cause acute emissions and discharges, and that the risk of injury or illness for particularly exposed groups of personnel will be markedly reduced. BOE: Any regrets; things you think Norway or other offshore nations should have done differently from a regulatory perspective? Looking back, which of course you should never really do, I think it would have been an advantage if Norway in its early years had fully realized it was to be a major oil and gas producer and what consequences that would have for the society. In those early days, Norway was quite good at conducting analyses to assess what was needed to properly administer and use our enormous and valuable resources to the benefit of the society at large. But as I see it, we did not properly analyze what was required to develop our resources in a safe and environmentally prudent manner. These analyses could possibly have helped us identify who had the competency to do that. Unfortunately, such analyses came much later and in the wake of sad disasters. From the early days, Norway's petroleum conservation administration was therefore excellent, but we were not so good with regard to assessing how we should be regulating safety. The question is whether it had been possible to walk that different lane at all. • As with many other retrospective exercises — I have to admit I simply don't know. BOE: You were one of the original members of the International Regulators Forum, which was founded in 1994. Can you comment on the benefits of cooperation among offshore safety regulators? With pleasure, Bud! First of all, I have thoroughly appreciated the many annual meetings and making acquaintances with my good colleagues from various countries. Over the years, some of these resourceful persons have sadly resigned, but other eager members have joined. Our discussions and debates have always been informative and constructive, and they have certainly contributed to expanding my own knowledge and insight of systems for statutory regulation and current regulatory issues. I think these acquaintances provide for the most beneficial aspect of being a member of the IRF: The single member can meet industry contacts that operate all over the world and still be fully updated on the regulatory specifics of other provinces. It gives you confidence as a regulator to know that we regulators actually do not conduct our business so much differently. I personally have appreciated IRF's coordinated initiatives to meet with the industry's big organizations such as OGP and IADC to debate issues of common interest. This has been most satisfying. Furthermore, our discussions and debates have been useful in identifying common regulatory issues, which we together as a group of regulators can address to improve on. • • Our collaborative activities often bring about new ideas and provide useful lessons, other ways of thinking, and impulses to carry the members' own agencies forward. BOE: Your senior advisor, Odd Bjerre Finnestad, has been a leader in establishing an effective communication network among offshore regulators. He has proven to be a highly reliable contact for those interested in offshore safety issues. Can you comment on Odd's contribution to international cooperation and safety achievement? Well, you have already said a lot about Odd's achievements in international cooperation, Bud. We at the PSA like to regard Odd as a kind of our own Secretary of Foreign Affairs: He always keeps us duly updated about what is going on in the world when it comes to regulatory matters and industry incidents. Due to his extensive network of global contacts we often get the news even before the world press learns about it. Personally, I honestly don't think the IRF would have come as far as it has today without Odd's keen driving force. With his insight and experience of regulatory systems as such he has been of invaluable support to me during our peer reviews of fellow regulatory regimes. I do hope Odd will keep on working with the PSA until he's 101 — which he himself actually has threatened to do! BOE: Thank you very much, Magne, for having been so candid in your answers and for your willingness to help us kick-off our blog. Anything else you would like to add? You know Bud; I could probably go on for ages as long as somebody is willing to listen to me! It's been a pleasure talking to you! E Bromwich at OTC 2011: Feds will regulate offshore contractors *updated* littp://fueffix.convblog/2011/05/02/bromwich-at-otc-201 1-teas-will-regulate-offshore-contractors/ Posted on May 2, 2011 at 1:28 pm by Jennifer Dlouhy The federal government will expand its oversight of coastal drilling to include new regulation of oil field service firms, rig suppliers and other offshore contractors, a top Obama administration official said today. Michael Bromwich, the head of the Bureau of Ocean Energy Management, Regulation and Enforcement, said a broad internal review of current laws concluded that the agency has "broad legal authority over all activities relating to offshore leases, whether it is engaged in by lessees, operators or contractors." "We can exercise such authority as we deem appropriate," Bromwich told the Offshore Technology Conference in Houston. Bromwich has floated the idea of expanding the ocean energy bureau's reach beyond oil and gas companies before — but he had been unsure whether the move would require Congress to go along with the plan. According to the administration's internal legal review, congressional action isn't necessary; the agency already has the authority. Historically, the federal offshore energy agency — previously known as the Minerals Management Service — has focused on leaseholders and operators. Other federal agencies, such as the Coast Guard, separately regulate entities such as drilling rigs and their owners. The benefit of the traditional system, Bromwich acknowledged, is that "it served to preserve clarity and the singular responsibility of the operator." isBut the drilling chief said that he was "convinced that we can fully preserve the principle of holding operators fully responsible — and in most cases solely responsible — without sacrificing the ability to pursue regulatory actions against contractors for serious violations of agency rules and regulations." Bromwich insisted the Obama administration would be "careful and measured in extending our regulatory authority to contractors." Later, he told reporters that the move, while "important," wouldn't change much in the day-to-day practice of the ocean energy bureau. Essentially, it is a chance to step in — and impose fines or take other enforcement actions — whenever a contractors' conduct is "egregious enough." Bromwich said. "The practice may not differ that much" from what we are doing now, Bromwich said. Although the agency may formulate more guidance for its oversight of service firms and contractors, Bromwich said there are no plans for new regulations and rulemaking to go along with it. The presidential commission that investigated last year's oil spill concluded that poor communication among contractors on the Deepwater Horizon rig contributed to the disaster. Sean Grimsley, the panel's deputy chief counsel, said that there was an absence of a sense of real responsibility at the Macondo well. "One of the problems is that there are upwards of 20 plus contractors out here on one of these rigs," Grimsley said. "What we saw here was that different contractors were making critical decisions, often times without communicating what they had learned to other decision makers." Visit FuelFix this week for the latest news from OTC. You can also like our page on Facebook or follow • @FuelFixBlog on Twitter. Look for updates from reporters @houstonfowler and @jendlouhyhc under the #OTCHouston hashtag. 4 0 • W161 I - The fatality rate in the Gulf is five times greater than it is in the North Sea, and the North Sea is a more punishing environment. So we clearly have some issues here.' William Reilly Flashback to OE's cover of December 1990 and the advent of the UKCS safety case regime. "MAW ana1v sis Safely case may be in store for US sting a `renewed culture of safety' taking hold in the offshore oil & gas industry, the co-chairman of the presidential commission set up to investigate the Macondo disaster told attendees at the March CeraWeek conference in Houston that the US could benefit from the implementation of a North Sea -style 'safety case' approach to deepwater drilling regulation. William Reilly, co-chairman of the US National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (OE last month), also called on oil & gas officials to support the Obama administration's request for $358 million in additional funding to beef up staff at the Bureau of Ocean Energy Management, Regulation & Enforcement (BOEMRE). 'The industry needs regulation ... and it needs to be as sophisticated as the industry itself,' he said. The safety case method has been in use in Norway since the late 1970s and was implemented in the UK after the 1988 Piper Alpha disaster (OE July 1988). Unlike US offshore oil & gas regulations, which critics say puts the burden of risk assessment on regulators, the safety case approach requires operators to anticipate possible problems with a specific well and spell out how they would address them. The method is 'much more collaborative', Reilly said, while acknowledging that oil & gas companies in the US might be reluctant to embrace the change. 'Industry has to really want to do this,' he said, noting that implementation of the safety case took nearly a decade in the UK. 'In that case, the regulator took the initiative, but industry came along and supported it as well, and now is quite accustomed to it.' The transition in the US could be done more 'gracefully' because many of the companies operating in the Gulf also do business in the North Sea and are used to the regulations there, he said. Reilly praised the industry for joining forces to create the Marine Well Containment Company and credited Helix Energy Solution Group's 'ingenuity' in putting together a rapid -response blowout containment system, both of which have been used to satisfy new BOEMRE permitting regulations. 'Timely response and containment capability was a vital but missing element in overall safe drilling plans,' he said. 'Now, thanks to an extraordinary effort, it is coming together in a practical way.' But he took issue with critics who have blasted the moratorium and pushed back against new regulations, noting that the commission's research turned up 79 cases of well control loss over a 10•year http://oe.oilonIine.com OFFSHORE ENGINEER I april 2011 13 • FJOAC��ff� period in the Gulf of Mexico, as well as a troubling number of offshore casualties. � `In fact, the fatality rate in the Gulf is five times greater than it is in the North Sea, and the North Sea is a more punishing environment,' he said. `So we clearly have some issues here.' Reilly singled out BP for Service companies cry foul Oil & gas companies operating in the Gulf of Mexico are still reeling from the aftershocks of the BP Macondo disaster and the subsequent deepwater drilling moratorium nearly a year after the event, a panel of industry insiders told the CeraWeek conference. During a forum involving representatives from offshore service firms, it was pointed out that job cuts and fleet demobilization had occurred in the wake of the 20 April 2010 Macondo disaster, just as the industry was beginning to recover from the protracted economic downturn of 2008/09. 'We cold stacked or mothballed about a third of our fleet in the global economic crisis,' said Hercules Offshore senior VP, general counsel and chief compliance officer James Noe. 'We laid off almost 2000 people leading up to Macondo.' The worst of the recession's effects appeared to have eased in 1Q 2010, Noe and other panelists said, as service companies began to rehire laid off employees and put out encouraging business forecasts for the year ahead. But the drilling halt after the Deepwater Horizon explosion and spill plunged the industry back into turmoil, the company officials said. `Our business completely collapsed with the announcement of the moratorium on all offshore drilling,' Noe said. Although federal regulators lifted the ban on drilling in the shallow water Gulf of Mexico in May 2010 and deepwater drilling was reinstated later, critics point out that activity remained suppressed due to slow permitting and an uncertain regulatory environment. Hardest hit were companies that work almost exclusively in the Gulf of Mexico, speakers said. `Fully 50% of the project work that we had in our forecast and our guidance for the fiscal year was immediately cancelled' after the moratorium was imposed, said Joe Dunbar, Parker Cabett Subsea business unit manager for Parker Hannifin Corporation. `We're 90% focused on the Gulf of Mexico ... it's been devastating.' `We have picked up a few projects here in the Gulf, but basically, our Morgan City fabrication yard is significantly underutilized,' said John Nesser, executive VP and COO at J Ray McDermott. The company mobilized alleged safety lapses. `Based on my discussions with people I respect within the industry, there were a lot of concerns about the safety record and practices of BP well before [Macondo] happened,' he said. `Yet there was no mechanism to address it. That is what the commission means in identifying a "systemic" its DB50 pipelay vessel -'the queen of the McDermott fleet'- to the Asia -Pacific region and cold stacked the installation vessel DB16, Nesser noted. `And we're not going to bring it out unless we have a campaign of work that we can put together that makes sense.' The company's international operations helped boost its 2010 profits, he said: `We're lucky. [But] any Gulf of Mexico -focused company that doesn't have international opportunities is suffering.' In lunchtime remarks during the Houston conference's opening day, BP chief executive Robert Dudley acknowledged the widespread .; industry effects of the Macondo disaster. `As we have learned in the past 11 months, one company's calamity quickly becomes every company's concern,' Dudley said. But the service company officials, avoiding mention of BP, blamed their woes on the Obama administration and the moratorium. `Who would have thought that a political administration would try to shut down an entire industry, like what is going on hereT observed McDermott's Nesser. An IHS study released in conjunction with the conference, however, forecast a stronger 2011 for many oilfield service companies. According to IHS Herold's latest update on the oil field services sector, several multi -service providers with a strong international focus .'... performed well in 2010, led by Baker Hughes, which saw 2010 revenues of $14.4 billion, compared to $9.6 billion in 2009. Offshore drillers fared less well, the report said, with Rowan posting `nominal revenue growth' of 3% and Deepwater Horizon rig owner Transocean taking a 17% hit in earnings and a drop of 43% in earnings. `As we mentioned in our preliminary report issued last December, many of the service companies, and, in particular the offshore drilling companies, took a financial beating following the Gulf drilling moratorium. That negative impact constrained what was otherwise a substantial recovery for the sector compared to 2009 results,' said IHS principal energy analyst and report author John Parry. The report said business should rebound in late 2011 or early 2012 as strong oil prices and more robust E&P budgets boost offshore drilling demand - except in the Gulf of Mexico, `where lower activity levels will continue to limit earnings for the sector', IHS said. problem. It is not to say that every company, or even most companies, do not have strong safety cultures. It is to say that the responsibility for taking necessary steps to avoid another Macondo falls on the industry as a whole.' One possible response, he said, would be the creation of `an industry safety organization to promote and promulgate best practices, to share information, and conduct routine safety audits of its members - and discipline or eject those companies which fail to implement best practices.' The organization could be modeled on the US Institute of Nuclear Power Operations (INPO), formed after the 1979 Three Mile Island nuclear plant accident It would seem the industry has already endorsed the idea. On 17 March, a little more than a week after Reilly's CeraWeek appearance, the American Petroleum Institute announced that its board of directors had approved the creation of a Center for Offshore Safety, modeled in part on INPO and the UK's Step Change in Safety and safety case regime. The center will be based in Houston and open to all companies engaged in deepwater E&P. Eventually, Reilly said, US regulators could make membership in such an organization mandatory. Reilly, who served as Environmental Protection Agency administrator under president George HW Bush, rejoined industry critics who disputed the commission's findings of `systemic' safety lapses in offshore E&P. `I know our use of that term upset many in the industry,' he said. 'But it seems to me the absence of subsea containment capability, even as thousands of wells have been drilled in deepwater, and then the pro forma character of response plans on the part even of the best companies, speaks for itself. 'It would be dangerous, and a tragic waste of all that we have learned over the past year, if we allow that complacency to slip back in.' OE 14 OFFSHORE ENGINEER I april 2011 http://oe.oiIonIine.com • http://www.petroleumnews.com/pnads/ 100046473.shtml Prevention the best cure Week of April 17, 2011 Canada's industry urges review of Arctic drilling to favor new blowout technology Gary Park For Petroleum News • The Canadian Association of Petroleum Producers and leading E&P companies are stepping up their defense of exploratory drilling in the Arctic offshore, making a case for preventive measures rather than relying solely on same -season relief wells to prevent or deal with blowouts. Among the submissions to the National Energy Board's ongoing review, CAPP described the current regulatory regime as "robust and effective." The industry's leading lobby organization, CAPP said that view was endorsed last year by the Canadian Senate Committee on Energy, the Environment and Natural Resources which concluded the offshore regime is "modern, up-to-date and among the most efficient and stringent in the world" compared with any other countries with active offshore industries. CAPP said 2009 legislation created a goal -oriented regulatory environment that allows the NEB to oversee and regulate offshore activities. It noted that 132 wells have been drilled in Canada's offshore, 89 of them in the Canadian Beaufort Sea, utilizing several drilling systems and operating in a wide range of ice conditions. "This suggests that the issue before the NEB is not whether Arctic offshore drilling can be done safely while protecting the environment, but how we can maintain best efforts to • reduce the risks involved and prevent incidents," CAPP said. • Open, collaborative approach But CAPP, while noting that individual operators were best positioned to address options for well control and spill response, welcomed the "open and collaborative" approach to reviewing lessons learned from other jurisdictions. It expressed confidence that the NEB will decide that "appropriate measures are in place to provide for safe and environmentally responsible Arctic offshore drilling and will provide additional clarity for operators on the NEB's filing requirements for applications." Other than fallout from BP's Macondo well blowout in the Gulf of Mexico, the issue in Canada has gained added traction during the current federal election campaign. If elected to form a government, the opposition Liberal Party has pledged to halt all leasing and exploration activities in Arctic waters until an independent examination of the issues is conducted. Work commitments made Although there is no current drilling in the region, companies such as Imperial Oil, ExxonMobil, BP, Chevron and ConocoPhillips have made work commitments in the • hundreds of millions of dollars to explore for oil and gas in the Beaufort. None has scheduled any drilling before 2014, but all are urging the NEB to drop its requirement for same -season relief wells in the event of a blowout or spill — a provision that environmentalists insist is the last certain safeguard against spills that could last for years. Chevron Canada Vice President David MacInnis told The Globe and Mail the information generated from the drilling of Arctic wells to date "provides Canada with a competitive opportunity among Arctic nations, all of whom are seeking to develop their northern oil and gas resources." He said the current same -season relief wells requirement "will likely not be feasible as exploration drilling moves into deeper water areas with more complex wells and with more challenging ice conditions than were experienced in the initial phase of Canadian Beaufort exploration." MacInnis noted that Chevron is developing an "advanced well kill system," which it believes would dramatically increase the capacity of traditional blowout preventers to cut through drill pipe and seal the well in the event of an accident." Separate blowout control 0 ConocoPhillips is recommending that companies deploy a separate blowout control unit on the sea floor that could be activated if the main blowout preventer failed. The two companies said a same -season relief well would take months to complete in even the best of conditions. Chevron said in its submission that "reliance on a relief well as the only mitigation option could, in many ways, result in the situation we are expressly trying to avoid, which is the potential for a large spill." William Amos, an attorney for Ecojustice and WWF-Canada, said in a filing that companies should be required to adopt new technology that would choke off a blowout before a relief well could be completed. But he said that type of technology had yet to be proven as fail-safe. However, Amos said the organizations he was representing were not urging a total ban on Arctic offshore drilling, given the support among the local Inuvialuit for commercial development. "It is up to industry to make the safety case for offshore drilling ... and if they can't make it, the drilling should not be allowed," he said. • 0 4p Government weighs more drilling contractor oversight http://news.yahoo.com/s/nm/20110412/us nm/us usa oil spill By Ayesha Rascoe Ayesha Rascoe — Tue Apr 12, 6:16 pm ET WASHINGTON (Reuters) — The U.S. offshore drilling regulator is weighing options for expanding oversight of rig contractors after last year's massive BP Plc oil spill exposed a possible regulatory gap, Interior official Michael Bromwich said on Tuesday. Bromwich, who heads the the Interior Department's Bureau of Ocean Energy Management, said the agency was examining whether it has the authority to extend its regulations beyond the rig operators. So far, officials have found that the agency's regulations cannot go beyond operators unless new laws are enacted, but the agency is still looking into the issue, Bromwich said. "We may want to push for reforms in that area," Bromwich told reporters, eight days . before the one-year anniversary of the rig explosion that killed 11 workers and led to the spill. In the case of Gulf spill, BP was the operator for the doomed Macondo well and received a drilling permit from Interior, while contractors such as Transocean Ltd owned and operated the drilling rig and Halliburton Co did cementing on the well. Some official probes into the spill blame mistakes by Transocean and Halliburton, as well as BP, for the drilling accident that led to the largest offshore oil spill in the U.S. history. "I think it is very important for our regulations to extend as broadly as possible to all entities operating offshore and not for us to be artificially limited to the individual operator that applies for permit," Bromwich said. DEATH OF OFFSHORE OIL DRILLING An explosion on Transocean's Deepwater Horizon rig ruptured BP's underwater Macondo well, spewing nearly 5 million barrels of oil into the Gulf of Mexico last summer. Nearly a year after the accident, Bromwich and Interior Secretary Ken Salazar said the Obama administration has instituted a slate of reforms that have made U.S. offshore drilling safer than ever before. 0 • But some Republican lawmakers have attacked the administration for moving too slowly to approve new offshore oil and gas development. These critics say Interior has imposed a so-called de facto moratorium on drilling. Salazar slammed three bills the House of Representatives Natural Resources committee will consider on Wednesday, with provisions that would force the department to speed permitting and hold a canceled lease sale off Virginia's coast. "I think the legislation illustrates in my view a sense of amnesia," Salazar said. "We can't afford to take that approach the future of the nation's energy security." "If we have another Macondo blowout and we didn't have the ability to contain it, it would probably be death to oil and gas development in America's oceans," he said. (Editing by Jeffrey Benkoe and David Gregorio) • 'The [Gullfaks C1 investigation revealed several areas that need to be tackled, among them well monitoring.' 0ystein Michelsen Statoil admits `dialogue' doubts over Gullfaks C near miss Norwegian operator Statoil acknowledged last month that it could have been clearer in its dialogue with Norway's Petroleum Safety Authority following the May 2010 incident where pressure build-up in well 34/10-006A resulted in a near blowout and the shutdown of the Gullfaks C platform. Meg Chesshyre reports. 0 ystein Michelsen, EVP for development & production Norway, said there had been frequent contact between Norway's Petroleum Safety Authority (PSA) and Statoil since the C6 well incident. `After we intensified the work of mapping the condition of •wells in the Gullfaks field, we presented our findings in meetings with the PSA and the NPD on 16 and 21 December. We acknowledge that the level of detail in the information given at these meetings has been inadequate and we will clarify with the PSA the need for further information in this work,' he added. Statoil has systematically surveyed all of the wells in the main Gullfaks field since May 2010. Inspections made last autumn indicated a pressure build-up in several wells — chiefly water injection wells — in certain areas, suggesting a connection between the location of these wells and pressure build-up in the Shetland group and the Lista formation. This led to 20 of the field's wells, mostly water injectors, being shut down. A further 30 wells were subsequently shut down, but Statoil explained that this had been done to extend reservoir life and not for safety reasons. Work is continuing to get as many as possible of these wells into production again. According to Michelsen, well integrity and other subsurface matters have been high on the agenda of the Gullfaks organisation since the C well incident. `The investigation revealed several areas that need to be tackled, among them well monitoring,' he said. `The shut-in wells are now being scrutinised in order to evaluate their integrity. If it should emerge that there is a fault in the barriers, remedial measures will be implemented. The incident at Gullfaks C last May, however, was caused by a leakage in a casing. Nothing similar has occurred in the wells that have now been shut down.' Michelsen emphasised that in future Statoil will maintain its dialogue with the supervisory authorities, partners, the NPD and the safety delegate service, ... as a 2009 incident on Shell's Bardolino field raises more questions Meanwhile, the UK Health & Safety Executive's piece by consultant Ian Fitzsimmons in OEthis things, why it took some eight months for first handling of another near -miss North Sea blowout • month. Reviewing the recent US Presidential news of the Sedco 711 problem to leak out and — when the Transocean-operated semi Sedco 711 Commission report on the Macondo disaster, to almost a year for it to become subject to an HSE was drilling on Shell's Bardolino field in December which the `eerily similar' UK incident four months memorandum to Parliament. 2009 — comes under close scrutiny in an opinion earlier is referred, Fitzsimmons asks, among other Sedco 711: the regulatory issues, seepage 39. Content is copyright protected and provided for personal use only - not for reproduction or retransmission. 16 OFFSHORE ENGINEER I march 2011 For reprints please contact the Publisher. http://oe.oiIonIine.com Ail OE's at -a - offshore h and key off globally is using data energy an (www.infie Reserves int by water dept Water depth nu Shallow Deep cc (Ultradeep • Shallow y Deep � Ultradeep Shallow a Deep 3 Ultradeep (last month) Greenfield re 2011-15 Water depth nu Shallow Deep Ultradeep Global offsh Shallow wad (last m;nlh • Ultradeep Total 18 OFFSHORE ick stats glance guide to ydrocarbon alysts he mbers ore er New discoveries announced reserves Depth shore infrastructure range 2008 2009 2010 2011 updated monthly Shallow 4_ 195 66 6 from leading Deep(s, ieoc i 31 38 23 3 Infield Systems Ullrade�p 1 Id.com). Total 202 175 107 10 N'te Operators do not announce oisxvery dates a, the rme o" discovery, so totals !or previous years ca- continue to change. Golden Triangle "^ w.w . h 2011 15 (operational and 2010 onwards) Field Liquid Gas' Jin (km) mbers reserves reserves (mmbbl) (bcf) Operational(installed 39,295 Planned/possible 20,515 50 3844.45 20,4b3.79' 59,810 (59,3a1) 24 3623.00 2460.00 8-16in 28 5279.20 6530.00 Operational[installed 71,100 29 113.76 1404.57 Planned/possible 44,790 39 2331.86 3525.57 115,890 (115,793) 25 2894.25 4160.00 A6In Operationalliinstalled 91,195 157 3459.07 12,934.15 Planned/possible 5a 144 48 7501.50 5980.00 145.339 (13s339) 15 2390.00 IPc,- � 415 31,437.09 59,178.08 Production systems worldwide operational and 20'. 0 onwards) Floaters: mot up Operational 242 serves Under construction/conversion 27 Field Liquid Gas Planned/possible 261 reserves reserves 530 (s2o) (mmbbl) (bd) Fixed (� -, (mlmorrh) Operational 9459 1343 74,352.48 645,402.82 Under construction/conversion 140 (t35a p`13d.84) (64=„632.63) Planned/possible 1575 180 16,392.86 79,955.74 11,174 (11,153) (179) (15.152.86) (8000100) Subsea wells: Operational 4033 74 10,603.45 40,480,00 Underdevelopment 396 (67) (15,626.15) (4�280Jr," Planned/possible 4857 1597 101,348.79 765,838� 'r- 9286 reserves (mmboe) onstream by water depth 2009 2010 2011 2012 2013 2014 2015 11,755.22 11,009.46 23,021.51 46,913.51 39,122.76 37,829.01 40,927.71 (11,75522) (12,723.91) (23,639.79) (4758176) (36,95 A?) (37.455.48) (41.00725) 5013.66 2488.06 2611.03 3563.62 5716.85 11,432.44 72202.88 (5005.16) (2672.04) (2554.01) (M83) (556124) (11,413.94) (7281.96) 1042.96 975.57 653.34 1157.14 2387.80 5477.89 8072.96 (368.8-') (2526M) (2375.80) (4m3m (8072% 17,811.84 14,473.08 26,285.88 54,802.33 47,227.41 54,739.34 56,203.54 All reserves hgures are proven - pmtaae. Content is copyright protected and provided for pers( ENGINEER I march 2011 For reprints please co) making sure that they are kept constantly updated about the status and development of the Gullfaks field. `No leakage has been established from the reservoir, either to the seabed or to the shallow layers as a result of Statoil's operations at Gullfaks,' he noted. `There are natural pockmarks in the Gullfaks field resulting from the movement, or migration, of gas in the subsurface. The field is monitored continuously by gathering well data. Seismic data and seabed surveys are also analysed regularly. For the past 10 years Statoil has observed and mapped a high-pressure zone which lies partly at the top of the Shetland rock formation and at the bottom of the Lista rock formation which lies above Shetland. `This high-pressure zone has spread to a certain extent, due partly to pressure build-up which occurs naturally and partly to changes in pressure resulting from water injection which has unintentionally taken different paths than the reservoir,' said Michelsen. Statoil has been studying these pressure conditions since 2003 and the latest study of the Shetland and Lista formations, in November last year, showed that the high pressure had contributed to reducing the margins between the formation's pressure and strength. Analyses of the Hordaland group and the Utsira formation overlying Shetland had concluded that they would serve as a barrier against movement of liquids and gas and prevent any leakage to the seabed should a fracture occur in the Shetland formation. Michelsen made it clear that the safety of its staff, colleagues and suppliers on the Norwegian continental shelf remained the company's highest priority. `This should be clearly understood by everyone and it requires a good dialogue between management, our employees, their associations and our safety delegates. We are now focusing intensely on this dialogue and Gullfaks ,nal use only ltact the Publ -0- management is now looking specifically into how we can strengthen it,' he added. Another shutdown Another Gullfaks well incident reported by Statoil last month occurred on an independent exploration prospect unconnected to the main Gullfaks field reservoir. At 03.25 hours on 10 February, the semisubmersible Deepsea Atlantic (pictured above) initiated emergency shutdown procedures while completing operations on a gas condensate discovery well, 34/10-53 near the Gullfaks South field. The incident led to the crew being mustered onboard in accordance with regulations. Normalisation efforts on the rig began half an hour later and the situation was quickly clarified. Work on the well was then resumed. The incident was reported to the Norwegian Petroleum Safety Authority and investigations are ongoing. According to Statoil, the well had been closed for seven days due to bad weather in the area but when the BOP was re -opened and mud circulated downhole, gas was detected in the mud processing unit on the rig, triggering an immediate well shutdown. `The gas in the well was circulated in a controlled manner and the second well barrier was thereby re-established.' The operator added that conventional drilling technology was being used on the well at the time, and that the area did not contain the same demanding reservoir pressure conditions found on the main Gullfaks field. Also pressure conditions in the well were within the calculations made in advance of drilling the well. OE - not for reproduction or retransmission. fisher http://oe.oilonline.cam 2r, I I Report to the President { National Commission on the BP Deepwater 't-orizon Oil Spill and Offshore Drilling 30 OFFSHORE ENGINEER I march 2011 http://oe . oi I online corn 'It was onshore personnel who probably contributed most to the fundamental causes of this disaster.' 0 Macondo and the Presidential Commission Never one to pull his punches, consultant Ian Fitzsimmons applauds the openness of Januarys National Commission report to President Obama on the Macondo well disaster, but reprimands the UK Health & Safety Executive over its handling of the'eerily similar North Sea incident that occurred in the North Sea four months earlier but took eight months to enter the public domain. he publication of the National Commission report into the Macondo disaster has taken us one step closer to the final chapter of this sorry tale. It has been well received and the commission are to be congratulated for producing an excellent document, which will stand the test of time. The report is divided into three parts, the first dealing with `Path to Tragedy', the second the `Explosion and Aftermath' and the third with 'Lessons Learned'. Apart from the causes and consequences of the disaster, the report deals with the environmental and regulatory issues arising from the disaster. And the final chapter of Part III deals with American energy policy and the future of offshore drilling. I recommend that everyone involved in the offshore (and onshore) oil and gas industry reads the report. It is some 368 pages long, and you may want to have a glass of wine to hand. It has to be said at the outset that this report reveals little about the Deepwater Horizon BOP, now languishing somewhere in an American state. That autopsy report has still to be delivered. It may take a very long time while various agencies in America argue over its custody. It may well require the president to intervene and remind them that the families of 11 dead men are waiting for the truth. The commission's report, the first independent account of the disaster, is a vast improvement on the previous offering from BP (OE November 2010). Of course, being independent means you do not have to worry about your mortgage and your career, and any legal consequences! The commission also had the advantage that it received written accounts from all the survivors of the disaster, and all the participating contractors. Most importantly, it was able to interview and receive testimony from both offshore and onshore personnel, thereby providing substantially more background information than the BP accident investigation report. As it turns out, it was onshore personnel who probably contributed most to the fundamental causes of this disaster. Preamble This piece summarises the events, causes and consequences of the disaster, and the lessons to be learned from it. Part II Chapter 4 pp89-127 is the reference document for this review of the Macondo disaster. I was impressed by the compassionate and measured style of the report. It is neither vengeful nor angry, but it is direct and it is pointed. It names all the key personnel involved in this tragedy, the offshore dead, the survivors, and the onshore personnel who called the shots. The report does not shy away from recalling and describing earlier BP disasters — namely the Texas City refinery fire and the Alaska pipeline rupture — and the Thunder Horse near - disaster. Had the commission delved deeper and longer, they would also have discovered the BP Sea Gem jackup disaster in the UK Southern North Sea, which occurred on 27 December 1965. Thirteen men were killed. A subsequent public enquiry held BP culpable for systemic management failures. It all sounds depressingly familiar. The commission report (p124) also references a North Sea incident in which a near -catastrophic blowout was narrowly avoided on 23 December 2009, some four months prior to the Macondo blowout. It is relevant to Macondo and worth recounting here. The Transocean-operated semi Sedco 711, working on the development of Shell/Bardolino oil field, suffered an `eerily similar near miss' (in the report's words) when gas entered the riser on the rig while the crew was displacing a well with seawater during a completion operation. As at Macondo, the rig crew had already run a negative pressure test on the lone physical barrier between the pay zone and the rig, and had declared the test a success. The tested barrier nevertheless failed during displacement resulting in an influx of hydrocarbons. Mud spewed onto the rig.tloor — but fortunately the crew was able to shut in the well before a blowout occurred.' One of the more curious aspects of this incident is that it took so long — something like eight months — to first enter the public domain. The report about the near miss was in the hands of the UK authorities, but it was held as `confidential' and never released to the public. Subsequent Transocean advisory notes did not reach the Deepwater Horizon crew. According to the Presidential Commission report: Had the [Deepwater Horizon] rig crew been adequately informed of the prior event and trained on its lessons, events at Macondo may have unfolded very differently.' 125 Was BP aware of any of the foregoing? If it was, it made no mention in its initial report. If it did not, what does that say aboutTransocean? And questions that must surely attach to the UK Health & Safety Executive's handling of this matter are raised in the companion piece to this article ('Sedco 711— the regulatory issues', page 39). > overleaf Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe.oiIonIine.com For reprints please contact the Publisher. OFFSHORE ENGINEER I march 2011 31 • • 'In spite of anomalies, BP believed that both valves had converted and re-established mud circulation in the well. On Monday 19 April, the production casing test was declared successful, and the rig crew were ready to begin the cementing process, which started immediately.' The road to disaster Macondo had been a difficult exploration well to drill. Initially planned to be 20,200ft deep, it was curtailed at 18,360ft due to a lost circulation event, which was eventually stabilised. On 10 April2010, BP informed its JV partners that 'well integrity and safety issues required the rig to stop drilling further'. As a result: 'Transocean were able to spend the nextfive days between April 11 and 15 logging the open hole. Based on the logging data, BP concluded that it was economically worthwhile to install a final production casing string that BP would eventually use to recover oil and gas.' W94) The onshore BP design team had originally planned to use a long string production casing — a single conduit (7in x 95/8in) hung from and locked down against the subsea wellhead. The shoe track would be cemented in place, as would the bottom 7in wellbore annulus. On 14/15 April BP and Halliburton analysed and reviewed the proposed cementing process. They came to the conclusion that the long string could not be cemented reliably. Accordingly, the BP onshore design team switched to a liner approach. The liner configuration would have taken longer to install, but would have been far less risky, incorporating bridging plugs and casing packers in addition to top cement plugs. However, following an internal review and recommendation by a 'BP in-house cementing expert', the BP design team reverted to the use of the long string method. Halliburton then pointed out that the BP long string design called for at least 16 centralisers, whereas only six were available from stock. Much discussion and analyses ensued, but eventually the BP onshore view prevailed and only six centralisers were used. Early on Sunday 18 April, the rig crew began lowering the long string production casing into the well. The leading end of the casing, or shoe track, began with a reamer shoe, which is Figure 4.2from the Presidential Commission report shows the two temporary abandonment options. designed to guide the long string through the wellbore. The reamer shoe was followed by about 180ft of Tin casing. Above this was a float collar with two spring loaded flapper type check (float) valves, both of which were held open by an open-ended 'auto -fill tube'. The mud in the wellbore flowed through the open ported reamer and the auto -fill tube as the long string was lowered. The long string installation in the well was completed the afternoon (13.30) of Monday 19 April. It had taken 37 hours to install. It had been landed in the subsea wellhead, but the 95/ein casing hanger lock-down/seal assembly was not activated. The casing hanger seal was in place, held down by gravity and nothing else. This was not an accidental choice — it was premeditated. Figure 4.4from the In preparation for cementing, Presidential Commission the auto -fill tube must be report shows the Macondo shoe displaced so as to enable the track andfloat collar. flapper valves to close. They are then converted to their original role, which is to allow the passage of mud and cement from above and to prevent the ingress/backflow of cement and well fluid into the long string production casing. In order to convert the valves, mud is pumped down and through the tube to displace it into the shoe track. The predicted rate of flow to achieve this was 6bpm with a differential hydraulic pressure of 600psi. In fact it took 3142psi to dislodge the tube. 'Significantly, however, the pump rate of mud into the well and through the shoe track thereafter never exceeded 4bpm, approximately.' BP concluded that the.11oat valves had converted, but noted another anomaly. The drilling mud contractor had predicted that it would take a pressure of 570psi to circulate mud after converting the valves. Instead, the rig crew reported that circulation pressure was much lower. - only 340psi.' In spite of these anomalies, BP believed that both valves had converted and re-established mud circulation in the well. By 19.30 on Monday 19 April, the production casing test was declared successful, and the rig crew were ready to begin the cementing process, which started immediately. Tuesday 20 April Transocean and Halliburton finished pumping the primary cement job at 00.36. BP and Halliburton performed a flowback test at the mud pump. 'While it is not clear how long the two men actually watched for potential flow, they eventually concluded the flapper valves were holding.' Readers will note that the tone of this quotation suggests the commission were not entirely satisfied with either the results or the observations made in respect of this test. However, with the cement job declared a success, BP and the Deepwater Horizon crew began to plan the final phase of its work — temporary abandonment of the well. > overleaf Content is copyright protected and provided for personal use only - not for reproduction or retransmission. 32 OFFSHORE ENGINEER I march 2011 For reprints please contact the Publisher. http://oe.oiioniine.com • • separates heavy drilling mud i from seawater — followed by seawater down the drill pipe to displace 3300ft of mud below the mudline to above the BOP as per the report's Figure 4.6. To conduct a proper negative test at Macondo, BP also had to isolate the well from the effect of the 5000ft column of drilling mud in the LP drilling riser. 'Those heavy columns of mud exerted much more pressure on the well than the seawater that would replace them after temporary abandonment. Specifically, the pressure at the bottom of the well would be approximately 2350psi lower after temporary abandonment than before.' 106 In short, the well would be massively underbalanced and would require intense Figure 4.6from the observation, appropriate to the Presidential Commission risk that BP and the rig crew report shows mud were about to instigate. displacement in preparation Once the crew had displaced for negative pressure testing. the mud top just above the BOP, they closed an annular preventer, thus isolating the well from the heavy mud in the LP drilling riser (the annular preventer had closed around the drill pipe). The crew could now perform the negative pressure test using the drill pipe. It was 16.54. The first step was to bleed off pressure at the top of the drill pipe (at the Deepwater Horizon drill floor). If the well was stable, the pressure at the top of the drill pipe would reduce to zero. But that was not the case. It was 1261psi. Repeated attempts to bleed off the pressure failed. When the isolation valve at the top of the drill pipe was closed, the pressure jumped back to 1262psi. The time was about 18.00 and the nightmare that was to become Macondo began to unfold. The crew noticed that the fluid level in the LP drilling riser had fallen. The annular preventer was re -pressurised, and the riser refilled. The crew then repeated the negative pressure test three times. And each time the drill pipe shut-in pressure increased to 1400psi. A successful negative pressure test would require the shut-in pressure to be zero. After discussion between BP and the rig crew, BP insisted on running another negative pressure test. This time the drill pipe would be shut-in and the test performed on the BOP kill line. The pressure on the kill line should be identical to pressure on the drill pipe as both flow to the well. Figure 4.7 illustrates the arrangement. For the second test, the crew opened the kill line and bled the pressure down to Opsi. A small amount of jluid.jlowed, and then stopped.' 108 In fact, according to the rig crew, the kill line was still flowing, albeit at a 'pencil rate' when it was shut-in at 19.55. But the pressure at the head of the drillpipe remained at 1400psi throughout the test. This reading could only have been caused by an active leak into the well. 'Nevertheless, at 8.00pm, BP Well Site Leaders ... made a key error and mistakenly concluded the second negative test procedure had confirmed the well's integrity.' fplm �A nal use only - not for reproduction or retransmission. 34 OFFSHORE ENGINEER I march 2011 For reprints please contact the Publisher. 'The cement used for Macondo was neither safe nor qualified for the purpose.' At 10.43, the BP well site leaders received an email from BP onshore personnel listing the temporary abandonment procedures for the well. It was the first time the BP well site leaders on the rig had seen the procedures they would use that day. BP shared the procedures with the rig crew at the 11.00 (same day) pre -tour meeting. According to page 104 of the commission's report, the basic sequence was as follows: 1. Perform a positive pressure test to test the integrity of the production casing. 2. Run the drill pipe into the well to 8367ft (3000ft below the sea bed.) 3 Displace 3300ft of mud in the well with seawater, lifting the mud above the BOP and into the (LP) drilling riser. 4. Perform a negative pressure test to assess the integrity of the well and bottom hole cement job to ensure outside fluids (such as hydrocarbons) are not leaking into the well. 5. Displace the mud in the riser with seawater. 6. Set the surface cement plug at 8367ft. 7. Set the 9118in casing lock-down/seal assembly.' It is obvious that BP onshore had made numerous changes to the original 12 April temporary abandonment procedures in the two weeks leading up to the Tuesday 20 April email. For example, the 12 April plan had set out the following: 1) Set the 9118in casing hanger lock down/seal assembly before setting the surface cement plug. 2) Set the surface cement plug in seawater 6000ft below the rigjloor-1000ft below sea level/BOP. 3) No requirementfor a negative pressure test. According to the commission: 'There is no evidence that these [20 April] changes went through any sort of formal risk assessment or management of change procedures.' Thus the countdown to disaster had begun with the initiation of an anomalous cement job, followed by the flawed 20 April temporary abandonment procedure, which initiated the negative pressure test. 41 minutes We know now, and BP and Halliburton knew then, that the cement used for Macondo was neither safe nor qualified for the purpose. In fact BP had been advised by Halliburton on 8 March of the results of a single stability test, which confirmed the point. 'To the trained eye, that test showed that the February foam slurry design was unstable ... and there is no evidence that BP examined the foam stability data in the report at all.' W101 Nevertheless, in accordance with the instructed temporary suspension procedure, the positive pressure test began around noon. The well was pressurised up to 250psi for five minutes, and then pressured up to 2500psi (on the rig) for 30 minutes. The pressure inside the well remained steady throughout. BP and the drilling crew considered the test successful at 12.00, and the rig crew began preparations for the negative pressure test. The crew ran the drill pipe down to about 8367ft below sea level and then pumped a 'spacer'— a viscous liquid that Content is copyright protected and provided for perso http://oe.oIIonIIne.com E • Figure 4.7from the Presidential Commission report shows the kill line test with drill pipe closed. This horrendous decision accelerated the end. Having declared the negative test a success, BP moved forward to the next stage of abandonment as prescribed by the flawed temporary abandonment procedure. At 20.02 the rig crew opened the BOP annular preventer and began displacing mud (above the BOP) from the LP riser. `The driller repeatedly rerouted the mud returnsfrom one pit to another in order to accommodate the incoming volume ... it is not clear whether the driller, assistant drillers, or mudlogger could adequately monitor active pit volumes (or flow in versus flow out) during that time given all the activity.' In short, how could the rig crew tell when all the mud above the BOP had been displaced? At approximately 21.01, drill pipe pressure began rising. The effect of mud displacement with seawater was initially to reduce the pressure at the head of the drill pipe. Now it crept upward from 1250psi to 1350psi. Had someone noticed, he would have to explain to himself how the drill pipe pressure could be increasing while pump rate was not. One possible reason might have been that hydrocarbons wereflowing up the well and pushing heavy mud up past the drill pipe.' 111 The injection pumps were shut down between 21.08 and 21.14 to perform a sheen test on the returns. During that time the drill pipe pressure should have remained constant. Instead it is recorded that it went up by 250psi - and nobody noticed. Pumping recommenced. 'Shortly before 9.3opm, the driller noticed an odd and unexpected pressure difference between the drill pipe and the kill line. At roughly 9.3opm the crew shut off the pumps to investigate. The drill pipe pressure decreased after the pumps were turned off but then increased by 550psi over a 5.5-minute period. Meanwhile the pressure on the kill line remained significantly lower.' 112 Despite the mounting evidence of a kick, the driller never attempted to shut in the well. Sometime between 21.40 and 21.43, drilling mud spewed over the rotary onto the drill floor. The crew took immediate action and routed the flow from the LP riser through the diverter system and overboard, before deciding to send it back through `This horrendous decision accelerated the end. Having declared the negative test a success, BP moved forward to the next stage of abandonment as prescribed by the flawed temporary abandonment procedure.' the mud -gas separator. Then they tried to close the annular preventer around the drill pipe to stem the flow. `Their efforts were futile. By the time the rig crew acted, gas was already above the BOP, rocketing up the riser and expanding rapidly ... a representativefrom Transocean likened it to 550 ton freight train hitting the rigfloor.' 114 The mud -gas separator was quickly overwhelmed, ignition and explosion were inevitable. Forty-one minutes had elapsed between the time when pressure was observed to be rising in the drill pipe during displacement of mud with seawater in the LP riser, and the time when mud spewed over the rotary onto the drill floor. No attempt was made to shut-in the well during those minutes. In fact the well should have been shut-in earlier at 20.00 as a result of the anomalous 1400psi shut-in pressure in the drill pipe discovered during the negative pressure test. This staggering anomaly could only have been explained by the fact that hydrocarbons had already entered the well. They must have entered the well before 16.54 when the first anomalous pressure reading was discovered in the drill pipe at the start of the negative pressure test. The first explosion occurred around 21.50, followed by another some ten seconds later. In the late evening of 20 April 2010, eleven men lost their lives, and it was all avoidable. Two days later, at 10.22 on Thursday 22 April, the Deepwater Horizon sank. Management of risk The commission searched for the root causes of this disaster. It was not a difficult task. Page 122 of the report states: `The most significantfailure at Macondo - and the clear root cause of the blowout - was a failure of industry management. Most, if not all, of thefailures at Macondo can be traced back to underlyingfailures of management and communication. Better management of decision making processes within BP and other companies, better communication within and between BP and its contractors, and effective training of key engineering and rig personnel would have prevented the Macondo incident.' Few would disagree with that conclusion. The commission also highlighted a failure of risk management. BP did not have adequate controls in place to ensure that key decisions in the months leading up to the blowout were safe or sound from an engineering perspective. While initial well design decisions undergo a serious peer -review process, and changes to well design are subsequently subject to a management of change process, changes to drilling procedures in the weeks and days before implementation are typically not subject to any such peer - review process. At Macondo, such decisions appear to have been made by the BP Macondo team in an ad hoc fashion without any formal risk analysis or internal review. This appears to have been a key causalfactor of the blowout.' 123 Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe.oil online. corn For reprints please contact the Publisher. OFFSHORE ENGINEER I march 2011 35 • 9 'It is very obvious that decisions being made on the hoot — both onshore and offshore — and without due consideration led to the disaster. It could have been avoided with just a little thought and common sense.' The following examples will illustrate the point. Readers should bear in mind that BP curtailed the Macondo well short of its target depth because `well integrity and safety issues required the rig to stop drilling further'. Cement The selection of nitrogen foam cement for Macondo went unchallenged. BP has little experience with foam technology for cementing production casing in the Gulf of Mexico and there is no evidence that this type of cement was even qualif led for Macondo. The record confirms that a round of tests was performed in mid -April 2010, just before pumping the final cement job. Halliburton began a second test on 18 April. That would normally take 48 hours, which takes us to 20 April, the day of the blowout. Had a risk analysis been correctly performed, it is obvious that this particular type of cement would never have been selected for Macondo. It represented a major technical and schedule risk. Temporary abandonment procedure The temporary abandonment procedure was sent to the Deepwater Horizon on 20 April and received at 10.43. There is no evidence that the changes from the original 12 April plan went through any sort of formal risk assessment or management of change process. The biggest risk concerned the addition of the negative pressure test without any risk assessment, and without any risked negative test procedure. `The most troublesome aspect of BP's temporary abandonment procedure was their decision to displace mud from the riser before setting the surface cement plug or other barrier in the production casing.' BP could have set the surface plug or a mechanical plug before displacing the riser. BP could have over -balanced the well with .. �s m;<Va Y� sa.en Sins! tarcl Pon+eps ePi Ce` Yes Sa ec Time eP an sht 0:a, 1.op _ -1 Spacer Mace pan cacao last C-aAG - ras Saud Tone 8P W stx e • als tc Aw4 Disposer Issues anq MW her a¢e: Beime .. ,:4 Solt .. Cement NO 8P m st(r,; _ S.r+ace caw. etta 3 WO�� Yes �'` ` W - snore _• Wd ts,e.., seawaigr �Nx>rurea au mm) N_ Imt.WgAdW,,— P' Y Bwnete DM g km:ic=,ary Yes Seaed T+ SP -!;I-. ,°y,.,-YjiYi 0 P4�1.el Nc ppAta+ VF~,wn! ,4i 4 aperosacS m liph; ,A kq m'o sa.reo T,me BP W4 Pert w'. 1 aiO UnmAasxd MJpA,a,. gr..�x . TWSDC n; am.$" Pas arc ctatdudlm DRw 1 vanspcaa ygWaa tlUS 0M d—; Ype shed T.m¢ ;a Pe+tw M D 9 D.Pbu,' erN An Figure 4.10from the Presidential Commission report shows examples of decisions that increased the risk at Macondo while potentially saving time. Content is copyright protected and provided for personal use only - not 36 OFFSHORE ENGINEER I m a r c h 2011 For reprints please contact the Publisher. heavier mud. It is not apparent why the company chose not to do any of these things. The lack of any formal risk assessment was a colossal mistake. Furthermore the decision to displace mud 8367ft below the drill floor, rather than the original 6000ft proposed, required explanation and risk assessment having due regard to the previous concerns about well stability. This new procedure was fundamentally flawed and was a root cause of the blowout. Nevertheless it was implemented at 12.00, just 77 minutes after its arrival offshore, and without any obvious review by BP and the rig crew. The following risk assessments should also have been executed by BP: • use of flapper valves in the float collar; • use of auto -fill tube for flapper valve conversion; • use of the long string configuration vs conventional liner configuration; • float collar conversion pressure and flow anomalies; • wiper plug disc rupture pressure and cement flow anomalies; and • the anomalous result of the negative pressure test and the pressure discrepancy between the drill pipe pressure and the kill line pressure. The first few points should have been assessed for risk as part of the original well design process. Point three, long string configuration vs liner, should have been revisited in light of the results found during well execution. All the remaining points constituted good reason to shut-in the well in favour of risk assessment reviews, until suitable procedures and alternative remedial options (if so required) could be put in place. It is very obvious that decisions being made on the hoof — both onshore and offshore — and without due consideration led to the disaster we regret today. It could have been avoided with just a little thought and common sense. Cost considerations The commission does not say the Macondo disaster was the result of cost cutting, but it has produced a simple analysis, Figure 4.10, to demonstrate where risk could have been increased at Macondo while potentially saving time. According to the commission, as of 20 April 2010, BP and the Macondo well were almost six weeks behind schedule and more than $58 million over budget. I do not find that fact surprising in the least. I have never heard of a well that came in on schedule and within budget, and I think most operators would agree. It would be puerile to suggest that cost and schedule are not background considerations. They are always there, but mainly during the desktop project development phase of any project. It is for that reason that risk assessments are required to demonstrate that cost optimisation and potential saving do not incur an unacceptable level of risk to either the asset or project personnel. In its report, the commission stated that: `There is nothing inherently wrong with choosing a less costly or less time consuming alternative — as long as it is safe. Whether purposeful or not, many of the decisions that BP, Halliburton and Transocean made, that increased the risk of the Macondo blowout, clearly saved those companies significant time and money.' The foregoing follows on from the commission's complaint about the lack of risk assessment evident in the planning and execution of the Macondo well. I have identified one such example, which does not appear in Figure 4.10 — the use of flapper valves in the shoe float collar, and their dependence on an auto -fill -tube to effect their conversion to more usual one way check valves. It occurs to me that this configuration and procedure contains a considerable for reproduction or retransmission. http://oe.o11onIine.com 'This horrific disaster could and should have been avoided, notwithstanding the fact that this had been a difficult exploration well to drill.' and unacceptable risk. If the float collar fails to convert, then the only way to recover and rectify the situation is to mill it out. This would have required a long return trip from the Deepwater Horizon lasting many days. It would have been possible not to use float collar flappers after that - it would have required the installation of a more dependable, wireline-set check valve in the production casing installation. However, this option would also have involved a long return trip from Deepwater Horizon. Tripping in 5000ft of water is expensive. It is a common frustration among those with experience of deepwater projects. The use of an integral float collar saved BP a considerable expense and rig time. The commission complains that a risk assessment should have been conducted to demonstrate if the float collar was a valid option when compared with the other available solutions. I suggest that, given the anomalous pressures that were required to effect the conversion, and the subsequent blowout, float collar conversion did not work and neither did the flappers. This failure was then compounded by the BP decision to proceed with the cement job, regardless. The correct decision would have been to shut-in the well and conduct a risk assessment of the recovery options then available, before proceeding further with execution of the cement job. Hopefully a risk assessment of the float collar configuration during the planning phase would have precluded their inclusion in the first place, in favour of a more risk free and dependable alternative, albeit at a greater cost. However, I do not believe cost considerations were a real driver in this disaster. I believe that, for the most part, it was due to carelessness born of frustration and weariness among the rig crew and BP, both offshore and onshore. Paradigms I have noticed and identified during the reading of both the initial BP report and the commission report, several well established paradigms which drive to the heart of this disaster. They were discussed in the first of my Macondo pieces with reference to the Titanic, Comet, and NASA space shuttle failures (OE July 2010) and have all been repeated in the Macondo disaster. Disbelief in humans is a common paradigm. It arises when we refuse to acknowledge the evidence of our eyes and common sense in face of the obvious (but unacceptable) truth staring us in the face. Pilots are trained at the outset of their careers to rely on their instruments, not their heart. It is a discipline that can itself still cause disasters, but that is a minute risk compared with the alternative. Nobody believed that a simple O-ring could have caused the Challenger shuttle disaster, and nobody believed that a piece of foam insulation could have caused the Columbia shuttle disaster. So great was the disbelief, qualification tests were instructed to dispel the suggestions as nonsense. The opposite proved to be the case. There were four events during the execution of the Macondo well that beggar belief: 01. The acceptance without interrogation of the obviously anomalous pressures and flow rates seen during the float collar conversion. In spite of the obvious, they chose to believe that conversion had been a success. No such basis existed for that belief. This was the first occasion that the well should have been shut in. 02. BP's accident investigation report described the hugely anomalous pressure (2900psi vs 900psi) required to rupture the bust disk in the bottom wiper plug, which landed on the float collar. The commission neglected to include this event in their report. Following on from (1) above, it is difficult to believe that this anomalous event could be dismissed as a simple coincidence, which could be ignored. It was now a systemic concern. But it was dismissed without any assessment of possible causes and remedial options. This was the second occasion that the well should have been shut in. 03. The acceptance without interrogation of the obviously anomalous pressure found in the drill pipe after the cement job, in preparation for the negative pressure test. The pressure in the drill pipe should have been zero. It was 1261psi and could only have come from the well. BP and the rig crew were offered and accepted a convenient and sophistic explanation, which they accepted without question. They did so because they could not believe what was happening - because it was not supposed to happen. They did not interrogate the anomaly because they chose to believe otherwise. They recorded the negative pressure test as a success in spite of the obvious fact that something was going badly wrong. That something was hydrocarbons entering the well. This was the third occasion that the well should have been shut in. 04. As per the temporary abandonment procedure, the rig crew began to displace mud from the LP riser above the BOP. The annular BOP had been opened and the well was now open to the sky. Pressure in the drill pipe continued to rise steadily. This was the third time the well should have been shut in. They must have realised that the previous anomalous pressure (1261psi) was a fact. It must have been obvious by now that the drill crew were facing a blowout. They chose to ignore the obvious and carried on. Some 41 minutes later, mud spewed through the rotary onto the drill floor. It was now 21.42 and the hydrocarbons had been in the well before 18.00, sending out signals that they refused to believe. Not once had they considered controlling the well. Bewildered by events, they routed the mud flow through the diverter. Then they re-routed back through the mud -gas separator (MGS), which was quickly overwhelmed by gas. The first explosion occurred at 21.50. The crew should have retained the diverters to send the mud and gas overboard. The diverter had been their last chance to save themselves and the Deepwater Horizon. At the very least it would have given them some time to escape. But they believed the MGS was the correct way to control hydrocarbons. They had been in a state of disbelief since 18.00. On page 119 of its report, the commission states: .. the Transocean crew should have been particularly sensitive to anomalous pressure readings and ready to accept that the primary cement job could have failed. It appears instead they started from the assumption that the well could not bellowing, and kept running tests and coming up with various explanations until they had convinced themselves their assumption was correct'. �p Content is copyright protected and provided for personal use only - not for reproduction or retransmission. JU OFFSHORE ENGINEER I march 2011 For reprints please contact the Publisher. http://oe.oiioniine.com n �J C� We can see in this quote that the paradigm of design infallibility can also be heard echoing from the Titanic and Comet disasters. Blowout preventer The Deepwater Horizon BOP was recovered in September and taken into custody for an autopsy. The results are still awaited and until we have this missing piece of the jigsaw the Macondo well disaster's final chapter cannot be written. But we can say that this magnificent bulwark was largely ignored throughout the disaster. The annular preventer seems to have been the workhorse for most of the time. We do not know why the driller did not immediately activate the BOP blind shear rams at 21.42 (mud overflows the rotary). Perhaps he did and they failed. We have to assume that the drill pipe joints had been correctly spaced out through the BOP stack. A witness account suggests that a member of the crew activated one of the annular preventers around this time. Pressure readings suggest that the crew activated a variable bore ram around the drill pipe at 21.46. But the blowout flow rates probably prevented their closure. After the explosion, crew members tried to activate the riser emergency disconnect system (EDS), presumably out of sheer desperation. The EDS should have closed the shear rams and severed the drill pipe, and released the riser from the rig. But nothing happened. We can reasonably assume that all communications with the BOP and LMRP had been lost. Notwithstanding the foregoing, the BOP does have a fail-safe activation system —'Deadman'—that should have been automatically activated after communication with the rig had been lost. It failed, but we have to wait for the autopsy for confirmation. Conclusion This horrific disaster could and should have been avoided, notwithstanding the fact that this had been a difficult exploration well to drill. The commission report will change the global oil and gas industry forever. It has addressed regulatory and environmental failings, and has reminded us that risk assessment and management are obligatory in the planning and execution of wells of all types. The commission considers the root causes of the blowout were a systemic failure of industry management and a failure of government to provide effective regulatory oversight of offshore drilling (page 122). Few would argue with that. The following commission quote comes from the same page: Finally, and perhaps most importantly, the rig crew had not been trained adequately how to respond to such an emergency situation. Infuture, well control training should include simulations and drills for such emergencies — including the momentous decision to engage the blind shear rams or trigger the EDS. While I endorse the foregoing without reservation, I close this piece with a simple if not banal reminder that we are all human, and to err is human. But within reason. The Macondo wounds will heal eventually, as did those of the Piper Alpha and Sea Gem tragedies. But it is such a pity we always have to learn things the hard way, and with such loss of human life. It is a paradigm the industry should strive to be rid of. GE o Ian Fitzsimmons, February 2011 Ian Fitzsimmons, a regular contributor to OE, is an independent • consultant with more than 30 years' offshore industry experience. He has worked for major operators around the world and major subsea hardware/ drilling equipment contractors, and has extensive due diligence and expert witness experience. He was chief engineer for RJ Brown & Associates in London. The views expressed in this article are the author's own and do not necessarily reflect OE's position. n the wake of the July 1988 Piper Alpha disaster in the UK North Sea, the Cullen Report introduced a risk management approach to offshore safety, making the production and maintenance of a risk -based `safety case' a legal requirement for every UKCS offshore facility, fixed or mobile. Lord Cullen referred to it as a living document that would be subject to continuous monitoring and updates (OE December 1990). The safety case has to be prepared by industry and presented to the UK Health & Safety Executive (HSE) for review. This review checks the risk assessment process for completeness, but the HSE does not actually approve the safety case. It seeks to satisfy itself that the risks have been identified and assessed by the operator, and that the risk to life and the operational asset have been kept as low as reasonably possible — the ALARP principle. The US Presidential Commission referred to this North Sea requirement and recommended that the same obligatory risk - based assessment approach to safety be introduced in the US. But it would be a mistake to assume that the production of the safety case is a panacea for the current ills in the offshore oil and gas industry — far from it. The UK came close to another major disaster of its own with the Sedco 711 incident, which occurred just a few weeks before Deepwater Horizon's 31 January 2010 arrival at the Macondo location. Near miss or otherwise, this `eerily similar' incident was avoidable, just like Macondo. Bardolino I must confess that this `near miss' had passed me by until page 124 of the Presidential Commission report drew my attention to the episode's direct relevance to Macondo. On 23 December 2009, a major blowout was narrowly averted on Transocean's Sedco 711 semisubmersible when a formation isolation valve (FIV) located in the production liner failed, with the well in an underbalanced state. The rig was working on the Shell -operated Bardolino field, a single subsea well tied back to the Nelson field fixed platform in the Central North Sea. The rig crew were circulating the well with seawater as part of the well completion and commissioning procedure. The isolation packer and FIV had been successfully pressure tested from above and then `successfully inflow tested to confirm the integrity of the mechanical barrier to the reservoir'. After the `successful' tests, the well was being circulated with seawater in preparation for commissioning. During clean-up and mud displacement, the well began to flow. Mud was displaced over the rig floor and gas detected in the shaker room. The circulating pumps were closed down and the lower annular preventer successfully activated. The middle BOP pipe rams were closed and the well came under control. By any standard this incident ranks as another negative test failure. In this case, the FIV failed when the well became Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe.oiIonlIne.com For reprints please contact the Publisher. OFFSHORE ENGINEER I march 2011 39 • 1 ) The Presidential Commission has investigated the Macondo disaster and reported the facts to the public. Will the Health & Safety Executive (HSE) now do the same for Bardolino and publish the results of the Shell investigation? 2) The HSE has stated it was satisfied with the Shell investigation and the 'corrective measures' it put in place. Will the HSE explain the foregoing in light of the Transocean submission that it 'did not require a specific change in procedures as a result of the Sedco 711 incident'? 3) Will the HSE publish the details of the 'corrective measures' proposed by Shell? 4) Why did the HSE not disseminate details of the Sedco 711 incident to other interested parties, for example the industry body Oil & Gas UK? 5) Why did the HSE not notify BP of the Sedco 711 incident? underbalanced. But, unlike Macondo, the BOP did its job, thereby averting a catastrophic blowout. Transocean subsequently suggested to the Presidential Commission that the North Sea incident was irrelevant to Macondo, claiming that the failure involved a different type of barrier. But the commission would have none of that nonsense, saying: 'Those are largely cosmetic differences. The basicfacts of both incidents are the same. Had the [Deepwater Horizon] rig crew been adequately informed of the prior event and trained on its lessons, events at Macondo may have unfolded very differently' Shell had reported the incident to the HSE, as it was obliged to do. In a written response to a separate UK Parliamentary Committee on 10 December 2010, the HSE stated the following: As a result of the HSE investigation ... a letter was sent to Shell regarding their general well integrity responsibilities under regulation 13, Offshore Installations and Wells Regulations 1996. HSE assessed the corrective actions implemented by Shell and Transocean and considered they addressed the shortcomings that led to this incident and have addressed the well control issues that occur when displacing mud out of the well.' Predictably, neither Shell nor the HSE published any details. Indeed, were it not for the Macondo disaster we might never have discovered the facts surrounding the Sedco 711 incident - and only then after a Parliamentary Committee had dragged them out of another government department. Was the HSE, in apparently making light of the issue and helping to draw a veil of secrecy over it, acting in the public interest here? Transocean advisories Submitting a supplementary submission in respect of the Sedco 711 incident to the same UK Parliamentary Committee in December 2010, Transocean said: 'The HSE was satisfied with the investigation led by Shell Why did the HSE not notify the Presidential Commission directly of the Sedco 711 incident? i I What notices have the HSE circulated in respect of negative pressure tests on wells and the use of single barriers in underbalanced wells? 2) Is the HSE satisfied that the Sedco 711 was operating with a valid safety case? 9) How many FIVs have been installed in the UK sector of the North Sea? 10) How many FIV failures have been reported to the HSE? Moreover, according to Transocean, neither the PowerPoint nor this advisory ever made it to the Deepwater Horizon crew.' 124 A footnote to Transocean's submission stated: 'Transocean continues to operate its rigs on the UK Continental Shelf with the highest degree of safety and diligence. It is committed to ensuring a sc(e and reliable work place for its employees and stands willing to assist the [Parliamentary] Committee in its ongoing inquiry.' In which case, how does it explain the deaths of 11 crew members on the Deepwater Horizon on 21 April 2010? Perhaps Transocean could begin by explaining why its 'advisories' did not make it to the Deepwater Horizon before the rig and 11 crew members perished. News blackout The Sedco 711 incident was not reported in the UK press at the time, as far as I can tell. Indeed, it only seems to have come into the public domain in August 2010 - some eight months after the event - when the US media picked it up, presumably as a result of the ongoing Presidential Commission interviews and activities. Having noticed the emerging similarities between Bardolino and Macondo, the UK Department of Energy & Climate Change (DECC) set up a Parliamentary Committee to investigate. They requested submissions from the HSE and Transocean, and these became a matter of public record in December 2010 (www.parliament.uk). Then the furore erupted. It reached the Scottish Parliament, which also attempted to downplay and trivialise the incident during a heated debate. What seems clear from the foregoing is that someone did a very thorough'news management' job over the many months it took for the first details of the Sedco 711 incident to emerge. If that 'someone' was the UK Health & Safety Executive - or it was complicit with others in doing so - one again has to ask: whose interests was the HSE serving here? and the actionsfrom the investigation reportfor Shell, Transocean and Schlumberger, and thus did not require a specific change in procedures as a result of the Sedco 711 incident on 23 December 2009. However, Transocean issued two operations advisories in response to the incident. A Well Operations Group Advisory, dated 5 April 2010 and issued to all Transocean installations, confirmed the Well Control Handbook would be modified to clarify the requirementsfor monitoring and maintaining at least two barriers when displacing to an underbalanced fluid during completion operations. `The second advisory was issued (14April) to the entire Transocean North Sea fleet and recommended specific • follow up actions related to well control preparedness during a completion phase, awareness of well control indicators, and adequate well programs.' The remainder of this submission is not worth repeating. It did not impress the Presidential Commission, and does not impress me In fact the commission noted: Case for change The Presidential Commission has established a new benchmark for public expectation and quite probably transformed the global offshore regulatory landscape forever. It is no longer good enough for the HSE to trivialise and secrete recorded events when direct action and reporting is required. A strong, vigorous regulatory regime is required - one that can learn to communicate freely with Parliament, industry and public alike. Although its starchy submission to the UK Parliamentary Committee hardly inspires confidence in that regard, the HSE can make a start by being open about the Sedco 711 incident and by answering the questions I have put to it (see above). The Deepwater Horizon created a huge wake when it sank on 22 April 2010. It has washed against the coasts of America and Europe and found its way into their seats of government - the fingers of 11 dead men pointing the way. Gone, but never forgotten. OE A!1 Content is copyright protected and provided for personal use only - not for reproduction or retransmission. 40 OFFSHORE ENGINEER I march 2011 For reprints please contact the Publisher. http://oe. aIIonIine.com • • Low Power Consumption • Eliminates O-Rings, �' Reduces Machining • Costs • Sub -Sea Compatible Materials Innovation in Miniature The Lee Company 2 Pettipaug Road Westbrook, CT 0649B www.theleeco.com/mpsv 860-399-6281 • BOO -LEE -PLUG Ofwelcornes letters reflecting all shades of offshore industry opinion but reserves the right to edit and condense. mailbag SEDCO 711 INCIDENT: THE HSE RESPONDS Sir, Ian Fitzsimmons accuses the Health & Safety Executive (HSE) of `drawing a veil' over the Sedco 711 incident and failing to act in the public interest by not disclosing the lessons learnt to BP ('Sedco 711: the regulatory issues', OE March). His assertion that HSE trivialises such incidents and, in this instance, colluded to keep news of it out of the public domain, is misplaced and inaccurate. While there are some similarities, it is not appropriate to draw direct parallels between the Sedco 711/Bardolino incident and Deepwater Horizon/ Macondo. The Bardolino incident was not a straight pre -ram of Macondo. It involved a proven negative pressure test on the FIV, which was subsequently damaged. In this instance the BOP worked effectively as planned and provided the barrier to shut the well in, stop it flowing and allow it to be brought back under control. This is very different to Macondo where the negative pressure test was patently non -proven, and the BOP did not work. HSE is responsible for regulating the offshore industry and influencing companies to ensure they properly manage and control the risks they create. We do not control the way information is disseminated between dutyholders, how it might be spread within BP or how it would even reach workers on Deepwater Horizon. Although HSE does not routinely make public all details of its interventions, we operate within the scope of •. w,n m. ... ,;.'k�„"^ „l,,.w:;tl....l h,lx,°aw,.. sn`r°,n1p...... in lxs9 ° wnrmme,:�2"e.n ' tlSENaenletl,l waautvxom ° Sex a a "x.awla ellMa I wannwx�l w"vVtl,tl IM xSE,m�amN aewlyw w'tlwa w^a>al ."xseZ y,�•a«e `aus�, °r..,�'y 'aa, � Qu tl � +•amn u`rm "wM wore", i'M l,Z, Mq 41y ^'M y°pyY d0.r` yla ... h rcu Le Po T the Freedom of Information Act ands° we have already responded to a number of FOI requests relating to this incident. However, the primary responsibility for sharing lessons learnt lies with the industry, as demonstrated by the Step Change for Safety SADIE database. It is therefore Shell, Transocean, and Schlumberger who are best placed to ensure industry is aware of the Sedco 711 incident via either Step Change for Safety, IADC or Oil & Gas UK. The UK offshore industry has recently created the Oil & Gas Well Life Cycle Practices Forum (WLCPF) to develop industry guidelines to ensure best practice in this area. This will include lessons learned from Macondo and other incidents such as Bardolino. HSE strongly supports this development, and I have already ensured that the WLCPF are fully aware of our priorities for their work. We will continue working with them as they take these crucial issues forward. Steve Walker Head of Offshore Division Health & Safety Executive, UK MIKHAIL KHODORKOVSKY Sir, This morning I read Professor Economides' column on Mikhail Khodorkovsky (OE February 2011). It is shocking and a shame that bullies can get away with what they do around the world. A long time ago I wanted to work internationally. Khodorkovsky's plight is a stark testament to the political risk you take on in the international arena. Professor Economides has a great perspective on our business. I have long argued he should be our industry's spokesman. Keep up the good work. Charles Gibson Operations Manager Cobra Oil & Gas, US 24 OFFSHORE ENGINEER I april 2011 http://oe.oilooline.com • Blowout preventers are no guarantee against disaster http://blogs.it.com/energy-source/2011 /03/28/blowout-preventers-are-no-g_uarantee- against-disaster/# March 28, 2011 12.17 pm by Sheila McNulty The oil and gas industry has been afraid there might be repercussions from the recent investigation that founH � .lacondo's blowout preventer failed to close because a section of drill pipe had buckled during the accident and blocked efforts to seal it off. • Gary Luquette, Chevron's president for North America exploration and production, said the industry would learn from the report. But he hopes it will not lead regulators to stop the permitting process just when companies have started to see progress. He explained: The best way to deal with a blowout is never to have one. In this case, the pipe was blown up the hole because of a loss of control situation. If you have complete loss of control, you can't imagine a BOP that can be designed for that. Michael Bromwich, director of the Bureau of Ocean Energy Management, Regulation and Enforcement, seems to agree. He told FT Energy Source: We knew all along (since Macondo) the BOP didn't serve its intended function. The specific ways it failed, as laid out in the report, is less significant than the fact that it failed. This is why, he says, the bureau has been so intent upon strengthening the system at every point. While the BOP is useful, and can play an important • function as a backup, it is not a guarantee against a blowout. The fact that he has accepted that means the investigation report is not as significant for him as it is for others who accepted the BOP as a major safeguard against diasasters. There was a complacency that existed. The companies believed their own reassurances. It's never been a riskless activity. There are risks. All you can do is drive down risks and prepare for the 'what ifs'. On that note, Marvin Odum, head of Shell's US operations, said the BOP is an area that needs additional research and development to improve its function. But if companies are as careful as Shell has always tried to be, he said — with a full list of safety procedures that have gone above those required by regulators — then they will have their "bases covered". Since the accident, Odum said, Shell has made some important tweaks in how it drills and well design. "But," he added, "they are tweaks nonetheless". The real changes for the company have been the frequency of testing equipment and the dialogue it will now have with regulators during drilling work and on BOP recertification. That is in addition to the development of the spill response 40 system with ExxonMobil, Chevron, and ConocoPhillips. In terms of operations, Odum said. - The changes in the amount of scrutiny to anyone operating on our behalf has changed in a notable way. But now that permitting has resumed, Odum is hopeful the US will move forward not only in the gulf but in Alaska, where has been truing for several years to . For he, like others in the industry, object to the US moving to import fuel from Brazil instead of ramping up its own production at home: I think building a strategic resource path into this country is important but should not be a priority ahead of our own resource production. 0 RIGZONE - UK Govt: Deepwater Oil Drilling Safety Rules Fit for Purpose Page 1 of 1 UK Govt: Deepwater Oil Drilling Safety Rules Fit for Purpose by James Herron • Dow Jones Newswires 3/22/2011 URL http://www.rigzone.com/news/article.asp?a_id=105325 The U.K. government gave its regulatory regime for deep water offshore oil and gas drilling a largely clean bill of health, saying that existing rules address most of the concerns raised by a parliamentary committee studying the impact of the Deepwater Horizon disaster in the Gulf of Mexico. U.K. lawmakers on the Energy and Climate Change Committee had raised serious doubts in January about whether the oil industry is prepared to tackle a deep water blowout and oil spill should it occur in the North Sea, but the government's response to these concerns published Tuesday said existing rules are adequate. "The U.K. government has already taken a number of actions (such as increasing the number of environmental inspectors and inspections to mobile rigs) to further bolster the already robust U.K. regulatory regime," the government report said. One of the Committee's principal concerns --that the oil industry couldn't handle an oil spill in the rough seas west of the Shetland Islands --has already been dealt with, the government said. Chevron has developed a cap that can be used to seal a blowout in this area that will be available for anybody to use, the government said. Additional capping devices are also in development, it said. The government did promise to assess in partnership with the oil industry whether oil rigs' blowout preventers--the crucial piece of equipment that failed aboard the Deepwater Horizon --should be upgraded to include extra failsafes, called blind shear rams. This assessment won't be concluded before summer, it said. • "We will also be considering the requirement of [compulsory] insurance as part of our review," it said. • Existing rules cover the other main concerns of the U.K. lawmakers —that companies spill response plans aren't adequate for the least likely but highest risk accidents; that existing financial provisions wouldn't cover the cost of a large spill; and that workers aboard offshore rigs fear reprisals if they raise safety concerns --the government said. brought to you by: C,. http://www.rigzone.com/news/article piasp?a id=105325 3/22/2011 innovative Lessons learned from Montara, Macondo and beyond While public perception in the wake of Macondo remains in the forefront of our industry, Australian Minister for Re- sources and Energy Martin FergusoiA faith in oil and gas is unwavering. To him, it's not about changing the world's mindset about what has already hap- pened: It's about bringing the energy in- dustry together to change the way things are done in the future. Ferguson received a bachelor's degree in economics from Sydney University and became the deputy premier of New South Wales in 1976 after working for the Federated Miscellaneous Workers' Union of Australia. After becoming president of the Australian Council of Trade Unions, he worked on a wide variety of advisory councils covering Australias social and economic issues. Ferguson assumed the title of shadow minister for transport, ds and tourism in 2006, and was pro- d to minister for resources and ener- and minister for tourism in late 2007. Ferguson soon came face-to-face with the grim reality of an offshore disaster. On Aug. 21, 2009, off the northwest coast of Western Australia, an oil and gas leak from Montara Field in the Timor Sea caused a blowout from the wellhead platform. While all 69 workers were safely evacuated from the West Atlas drilling rig, it took 10,000 liters of dispersants and five attempts to reach the leak via a relief well. The blowout was finally quelled 73 days later when 3,400 bbl of mud was pumped in through a relief well. The disaster left behind an estimated 1.2-6.1 million of gallons of spilled oil, making it one of the worst spills in Australian history. While Ferguson commissioned a battery of tests on the affected area, in- cluding ecological studies, spill model- ing analyses and an examination of the effects of dispersants, a commission of inquiry was brought together to compile a report about the causes of the spill. US officials joined Australia's response efforts and provided assistance in both the on- leanup and discussions on technol- and response procedures throughout the disaster. Reports —including one in- dependently performed by the US —in- dicated that the primary cause of the spill was a breach in the well's casing. Australian Minister for Resources and Energy Martin Ferguson. As the recovery efforts continued, Fer- guson announced his decision not to sus- pend offshore exploration or drilling. In- stead, he focused on implementing a new regulatory system to re-examine the pro- cess by which companies conduct those activities offshore Australia. "We [wanted to] make sure we [had] the strongest pos- sible national, consistent approach, rather than allowing potential differences to de- velop," Ferguson said. In the spring of 2010, Ferguson ap- proved new areas for offshore explora- tion —some in waters over 12,000 ft deep —and faced his critics head on, ex- plaining at a press conference, "There is no intention by the government to scale back the development of the oil and gas industry in Australia. It is very important in terms of the nation's energy security, jobs and the overall economy, but I am totally focused on the need to ensure we have the absolute best practices in place." Then April 20 happened. Ferguson immediately knew that Australias expe- rience with the Montara disaster could yield vital insight into response proce- dures at Macondo. "The US contacted us [about] the use of dispersants and the cleanup methodology we've adopted," Ferguson said. In the end, officials at Ma - condo deployed over two million gallons of chemical dispersants that broke up sur- face oil from the spill. "The expertise was shared on how you do the relief wells. The big breakthrough was on how you cap the blowout," Fer- guson said. While the West Atlas was only drilling in 250 ft of water, the blow- out occurred 8,600 ft below the seafloor, posing similar challenges to those facing the 18,000-ft-deep Macondo blowout. After drilling the relief well to its target depth at Montara, engineers attempted to target the 10-in. rupture in the dam- aged well,. but they missed the well and had to drill several different trajectories before the leak was reached. Australian officials consulted with the international team working on Macondo to develop the techniques used in the re- lief operation. Whereas Australian regula- tors prohibited surface capping at Mon- tara (deeming it too dangerous), the use of ROVs at Macondo made previously impossible well control operations —es- pecially in such deep waters --a reality. For Ferguson, the teamwork and un- abated cooperation behind the scenes from experts the world over have made both Montara and Macondo anything but dismal case studies in oil and gas his- tory. From collaboration on the develop- ment of new technologies and response procedures to onsite aid, he sees both disasters as a testament to the energy industry's ability to come together and create solutions —even amid the most adverse of situations. In August 2011, an international committee, including Ferguson, will present a comprehensive report about Montara and Macondo, which will dis- cuss the international standardization of equipment, worst -case -scenario emer- gency response procedures and interna- tional regulatory programs. While Ferguson's office is continuing to issue new exploration permits (recently awarding deepwater exploration licenses to BP in South Australias Bight Basin), he is optimistic that the new communica- tion structure between operators and his agency and more stringent regulatory and approval processes will work to stop po- tential disasters before they occur. "Whether it's BP or another com- pany, the actions of one company have an impact on the standing of the whole industry," Ferguson said. AS is, so is the lesson out of Macondo and Montara. We must [all] pull together to work with governments and regulators to prove that we have a right to operate while [protecting] the environment." WO World Oil FEBRUARY 2011 21 • PSA reviewing Macondo February 20, 2011 by offshoreenergy P E T R 0 L E U M S T I L S Y N E T P F T Q O t E U M SAFETY AUTHOR 1 1 Y N O R W A Y The PSA established a project team on 7 May 2010 with some 20 members drawn from relevant disciplines to follow up the Deepwater Horizon disaster. Its overall goal is to systematise and assess experience and investigations in the wake of this incident, so that appropriate lessons can contribute to learning and improvement on the NCS. The project will identify areas where enhancements can be made to the requirements in Norway's regulations and/or other types of measures related to Norwegian petroleum operations. PSA.no Deepwater Horizon: An American Tragedy http://www.ptil.nolnewsldeowater-horizon-an-american-tragedy-article7625-79.html 18.02.2011 1 The global oil and gas industry has been responsible for several disasters over the past decade, but few have heard of them. When Deepwater Horizon exploded in the Gulf of Mexico, safety in this business became a worldwide issue. Read more: • Be prepared after Deepwater • Deepwater Horizon: Not only downhole Some of the incidents which rocked the industry in recent years are known to and much discussed by insiders. They include Montara off Australia in August 2009 and the Aban Pearl and Petrobras P36 sinkings off Venezuela last year and Brazil in 2001 respectively. • But neither the industry nor society as a whole has taken much notice of platform losses which reportedly occurred off Egypt in the past three-four years. • Little information is available about these events.A number of other serious oil and gas accidents in nonwestern parts of the world have also failed to arouse much interest. But the tragedy in the US Gulf has become a global disaster. Almost 4.7million Google searches for Deepwater Horizon were recorded this January.Everyone has heard of this accident, seen the pictures, heard the comments and noted that an oil disaster has occurred off Louisiana. Disaster The incident was certainly a disaster in anyone's terms, and accords with the PSA's own deft nition of a major accidentin the petroleum industry. This is an acute incident, such as a major spill, fire or explosion, which immediately or later causes a number ofserious personal injuries and/or loss of human life, serious harm to the environment and/or loss of large material assets. Deepwater Horizon meets all these criteria. Eleven people were killed and 17 injured — some seriously. Huge volumes of oil were discharged to the sea. The financial losses are astronomic. • This US disaster has been responsible for nothing less than a paradigm shift in society's perception of the importance of safety in the petroleum industry. Most of the world's major producing nations have initiated follow-ups, projects and studies in the wake of the tragedy, and demands and expectations for action are being voiced. These include calls for global regulation, international coordination, crossnational regulatory requirements and a more unified safety regime in general for petroleum operations. Supranational bodies and certain nations have launched initiatives on international cooperative eff orts to assess how regional and global challenges can be tackled. They include the European Union, the Oslo -Paris convention for the protection of the marine environment of the north-east Atlantic (Ospar), the G20, the International Association of Oil & Gas Producers (OGP) and the International Association of Drilling Contractors (IADC). Project The PSA established a project team on 7 May 2010 with some 20 members drawn from relevant disciplines to follow up the Deepwater Horizon disaster. 0 Its overall goal is to systematise and assess experience and investigations in the wake of • this incident, so that appropriate lessons can contribute to learning and improvement on the NCS. The project will identify areas where enhancements can be made to the requirements in Norway's regulations and/or other types of measures related to Norwegian petroleum operations. Other assignments for the team include: • charting and assessing all aspects of Deepwater Horizon which relate to safety and emergency preparedness, and clarifying the scope, course and causes of the accident • identifying and describing observations concerning direct and underlying causes as well as non-compliance with regulations, methods and procedures • assessing and comparing relevant US and Norwegian regulatory requirements • describing the actual consequences of the accident, including harm to people, material and fi nancial assets and the environment (duration and quantity of oil discharges) • assessing the potential of the incident to cause such harm • helping to convey information to other players and government agencies, primarily via established collaboration arenas at national and international level. The project will assess Deepwater Horizon in relation to similar incidents in order to • identify common features, with particular reference to Montara, Aban Pearl and the loss of mooring chain on Ocean Vanguard off Norway in 2004. Plans call for the team's conclusions to be published this spring. No final date had been set when this issue went to press. Key elements will be published on the PSA website Be prepared after Deepwater 18.02.2011 1 Studies of emergency preparedness and well integrity, design and construction were launched in Norway a. er a review of initial analyses and reports from the Deepwater Horizon incident. This work is being coordinated by the OLF at the request of the PSA. Read more: • Deepwater Horizon: An American tragedy Deepwater Horizon: Not only downhole The industry's need to assess the validity of emergency response principles for halting a possible subsea blowout in Norway was stressed by the PSA on 15 June in a letter to the OLF. In addition, the industry association was asked to evaluate existing strategies for limiting the volumes discharged from a blowout while it is under way. That would also mean identifying possible improvements in the fonn of new practices, development of technology and/ or a revised understanding of preparedness requirements. Comparison The PSA compared the 21 recommendations in the report on Deepwater Horizon published by US interior secretary Ken Salazar in late May with the minimum requirements in the Norwegian regulations. These proved to accord almost entirely with the US proposals. However, the PSA resolved to initiate analyses of the following areas in Norway: 1. Well integrity, including: • organisational factors — educating, training and qualifying people with critical functions in planning and executing well operations • • operational and technical management systems for well control • operational and maintenance requirements for blowout preventers (BOPs), including existing systems for certifying such equipment 2. Well design and construction It was resolved to pursue part of the work under the two fi rst sub -items in the list above in cooperation with the Well Integrity Forum (WIF). This group was established at the PSA's initiative in 2006 and is run by the OLF. The assessment of the Salazar fi ndings was commissioned on 1 July, and its results had not been fi nalised when this issue went to press. This article was published in the publication "Safety - status and signals 2010-2011 ". s Deepwater Horizon: Not only downhole 18.02.2011 1 Widening the perspectives of work being done in the wake of the US disaster is a key concern for Kjell Marius Auflem, the PSA's discipline leader for drilling and well technology. He also headed the PSA's project team on lessons from Deepwater Horizon for the first six months. Read more: • Deepwater Horizon: An American tragedy • Be prepared after Deepwater "I've noted that most people are talking about technology, deep water, cement, BOPs, casing and tubing after Deepwater Horizon," he says. "I believe it's equally important to focus on responsibilities, roles and union -management cooperation. "It's gratifying to affirm that conditions in these areas are good in Norway, including a well -functioning system of safety delegates who have the right to halt work." • He emphasises that a good safety culture is one which involves employees, shows respect for divergent opinions and tolerates challenges to decisions when life and health are under threat. "That said, a number of technical conditions need to be looked at more closely after the US accident, including the design of BOPs. "The PSA, acting on behalf of the International Regulators' Forum*, has launched a study through the IADC ** and the OGP *** to assess this in more detail. "Cementing and the quality of cement plugs will also occupy a key place in the technical part of the post-Deepwater studies." * IRF. International Regulators' Forum ** IADC: International Association of Drilling Contractors. *** OGP: Oil and Gas Many lessons to learn The US presidential commission's report on Deepwater Horizon was published just after Hilde-Karin Ostnes took over as head of the PSA's post -accident project in January. • "This is a very voluminous document, which we're going through in great detail," says Ms Ostnes, who comes like her predecessor from the drilling and well technology discipline. "The report is fairly scathing in its judgement of the way the companies involved handled the conditions which led to the rig explosion. "That off ers many lessons for the industry, also in Norway. But it remains to be seen whether these and other findings prompt the PSA to propose regulatory changes or the like at home." Although the division of responsibility in the PSA and its opposite number in the USA are very different, she also considers it interesting that the commission report so openly emphasises the need for a competent and clear regulator with adequate resources. "It's also worth noting that the commission deals with the industry's independent duty to operate safely, and calls for a model which focuses more on the approach to risk and on enhancing the responsibility of the US industry. "That coincides with the safety regime we've had in Norway for many years". This article was published in the publication "Safety - status and signals 2010-2011 ". • 0 • BP slammed again by spill commission, complains Feinberg's payouts are too generous http://news.yahoo.com/s/�blog_thelookout/20110217/ts yblog thelookout/bp-slammed- a ag in-b�-spill-commission-complains-feinbergs-payouts-are-too-generous Maybe you thought that when the commission appointed by President Obama to investigate the BP oil disaster issued its final report last month, the body was through releasing reports. If so, well, you were badly mistaken. Today +hP rommissior, issued anoth(,r report in an effort to, in its words, provide the public with the "fullest possible account" of the Gulf spill. The reason for the updated report? A team of commission investigators, led by Fred Bartlit, uncovered even more evidence that BP willfully neglected to take the necessary precautions to prevent the spill. "The sad fact is that this was an entirely preventable disaster," Bartlit said in a statement. "Poor decisions by management were the real cause." • Bartlit and his team conclude in the new report that BP failed to perform simple due diligence in appraising the scale of the Deepwater Horizon explosion that set off the spill. The report finds that Bob Kaluza, BP's leader aboard the Deepwater Horizon, sent an email to company executives offering a scientifically implausible explanation for a failed pressure test in the well. Initially, the account was greeted with extreme skepticism: Pat O'Bryan, BP's vice president responsible for drilling and well completions, responded with a series of 400 question marks. After that, the report says, no further action was taken --and Bartlit's team contends that had BP simply followed through on those doubts and solicited expert assistance from inside and outside the company, then "the blowout might never have happened." Bartlit also found that BP had contended for years with substandard cementing work that the Halliburton group had done under contract for the oil giant. Nevertheless, BP continued to seek Hallburton's services for such jobs, and overlooked problems with the cement on the Deepwater Horizon. Reports New Orleans Times -Picayune: Also, BP leaders had expressed major concerns with the stability of the cement that was going to be used by-ontractor t to line the well. They were so dismayed with the Halliburton cementing engineer assigned to the Macondo project that they wanted him reassigned. But instead of insisting on more cement stability tests and more closely • supervising Halliburton engineer Jesse Gagliano, the BP engineering team • simply ignored Gagliano when he offered warnings days before the blowout about risks in the design of the well's lining. They then went ahead and started the process of pouring the cement before receiving results of cement stability tests that Gagliano had been running. When asked why BP didn't wait for a clear indication of the cement's stability before using it, BP's chief investigator, Mark Bly, said: "I think we didn't appreciate the importance of the foam stability tests. " In other BP news, the company believes Gulf Coast claims administrator Feinberg has been too generous in tendering .ompensation o :rs to rPgiden+c suffering economic fallout from the spill. Most claimants would probably beg to differ, especially considering that the only settlement paid out by the fund not of the "quick pay" variety has been one shrouded in mystery that was issued to an unnamed "BP business partner" for $10 million. And the pool of potential claimants is cut off from filing for benefits after the end of next year. At one public forum, an exasperated claimant dropped to his knees to beg for more timely processing of his claim. Judge Carl Barbier, who is presiding over the consolidated spill compensation suits, recently ruled that Feinberg, rather than operating the escrow fund independently of BP, had been essentially q as a legal adiunrt of the company. Henceforth, he ordered all communication between the two parties go through him 0 BP's Safety Drive Faces Rough Road http://ontine.wsj.com/article/SB 10001424052748704515904576075992850313426.html? mod= W SJ_Energy_leftHeadlines Ilk ssociated Press A BP operation in the Beaufort Sea off Alaska's North Slope. Bob Dudley, the new chief executive of BP PLC, has vowed to change the safety culture of the accident-prone oil giant in the wake of the deadly explosion and spill at one of its wells in the Gulf of Mexico last year. But the story of a little-known BP safety official on the desolate North Slope of Alaska offers some cautions about just how difficult a job that will be. The day after the Gulf well blew out last April, killing 11 rig workers, Phil Dziubinski was suspended from his job and escorted out of his office in Alaska. The company said he was let go as part of a broad management overhaul. In a five -month skirmish, two government agencies rejected Mr. Dziubinski's claims that he was fired as retribution for warning of safety risks. His back -and -forth with the British oil giant, though, sheds light on what Mr. Dudley is up against. 0 • Costly Mistake BP's shares have yet to recover from the Gulf spill disaster April 20: Gulf rig explodes �60 50 40 30 20 2010 11 Source: WSJ Market Data Group Mr. Dudley has created a new global safety division at BP, a company that also suffered a 15-fatality refinery explosion in Texas five years before the lethal Gulf accident. He has given the division power to intervene in or shut down any operation seen as too hazardous. More • • BP Resumes Dividend as Profit Rises 30% Heard: BP Faces Old Challenges The safety issue goes to the heart of BP's corporate culture, say some critics, who contend that compared with its Big Oil rivals, the company has historically been focused more on deal -making and less on safety and operational excellence. "Other companies were less aggressive on growth and more focused on their safety -management systems," says John Hofineister, a former president of Shell Oil Co. "Changing the culture is hard." One area where safety concerns have loomed large is Alaska's North Slope, home to BP -operated Prudhoe Bay, the largest oil field in North America. Workers at the field, which opened in 1977, have long complained of aging infrastructure and a lengthy backlog of needed maintenance work. In addition, as thousands of Alaska oil workers retired in recent years, overtime has piled up, and some workers have complained of fatigue. This is an issue Mr. Dziubinski repeatedly raised with his bosses, once referring to it in an email as an "imminent safety risk." BP technicians on the North Slope work 14 days straight and it isn't uncommon for them to put in shifts lasting 16 or 18 hours, sometimes on successive days. BP says it has taken steps to reduce Alaskan workers' maximum hours and won't operate any facilities unless it is sure it can do so safely. • As Mr. Dudley tackles the BP safety culture, he will be under pressure, not least from • U.S. authorities, to show improvements. A U.S. presidential commission's report last month on the Gulf disaster said decision -making processes by BP and its contractors "did not adequately ensure that personnel fully considered the risks created by time- and money -saving decisions." BP says the report supports its own view that the accident was "the result of multiple causes, involving multiple companies." View Full Image Oil on the North Slope OP was 1t� word L),q st or proAKr on Alaoal None, Slope.. I009 but 1a4 tl d tglh omr a dreada +ir+i 0 "� UNOCAL* rlo(n ,<-VA. L, wv,ea,enn- .+zoay. zoo 46� WfK._ IIIIiii11/ IINIIIN♦ 6664 Nil �.1+wr. 1• HI�NNI• Oil on the North Slope BP was the second-largest oil producer on Alaska's North Slope in 2009 but had the largest number of spills over a decade. • by PIONEER "';/TO Q ConocoPhillips 0 1111,1111111111111111OCAM NATUAALAE80uRCEs Average Alaska oil production In 2009, in barrels per day 4110 • 71000 4,600 Z.700 of spills 666,/66116 -5sptlls �I 466,666466 4466666444 14,166614, 666666,64, 6664446666 664 Volume spilled, SISSI 24,642 223 307 0 in barrels Between Jan. L 2000, and May 3L 2010, for spills of mare than 100 gallons: 42 gallons =1 barrel Note: Una it it owned tvr Ctaewm XTO is now owned by EKxormobil Sources: Alaska Department of Environrne 0l (onservaticr: !spill data): the companies BP "is working with regulators and the industry to ensure that the lessons learned from [the Gulf well] lead to improvements in operations and contractor services in deep -water • drilling," the company said. Even before the report, BP said, it was taking steps such as • changing its pay structure to better reward safety performance and risk management. BP reports fourth-quarter financial results on Tuesday. Mr. Dziubinski became BP's ethics and compliance leader for Alaska operations in mid- 2006, shortly after the company suffered a 4,000-barrel oil spill on the North Slope. That happened a year after the refinery explosion in Texas City, Texas, an accident that led a federal agency called the Chemical Safety Board to suggest BP managers didn't listen enough to what workers were telling them. "Reporting bad news was not encouraged," the report said, "and often Texas City managers did not effectively investigate incidents or take appropriate corrective action." Promising change, BP in 2006 appointed an ombudsman, retired federal judge Stanley Sporkin, to receive and act on concerns raised by workers throughout the company. For BP Alaska, the company set up a program to allow employees and contractors to raise issues without fear of retribution, placing Mr. Dziubinski, a veteran safety official, in charge. At first, workers were skeptical. "I thought, 'Here's another supervisor from Anchorage... I'm going to have to be on guard with this guy,"' says Marc Kovac, a steward of United Steelworkers' Alaska Local 4959. ,brahm Lustgarten/ProPublica Union steward Marc Kovac sat in on safety meetings. Suspicions faded, and employees soon began turning to Mr. Dziubinski with their grievances. Mark McCarty, a technician who sat on a BP health, safety and environment committee, says, "Phil was a bulldog in terms of making sure our concerns were addressed." In 2006, BP decided to survey its Alaska workers. It had done this several years earlier and heard concerns about equipment such as fire- and gas -detection systems in need of upgrading, and complaints that cuts in staffing and training had made operations less • safe. So BP re -interviewed several hundred workers to see if these issues had been addressed. • The review team, consisting of Mr. Dziubinski, three other managers and a few workers, found progress on some things, like pipeline inspections, but concluded that other matters, such as staffing levels and upgrades to fire- and gas -detection systems, still "need work." BP'S plan was to share the detailed survey results with the work force, according to the USW. Instead, BP decided not to. It declined to say why or discuss the issue. At a meeting in March 2007, Mr. Dziubinski disagreed with a supervisor's assessment that the company was on track to fix all safety issues. Mr. Dziubinski said that several problems flagged by workers in the past still hadn't been addressed, and that BP was taking too long to deal with workers' current concerns. "We tend not to listen to the workers," Mr. Dziubinski said, according to notes of the meeting taken by the USW's Mr. Kovac, who was there. Mr. Dziubinski also was frustrated that BP had decided against releasing the report, according to Mr. Kovac. "That was the beginning of the decline of Phil's relationship with upper management," he says. Dziubinski for State Senate Phil Dziubinski warned of safety risks In 2009, Mr. Dziubinski engaged his bosses about staffing levels and the length of work shifts. North Slope workers' normal schedule was two weeks of 12-hour days and seven- day weeks followed by two weeks off. But overtime was common, and some workers told their company safety committees that people were showing signs of fatigue. "You had walking zombies up here," says Mr. McCarty, the BP technician. The USW asked BP in 2008 how much overtime had been logged over three years. It turned out to be double the industry average, according to Glenn Trimmer, a North Slope technician who is secretary -treasurer of the union's Alaska local. BP added several dozen people to its work force of about 2,000 in Alaska and changed its rules so that for all shifts of longer than 16 hours, approval was needed from what is known as an area manager. Later, BP stiffened this requirement for managerial approval, following a complaint to its ombudsman that some technicians were working consecutive 18-hour shifts. Mr. Dziubinski, who had access to overtime records, informed his bosses about situations that concerned him, including one employee who had worked 36 consecutive days without proper managerial approval and who had logged 320.5 hours of overtime in a single month. He told his superiors that at three "gathering centers" —facilities that separate crude into oil, gas and water —some workers "have excessive overtime rates that may require leadership intervention to decrease a safety risk." His emails to his bosses, which were contained in the OSHA complaint he later filed and have been reviewed by The Wall Street Journal, said the rule requiring area -manager approval for shifts of 16 hours or more was followed only about half of the time. In an Oct. 30, 2009, email, Mr. Dziubinski described the overtime situation as "an imminent safety risk." Citing shift patterns, he wrote to his bosses that "allowing the continuation of the 16+ hour work shifts would be seen by internal and external stakeholders as putting production ahead of safety." Asked about the overtime issue, a BP spokesman said it "is being managed at the highest levels" of the company's Alaska unit. "We have taken measurable steps to reduce the maximum allowable hours," the spokesman said, adding that the company will "not operate facilities unless we are sure we can do so safely." A facility called the Lisburne Production Center suffered a small spill in autumn 2009, which Mr. Dziubinski came to regard as symptomatic of a larger malaise. A worker there emailed BP two months later with a long list of equipment the worker described as out of service or not working well. Mr. Dziubinski investigated and later told the USW's Mr. Kovac, "The maintenance condition of [that facility] is in a poor state and BP management was not paying attention to it." After he started emailing his bosses about the overwork issue, some of his responsibilities were shifted to others, Mr. Dziubinski asserted in his later OSHA filing. He also said a website where employee concerns were logged was changed, and he no longer received email notification of new complaints. BP disputed these claims. A company lawyer told OSHA that "no effort was made to preclude" Mr. Dziubinski from access to new complaints and that Mr. Dziubinski remained "the single point of contact for roughly 52% of all concerns filed between January 2009 and May of 2010." By May he was gone. On March 15, 2010, BP told Mr. Dziubinski, then 59 years old, that he wouldn't have a position in the Alaska operation after it was reorganized. On April 21, while Mr. Dziubinski was still coming to work at his Anchorage office, management accused him of trying to contact other staffers who were being let go. Security guards escorted him out. • His suspension came two months after BP's ombudsman, Mr. Sporkin, had written to BP Alaska saying "we are concerned that the contractor work force has not received adequate assurances of non -retaliation for raising concerns about BP's operations." BP says that "we expect and encourage our employees to raise safety concerns" and "have a zero tolerance policy regarding retaliation." Mr. Sporkin declined to be interviewed. The company, in denying to OSHA that Mr. Dziubinski had been dismissed because of his safety activism, said he was terminated as part of a wholesale reorganization of the U.S. business that would shed 200 managers in all, including 30 in Alaska. A BP lawyer told OSHA Mr. Dziubinski's job performance didn't "reflect the level of competency or effectiveness" BP sought for the new organization it was forming. Mr. Dziubinski's lawyer countered that his client had several years of consistently positive job evaluations and had received a bonus in 2008 and pay increase in 2009. His 2009 performance review described the numerous appeals workers sent to him as "a testament to his reputation and expertise." "Phil did a fantastic job during a tough time for the company" and "had [my] fullest confidence," says a former BP Alaska executive who supervised him. In July, an OSHA investigator ruled in BP's favor, finding insufficient evidence for Mr. Dziubinski's claim he was punished for pushing the safety issue. The Alaska labor department declined to disturb the ruling. Subsequently, as Mr. Dziubinski was preparing a wrongful -termination suit, in the midst of the furor over the Gulf spill, he and BP reached a settlement, which is confidential. • • • Macondo: the human factors Responding to consultant Ian Fitzsimmons' recent remarks in OE about BPdaccident investigabon report on the Gulf of Mexico's Macondo well disaster, drilling specialist Dr John Thorogood argues that it's time to stop pointing the accusatory finger and start learning the human factors lesson. an Fitzsimmons' article Macondo — the unfolding aftermath 60E November OCIMeserves comment. His is a viewpoint that polarises views on a complex issue and provides little insight into the underlying causes of the tragedy. There appears to be a desire to blame ¢ t through criticism of the long string casing design and the technically incorrect use of the word 'reckless'. However, his final comments at the end of the article point in a promising direction. The leak path through the shoe -track negates the assertion that the design itself was a contributory cause of the accident, refuting his assertion of a 'glaring omission'. Cement testing even at simulated downhole conditions may not be conclusive. Shoe tracks fail for a variety of reasons, not all related to the cement formulation. Possible causes of failure include, for example, over -displacement of the slurry, failure of plugs, or obstructions in the float equipment. In addition to the well-known 'Swiss cheese' model, Professor James Reason also formulated the 'just culture' model to provide an objective means of testing the motivation behind people's actions. Without the benefit of hindsight, it is not possible to assert that the actions of the people involved would have failed the 'substitution test'. Certainly, they do not fall anywhere near the region of negligence or deliberate sabotage, which would be required to prove recklessness. Professor Andrew Hopkins observes in his book Failure to learn that blame is the enemy of understanding. Fitzsimmons falls into precisely the trap of pointing fingers rather than shedding light. As Professor Hopkins explains, the investigator must continue asking'why?' until the causal trail is exhausted. Whilst much may be going on behind the scenes, certainly there is, as yet, no evidence in the public domain to suggest that this trail has been followed to its end. Only after such an investigation has been undertaken can solutions be developed to reduce the potential for similar incidents in the future. Montara, 21 August 2009 (far left) and Macondo, 20 April 2010., common factors? Ultimately, multiple barriers are required to prevent catastrophe and these include the mindfulness, risk awareness, skills and knowledge, vigilance and competence of the people on the rig. Fitzsimmons steered away from considering the reasons why the crew made the selection of flow diverter routing, but he suggested that external pressures might have contributed to the misinterpretation of the pressure test results and, implicitly, the subsequent failure to recognise the signs of a massive influx until it was too late. In their defence, one might speculate that, in part, the selection may have been driven by an overriding instinct not to discharge hydrocarbons deliberately into the sea. This impulse is strongly reinforced by the severe regulatory consequences of reporting overboard spills, however small. These types of questions must be investigated by trained and competent specialists to determine where failures in the barriers occurred, and to identify lessons for the future. The real tragedy, as Professor Hopkins notes, is that there is no such thing as a new industrial accident. They have all happened somewhere else; so it may be with Macondo. As widely reported in the media, including the New York Times, ¢ ¢ 0 news, the Daily Telegraph and Aberdeen Press & Journal, an eerily similar precursor to Macondo occurred on ODecember 930k in the UK North Sea involving Transocean and Shell. In this case, a downhole barrier was compromised and a potentially catastrophic event was averted only at the last moment when mud from the well was gushing way up the derrick; the incident being halted by one of the final 'barriers' on this occasion. The I�AA9 t Montara blowout in the Timor Sea 60E December 2009), just eight months before Macondo, is another example of the consequences of blindness to the risks of shoe -track integrity. It is, perhaps a missed opportunity, that all the final recommendations on that event also focused on the technical and regulatory aspects of the disaster and not on the evident I rMac:;djothe unfolding aftermath f— human factors issues. The common factor in these three incidents was that they all took place in cased hole in a supposedly safe situation and all in well regulated areas. There is no obvious explanation as to why? In all three cases the warning signs were missed. To explain this incident, and its precursors in the North Sea and Timor Sea, in a way that we can take effective steps to prevent a repetition, it will be necessary to go beyond the obvious regulatory and technological responses now being pursued. It is probable that in the fullness of time it will be recognised that the industry has a fundamental gap in the realm of human factors, in terms of crew resource management and non- technical skills. It is not simply a matter of flogging the offshore workforce with the mantra of'competence'. Competence and human Dpolfodjt!dpgz1hi dgspLfdtfe!boelgspv4efe!Tslgfstpobrtvtf!pore!!,!opdgDslsfgspevdypo!pslsftEbotnjttjpd 24 OFFSHORE ENGINEER i january 201- (?ps!sfgloLt!grfbtf!dpotbddd f!Ovcrjti fs( http://oe.cilonline.com • factors are fundamentally different. Competence does not explain why highly skilled, trained, professional and regularly checked aircrew fly perfectly serviceable aircraft into the ground. Human factors analysis does. Fitzsimmons is correct in observing that other communities have well -developed training procedures. However, these training procedures are the product of extensive research into accident causation in the domain and also to the human factors issues. In aviation, the training is not simply around competency testing, but also checking and testing the non- technical aspects, the Crew Resource Management skills. For drilling operations, it will be necessary to train in relation to critical influences, such as the trade-off between complying with regulations, such as not venting overboard, against managing a rapidly evolving situation. Such instances do not need more procedures. Drilling teams must be equipped with knowledge about decision making and critical influences, assessing situations and managing surprises. There are no instant answers, the industry will have to devote time and people to examining the human factors issues before it can define what sorts of training, simulation or testing of non- technical skills are appropriate. If problems are only viewed through a technical lens, then technical solutions are the only answer; to make progress, both the technical and non -technical issues must be equally addressed. It is to be hoped that the drilling community will learn the lessons from high hazard industries such as aviation, nuclear and other process industries where the human factors approach has been adopted and look much further and deeper into the realms of safety culture and human factors to find a fuller and more meaningful explanation for these tragedies. OE John Thorogood is an independent consultant after a 34-year career with ¢P in drilling operations, technology and exploration project management. In 2002-2003 he undertook research with the University of Aberdeen Department of Psychology and published work on drilling teams and decision making and human factors. He is the 2011 recipient of the Society of Petroleum Engineers International Drilling Engineering Award, a former technical director of the SPE and author of more that 40 technical papers and articles on drilling engineering. He has BA and PhD degrees in Engineering from the University of Cambridge. Acknowledgement Margaret Crichton, peoplefactor consultant, provided valuable comments on the drafts of this article. References Failure to Learn; The BP Texas City Refinery Disaster. Prof A Hopkins, CCH, 2008. Command skills for drilling and completion teams. Thorogood, Crichton & Henderson, SPE 89901. Managing the risk of organisational accidents. Reason, Ashgate, 1997. After another close call, Transocean changed rules. New York Times, 17 August 2010. Report of the Montara Commission of Inquiry. Commissioner D Borthwick, June 2010. Dpotf odjt !dpgz1 hi dgsp f dtf e!boe!gspvyef e!g)slgf stpobrtvt f ! pore!!. !opdgDslsfgspevdtjpo!pslsf tEbot n jtt j po/ http://oe.aiIanIine.com (?pslsfglotf!grftbtf!dpotbddd f!Q✓crjti fs( OFFSHORE ENGINEER ! january 2011 25 • Read more: http://www.adn.com/2011/01/30/1675582/alaskas-ulmer-reflects-on- experience.html#ixzzl CdJBrgj q UAA chancellor reflects on experience with Gulf oil spill COMMISSION: Panel found fault with oil industry, regulators. By DAN JOLING The Associated Press Published: January 30th, 2011 10:21 PM Last Modified: January 31 st, 2011 07:40 AM President Obama in June tapped University of Alaska Anchorage Chancellor Fran Ulmer for the presidential commission investigating the Deepwater Horizon drilling rig explosion, and as crude oil continued to spew from the Macondo well 40 miles from • shore in the Gulf of Mexico, Alaska's former lieutenant governor found herself in a helicopter sizing up the spill. DAN JOLING I The Associated Press Fran Ulmer, chancellor of the University of Alaska Anchorage, was a member of the presidential commission investigating the Deepwater Horizon drilling rig explosion and oil spill at the Macondo well 40 miles offshore in the Gulf of Mexico last summer. She spoke to worried local officials, watched responders pick up oiled pelicans, and remembered 1989, when she witnessed millions of gallons of crude oil spew 0 from a tanker gashed on a rock in Prince William Sound. • "You hope that you don't repeat the same errors over time as a human society," she says. "And so, yes, it was a real sense of dejA vu, and a sense of, 'Gee, I thought we learned something after the Exxon Valdez."' In the next breath, she remembers what did happen after Alaska's tragedy: a federal law that has phased in double hull tankers; a requirement for tanker escorts into Port Valdez; creation of regional citizen councils that act as industry watchdogs; storage facilities in Alaska fishing communities where spill response gear is cached. But the lessons didn't translate to the Gulf of Mexico, which was far more prepared for hurricanes than oil spills. "I was surprised at how little preparation there was on the ground, apparently, in the Gulf of Mexico, given the amount of oil and gas drilling that exists in the Gulf of Mexico," she said. The explosion and fire killed 11 men. The commission report, released Jan. 11, faults both industry and the government regulators for failing to prevent the blowout and then failing to contain it. • The industry's safety programs have not kept pace with the astonishing technological advances that allow drilling 10,000 feet below the water and then thousands of feet into the ocean floor, Ulmer said. It's like going to the moon, but workers die in the Gulf of Mexico at four times the rate of workers in the North Sea, she said. "What needed to happen in sort of a parallel course is the development of more sophisticated risk management techniques that would allow the people both on the rigs, and the people back in Houston at central headquarters, to be able to not only monitor what is going on on the rigs affecting safety, but also integrate that to a decision regime," Ulmer said. On any given rig, dozens of specialists from a variety of business cultures work together in a high -risk, complicated environment. On the Deepwater Horizon, the safety regime failed. "It was shocking to us, the very elementary -- not sophisticated, very elementary - • - degrees in which on this rig, those mechanisms -- some of them were there but • they weren't being done in a way that was commensurate with the amount of the risk," she said. Previous successes led to a false sense of security. "Both government and industry had been in a mindset that it's all safe and we don't really have to worry about it, and don't hold our feet to the fire because there hasn't been a really big spill in years." The number of deep water offshore wells expanded but the federal Minerals Management Service budget remained flat. "They were being deprived of the resources they needed to effectively regulate," she said. "And, I might note, when they tried to increase regulatory standards, the industry and Congress pushed back and said, No, don't worry, this is unnecessarily burdensome. We don't like regulations. We're in an era of deregulation. Get off the industry's back."' Ulmer said. "That in the long run is not good for either industry or the nation." • The Obama administration responded by restructuring and renaming the MMS, splitting its energy development and safety mission. The commission recommended oil producers imitate the nuclear power industry and fund a safety institute to define best practices and police themselves, in part to ensure that companies with strong safety standards are not compromised by companies with weak records. The commission also recommended that a "safety case" approach be taken for deep -water wells and high risk areas such as the Arctic. Used in the North Sea, the approach requires oil companies to develop a drilling plan based on the physical conditions of a specific well, plus a specific containment and spill response plan. Those too were lacking in the Gulf of Mexico, where the industry was taken at its word that the chance of a spill was minute. "Not only could they not contain it, none of the other big companies doing business in the Gulf of Mexico were prepared to come in and help them contain • it," Ulmer said. "It took months before they figured it out. They basically on the fly figured out a new containment system." Ulmer was struck by how little the cleanup tools -- boom, skimming, burning, dispersants -- had changed since the Exxon Valdez. "The sophistication in the cleanup of oil was very, very small, very marginal improvements. Unfortunately, neither the industry nor government have really invested the dollars needed to advance those technologies," she said. The commission chose not to comment on specific proposals for what may be the next offshore battle ground, the Arctic Ocean waters of the Chukchi and Beaufort seas off Alaska's northwest and north coast. Shell Oil in 2008 spent $2.1 billion for leases in the Chukchi at an MMS sale and pressure to drill there is increasing as onshore Alaska wells diminish and offshore drilling in other states has been declared out of bounds. America continues to consume 18.7 million barrels of oil per day, the report noted. • Ulmer quickly ticks off Arctic Ocean natural hazards: extreme cold, extended seasons of darkness, hurricane -strength storms, pervasive fog. The nearest Coast Guard base is more than 1,000 miles away and its leaders acknowledge a lack of basic information available in the gulf, such as navigation hazards and currents. The Arctic is rich in marine mammals such as endangered whales, polar bears, walrus and ice seals and the U.S. Geological Survey is assessing an acknowledged gap in habitat studies for making policy decisions. Ulmer said commissioners did not want to substitute their judgment for regulators considering drilling permits or science gaps. But speaking in general of offshore drilling, Ulmer said it will continue. "That's where the oil is and so that's where we're going to be drilling. So we better do a better job of prevention, containment and oil spill cleanup in the future." • http://uk.finance.yahoo.com/news/BP-guide-modern-executives-ftimes- 9023 2953.htm1?x=0&.v=1 http://search.yahoo.com/search?n=10&ei=UTF- 8&va vt=any&vo_vt=any&ve_vt=any&vp_vt=any&vd=m3&vst=0&vf=all&vm=p&fl= 0&fr=yfp-t-316&p=gulf %2C+rig+%22chronic+unease%22&vs= http://www.ft.com/cros/s/O/d2ab 1012-226a-11 e0-b6a2- 00144feab49a.htm1?ftcamp=rss#axzzl BLOp2Zb4 http://www.ft.com/cros/s/0/d2abl 012-226a-11 e0-b6a2-00144feab49a.html#ixzz1 BPdvzrL4 BP is a guide for modern executives By Andrew Hill Published: January 17 2011 20:51 1 Last updated: January 17 2011 20:51 Don't let the jargon of the offshore oil industry, with its mud -loggers, tool -pushers and roustabouts, deter you. The implications of the iss.led last week by US President Barack Obama's national commission on the Deepwaterw go far beyond BP and its partners on the rig and Halliburton, or the oil industry. It should be required reading for any business leader. The narrative account of the events of April 20 2010 is grim. But from a manager's point of view, the most sobering pages tackle the "overarching management failures" of the oil industry, which created the • conditions for the explosion and spill. As the commission's chief scientific and engineering adviser remarked in an e-mail to staff in November: "In some ways, the blowout began in early 2009 when [BP) initially designed the well." It's astonishing that it is even possible to level such an accusation at the oil company, given its recent history of well -publicised accidents, from the 2005 Texas City refinery explosion to the 2006 Alaskan pipeline leak. If BP paid the price for complacency at Deepwater Horizon, as the commission alleges, it was already acutely aware of the potential bill for continued smugness four or five years earlier. The report shows, first, how slowly cultural change comes to big companies. Leaders must attempt to implement those changes from the top and spread them throughout the organisation. BP was part of the way to meeting post -Texas City recommendations on process safety at refineries, according to its own independent expert. Yet the commission identified flaws in process safety on Deepwater Horizon, despite one BP representative's later testimony that it was "one of the top -performing rigs" in the fleet for drilling and safety. Second, the Deepwater story shows the fight against complacency is a continuous struggle, not a single battle. An executive at another oil major told me the default setting for safety managers should be "chronic unease". That's easy to see if you're a prison governor or lighthouse -keeper. But it should be part of any executive's attitude. Constant vigilance against, say, new competition, supply chain disruption, or unforeseen technological change is a must for modern managers. Third, the Deepwater disaster teaches some brutal lessons about how to run the ultimate "extended enterprise". At the centre of the commission's analysis of the causes of the explosion is the accusation that the "corporate cultures, internal procedures and decision -making protocols" of the different companies working together on the Deepwater Horizon were poorly integrated. The more closely producers, suppliers and customers collaborate, the more obvious it should be that gaps in communication and understanding — of goals, values or merely how work is best done — can undermine the whole undertaking. Think of the • public rifts that have opened recently in the relationship between BAA, owner of Heathrow airport, and Virgin Atlantic and ' !fthansa. The re refusing to pay tees because of snow disruption at London's main airport, despite BAA's claims they all shared responsibility for a flawed emergency plan. Finally, and fundamentally, the Deepwater report is about risk, in its rawest sense. The commission finds no direct evidence that employees of BP and its partners ran greater risks in the Gulf of Mexico because they were cutting corners. It says only that many of the decisions made, "whether purposeful or not", did save time and money. But the graver conclusion is that workers did not "fully consider the risks created by time - and money -saving decisions" (the emphasis is in the report). A safety survey of the Transocean crew on the rig concluded, before the disaster, that they "don't always know what they don't know". Similarly, the most damning charge against Richard Fuld, i_ehman Brother boss, was that he failed to recognise pressure building up in the bank until it was too late. The Deepwater report concentrates on safety, of course. It will probably lead to stricter operating standards, just as the financial crisis has led to tougher rules for banks. But as one oil company chief executive said to me, the ultimate spill mitigation measure would be to make rigs drill a second relief well beside the first — which would make production impossibly expensive. The question the Deepwater Horizon report cannot address — one BP will be better -placed to answer if its newly annoi: ed alliance w of Russia pays off — is how to reap the rewards of expansion without running undue risks. andrew.hill@ft.com Copyrigh, The Financial Times Limited 2011. You may share using our article tools. Please don't cut articles from FT.com and redistribute by email or post to the web. • 0 http://www.omj.com/index/article-display/6571735901/articles/oil-gas-journal/drilling_ production-2/20100/01 /several-immediate/QP 129867/cmpid=EnlEDJanuM 132011.html Several immediate causes contributed to Macondo blowout Jan 12, 2011 Guntis Moritis OGJ Production Editor • HOUSTON, Jan. 12 -- The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling found several immediate causes contributed to the Macondo well blowout on Apr. 20, 2010, although its Jan. 11 report concluded that the root cause was a failure of management by the three main companies involved in drilling the well: BP PLC, the well's operator; Halliburton Co., which provided cementing services; and Transocean Ltd., the rig's owner and operator. • The immediate causes listed in the report include the cementing, pressure testing, temporary abandonment, kick detection, fluid diversion, and blowout preventer activation procedures. Because of the ongoing investigation by a government -sponsored forensic analysis team, the commission did not speculate in the report on why the blowout preventers failed to operate as designed. Cementing Factors that may have led to a poor cement job of the production casing string included: • Running a long -casing string instead of setting a liner. The report said it was unclear whether this directly contributed to the blowout, but running a long string did make it more difficult to obtain a good primary cement job. Page 1 of 4 OGJ-Jan 12, 2011 • - Inadequate number of casing centralizers. Again the report noted that it was unclear whether this was a direct cause but it did find fault with BP's management and centralizer design procedures, as well as poor communication between BP and Halliburton on the centralizer design. • - Float collar conversion. The report said it may never be established with certainty that the float collar valves closed, but it did fault BP personnel for not considering how anomalous pressure readings might increase the cement job's risks. The report noted that because of equivalent circulating density concerns, BP engineers used a very low circulating pump rate, lower than the flow rate needed for closing the float collar valves. - Not running cement evaluation logs. The report said BP personnel erred by focusing on full returns as the sole criterion for deciding on whether to run a cement evaluation log. It said receiving full returns indicated that cement or other fluids had not been lost to a weak formation but full returns provided limited or no information on where the cement went, channeling, contamination, or stability of the foam cement. Cement evaluation logs although of limited use in a well such as Macondo should have been run, the report said. - Foam cement instability. The report noted that Halliburton may have pumped foam cement into the well that available tests indicated would be unstable. Other factors that the report said BP did not adequately consider in assessing the cement job risks included serious lost returns in the cementing zone, no bottoms up circulation, and low cement volume. Negative -pressure test The report said the failure to properly conduct and interpret the negative -pressure test was a major contributing factor to the blowout. The report noted that the cement spacer may have clogged the kill line and that pressure data showed that formation fluids were flowing into the well. The commission identified several factors that may have led to an incorrect test interpretation, such as: - The Mineral Management Service and the industry having no standard procedures for running or interpreting the test and lack of any requirement to run the test. - BP and Transocean having no internal procedures for running or interpreting negative - pressure tests and not formally training their personnel in how to run them. - BP Macondo personnel not providing the wellsite leaders or rig crew with specific procedures for performing the negative -pressure test. - BP not having in place (or not enforcing) any policy that would require personnel to contact the shore office for a second opinion about confusing data. Page 2 of 4 OGJ-Jan 12, 2011 • - Due to poor communication, the personnel performing and interpreting the test may not have had a full appreciation of the context in which they were performing it. Temporary abandonment procedures BP's temporary abandonment procedure also may have contributed to the blowout, the report said. It noted the following problems in the procedures: - Replacing 3,300-ft of mud below the mudline with seawater because of BP's preference for setting cement plugs in seawater instead of in mud to avoid mud contamination. - Not setting one or more noncement bridge plugs. - No evidence that BP evaluated the risks for removing 3,300 ft of mud from the well. - Setting the planned cement plug as deep as 3,300 ft. The report noted that BP Macondo personnel planned that in order to set the casing lockdown sleeve last in the temporary abandonment sequence to minimize the chances of damage to the sleeve and to generate the 100,000 lb force for setting the sleeve by hanging 3,000 ft of drill pipe below the sleeve. - Displacing mud from the riser before setting the cement plug was the most troubling • aspect of the procedure, the report said. This left only the cement at the bottom of the well as the only barrier to fluid influx. Kick detection The report said the drilling crew and other individuals on the rig missed signs that a kick was occurring but it is unclear on why they missed these signals, such as the Sperry Sun mudlogger data between 8:00 p.m. and 9:49 p.m. These signals included increasing drill pipe pressure after the pumps were shut down for the sheen test at 9:08 pm and the anomalous difference between the drill pipe and kill line pressures recognized by the driller and toolpusher at 9:30 pm. The report noted the crew may have missed these signals because after 9:08 p.m., they began sending well fluid returns overboard, bypassing the active pit system and the flow - out meter (at least the Sperry Sun flow -out meter). The mudlogger then only performed a visual flow check. The report recommended that in the future, the rig instrumentation and displays should be improved by installing more sophisticated, automated alarms, and algorithms to alert the driller and mudlogger of anomalies. The report faulted the current rig operations in which individuals sit for 12 hr at a time in • front of displays with the operations requiring the right person to look at the right data at Page 3 of 4 OGJ-Jan 12, 2011 • the right time, and then to understand its significance in spite of simultaneous activities and other monitoring responsibilities. Diversion, BOP activation The report said the crew should have diverted the flow overboard when mud started spewing from the rig floor to reduce the risk of gas igniting. It said the crew possible did not do that because of: • Not recognizing the severity of the situation, although this is unlikely because of the amount of mud spewing from the well. • Not having much time to act. The explosion occurred about 6-8 min after mud first emerged on the rig floor. • Most significantly, not having been trained adequately how to respond to such an emergency. The report recommends that in the future, well -control training should include simulations and drills for such emergencies, including engaging the blind shear rams and triggering the emergency disconnect. • Contact Guntis Moritis at 2untismAodonline.com. • Page 4 of 4 OGJ-Jan 12, 2011 • http://www.halliburton.com/public/news/pubsdata/press release/2011/corpnws 0111201 1.htm1?SRC=Nationa1Comm 2011 Press Releases Fnp TMMIPMn,TG PrI �:'ncF: January 11, 2011 HALLIBURTON COMMENTS ON FINAL REPORT FROM THE NATIONAL COMMISSION ON THE BP DEEPWATER HORIZON OIL SPILL AND OFFSHORE DRILLING HOUSTON (Jan. 11, 2011) - This statement is in response to the findings of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling contained in its investigation report released to the public on Jan. 11, 2011. Halliburton (NYSE: HAL) disagrees with the report's characterization of the February and April foam stability tests related to the cement pumped on the Macondo well, specifically: • The February tests were pilot tests and final well conditions were not known yet. The February tests were not conducted under final well conditions. • The first April foam stability test is irrelevant because of lab technician error in • weighing up the sample of the cement mix. This evidence was supplied to the National Commission; however, the National Commission did not include this information in its report. • The second April foam stability test was a re -test due to the lab errors in the first test. The foam stability test on the cement used to seal the final casing string was completed in 38 hours and finished prior to 4:14 p.m. on April 19, 2010; prior to pumping the cement job. Halliburton has evidence showing that lab tests related to the final cement job, including the foam stability test, were finished in lab by 4:14 p.m. on April 19. Electronic notification of this lab testing status, indicating the foam stability passed, was sent to Halliburton's engineer at 4: 14 p.m. on April 19 and has been provided to the National Commission. • Contrary to the National Commission report, a foam stability test does not require 48 hours to complete. As noted above, the final foam stability test on the cement pumped for the Macondo well was completed and passed laboratory testing in 38 hours. In general, the National Commission selectively omitted information provided to it by Halliburton in response to its numerous inquiries. Further, Halliburton has attempted repeatedly to correct the National Commission's mistaken conclusion that a foam stability test normally requires 48 hours. A representative of the Company testified at the National Commission hearing Nov. 8, 2010 that the test takes as long as necessary for the cement sample to set, which may be less than 48 hours. That same day, we also spoke to a • National Commission staff attorney who acknowledged the test can be completed in less • than 48 hours, and soon after we sent the Commission industry standards noting that the foam stability test can be completed after curing 24 hours or until the sample is set. Halliburton does not believe the issues relating to cement testing invalidates BP Exploration's indemnification obligations as discussed in Halliburton's Form 10-Q for the quarter ended September 30, 2010. Halliburton's contract with BP Exploration relating to the Macondo well is available on its website at www.halliburton.com. Halliburton continues to view safety as critical to its success and is committed to continuously improving performance. Following the National Commission's report today, Halliburton remains committed to upholding its spirit of cooperation with the National Commission by providing as much information as possible to ensure a complete and thorough review process. Halliburton continues to review the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling's final report issued earlier today and will provide additional comments as appropriate. ABOUT HALLIBURTON Founded in 1919, Halliburton is one of the world's largest providers of products and services to the energy industry. With more than 55,000 employees in approximately 70 countries, the company serves the upstream oil and gas industry throughout the lifecycle of the reservoir - from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Visit the company's website at www.halliburton.com. 0 • http://www.washingtonpost.com/wp- dyn/content/article/2011 /01 /06/AR2011010606026.html In over their heads Friday, January 7, 2011 SOME IN THE offshore oil drilling business would have Americans believe that the Deepwater Horizon spill in April was the fault of a single, irresponsible company. In an exhaustively researched report, portions of which were released Wednesday, the presidential oil spill commission concludes that the causes of the disaster aren't so neatly explained. "The blowout was not the product of a series of aberrational decisions made by rogue industry or government officials that could not have been anticipated or expected to occur again," the commission argues. "The missteps were rooted in systemic failures by industry management (extending beyond BP to contractors that serve many in the industry), and also by failures of government to provide effective regulatory oversight of • offshore drilling." Yes, critical mistakes were made by BP. But also by Halliburton, the contractor responsible for the cementing, and by Transocean, the rig owner. All three companies have extensive operations around the world. Though some players have done better than others, commission members describe an entire industry that moved over the past two decades from shallow -water drilling to far riskier deep -water operations - without the required adjustments in technology or mentality. Deep -water drills use extremely sophisticated techniques in dangerous, high-pressure conditions. For the most part, neither government inspectors nor industry managers acknowledged or prepared for the new risks. Commission leaders liken the past 20 years to the era when electric utilities moved from coal to nuclear without sufficient attention to the dangers - until an accident at Three Mile Island snapped the industry to attention, with its very survival at stake. The drilling industry needs to take Deepwater Horizon as a similar wake-up call. The commission is due to deliver its recommendations next week. But already this much is clear from the pages and pages of technical details, which changed practically daily as Deepwater Horizon operated: No government regulatory structure alone can guarantee safety in an industry that must constantly adapt new technology to natural variations in drilling sites and unexpected natural phenomena. Oversight must improve, as the Obama administration has made clear, but also every company involved in oil drilling - not just BP - must individually and in concert with others evaluate industry standards and safety • research programs. And none should assume that BP's mistakes could not occur elsewhere. http://finance.yahoo.com/news/Exxon-CEO-disputes-panel-rb- 776452958.html?x=0&sec=topStories&pos=3&asset=&ccode= Exxon CEO disputes panel finding on BP spill cause On Thursday January 6, 2011, 1:31 pm EST By Kelley Shannon AUSTIN, Texas (Reuters) - Exxon Mobil Corp's chief executive officer disputed findings from a White House commission that lax industry practices were to blame for last year's massive BP oil spill. At a conference in Austin on Thursday, Rex Tillerson, CEO of the world's largest publicly traded oil company, sought to insulate Exxon and the industry from blame for the incident, the worst offshore spill in U.S. history. "I do not agree that this is an industrywide problem," Tillerson said, referring to a report released on Wednesday by the White House spill commission that pins some of the blame on lax industry practices. "The commission did not investigate the entire industry," Tillerson told reporters. "It seems to ignore years of record of good performance, so I do not agree with that conclusion." BP's mile -deep Macondo well in the Gulf of Mexico ruptured on April 20, 2010, causing an explosion aboard the Deepwater Horizon drilling rig that killed 11 people, spewed more than 4 million barrels of oil into the sea and spurred a temporary ban on U.S. deepwater drilling. The accident was "a painful reminder' of the harm that can result from failure to uphold performance standards, Tillerson said. Tillerson pointed to the Exxon Valdez disaster in 1989, which spilled 257,000 barrels of oil into Alaska's Prince William Sound. "It was a low point for our company, but also a turning point," Tillerson said. Exxon is one of five major international oil companies in a $1 billion venture to develop a subsea spill containment system that could be quickly deployed in the event of future accidents. Questioned on the state of the global economy, Tillerson said he saw a "slight uptick" in the manufacturing sector. "Generally things feel stable, and the sense is that they are improving," Tillerson said. "The question that's still out there is the pace." Shares of Exxon were up 0.5 percent at $75.06 in afternoon trading. • (Writing by Chris Baltimore; Editing by Derek Caney and Lisa Von Ahn) • n u 0 The Telegrapb http://www.telegraph.co. uklearthlearthnews/823 6144/MPs-give-backing-to-deep-water- drilling-off-UK.html MPs give backing to deep water drilling off UK MPs have ruled out a moratorium on deep water drilling in the North Sea, despite concerns it could lead to a disaster worse than BP's oil spill in the Gulf of Mexico last year. Photo: CHRIS WATT T By Louise Gray, Environment Correspondent 7:OOAM GMT 03 Jan 2011 3 Comments Following the Deepwater Horizon spill, the Energy and Climate Change Committee was asked to look into the risks of drilling in deep water off the UK. • Oil companies have openly admitted that current plans for deep water drilling off the Shetland islands could cause an oil spill worse than the Gulf of Mexico disaster. But Tim Yeo, the Chairman of the Committee, said both the energy and national security of the UK depends on the newly discovered oilfields. He said safety procedures could be "tightened up" but on the whole the industry is safe and the regulatory system "robust', following reforms brought in after the Piper Alpha disaster. "Although we heard evidence it is not always done right — and I am sure it is not always done right. Nevertheless, I think the concerns are nothing like big enough to justify stopping the process," he said. Related Articles Shetland drilling could trigger spill worse than BP's 27 Oct 2010 • . Greenpeace sues UK to end Shetland drilling 12 Nov 2010 Ws rule out deep -water drilling ban 03 Jan 2011 Government to launch North Sea review 03 Jan 2011 BP leads plans for North Sea oil spill cap 03 Jan 2011 Obama faces first backlash in the US over his continued attacks on BP 03 Jan 2011 0 • A quarter of the UK's currently discovered oil and gas reserves, around four million barrels, lie in deep water off the West of Shetland. Oil companies are already drilling in the `new frontier' and expect to open up hundreds of new wells in future. Just four fields are currently producing oil west of the Shetland Islands but more than 100 exploration licences have been granted by the Government with more pending. Ben Ayliffe of Greenpeace pointed out that independent studies into what caused the disastrous spill in the Gulf of Mexico have not concluded yet. He also pointed to recent Health and Safety Executive figures that show an increase in both serious accidents and spilt oil in rigs operating off the UK. Serious accidents almost doubled from 106 per 100,000 in 2008/09 to 192 last year, while spills of hydrocarbons were up from 61 to 85. "They are pressing ahead regardless of the holes in their own regulatory system. It is like they have learned nothing from the Deep Water Horizon spill," he said. Greenpeace are currently trying to block any more deep water drilling through the High Courts by claiming that it is threatens environmental sites protected under EU law. • If successful, the action will affect over 20 oil production licences — mainly west of Shetland — and could halt future licensing rounds Rare species in danger include several species of whales, dolphins, sea birds and seals. There are also important cold water coral reefs in the area. The environmental consequences could be worse than the Gulf of Mexico because the oil disperses more slowly in cold water and dispersants would be less effective. Conditions can also be more difficult because of storms and rough seas in the area. The Marine Conservation Society also want a moratorium on drilling in the area because of the risk to wildlife and fisheries. Chevron has admitted its new deepwater drilling campaign off the Shetland Islands could release 77,000 barrels per day — 25 per cent more than gushed into the Gulf of Mexico last year. The US oil giant is currently drilling the Lagavulin prospect around 160 miles north of the Shetland Islands in 1,569m of water — deeper than BP's ruptured well. In written evidence BP also admitted that there are risks to deep water drilling. 0 • "It is impossible to eliminate risk from any aspect of North Sea operations, whether in shallow or deep water," read a statement. "But the lessons to be learnt from the tragic accident of the Gulf of Mexico will enable the industry to reduce greatly these risks, and to help prevent a similar occurrence happening elsewhere." The oil company insisted that delay to deep water drilling would have "implications for the security of UK oil and gas supplies" and West of Shetland has the "greatest exploration potential". Chris Huhne, the Energy and Climate Change Secretary, has acknowledged that an oil spill off the West of Shetland would be "an absolutely enormous environmental disaster" but he has insisted the measures governing the oil and gas industry in UK waters are "fit for purpose". 0 DISASTER IN THE GULF NICK de la TORRE : CHRONICLE TESTIMONY: Joseph Keith, a mud logger for Sperry Sun, said that when he got back to his terminal after his break, there was no indication of trouble. Hear onw ing ell i focuses mud work Engineer describes what he saw before Deepwater Horizon blowout By TOM FOWER HOUSTON CHRONICLE The engineer watching the flow of drilling mud from Bp's Macondo well was on a coffee and smoke break when the well showed signs WEDNESDAY DECEMBER 8, 2010 HOUSTON*CHRONICLE 'chr'On .com /business of its imminent blowout, ac- cording to testimony Tues- day before a panel investigat- ing the accident. Joseph Keith, a mud log- ger for Sperry Sun, a unit of Halliburton, said he took the 10-minute break on the evening of April 20 while the crew of the Deepwater Hori- zon drilling rig displaced a portion of the well's drilling mud with seawater. Data logs reviewed during the hearing Tuesday showed that in the hours leading up to the accident, the flow of mud out of the well was greater than the amount go - Please see HEARING, Page D8 • • • --THE JUMP PIGE Wednesday, December 8, 2010 NICK de la TORRE : CHRONICLE DELIVERING EVIDENCE: Coast Guard Lt. Cmdr. Robert Butts returns to his seat after presenting Joseph Keith, a mud logger for Sperry Sun, with a sheet of evidence during a hearing Tuesday about events leading up to the Gulf of Mexico oil spill. REARING: Moving a lot of mud' CONTINUED FROM PAGE DI ing in — an indication that hy- drocarbons might be building up in the well. Some of the changes in readings occurred during the time when Keith said he was on break. Tuesday's was the first of a three-day round of hearings in Houston that are part of the joint investigation by the Coast Guard and the Inte- rior Department's Bureau of Ocean Energy Management, Regulation and Enforcement. Testimony resumes at 8 a.m. today. No indication of trouble Keith said that when he got back to his terminal after his break, there was no indica- tion of trouble. Had he seen an issue, he would have called a supervisor or called the drilling floor to warn workers there, he said. The Macondo blowout de- stroyed the Deepwater Ho- rizon, killed 11 workers and started an 87-day oil spill in the Gulf of Mexico. The joint panel has held five previous sets of hear- ings, looking at issues from the chain of command on the Transocean drilling rig to BP's design of the deep -water well. It is scheduled to present its final report by March 27. Panelists will conduct at least one more hearing, to discuss forensic tests on the blowout preventer that failed as the last line of defense against the disaster. The blowout preventer is being analyzed at a NASA fa- cility near New Orleans. Keith, who had served on the rig for nearly eight years, said Tuesday he was uncomfortable with the number of activities going on aboard the rig the day of the blowout. "They were moving a lot of mud around," Keith said, referring to mud engineers shifting mud in and out of several different pits and off- loading some of the mud to a ship waiting alongside the rig. That made it difficult to keep track of the mud that was leaving the well. . Keith said he didn't raise that issue with supervisors or others, however, even though the rig's safety rules em- powered him to. call a halt to operations. The work was intended to get a number of the mud tanks ready for cleaning, Keith said, part of preparations for mov- ing the rig to a new well. Acted differently? John Gisclair, a fellow Sperry Sun worker and an expert in the electronic data gathered from the rig, testi- fied that it appears the crew would have had a hard time getting accurate readings of what was coming from the well. "I can't say, looking at these charts, I would have acted any differently than Mr. Keith," Gisclair said. Coast Guard Lt. Cmdr. Robert Butts, one of the panel members, said it appeared the mud logger and drillers didn't know what was going on in the well — and noted the panel still doesn't know. "If we can't tell now, months after the incident, how could the guys have been able to know?" Gisclair agreed. "I see nothing on the charts that tells us without a doubt there was going to be a blowout," Gisclair said. tom.fowler@chron.com • BP says Gulf well shutdown was delayed • 49 MINUTES: Distractions kept rig workers from reacting. By HARRY R. WEBER The Associated Press Published: December 8th, 2010 07:29 PM Last Modified: December 8th, 2010 07:29 PM HOUSTON -- Workers on the doomed Gulf of Mexico oil rig were distracted by multiple activities going on simultaneously and didn't try to shut the well until 49 minutes after potentially explosive gas particles began flowing in, a BP vice president told a federal investigative panel Wednesday. Steve Robinson, who led the team that questioned the well -site leaders as part of BP's internal probe, said at hearings in Houston that the actions were late. He said that by the time the crew reacted, the hydrocarbons were already in the riser. He said they couldn't be contained, only diverted. An explosion occurred just minutes later, killing 11 workers and leading to more than 200 million gallons of oil spewing from BP's well a mile beneath the sea, according to government estimates. Steve Robinson The joint U.S. Coast Guard -Bureau of Ocean Energy Management, Regulation and Enforcement panel is nearing the final stretch in its quest to assign blame for the April 20 disaster. This is the panel's sixth series of hearings, and at least one more is expected before the panel issues its report, which is due by March 27. The panel is still • awaiting the results of forensic testing on a key piece of evidence -- the blowout • preventer that failed to stop the spill. Investigators are analyzing it at a NASA facility in New Orleans. BP has previously acknowledged that its engineers and employees of Transocean misinterpreted a pressure test of the well's integrity before the explosion. It also previously blamed employees on the rig from both companies for failing to respond to other warning signs that the well was in danger of blowing out. Robinson, vice president of wells for BP's Alaska business, also testified that a technician for a unit of Halliburton who was responsible for monitoring gas levels told BP's internal investigators he never left his post in the hours before the blast. However, the technician, Joseph Keith, testified before the federal panel Tuesday that he left his post around 9 p.m. for about 10 minutes to grab some coffee, smoke a cigarette and use the restroom. Robinson said that if that is true, there could have been a gap in monitoring during a critical time. Investigators appear now to be trying to draw a link between the distractions on • the rig, the time it took to respond and the consequences. The co-chairman of a separate presidential commission on the Gulf oil spill said Wednesday during a speech to oil industry lawyers in New Orleans that there is widespread belief that "breathtakingly inept" mistakes by BP, Halliburton and Transocean led to the disaster. William Reilly also said the industry must do a much better job of regulating itself. BP declined to comment on the remarks, while Transocean said in a statement that BP was in charge of the well design and construction. Halliburton said it remains confident that all the work it performed with respect to BP's well was completed in accordance with BP's specifications and instructions. Robinson told the USCG- BOEMRE panel he was asked on April 25 to join BP's investigation team looking into the disaster. He participated in interviews, including the questioning of BP's three well site leaders who were on the Deepwater Horizon at the time of the blast. Robinson said that as part of its probe BP used data and other information to 49 create models of what occurred on the rig. He said those models show that the • well began to flow at 8:52 p.m., but it wasn't until 9:41 p.m. that there were any well -control responses by the crew. "I believe it was late," Robinson said. Read more: http://www.adn.com/2010/12/08/1595014/bp-says-gulf-well-shutdown- was.html#ixzz 17j 8BIaDK • 0 n • 0 2010 Canada US Northern Oil and Gas Research Forum Draft Programme The Second Canada - United States Northern Oil and Gas Research Forum is an opportunity for American and Canadian regulators, Aboriginal people, industry members, and scientists to discuss current scientific research and its relevance to northern oil and gas management. The Forum will examine the current status and future directions for the Beaufort and Chukchi Seas, North Slope and Mackenzie Delta, with a focus on technical, engineering and scientific research concerning offshore drilling safety, oil spill prevention and management, ice engineering and transportation issues as well as the environmental effects of oil and gas exploration and development in the North. 1 • General Programme GeneralProgramme............................................................................................................................... 3 PlenarySessions..................................................................................................................................... 4 TopicalSessions......................................................................................................................................7 Posters......................................................................................................................................................15 Abstracts- Panel Sessions................................................................................................................16 Abstracts - Topical Sessions............................................................................................................23 9 Abstracts - Poster Session................................................................................................................36 ForumSponsors....................................................................................................................................45 ForumPartners.....................................................................................................................................46 Floorplan..................................................................................................................................................48 • • C. [7 Tuesday Nov 30 s Wednesday Dec 1 Thursday Dec 2 GENERAL PROGRAMME 8:30 Welcome 8:40 Opening remarks by Canadian and US officials 9:10 Overview of Canadian Northern Oil and Gas Research Programs 9:35 Overview of US Northern Oil and Gas Research Programs 10:00 Break 10:30 Management panel: US and Canadian research processes in North needs and priorities, and the regulatory 12:00 Lunch 13:30 1430 Panel: Environmental conditions in exploration areas Scientific talks (2) Panel: Safety on northern offshore platforms & EER issues Scientific talks (2) 15:10 I Break 15:40 Scientific talks (4) Scientific talks (4) 17:00 End of Day 1 8:30 Industry panel: US and Canadian research priorities from an Industry perspective 10:00 _ Break ---- - 10:30 11:30 Panel: Monitoring for cumulative effects in the Arctic Scientific talks (2) Panel: Transportation logistics for exploration and development in the Arctic Scientific talks (2) 12:10 Lunch 13:30 Scientific talks (2) Scientific talks (2) 14:10 Panel: Interaction of oil and gas activities Panel: Ice engineering for offshore with sensitive coastal habitats operations 15:10 15:30 17:10 18:30 8:30 9:30 10:10 10:40 11:40 12:20 13:30 14:50 Break Scientific talks (4) Scientific talks (4) Poster session and Reception (hors d'oeuvres & cash bar) End of Day 2 Panel: Oil spill prevention in the Arctic Scientific talks Break Panel: Oil spill management in the Arctic Scientific talks (2) Lunch Scientific talks (4) Forum wrap up and closing remarks 3 • E 15:30 Close of Forum PLENARY SESSIONS Imperial Ballroom 4/6/8 Tuesday, November 30 - 8.30 to 10.00 OPENING PLENARY -chair Genevieve Carr, Science Advisor, Northern Oil and Gas Branch, Indian and Northern Affairs Canada US chair TBD 8:30 Welcome 8:40 Patrick Borbey Opening remarks from Canada Sr Assistant Deputy Minister, Treaties and Aboriginal Government, Indian and Northern Affairs 8:55 TBD Opening remarks from the United States 9:10 Mimi Fortier Overview of Canadian Northern Oil and Director General, Northern Oil and Gas Branch, Gas Research Programs Indian and Northern Affairs Marc D'iorio Director Genereal, Office of Energy Research and Development, Natural Resources Canada 9:35 John Goll Overview of US Northern Oil and Gas Regional Director Alaska Region, Bureau of Research Programs Oceans and Energy Management, Regulation and Enforcement Mark Myers Coordinator, Alaska Gasline Inducement Act 10:00 Break • .7 • Tuesday, November 30 -10:30 to 12:00 MANAGEMENT PANEL: U.S AND CANADIAN RESEARCH NEEDS AND PRIORITIES Co-chairs Mike Peters, Canadian Association of Petroleum Producers Mark Myers, Coordinator, Alaska Gasline Inducement Act Robert Steedman The National Energy Board's Arctic Offshore Professional Leader, Environment, National Drilling Review: research and risk assessment in Energy Board the context of safety and environmental regulation. Brenda Pierce USGS Study on Science Needs to Inform Acting Chief Scientist, Geology Program Decisions on Outer Continental Shelf Energy Coordinator, Energy Resources Program, U.S. Development in the Chukchi and Beaufort Seas Geological Survey Frank Pokiak Wildlife and Environmental Research and Chair, Inuvialuit Game Council Management in the Inuvialuit Settlement Region John Payne North Slope Science Initiative: Mission and Executive Director, North Slope Science Initiative Organization Bill Streever Research Priorities and Resource Management Chair, North Slope Science Initiative's Science on Alaska's North Slope: Old Problems and New and Technical Advisory Panel, and BP Alaska Opportunities Exploration, Inc LUNCH (12:00) Wednesday, December 1 - 8.30 to 10:00 INDUSTRY PANEL: U.S. AND CANAD/ANRESEARCH PRIORITIES Co-chairs Martin Fortier, Executive Director, ArcticNet Richard Ranger, Upstream/Industry Operations, American Petroleum Institute Mike Peters Canadian industry perspective of emerging oil Manager, Northern Canada Operations, Canadian and gas research needs in the North. Association of Petroleum Producers Pete Slaiby Offshore Alaska oil and gas research needs; General Manager, Alaska, Shell Exploration & environment, technology, and resources Production Company Bill Streever Ecological Research in a Mature Arctic Oilfield: Environmental Studies Program Director, BP Alaska Prudhoe Bay, Alaska Exploration Inc, Alaska Jim Hawkins Research needs in the Beaufort Sea: unique Beaufort Mackenzie Operations/Regulatory challenges of exploring in deepwater regions. Manager, Imperial Oil Resources BREAK (10:00) • • • TOPICAL SESSIONS is • Imperial 4/6/8 Tuesday, November 30 -13:30 to 17.00 ENVIRONMENTAL CONDITIONS IN EXPLORATIONAREAs Co-chairs Leslie Holland -Bartels, Deputy Alaska Regional Director and Director Alaska Science Center, U.S. Geological Survey Henry Huntington, Science Director, Oceans North/Pew Environment Group Panel Richard Glenn Alaska North Slope oil and gas history - Traditional Executive Vice President, Arctic Slope and Western Science. Regional Corporation, Lands and Natural Resources Louis Fortier Current understanding of Beaufort Sea Scientific Director, ArcticNet environment and its relation to oil and gas activities 13:30 Dee Williams Environmental and socioeconomic studies in US 14:30 Chief, Environmental Studies Section, Arctic marine and coastal areas related to oil and Bureau of Ocean Energy Management, gas activities. Alaska Giles Morrell Using existing data to identify environmental and Manager, Oil and Gas Regulatory social sensitivities to oil and gas activities: the Affairs, Indian and Northern Affairs Petroleum Environmental Management Tool. Canada Q&A, discussion Science Talks 14:30 Robert Day, ABR Inc. "The Chukchi Sea Environmental Studies Program: an overview" 14:50 Kenneth Dunton, Marine Science Institute, University of Texas at Austin "An Integrated Chemical and Biological Study of the Benthos of the Chukchi Sea: Preliminary Results from the COMIDA-CAB Program" 15:10 BREAK 15:40 James Hall, Imperial Oil Resources Ventures Limited "Collaborative Research to Characterize Biological, Physical and Geotechnical Conditions in Support of Beaufort Sea Drilling Operations" 16:00 Susanna Blackwell, Greeneridge Sciences Inc. "Assessing the effects of seismic exploration activities on bowhead whale call distribution in the Alaskan Beaufort Sea: 3-year summary" 16:20 Sharon Smith, Natural Resources Canada "Updated Characterization of Permafrost Thermal Conditions in the Mackenzie Delta Region" 16:40 Philip Marsh, Environment Canada "Hydrology of the outer Mackenzie Delta in the vicinity of proposed natural gas development" r17-00 End of Day 1 • • Imperial 5/7/9 Tuesday, November 30 -13:30 to 16:00 SAFETY ON NORTHERN OFFSHORE PLATFORMS AND EER ISSUES Co-chairs Anne Barker, Project Engineer, National Research Council Canada Jim Regg, Petroleum Engineer, Alaska Oil and Gas Conservation Commission Panel Bharat Dixit Regulating and ensuring safety when Team Leader, Conservation of Resources, authorizing offshore operations National Energy Board LT Darin W. Qualkenbush United States Outer Continental Shelf 13:30 National Technical Advisor, US Coast Guard Regulatory Overview 14:30 Jeffrey Walker Offshore safety issues and inspections Regional Supervisor for Field Operations - Alaska, Bureau of Ocean Energy Management Regulation and Enforcement Q&A, Discussion Science Talks 14:30 Anne Barker, Research Council of Canada "Seasonal Strategies for Evacuation from Offshore Structures in the Beaufort Sea" 14:50 Chris Hill, Canatec Associates International Ltd. "Ice Forecasting for Offshore Operations" 15:10 BREAK 15:40 Frank G. Bercha, Bercha Group "Arctic Emergency Evacuation and Rescue: Present and Future" 16:00 End of Session 17-1 40 Imperial 4/6/8 Wednesday, December 1 -10:30 to 14.10 MONITORING FOR CUMULATIVE EFFECTS /N THEARCT/C Co-chairs Lisa Loseto, Section Head, Ecosystem Impacts, Fisheries and Oceans Canada Robert Suydam, Wildlife Biologist, North Slope Borough Panel Cynthia Pyc Cumulative Effects Assessment for the HSSE/Regulatory Team Lead, North American Canadian Beaufort Sea Arctic Exploration, BP Exploration Company Robyn Angliss Monitoring of oil spill effects Deputy Director, National Marine Mammal Laboratory, National Ocean and Atmospheric 10:30 Administration 11:30 Dave Yokel Monitoring Terrestrial Ecosystems in Wildlife Biologist, Bureau of Land Management, the National Petroleum Reserve - Alaska Alaska State Office for Effects from Oil and Gas Activities Marc Lange Cumulative Impacts Monitoring Manager, Environment and Conservation, Program in the Northwest Territories Indian and Northern Affairs Canada Q&A, Discussion Science Talks 11:30 Neil 1. Mochnacz, Fisheries and Oceans Canada "Modelling habitat of Dolly Varden (Salvelinus malma) in the Western Canadian Arctic in support of ecosystem -based management" 11:50 Doug Mason, Nunami Stantec "A New Tool for Identifying Sensitive Areas and the Relative Environmental Risk of Hydrocarbons Activities in the Canadian Arctic" 12:10 LUNCH 13:30 Robert Suydam, North Slope Borough Department of Wildlife Management "Traditional knowledge and scientific information about the sensitivity of bowhead whales (Balaena mysticetus) to anthropogenic sounds" 13:50 Wojciech Walkusz, Fisheries and Oceans Canada "Zooplankton of the coastal Beaufort Sea - past, present and future studies." 14:10 End of Session E • Imperial 5/7/9 Wednesday, December 1 -10:30 to 14:10 TRANSPORTATION LOGISTICS FOR EXPLORATIONAND DEVELOPMENT IN THEARCTIC -chairs Ivana Kubat, Project Engineer, National Research Council Canada Jeffrey Walker, Regional Supervisor of Field Operations, Bureau of Ocean Energy Management, Regulation and Enforcement, Alaska Panel Victor Santos -Pedro Regulating transportation in harsh Director, Design, Equipment and Boating Safety, Arctic environments Transport Canada David M. Seris Port Access Route Study for the Bering 10:30 Deputy Waterways Management, United States Strait - Coast Guard 17th District 11:30 Allison Iversen Permitting, monitoring, and Coordinator, Petroleum Systems Integrity maintenance of onshore and offshore Office, Alaska Department of Natural Resources pipelines Q&A, Discussion Science Talks 11:30 Ivana Kubat, National Research Council "Canadian Research to Improve Navigation in the Arctic" 11:50 Michael Lilly, Geo-Watersheds Scientific "Alaska North Slope Oil and Gas Transportation Support Systems: Taking Alaska Forward Into New Development" 12:10 LUNCH 13:30 Rod Smith, Natural Resources Canada "The application of seismic shothole drillers' log records to the understanding of permafrost, ground ice, bottomfast ice, and granular aggregate resources in the Mackenzie - Beaufort region." 13:50 Julian Kanigan, Indian and Northern Affairs Canada "Ariability of active -layer freezeback in the outer Mackenzie Delta, Northwest Territories" 14:10 End of Session 10 • • • Imperial 4/6/8 Wednesday, December 1 -14:10 to 17:00 INTERACTION OF OIL AND QsACTIVITI6s WITH SENSITIVE COASTAL HABITATS Co-chairs Linda Graf, Manager, Environment and Stakeholder Engagement, Canadian Arctic, ConocoPhillips Wayne Svejnoha, Bureau of Land Management Panel Frank Pokiak The Significance of Coastal Habitats to Chair, Inuvialuit Game Council the Inuvialuit Craig George Regional biology and activity on the Senior Wildlife Biologist, North Slope Borough North Slope Department of Wildlife Management 14:10 Steve Solomon Distinguishing between natural - Coastal Geologist, Geological Survey of Canada variability and hydrocarbon extraction 15:10 effects on the biophysical environment of the Beaufort Sea coastal zone William E. Schnabel Evaluating Source Waters for Ice Road Director, Water and Environmental Research Planning Center, University of Alaska Fairbanks Q&A, Discussion 15:10 BREAK Science Talks 15:30 Caryn Rea, ConocoPhillips "Environmental Considerations associated with Oil and Gas Exploration and Development on Alaska's North Slope" 15:50 Stephen Braund, Stephen R. Braund & Associates "Oil Development Impacts on Subsistence: Monitoring and Assessing Mitigation" 16:10 Rachel Cox, Exxon Mobil "Proactive Management of Potential Interactions between Polar Bears and North Slope Oil & Gas Development - the Point Thomson Project" 16:30 Lois Harwood, Fisheries and Oceans Canada "Potential for displacement of whales and seals by seismic and exploratory drilling activity in the Canadian Beaufort Sea - what have research and observations revealed to date" 16:50 End of Session 11 Ll • • Imperial 5/7/9 Wednesday, December 1 -14:10 to 17.00 ICE ENGINEER/NG FOR OFFSHORE OPERATIONS Co-chairs Humphrey Melling, Research Scientist, Department of Fisheries and Oceans Kyle Monkelien, Sernior Petroleum Engineer, Alaska Region Bureau of Ocean and Energy Management, Regulation and Enforcement Panel Garry Timco Four Approaches for Addressing Ice A/ General Manager, Canadian Hydraulics Forces on Offshore Platforms Centre, National Research Council Karen Muggeridge Design Challenges for Offshore 14:10 ConocoPhillips Structures in the Arctic 15:10 Hajo Eicken Sea -ice predictions and integrated University of Alaska Fairbanks observations for offshore operations Michael J. Paulin Ice Related Arctic Pipeline Design Issues Operations Director Canada, INTECSEA and Research Needs Q&A, Discussion 15:10 BREAK Science Talks 15:30 Humphrey Melling Fisheries and Oceans Canada "Recent observations of multi -year ice in the Canadian High Arctic" 15:50 William Perrie, Bedford Institute of Oceanography, Fisheries and Oceans Canada "The impacts of increased open water on Arctic summer storms" 16:10 Christopher Haas, University of Alberta "Ice thickness information for safe and environmentally responsible offshore operations" 16:30 Scott Tiffin, Canatec Associates International Ltd. "The importance of Ice Islands and Extreme Ice features in relation to offshore structures" 16:50 End of Session 12 • • Imperial 4/6/8 Thursday, December Z - 8.30 to 10:10 OIL SPILL PREVENTION IN THE ARCTIC Co-chairs Sharon Smith, Permafrost Research Scientist, Natural Resources Canada Cathy Foerster, Commissioner, Alaska Oil and Gas Conservation Commission Panel Steve Blasco The Importance of Geohazard Resource Engineering Geophysicist, Natural Assessment in Preventing Oil Spills Resources Canada Bill Scott Limiting The Flow - A Pragmatic Manager, Chevron Arctic Center, Chevron Approach To Oil Spill Containment 8:30 Larry Iwamoto Spill Prevention and Response in - Alaska Department of Environmental Alaska's Arctic Waters 9:30 Conservation Kyle Monkelien New Regulatory Requirements as a Senior Petroleum Engineer, Alaska Region Result of the Presidential Commissioned Bureau of Ocean and Energy Management, Safety Measures Report Regulation and Enforcement Q&A, Discussion Science Talks 9:30 Frank G. Bercha, Bercha Group "Arctic Oil Spill Probabilities" 9:50 Mark Swanson, Prince William Sound Regional Citizens' Advisory Council "Oil spill prevention Planning" 10:10 BREAK End of Session 13 • • Imperial 4/6/8 Thursday, December 2 -10:40 to 14:50 OIL SPILL MANAGEMENT IN THEARCTIC Co-chairs Sonia Laforest, Emergency Operations Officer, Environment Canada Capt. Carl Uchytil, Chief of Plans, 17th District (Alaska), US Coast Guard Panel Ed Owens Oil Spill Management Techniques In or Principal, Polaris Applied Sciences Inc Near Sensitive Coastal Habitats Ken Lee Clean up and containment of oil spills in Bedford Institute of Oceanography, ice infested waters Department of Fisheries and Oceans 10:40 Ron Morris Alaska Clean Seas - Oil Spill Removal - President and General Manager, Alaska Clean Organization with a long history in R&D 11:40 Seas Jeep Rice Habitat Assessment & Marine Chemistry, Oil Spill Management; biological National Oceanic and Atmospheric considerations Administration Q&A, Discussion Science Talks 11:40 Elizabeth Logerwell, Alaska Fisheries Science Center "Natural resource damage assessment in Arctic waters" 12:00 Jason Duffe, Environment Canada "Earth Observation data to support emergency response and wildlife management in case of an oil spill in Canada's northern coastal ecosystems" 12:20 LUNCH 13:30 Thomas Weingartner, University of Alaska "Shore -based, high -frequency surface current measuring radars in remote arctic settings" 13:50 Roger Pilkington, Canatec Associates International Ltd. "Understanding Ice Movement for Oil Spill Monitoring and Cleanup" 14:10 Steve Potter, SL Ross Environmental Research Ltd. "In situ Burning in Arctic and Ice -Covered Waters: Tests of Fire -Resistant Boom in Low Concentrations of Drift Ice" 14:30 Steve Potter, SL Ross Environmental Research Ltd. "Beaufort Sea Oil Spills State of Knowledge Review and Identification of Key Issues" Thursday, December 2 -14:50 to 15:30 CLOSING REMARKS 14:50 Closing Remarks and Discussion 15:30 Close of Forum 14 • • is Grand Foyer 3 & 4 POSTERS Wednesday, December 1 -17.00 to 18:30 POSTER SESSION [1] G. Pavia and S. Blue, "The Arctic Regulatory and Stakeholder Experience" [2] A.R. Majewski and J.D. Reist, "Fisheries research in support of Fisheries and Oceans Canada's regulatory role in hydrocarbon development in the Canadian Beaufort Sea" [3] Nachman and S. Guan, "The U.S. Marine Mammal Protection Act Incidental Take Authorization Process: Challenges in the Arctic" [4] R. Goodwin, "The Hydrocarbon Impacts Database: Your Gateway to Northern Canadian Oil and Gas Environmental, Socio-Economic and Regulatory Publications" [5] M. Lilly et al. "The Role of Soil Conditions in Managing Arctic Transportation on the North Slope, Alaska" [6] M. Lilly et al. "The Role of Snow in Arctic Transportation Networks: From Design to Management" [7] M. Lilly et al, "The Use of Lakes and Reservoirs in Arctic Transportation Networks and Applications of Adaptive Water Resources Management to Improve Water Availability While Reducing Environmental Risks" [8] R. Brumbaugh, "Who Needs an Ice Road?" [9] S. Guyer et al., "Land Cover Mapping of Alaska's North Slope Utilizing Landsat TM Imagery" [10] L. Jenkins et al. (presented by R. Shuchman) "Data Assimilation of Robotic and Satellite Data for Characterization of North Slope, Alaska Lakes" [11] Grunblatt and D. Atwood, "Using SAR to Characterize Winter Liquid Water Availability in Lakes on the North Slope Coastal Plain ofAlaska-A Regional Assessment" [12] Jones and K. Pierce, "Geoscience Data for the Peel Plateau and Plain, Northwest Territories and Yukon" [131 P. Marsh and S. Endrizzi, "Hydrology and northern pipelines: hazards and environmental protection" [14] Stevens et al., "Controls on permafrost distribution within the near -shore zone of the Mackenzie Delta" [15] D. Forbes, "Measuring natural subsidence, enhanced flooding, and habitat loss in the outer Mackenzie Delta, western Arctic Canada" [16] S. Solomon et al., "Understanding Nearshore Processes of a Large Arctic Delta Using Combined Seabed Mapping, In Situ Observations, Remote Sensing and Modeling" [17] Blanchard et al., "Influence of environmental gradients on macrofaunal community structure in the northeastern Chukchi Sea." [18] Parris and A. Blanchard, "Distributions of epibenthic macroinvertebrates in the northeastern Chukchi Sea, 2009" [19] Matthew Sexson, "Distribution and migratory timing of threatened Spectacled Eiders in the Beaufort and eastern Chukchi seas" [20] Funk and A. Macrander, "A marine mammal monitoring and mitigation program for oil and gas exploration in arctic Alaska" [21] Roth et al., "Using passive acoustics to monitor anthropogenic activity in the Chukchi and Beaufort Seas" [22] R. Greer, "Effects of Ambient Artificial Light on Arctic Marine Fauna" [23] S. Prinsenberg et al., "Observing the snow and ice properties in the Arctic coastal waters of the Canadian Beaufort Sea with helicopter -borne Ground -Penetrating Radar, Laser and Electromagnetic sensors." [24] T. Sylvestre et al. "Using Position Beacons to Measure Ice Movement for Beaufort and Chukchi Offshore Petroleum Activities" 15 ABSTRACTS - PANEL SESSIONS Management Panel NORTH SLOPE SCIENCE INITIATIVE. M►SSIONAND cumulative impacts of development, infrastructure, and ORGANIZATION maintenance activities offshore and onshore on ecosystems, landscapes, seascapes, water quality, seafloor and land stability, and subsistence hunting and fishing; effective and John F. Payne reliable oil spill response in ice -covered regions; changing climate conditions and how they will either mitigate or North Slope Science Initiative, c/o Bureau of Land compound the impacts from energy development in the Management, Alaska State Office (910) 222 West 7th Arctic environment The analysis will focus on any Avenue, #13, Anchorage, Alaska 99513 particular concerns that may be unique to the Chukchi and Beaufort The talk presented at this meeting will update the The North Slope Science Initiative (NSSI) was formally audience as to findings to date and request thoughts and established by legislation in the Energy Policy Act of 2005, considerations related to our study. but planning for such an initiative began several years prior when local, state and federal governments with responsibilities for land and ocean management recognized WILDLIFE AND ENVIRONMENTAL RESEARCH AND the need to facilitate and improve collection and MANAGEMENT IN THE ►NUVIALUIT SETTLEMENT REGION dissemination of ecosystem information of Alaska's North Slope region, including coastal and offshore regions. The Frank Pokiak NSSI's mission is to improve scientific and regulatory understanding of terrestrial, aquatic and marine ecosystems Inuvialuit Game Council for consideration in the context of resource development activities and climate change. The NSSI's vision is to identify The Inuvialuit Final Agreement (IFA), signed in 1984, the data and information that government agencies will need established a system of co -management that, more than ever in the future to manage development using the best before, provided for a heightened level of community information and mitigation to conserve the environments of participation in resource management along with increased the North Slope. The NSSI adopts a strategic framework to institutional accountability. This process allows the provide resource managers with the data and analyses they Inuvialuit and different levels of government, researchers need to help evaluate multiple simultaneous goals and and developers to work together in wildlife and objectives related to each agency's mission on the North environmental research and management Slope. The NSSI uses and complements the information produced under other North Slope science programs, both This presentation will review the Inuvialuit wildlife co - internal and external. The initiative also facilitates management system and the role that the Inuvialuit play in information sharing among agencies, non -governmental research in the ISR. This review will look at how input from organizations, industry, academia, international programs the local HTCs, co -management boards and the Inuvialuit and members of the public to increase communication and Game Council informs conservation, research, management, reduce redundancy among science programs. enforcement and the utilization of wildlife resources in the ISR. It will explore how both the Inuvialuit and research has USGS STUDY ON SCIENCE NEEDS TO INFORM DECISIONS benefited from a co -management approach to wildlife ON OUTER CONTINENTAL SHELF ENERGY DEVELOPMENT management IN THE CHUKCH►AND BEAUFORT SEAS Brenda Pierce' and Leslie Holland-Bartelsz 1 U.S. Geological Survey, Energy Resources Program Coordinator 2 U.S. Geological Survey, Regional Executive, Alaska The U. S. Geological Survey (USGS) is conducting an initial evaluation of science needs to understand the resilience of Arctic coastal and marine ecosystems to Outer Continental Shelf resource extraction activities. The study will summarize major information is available, significant knowledge gaps, and what priority research is needed to mitigate risks. The evaluation will look at the work done by many organizations that can help inform energy development decisions in the Arctic. The report will address issues such as the effect of noise on marine mammals; THE NATIONAL ENERGY BOARD'S ARCTIC OFFSHORE DRILLING REVIEW. RESEARCH AND RISKASSESSMENT IN THE CONTEXT OF SAFETYAND ENVIRONMENTAL REGULATION. Robert Steedman National Energy Board On 11 May 2010 the National Energy Board (NEB) announced a review of Arctic safety and environmental offshore drilling requirements (the Arctic Review). The Arctic Review will examine the best available information concerning the hazards, risks and mitigation measures associated with offshore drilling activities in the Canadian Arctic and measures to both prevent and respond to 16 • r� accidents and malfunctions. The review will be conducted in three phases dealing with: Fact-finding and information gathering (Phase 1, now underway); Examination and consideration of facts and Information gathered (Phase 2); and Preparation of a public report (Phase 3). All information submitted during the course of this review will be available on the Board's website (www.neb-one.gc.ca). As of November 2010 approximately 120 participants had registered. The scope of this review will include considerations in four categories: Drilling safely while protecting the environment, Responding effectively when things go wrong, Learnings, Filing requirements. The presentation will include an update on progress of the Arctic Review, with specific reference to opportunities for researchers to become engaged. RESEARCH PRIORITIES AND RESOURCE MANAGEMENT ON ALASKA S NORTH SLOPE. OLD PROBLEMS AND NEW OPPORTUNITIES Bill Streever North Slope Science Initiative's Science and Technical Advisory Panel, and BP Alaska Exploration, Inc., 900 East Benson, Boulevard, Anchorage, Alaska 99502. Senior Executives of federal, state, and regional resource management agencies asked the North Slope Science Safety on Northern Offshore Platforms and EER Issues UNITED STATES OUTER CONTINENTAL SHELF REGULATORY OVERVIEW LT Darin W Qualkenbush (darin.w.qualkenbush@uscg.mil) U.S. Coast Guard, Outer Continental Shelf National Center of Expertise, Morgan City, LA 70380 Discussion of regulatory scheme for Mobile Offshore Drilling Units, Floating Offshore platforms, offshore supply vessels and specialty vessels operating on US outer continental shelf. Industry Panel OFFSHORE ALASKA OIL AND GAS RESEARCH NEEDS; ENVIRONMENT, TECHNOLOGY, AND RESOURCES Pete Slaiby Shell Exploration and Production Company, Anchorage AK As a leading Global oil and gas explorer and operator, Shell has long been at the forefront of scientific research and development technology to operate safely and reliably and to reduce environmental impacts. Our experience in Alaska offshore geophysical exploration and preparation for exploration drilling and our operations in sub -Arctic areas of the world, have underscored that there Initiative's Science and Technical Advisory Panel to develop short issue papers on ecological and environmental topics relevant to management of Alaska's North Slope. Even though these papers were by necessity simplifications, the end result was an unwieldy collection of summaries that did not offer clear advice on the way forward. With that in mind, the Senior Executives asked the Panel to assess relationships between issues and, in part based on the degree to which the issues might impact one another, to suggest priorities for future work. The Panel's suggestions include: Open, transparent, and systematic consideration of the likely range (from "least" to "most") of additional industrial development spanning the next twenty years in a manner that will generate scenarios capable of informing research planning. Development of regional climate scenarios for the next twenty years in a manner that will further inform research planning. A dedicated effort to improve collection of weather and climate data across Alaska's North Slope. A concerted effort to support ongoing communication among researchers, resource managers, and stakeholders, with a "place -based" focus that breaks down institutional barriers and encourages communication across disciplines. The Panel also suggested general research priorities for each of the issues or topics, noting that some of these priorities may change as future development and climate scenarios become clearer. Furthermore, the Panel noted that some issues are sufficiently understood to support management decisions, while others —including aspects of marine mammal science and tundra restoration science —are not. are multiple business drivers for Science These include Permit Stipulations; Support of Engineering/Operational Planning; Compliance with Regulatory; internal Shell sustainable performance requirements; and to mitigate litigation and legal challenges. All of these drivers make it essential to have robust scientific research carried out which is both transparent and independent and involves local communities to the greatest degree possible. The presentation will describe our Science Program for Alaska, including our recently agreed collaborative science agreement with the North Slope Borough and future science needs. Technology deployment and research is a key feature in Arctic development. We are actively developing technologies in our company and in Joint Industry Projects to advance oil 17 spill prevention and oil spill response capability in ice. Our Technology program is aimed at reducing our operating •footprint and impacts, improving the safety of operating in ice and extending our capability to harsher conditions. We also recognize the importance of incorporating traditional knowledge into our technology programs and activities. The presentation will outline our approach to technology development including an overview of our current focus areas and future technology challenges that need to be addressed. The presentation will give real life examples of our successes. ECOLOGICAL RESEARCH IN A MATURE ARCTIC OILFIELD: PRUDHOE BAY, ALASKA Bill Streever BP Alaska Exploration Inc., Anchorage AK Oil and gas exploration and development in the Arctic often leads to ecological study requirements ranging from inventories to impact assessments, but what about research needs in mature arctic oilfields? Experience in the Prudhoe Bay oilfield, which has produced oil for more than three decades, suggests that research needs change over time but do not disappear. Current study needs include long-term ecological monitoring, tundra rehabilitation monitoring and research, and occasional studies to assess potential impacts of satellite developments and other activities, such as 4-D seismic surveys. Examples of ecological monitoring include studies of fish, birds, foxes, permafrost, and vegetation. Examples of rehabilitation monitoring and research include tracking of more than seventy sites and a study designed to develop methods of seeding native sedges. Examples of impact assessment work include an effort to document very low frequency underwater sounds associated with extended reach drilling under the Beaufort Sea. Importantly, in addition to support of the studies themselves, companies managing mature oilfields also have a role facilitating research access by third parties and a role as active participants in the broader ecological and environmental research community, where decades of experience can inform and improve new efforts in the Arctic. Transportation Logistics for Exploration and Development in the Arctic PORT ACCESS ROUTE STUDY FOR THE BERING STRAIT David Seris • U.S. Coast Guard The Port Access Route Study is the initial step toward establishing International Maritime Organization (IMO) Monitoring for Cumulative Effects in the Arctic CUMULATIVE EFFECTS ASSESSMENT FOR THE CANADIAN BEAUFORT SEA Cynthia Pyc North American Arctic Exploration, BP Exploration Company A discussion of current regulatory requirements for cumulative effects assessment associated with offshore Beaufort Sea exploration, and the Beaufort Regional Environmental Assessment effort MONITORING TERRESTRIAL ECOSYSTEMS IN THE NATIONAL PETROLEUM RESERVE - ALASKA FOR EFFECTS FROM OIL AND GAS ACTIVITIES Dave Yokel Bureau of Land Manadement The 9 million hectare (22 million acre) National Petroleum Reserve - Alaska (NPR -A) on Alaska's North Slope was set approved, binding ship traffic routing measures such as Recommended Routes, Traffic Separation Schemes, Areas to be Avoided, etc. The study process involves coordination with Industry, Federal, State, Tribal, Russian Federation and Canadian interests to consider the views of maritime community representatives, environmental groups, native tribes, and other stakeholders. A primary purpose of this coordination is, to the extent practicable, to reconcile the need for safe access routes with other reasonable waterway uses. aside in 1923 for oil and gas exploration and production. The U.S. federal government conducted two exploration programs during 1944-1953 and 1974-1981, and two oil/gas leasing programs in the early 1980s and from 1999 to the present The oil industry followed the lease sales with renewed seismic exploration and exploratory drilling, both during winters. Despite all this, the NPR -A remains largely pristine. The NPR -A is managed by the U.S. Bureau of Land Management (BLM), which has a multiple -use mission including both extraction of non-renewable, subsurface resources and conservation of renewable, surface resources. Following the renewal of lease sales in 1999, the BLM established an advisory panel to provide recommendations on research and monitoring projects related to impacts of oil and gas activities on surface resources and the effectiveness of lease stipulations in mitigating those impacts. The panel's four-year life concluded with an attempt to develop a monitoring plan for the NPR -A. It fell short of this goal, but succeeded in producing a strategy to create monitoring plans for ten issues it felt were most important among surface resources in the NPR -A. Those were caribou, molting geese, fish, subsistence user access, social/cultural systems, cliff -nesting raptors, predator/prey relations, threatened eider species, deflection of migrating bowhead whales, and environmental contaminants. 18 This presentation focuses on the caribou issue to demonstrate a strategy for taking a comprehensive view of •the pathways through which oil and gas activities may impact a resource and how to distinguish the impacts from Ice Engineering for Offshore Operations SEA -ICE PREDICTIONSAND INTEGRATED OBSERVATIONS FOR OFFSHORE OPERATIONS Hajo Eicken (hajo.eicken@gi.alaska.edu) Geophysical Institute & International Arctic Research Center, University of Alaska Fairbanks, Fairbanks, AK 99775-7320, USA, The principal challenges for operations in seasonally ice - covered waters considered in this presentation are (1) to assess and forecast the distribution of different ice types and potential ice -related threats to activities in open water (e.g., vessel traffic, exploration drilling), (2) predict ice loads to inform design of structures, and (3) project changes in the sea -ice and met -ocean regime over the lifetime of such structures. The Beaufort and Chukchi Seas are of particular interest in this context, because of substantial changes in the ice regime over the past decades, including substantial reductions in the areal fraction of multiyear ice, and because of the interplay between seasonal ice retreat and advection of ice into the area. While a combination of satellite remote sensing, ground -based radar and ice forecast models are able to provide good insight into ice drift and distribution on the relevant time scales, assessments of the distribution and thickness of multiyear ice in the summer months is somewhat more challenging. Here, integration of data obtained from the emerging Arctic Ocean Observing Network may be of value. A combination of ice -ocean model output and local -scale assessments of ice movement and action may help develop realistic scenarios for ice loads that can inform structural design. Anticipating ice and met -ocean conditions on timescales of decades over the lifetime of major structures is a challenge, mostly because of the inherent uncertainties in climate model output for the region. Here, a combination of heuristic models based on present-day circulation patterns and information gleaned from local -scale studies referred to above may provide further insights. ICE RELATED ARCTIC PIPELINE DESIGN ISSUES AND RESEARCH NEEDS Michael J. Paulin INTECSEA With the oil industry's continued quest for oil and gas in frontier offshore locations, several developments have taken place in regions characterized by seasonal ice cover • including the US Beaufort, North Caspian, and Sakhalin Island. In these projects, pipeline transportation systems those of other stressors. Knowledge of these factors aids determination of which variables indicating status of the caribou resource would be most relevant for monitoring to support the BLM's mission. have been used, which are a cost-effective, safe and reliable mode of hydrocarbon transport to shore. Ice plays a major role in the design of pipelines for offshore Arctic areas. One of the key design issues is ice keel gouging that affects engineering considerations with respect to strain based design, target burial depth requirements, cost and safety. It is generally accepted that offshore pipelines in ice environments will need to be trenched and backfilled for protection. Burial depth requirements will be a function of the design ice gouge depth (to prevent interaction between the ice and pipe) and an acceptable level of subgouge deformation beneath a gouging ice keel (which strains the pipeline). In this presentation, the author will provide an overview of ice keel related arctic pipeline design issues and research which is required to advance the state-of-the-art. FOUR APPROACHES FOR ADDRESSING ICE FORCES ON OFFSHORE PLATFORMS Dr. Garry Timco (garry.timco@nrc.gc.ca) Cold Regions Technology, Canadian Hydraulics Centre, National Research Council of Canada, Ottawa, Ontario K1A OR6 CANADA. Understating and predicting ice forces is still one of the main challenges facing operations in ice -covered waters. Ice itself is a very complex material that behaves differently depending upon how, and for how long it interacts with an offshore platform. Structural shape and size, ice thickness and morphology, ice type, loading rate, pack ice pressures, etc. all play a role in shaping the loads that the ice will exert on an offshore platform. The question is - how can we try to predict the ice behaviour and the subsequent loads that the ice will exert on any specific offshore platform? Basically four different approaches can be used - physical modelling, numerical modelling, field measurements of ice loads, and data mining of previous measured ice load events. This presentation will briefly describe each technique with examples and highlight the advantages and disadvantages of each technique. 19 • r] • Interaction of Oil and Gas Activities with Sensitive Coastal Habitats THE SIGNIFICANCE OF COASTAL HABITATS TO THE INUVL4LU►T Frank Pokiak Inuvialuit Game Council, Inuvik NT To the Inuvialuit, the coastal environment and the wildlife that inhabits and utilizes it are of great importance. This presentation will begin with a look at the important role that the coastal environment plays in the Inuvialuit culture. The Inuvialuit depend on fish, whales, birds, seals and polar bears that live and migrate along the Beaufort Sea. The coast also is a place of cultural significance for the Inuvialuit with many historic sites still found along the coast The presentation will also provide an overview of planned and current oil and gas research and monitoring from an Inuvialuit perspective. The third part of this presentation will look at the roles of communities in the ISR in oil and gas activities and related research. The Inuvialuit co -management system provides the Inuvialuit a system to be equal and meaningful partners in resource management from the individual level up to the international level. Communities have voiced concerns over the effects of oil spills and the effects of mitigation techniques, such as the use of dispersants. There is also a lack of capacity and support for the communities that are expected to be the first responders in the event of an oil spill. EVALUATING SOURCE WATERS FOR ICE ROAD PLANNING Bill Schnabel Water and Environmental Research Center, University of Alaska Fairbanks, Fairbanks AK Ice roads represent a critical component of oil and gas exploration activities on Alaska's North Slope. Ice road construction requires access to surface water, however, and surface water is a limited resource in many parts of the North Slope. Moreover, unchecked depletion of surface water can damage sensitive arctic ecosystems. In order to optimize the water available for ice road withdrawals as well as protect arctic ecosystems, we need to understand not only where and when is the water available, but also what are the ecological ramifications of using it This presentation summarizes a series of projects undertaken by WERC and their collaborating partners to monitor and model the impacts to dissolved oxygen of winter water withdrawal; to evaluate lake depth and late -season water availability using Synthetic Aperture Radar; and to communicate results and planning tools via an online Decision Support System. DISTINGUISHING BETWEEN NATURAL VARIABILITYAND HYDROCARBON EXTRACTION EFFECTS ON THE BIOPHYSICAL ENVIRONMENT OF THE BEAUFORT SEA COASTAL ZONE Steven Solomon Marine Environmental Geosciences, Natural Resources Canada, Dartmouth NS The Arctic coastal zone is an inherently unstable environment where energy from sun, wind, ice and water combine to cause flooding, erosion, land surface deformation and sediment movement This is especially apparent in the western Canadian Arctic and the adjacent US North Slope, where coastal sediments are generally fine-grained and unconsolidated and the coastal plain is often flat and low- lying. In these locations, rapid change under natural conditions is the norm and in many cases, those changes result from infrequent, but severe events. Examples of rapid change include erosion rates of 10s of in per year (sometimes as a result of a single event), and storm surge flooding over hundreds of square kilometres. Differentiating between natural environmental changes and those induced by industrial development is a challenging task. Monitoring of key variables can reduce the degree of scientific uncertainty regarding attribution of impacts from development This approach depends on the development of a baseline, departures from which are considered to be outside of the natural range. This is complicated by uncertainty regarding the length of time necessary to establish the baseline and the fact that the baseline itself may be changing (i.e. is actually superimposed on a trend such as the case of rising sea level or thickening active layer). In light of these uncertainties, a comprehensive understanding of the processes that control the changes in question is a pre -requisite for differentiating between those that are natural and those that are induced by development However, the complexity of coastal processes means that we will not be able to reduce uncertainties to zero and scientific information will ultimately remain indicative rather than deterministic. 20 • Oil Spill Prevention in the Arctic SPILL PREVENTION AND RESPONSE IN ALASKA S ARCTIC WATERS Larry Iwamoto State of Alaska, Department of Environmental Conservation, Spill Prevention and Response Division The spill prevention and response planning process in Alaska's Arctic waters is an area of continual focus for federal, state, local, tribal, and non -governmental entities. In the wake of the Deepwater Horizon spill, the Outer Continental Shelf lease sales for the Beaufort and Chukchi Seas, and the federal moratorium on offshore drilling, both government and industry contingency plans have received additional scrutiny. In the State of Alaska, the federal and state regulators (e.g., Coast Guard, EPA, and the Alaska Department of Environmental Conservation) previously implemented a joint planning process to satisfy both federal regulatory and state statutory requirements. The resultant products are the Federal/State Unified Plan and ten region - specific subarea contingency plans. These plans provide the basis for responding to an oil or hazardous substance release by identifying tactics and strategies, environmentally sensitive areas, and available resources. The industry oil discharge prevention and •contingency plans also include measures for preventing major oil spills. Although the proposed OCS exploration and production will occur beyond the State of Alaska's jurisdictional boundaries (e.g., three miles offshore), State agencies play an active role in reviewing and commenting on contingency plans and related documents to ensure the State's interests and concerns are properly addressed. The challenges for launching a major spill response in Alaska's Arctic waters are daunting. There are seasonal considerations and limitations posed by ice conditions. Logistical support to oil spills in remote locations is also a major concern, given the vast Arctic expanse and limited support infrastructure along the Arctic coastline. Several spill response planning initiatives are underway for the Arctic waters including updates to the subarea plans, development of geographic response strategies, identification of potential places of refuge for disabled Oil Spill Management in the Arctic ALASKA CLEAN SEAS - OIL SPILL REMOVAL ORGANIZATION WITH A LONG HISTORY IN R & D Ron Morris Alaska Clean Seas Alaska Clean Seas has maintained an active oil spill research • and development program since the early 1980's and acts as a facilitator for much of the research and development related to spill response in arctic conditions. The R & D program focuses on specific areas such as oil spill recovery vessels, increased coordination between the Canadian Coast Guard and U.S. Coast Guard (.e.g., CANUS North), an Arctic Natural Resource Damage Assessment work group, plus other initiatives. NEW REGULATORY REQUIREMENTS AS A RESULT OF THE PRESIDENTIAL COMMISSIONED SAFETY MEASURES REPORT Kyle Monkelien Bureau of Ocean Energy Management, Regulation and Enforcement As a result of the Safety Measures Report developed at the request of the President the Bureau of Ocean Energy Management, Regulation and Enforcement, developed a set of regulations to implement certain safety measures recommended by that report While these new regulations did not specifically address all aspects of the report it did cover what the report had determined to be appropriately addressed through an emergency rule making process. This presentation will provide a summary of these measures and how the BOEMRE plans to implement them in the near term LIMITING THE FLOW- A PRAGMATIC APPROACH TO OIL SPILL CONTAINMENT Bill Scott Chevron The presentation will discuss the impacts of the Macondo incident in the US and the Same Season Relief Well (SSRW) debate in Canada on approaches to future arctic oil and gas exploration & development operations. The issue will be examined from a late season blow-out perspective in a pack ice operating environment and will include discussion of the following key issues: People, Procedures and Training; Well Design; Enhanced Blowout Preventer (BOP) Capability; Well Capping Capability; Late Season Oil Spill Containment techniques in, on, and under ice and during various broken ice conditions. Other areas of research include viscous oil pumping, methods to detect and track oil under ice, and alternative response options. This presentation will highlight some of the R & D efforts and how we have integrated that work into the tactics available for response. 21 • • OIL SPILL MANAGEMENT; BIOLOGICAL CONSIDERATIONS Jeep Rice National Oceanic and Atmospheric Administration While the physical stopping of a spill and the clean-up are the first priorities in managing a spill event, there are biological considerations. NOAA has multiple interests regarding oil development and spills; ranging from commenting on leases to damage assessment and restoration after a spill event We never have all the information we desire, but for the Arctic, our information base is considerably less than other areas, such as Exxon Valdez or Deepwater Horizon events. For the Arctic, we often know a "list" of the species involved, certainly the major players, but we generally lack population dynamic information over a time period and we often lack a detailed understanding of the ecosystem, energy dynamics, or for example, the significance of late springs on populations. Predicting the consequences of development, climate change, oil exposure events or treatment alternatives is problematic for most populations; likewise, evaluating different restoration and mitigation strategies is also difficult without adequate information. Jury is out regarding long term effects to fish in the Deepwater Horizon spill, but Exxon Valdez event resulted in long term persistence of oil and long term effects for several years to nearshore fish. The absence of biological and chemical baselines will make it difficult to define the restoration goals following an event 22 L-] C] ABSTRACTS - TOPICAL SESSIONS Environmental Conditions in Exploration Areas ASSESSING THE EFFECTS OF SEISMIC EXPLORATION ACTIVITIES ON BOWHEAD WHALE CALL DISTRIBUTION IN THEALASKAN BEAUFORT SEA; 3-YEAR SUMMARY Susanna B. Blackwell (susanna@greeneridge.com)', C.S. Nations2, T.L. McDonald2, A. Thode3, K.H. Kim', C.R. Greene', Jr., M. Guerra3, D. Mathias3 and A.M. Macrander4 ' Greeneridge Sciences Inc., 6050C Wallace Becknell Road, Santa Barbara, CA 93117, USA, 2 WEST Inc. 3 Scripps Institution of Oceanography 4Shell Exploration and Production Company The bowhead whale (Balaena mysticetus) is central to the culture of Alaska natives and an important food source for them. In addition, its threatened status guarantees additional protection by the U.S. government. Therefore, understanding the effects of oil and gas exploration on bowhead whales is a key part of a sound development plan for oil companies in Alaska. In 2007, 2008, and 2009, 35-40 directional autonomous seafloor acoustic recorders (DASARs) were deployed at five sites spanning -280 km of the autumn migration corridor of bowheads to study the effects of seismic exploration on the locations of calling whales. Continuous recordings were obtained from mid - August to early October annually. Over the three seasons, >713,000 calls were localized by triangulation, and >250,000 airgun pulses were detected and analyzed. The study area was divided into a hexagonal grid (hexagon width -1.75 km). Received sound pressure levels (SPL) and cumulative sound exposure levels (SEL) of airgun sounds were modeled for each hexagon in the study area during 15-min periods over the season, using information on the timing and location of airgun activities, the size of the airgun array, and other covariates. Logistic regression modeled the occurrence of whale calls as a function of received levels and other covariates. The purpose of the logistic regression was to estimate the threshold of received level at which call distribution changes are detectable. Received SEL of airgun pulses in the range 115-125 dB re 1 uPa2 • s (over 15 minutes) resulted in a drop in bowhead call detection rates. SEL in this range could result from a single high amplitude pulse or many weaker pulses. Knowledge of such behavioural thresholds will aid in studying cumulative effects of industrial activities on migrating whales. (Work supported by Shell Exploration and Production Company.) THE CHUKCHI SEA ENVIRONMENTAL STUDIES PROGRAM. - AN OVERVIEW Robert H. Day (bday@abrinc.com)', Caryn L. Rea2, and Michael Macander3 and Sheyna S. Wisdom¢ 1 ABR, Inc. Environmental Research & Services P.O. Box 80410 Fairbanks, AK 99708-0410 2 ConocoPhillips Company Alaska, Inc., P.O. Box 100360, Anchorage, AK 99510-0360 USA 3 Shell Exploration & Production Company, 3601 C Street, Suite 1334, Anchorage, AK 99503 USA 4 Fairweather LLC, 9525 King Street, Anchorage, AK 99515 In 2008, we began a multi -year, inter disciplinary ecological study (CSESP) in the vicinity of two proposed exploration oil and gas prospects in the northeastern Chukchi Sea. This study was designed to collect information on the ecosystem prior to exploration to fill data gaps in this area and to provide baseline environmental data that can be used for permit applications and for post -development comparisons. CSESP focuses on intensive studies conducted within two nearby study -area boxes (Klondike and Burger) that are 3000 NM (-55x55 km) in size, -40 NM (-70 km) apart, and located -60-90 NM (-100-160 km) offshore from the coast of northwestern Alaska. The integrated studies consisted of the following nine components: physical oceanography; nutrients, primary productivity, and zooplankton ecology; benthic ecology; fisheries oceanography (2009 only); seabird ecology; marine - mammal ecology; marine -mammal hydroacoustics; and baseline chemistry (primarily 2008). We sampled the two study areas primarily during three research cruises that matched seasons within this arctic area: late summer, early fall, and late fall. We also deployed oceanographic and hydroacoustic moorings before and after these three cruises, during the open -water period, and deployed some over the winter. We describe the study background and study design to provide an overview for the various presentations on this study. AN INTEGRATED CHEMICAL AND BIOLOGICAL STUDY OF THE BENTHOS OF THE CHUKCHI SEA: PRELIMINARY RESULTS FROM THE COMIDA-CAB PROGRAM Ken Dunton (ken.dunton@mail.utexas.edu)', Jackie Grebmeier2, H. Rodger Harvey2, Brenda Konar3, David R. Maidment', Susan Schonberg', and John H. Trefry4, Lee Cooper2 1 Marine Science Institute The University of Texas at Austin 750 Channel View Drive Port Aransas, TX 78373 2 Chesapeake Biological Lab, University of Maryland Center for Environmental Science, (UMCES) 3 University of Alaska Fairbanks 4 Florida Institute of Technology The Chukchi Sea Offshore Monitoring in Drilling Area, Chemistry and Benthos (COMIDA-CAB) Project is a comprehensive program funded by the Bureau of Ocean Energy Management (BOEMRE) that is designed to establish 23 an integrated knowledge of this biologically diverse •ecosystem. This component addresses the benthic system with a particular emphasis on sediment chemical characteristics and the benthic biota. Much of our work was focused in Lease Sale 193 in the northeastern Chukchi Sea, which generated 2.6 billion in bids in 2008. Our objectives for the 2009/2010 summer field seasons were (1) to establish baseline data set for benthic infauna and epifauna, organic carbon and sediment grain size, radioisotopes for down core dating, as well as measure trace metals in sediments, biota and suspended particles, and (2) to determine the sources, cycles and fate of carbon, selected trace metals and the role of trace metals on organic carbon dynamics and food web dynamics on the inner shelf of the Chukchi Sea. Sampling efforts in both years generated immense amounts of data and samples for chemical and biological analysis from over 70 stations that will be used for both contemporary and retrospective evaluation of the region. Preliminary results reveal that sediments contained low or background values for metals and aliphatic hydrocarbons and that the northern whelk, Neptunea heros, is a potentially valuable indicator for metals and organic contaminants. Our field efforts included the deployment of a submersible video system to survey a wide variety of epibenthic communities. Our observations reveal that the northeastern Chukchi Sea is a productive but highly complex system that is characterized by significant spatial heterogeneity in both benthic infaunal and epifaunal populations. It forms an invaluable database of information of the seabed in the Sale 193 area that will be of significant • value for both science and industry. COLLABORATIVE RESEARCH TO CHARACTERIZE BIOLOGICAL, PHYSICAL AND GEOTECHNICAL CONDITIONS IN SUPPORT OF BEAUFORT SEA DRILLING OPERATIONS James A. Hall (james.hall@exxonmobil.com)', Cynthia D. Pyc2, Michael J. Curtin2, James R Hawkins' 'imperial Oil Resources Ventures Limited, 237 Fourth Street, Calgary, AB, T2P 3M9, Canada. 2BP In July 2010, Imperial Oil Resources Ventures Limited (Imperial), ExxonMobil Canada Ltd. and BP Exploration Operating Company Limited signed a joint operating agreement covering Exploration Licenses 446 and 449 with Imperial as the operator of the joint venture QV) project The exploration licenses are in water depths of 90m to 1200m and include shelf, shelf -break and deeper water environments. In support of drilling operations, multi- disciplinary, multi -year, collaborative field programs were designed and implemented with significant Inuvialuit participation to characterize the baseline conditions of the project area. These 2008 to 2010 field programs included multiple vessel based and aerial platforms and drew heavily on academic and government expertise and traditional knowledge (TK) in the north. In the summer and fall of 2009 and 2010, the JV partners collaborated with ArcticNet • onboard the CCGS Amundsen to collect biological, physical and geological baseline information in the license areas. In 2009, a collaboration with Fisheries and Oceans Canada (DFO) onboard the Nahidik conducted similar studies in the shallow water environment of the Canadian Beaufort coastline including the potential shorebase of Tuktoyatuk Harbour. In 2008-2010, the JV partners collaborated with Cornell University to characterize bowhead and beluga whale distribution in the vicinity of the project These vessel based studies were complemented by regional aerial surveys of marine mammals in 2008-2010 conducted both in collaboration with DFO and independently by the JV partners, and by a pilot aerial survey program in the winter of 2009 to test the efficacy of fixed wing offshore polar bear surveys. Baseline information was also collected via a subsistence harvesting study in Tuktoyaktuk harbor in 2009 and via a TK study with the six Inuvialuit Settlement Region communities in 2010. Finally, ice drift studies were conducted in 2009 and 2010 to support oil spill modeling efforts and support US Canada trans -boundary spill response planning. The 2008-2010 field programs were extremely successful and have built a strong foundation for future drilling operations. Past and future programs will contribute significantly to ensuring environmentally responsible operation of any future exploration drilling program in the Canadian Beaufort Sea. HYDROLOGY OF THE OUTER MACKENZIE DELTA IN THE VICINITY OF PROPOSED NATURAL GAS DEVELOPMENT Philip Marsh (philip.marsh@ec.gc.ca)', Don Forbes2, Steve Solomon, Stefano Endrizzi3 1 National Hydrology Research Centre Environment Canada 11 Innovation Blvd. Saskatoon, SK S7N 3H5 Canada 2 Natural Resources Canada, Bedford Institute of Oceanography, Halifax, NS, Canada 3 University of Zurich, Zurich, Switzerland The proposed Mackenzie Gas Project (MGP) will carry natural gas southward from two gas fields in the Kendall Is. Bird Sanctuary (KIBS) located in the low-lying (<1 in elevation) outer Mackenzie Delta. Gas extraction induced subsidence at these two anchor fields, in combination with natural subsidence and a changing climate, will likely result in changes to the hydrology of the KIBS and to bird habitat Recent hydrologic observations, in conjunction with high resolution digital elevation models derived from Lidar and semi-annual GPS measurements (see Forbes et al. submitted to this meeting) have provided sufficient data to consider various aspects of the hydrology of KIBS, including frequency of flooding due to spring breakup of the channels of the Mackenzie River, summer floods from the Mackenzie River, and storm surges; spatial variability in flooding; and the hydrology of lakes in KIBS. These data provide the basic information needed to consider future increases in flooding due to induced subsidence. However, in order to better quantify future changes, there is an ongoing need to understand factors controlling spatial variability in flooding and to consider other natural, and anthropogenic, factors that will also impact flood frequency, duration, and timing in the coming decades (see paper by Forbes et al. to this meeting). Another impact of induced subsidence will be to affect the extent and duration of standing water, soil moisture, evaporation, and runoff to key lakes in KIBS. 24 Potential impacts of this will be considered through the use •of a high resolution hydrologic model to consider the impact of induced subsidence on runoff to key lakes in KIBS. UPDATED CHARACTERIZATION OF PERMAFROST THERMAL CONDITIONS IN THE MACKENZIE DELTA REGION Sharon Smith (Sharon.Smith@nrcan-rncan.gc.ca)1 1 Geological Survey of Canada, Natural Resources Canada, 601 Booth St, Ottawa, Ontario, K1A 0E8 GSC Permafrost is an important component of the landscape of the Mackenzie Delta region and has an important influence on ecosystems and resource development. Permafrost and its associated ground ice can influence drainage and terrain stability and can present challenges to the design of production and transportation facilities associated with oil and gas development. Updated and reliable information on permafrost thermal state is critical for engineering design, environmental assessment and sound environmental management of resource development projects. With support from the Northern Energy Development Initiative, the Geological Survey of Canada in collaboration with Indian and Northern Affairs Canada undertook a major field program to address gaps in our knowledge of ground • Safety on Northern Offshore Platforms and EER Issues SEASONAL STRATEGIES FOR EVACUATION FROM OFFSHORE STRUCTURES IN THE BEAUFORT SEA Anne Barker (anne.barker@nrc-cnrc.gc.ca)1 and Garry Timcol 1 National Research Council of Canada - Canadian Hydraulics Centre M-32, 1200 Montreal Road, Ottawa, ON K1A 0116 Canada This presentation will discuss results from an integrated research project, carried out over many years, that examined a variety of evacuation strategies for offshore structures in the Beaufort Sea. The objective of the projects was to address the safety of offshore personnel working in Canada's Arctic environment by examining the issues surrounding emergency evacuation from an offshore structure under the diverse range of conditions in the Beaufort Sea. This was accomplished through: quantification of the ability of individuals to cross ice of a varying degree of severity by foot; the development of decision flow -charts for the establishment of on ice evacuation shelters and their associated costs and logistics; an examination of ice management options when ice rubble is present around an offshore structure; and an examination of generic means of • evacuation and their adequacy for four "seasons" of evacuation: open water, moving pack ice, quasi -stable rubble and stable rubble/landfast ice. The project results will provide 1) information related to the viability of systems for a range of realistic ice conditions, especially those involving thermal conditions in the Mackenzie Delta region. These efforts resulted in the establishment of about 25 new instrumented boreholes up to 20 m deep. New information has been generated on ground thermal conditions for areas where little recent information was available. The new field data along with data collected from existing long-term monitoring sites have led to a more complete characterization of current baseline permafrost conditions in the Mackenzie Delta region. Collaboration with US colleagues has enabled the development of a new map and database presenting a current snapshot of permafrost thermal state for northwestern Canada and Alaska. Key publicly available databases have been generated from the project, disseminating information on permafrost temperatures and active layer conditions for use by industry, regulators, land managers and local communities. The information generated and the enhanced permafrost monitoring network in the region have contributed to improved understanding of the regional environmental framework, provide a baseline to support cumulative impact assessment and are key components of future environmental monitoring and management programs associated with resource development projects. ice rubble, 2) provide input into the development of the evacuation and rescue options and strategies for Beaufort Sea structures and 3) be used by Operators and Regulators to examine the feasibility of proposed evacuation systems for the Beaufort Sea. ARCTIC EMERGENCY EVACUATION AND RESCUE. PRESENT AND FUTURE Frank G. Berchal 1 Bercha Group, P.O. Box 61105 Kensington P.O., Calgary, AB, T2N 4S6 The paper presents a historical, current, and developing the state of art review of EER for arctic offshore installations. Technologies, engineering and analysis, and regulatory provisions relating to arctic EER operational today and under development are reviewed. Current national and international regulatory performance based regime has necessitated the development of tools for the evaluation and setting of performance based goals such as availability and reliability requirements, mirrored in current Transport Canada and ISO standards. To facilitate setting of reliability targets in the Canadian standards, as well as to assist in assessing reliability expectations of arctic installation EER, a multifaceted research and development program was initiated in parallel with regulatory developments. Some of the full scale manned and model tests, engineering and computer simulation, and world wide consultations and 25 •studies on human performance in life threatening conditions are described. Concurrently, industry and the private sector have addressed the frontier and arctic EER needs through analyses, development of novel systems, and participation in developing performance based standards. Use of conventional EER systems and technologies was found to have limited applicability in ice populated waters, requiring the development of systems and procedures suited to the environmental, operational, and logistical requirements of arctic offshore regions. The paper summarizes available and emerging regulatory, modeling and research, and non- proprietary technological developments in arctic EER and gives recommendations on a number of promising systems and developments, as well as an estimate of the reliability of currently available arctic EER provisions. ICE FORECASTING FOR OFFSHORE OPERATIONS Chris Hill', Doug Hagen', Dave McGonigal', Dr. Roger Pilkington' 'CANATEC Associates International Ltd. Alastair Ross Technology Centre Suite 122, 3553 - 31st Street N.W. Calgary, Alberta, Canada T21, 2K7 Forewarning of near -term - from 6 to 72 hours in advance - movements of area and regional ice are regularly sought by offshore operators for purposes of: 1. Avoiding damage to assets due to ice collision, 2. Maximizing productive operating time, 3. Positioning vessels for potential evacuation of drilling and production units. 4. Evacuation of on -ice installations. Forecasting systems include a simple empirical wind model, an empirical model with wind, current, and tidal inputs, and a warning system based on remote environmental changes. A key element of an effective ice forecast system is an historical record of the timing and effect of episodic local events. Such events may cause significant changes in the ice conditions, and the rapid occurrence of hazardous ice at the location of interest Local environments in which operational ice forecasts have been formulated and which figure in this presentation are: 1. Sakhalin Island marginal ice zone, 2. Beaufort Sea residual seasonal ice, 3. Multi -year pack ice near the North Pole, 4. Landfast ice surrounding an artificial island installation. Tidal currents are the dominant factor in moving ice along the Sakhalin coast but are absent in the Beaufort Sea and high Polar areas. The empirical model allows input of pre - calculated tidal currents based on antecedent measurements of local current The Beaufort zone has significant non -tidal currents due to Mackenzie River outflow, winds, and atmospheric pressure differences. The empirical model was effective in this region since non -tidal currents persisted over many hours. An empirical wind model, with no non - tidal current element, was more effective in forecasting ice drift in the North Pole area. In fast ice movement forecasting, water level change is the critical parameter, but is associated with oceanographic phenomena further removed from the area of interest Transportation Logistics for Exploration and Development in the Arctic ARIABILITY OFACTIVE-LA YER FREEZEBACKIN THE layer freezeback, and soil strength among four common OUTER MACKENZIE DELTA, NORTHWEST TERRITORIES terrain types of the outer Mackenzie Delta in the early winter. Results will contribute to the development of Julian C.N. Kanigan (Julian.kanigan@inac-ainc.gc.ca)', Steve appropriate practices to minimize terrain disturbance KokeljZ, and Ron Coutts3 associated with winter overland travel. Two years of data 'Land Administration, Indian and Northern Affairs Canada, Yellowknife NT ' Water Resources Division, Indian and Northern Affairs Canada, , Yellowknife, NT 3Ardent Innovation, Calgary AB In the resource -rich Mackenzie Delta region, winter overland access to remote seismic or drilling locations is often required. The impacts of historic overland travel have persisted for many decades causing regulators to seek ways to minimize future environmental impacts. Vehicle travel in early winter over terrain that is unfrozen or lacking sufficient snow cover can cause surface erosion, active -layer deepening, and surface subsidence in areas of ice -rich permafrost These disturbances can lead to increased soil • moisture and long-term vegetation change. The purpose of this research is to determine the variability of snow, active - have been collected in each of the four terrain types to characterize the natural variability of the ground thermal regime, soil moisture content, snow accumulation, soil strength, and vegetation community composition. Site conditions and freezeback dates vary significantly between the terrain units. A calibrated ground thermal model was used to investigate the effects of changing environmental conditions on ground temperatures in each of the terrain units, including the timing of snow arrival and air temperatures. Results suggest that the timing of overland travel in early winter should account for the variability of environmental conditions between the terrain units. W. IF ARCTIC RESEARCH TO IMPROVE NAVIGATION IN THE ARCTIC Nana Kubat (ivana.kubat@nrc-cnrc.gc.ca)', Garry Timcol, and Michelle Johnston' 1 NRC - Canadian Hydraulics Centre 1200 Montreal Rd, Bldg M-32 Ottawa, Ont. K1A OR6 Canada Experienced Captains in Arctic shipping were interviewed as part of the "Scoping Study: Ice Information Requirements for Marine Transportation of Natural Gas from the High Arctic" (Timco et al., 2005). The survey overwhelmingly showed that multi -year (MY) ice and pressured ice are the key factors posing hazards to navigation, causing vessel damage, and affecting offshore operations in the Arctic. The Captains indicated that detection of MY ice should be the key research area and that more information on pressured ice regions is needed. Over the past 15 years, the Canadian Hydraulics Centre of the National Research Council of Canada (NRC-CHC) have carried out a number of research projects to address issues dealing with shipping and ice conditions in Canadian Arctic. The overall objective of these projects was to ensure safe and efficient shipping operations in the Arctic. This presentation will discuss results from three projects that focused on (1) Canadian Arctic Regulatory shipping system, (2) multiyear ice as hazards to navigation, and (3) prediction of pressured ice zones. It will Isdiscuss the proposed changes to shipping regulations and present new tools which will enhance efficiency and capability of ships to navigate through ice and diminish the risk of environmental pollution due to oil spills. These will have implications on the Arctic activities of the oil and gas industry. With increased demand for oil and gas, a large increase in vessel traffic in Canada's Arctic is expected in the near future. Drilling operations, LNG tankers, marine supply, support vessels and evacuation vessels, would be affected by ice conditions unique to the Canadian Arctic. Results of the research projects presented here will provide mariners with tools to allow safer, cost efficient, and environmentally responsible offshore operations. ALASKA NORTH SLOPE OIL AND GAS TRANSPORTATION SUPPORT SYSTEMS. TAKING ALASKA FORWARD INTO NEW DEVELOPMENT Michael R. Lilly (mlilly@gwscientific.com)', Horacio Toniol02, Vlad Romanovsky22, Jessica Cherry2, Yuri Shure, Matthew Bray2, Chien-Lu Pin 2, Gary Michaelson 2, Ron Paetzold', Jeffrey Derry', Gerald Sehlke3 'Watersheds Scientific, PO Box 81538, Fairbanks, Alaska, 99708, Tel: 907-479-8891, Fax: 907-479-8893, 2University of Alaska Fairbanks 3Idaho National Laboratory North Slope, Alaska, oil and gas development has depended on Arctic transportation systems for the life of existing fields. Approaches to build, manage and regulate ice and snow roads were developed in flat coastal terrains, which had a high concentration of natural lakes and some man-made reservoirs. This development occurred from the early development of Prudhoe Bay and Kuparuk fields to current field operations. Development of seasonal ice roads is reliant on adequate snow cover and freezing -soil conditions to protect the fragile tundra landscape. Adequate water sources are also needed to build and maintain ice road networks. Current development is expanding into new regions in the foothills of the Books Range. These new areas of development bring in new challenges with rougher terrain, different lake types and lower lake densities, and different snow conditions. There is also an increase in the number of companies doing exploration and relying on ice and snow roads. Our research project is taking an integrated approach to looking at these multidisciplinary aspects of developing, managing, and regulating Arctic Transportation systems. Improving the efficiency of these systems is important to both address the needs of increasing energy demands and maintaining fragile ecosystems in the Arctic. Our project introduced data standards related to snow and hydrologic observation, and developed simple forecast tools for lake ice formation, soil temperatures, and the application of basic watershed modeling. Future development efforts will contribute to the understanding of blowing snow models running in conjunction with weather forecast models, soil -strength studies to evaluate the potential for different guidelines related to traffic loads on ice and snow roads, and adaptive water management for winter water use in lakes and reservoirs. Current applications of these tools will be presented, which are being achieved with cooperative programs with industry and state and federal agencies. THE APPLICATION OF SEISMIC SHOTHOLE DRILLERS' LOG RECORDS TO THE UNDERSTANDING OF PERMAFROST, GROUND ICE, BOTTOMFAST ICE, AND GRANULAR AGGREGATE RESOURCES IN THE MACKENZIE - BEAUFORT REGION. I. Rod Smith (rodsmith@nrcan.gc.ca)' ' Natural Resources Canada, Geological Survey of Canada 3303 - 33 St NW Calgary, AB T21, 2A7 This research discusses the recent database compilation of >275,000 seismic shothole drillers' log records from northern Yukon and the Northwest Territories. These previously, largely unused records have provided a wealth of baseline, near -surface (10-60 m) geoscience information that has enabled the publication of several new and original GIS-based geoscience interpretations and models. Characteristics of permafrost and distribution of massive ice and ground ice is often understood in detail at monitoring stations, but may be poorly constrained on regional bases. While the seismic shotholes are generally too shallow to constrain permafrost depths in the Mackenzie - Beaufort region, they do record 100s of instances of sub -surface unfrozen sediments. These records reflect both hazards to development, and highlight aspects of channel migration and 27 • lake drainage that is of key concern to infrastructure planning and design. The shothole database also has 2111 records of massive ice, and 11,666 records of ground ice, providing far greater understanding of their distribution and character than presently exists. Bottomfast ice formation in near -shore marine areas also represents a significant hazard to pipelines and related infrastructure. There are 12,069 shothole records that constrain bottomfast and floating ice extents and provide a temporal record of conditions that largely predates satellite -based observations. Identification and delineation of granular aggregate resources is one of the key development constraints in the arctic. The shothole records are ideally suited to identifying new potential resources owing to the drillers' propensity for recording gravel and other granular aggregates. Also, in Monitoring for Cumulative Effects in the Arctic A NEW TOOL FOR IDENTIFYING SENSITIVE AREAS AND THE RELATIVE ENVIRONMENTAL RISK OF HYDROCARBONS ACTIVITIES IN THE CANADIANARCTIC Doug Mason (doug.mason@stantec.com)1, Giles Morre112 and Tom Duncanz 1 Douglas Mason Nunami Stantec 4370 Dominion Street 5th Floor Burnaby BC V5G 4L7 inz Indian and Northern Affairs Canada The Petroleum and Environmental Management Tool (PEMT) is an Internet -based mapping tool for regions of the Canadian Arctic. Under development by Indian and Northern Affairs Canada, the tool presents expert judgments on relative environmental sensitivities for selected valued ecosystem components based on syntheses of published information. It is intended as a first order decision support tool to help government, oil and gas companies, Aboriginal groups, resource managers and the public visualize the geography of sensitive areas in the Arctic and their potential interaction with oil and gas activities. It provides a basis for more extensive conversations with Aboriginal groups and other expert authorities to correct and refine the depiction of sensitivities. This presentation will introduce the tool and options to develop the PEMT beyond its current focus on relative environmental sensitivity. The extension under consideration would provide a view of the relative environmental risk associated with oil and gas activities and give some early indication of the potential for cumulative effects. The perception of risk is based on two factors: the scale of the effect of the proposed activity and the sensitivity of the area where it will occur. This approach would not replace the need for proponents of activities to carry out an environmental assessment based on project specific considerations but, if successful, would provide an initial •indication of relative environmental risk that could help inform decision making processes in early stages of areas characterized by extensive bog and muskeg, the drillers' logs can serendipitously identify surface and subsurface deposits that otherwise have no geomorphic expression. Application of this research to the Alaskan North Slope and Beaufort coast is considered of high potential to resolve similar issues of terrain hazards and environmental constraints to oil and gas exploration and development. engagement. Challenges and opportunities will be highlighted in the discussion. MODELLING HABITAT OF DOLLY VARDEN (SALVELINUS MALMA) IN THE WESTERN CANADIAN ARCTIC IN SUPPORT OF ECOSYSTEM -BASED MANAGEMENT Neil J. Mochnacz (neil.mochnacz@dfo-mpo.gc.ca)1, H. Ghamry, E.C. Enders, and J.D. Reist 1 Fisheries and Oceans Canada, 501 University Crescent, Winnipeg, Manitoba, R3T 2N6 Dolly Varden (Salvelinus malma) is a char native to western North America that is harvested by northern communities for subsistence purposes. Populations occur in eight river systems found across the Canadian Western Arctic and several of these have experienced significant declines. As a result, local communities, co -management boards, and government agencies agreed to implement conservative harvest quotas, which included fishing closures in some areas. Several stakeholders believe that changes to habitat, specifically low water levels over successive years, are partially responsible for declining stocks. Winter habitat, which is critical for survival of this species in northern environments, is spatially limiting as it is restricted to several small areas in headwater sections of freshwater streams. Spawning and winter habitats typically overlap and both are associated with perennial groundwater sources. We surveyed two spawning and overwintering reaches from Fish Hole Creek, a tributary to the Babbage River, and Little Fish Creek, a tributary to the Big Fish River. Depth, velocity, substrate, and cover were measured at positions in the stream where fish were observed and also at spawning redds. A two-dimensional hydrodynamic fish habitat model (River2D:www.river2d.ca) was developed and used to estimate minimum discharge thresholds for spawning and winter habitats. These discharges can be used as a guideline to help stakeholders manage Dolly Varden stocks more effectively by monitoring water levels in these rivers 28 �J 0 annually. Developing a metric which can be used to monitor limiting habitat for this culturally important fish, is an integral component of ecosystem -based management. TRADITIONAL KNOWLEDGE AND SCIENTIFIC INFORMATION ABOUT THE SENSITIVITY OF BOWHEAD WHALES (BALAENA MYSTICETIIS) TO ANTHROPOGENIC SOUNDS Robert Suydam (Robert.Suydam@north-slope.org)' and John Craig George' 1 North Slope Borough Department of Wildlife Management Box 69, Barrow, AK 99723 Bowhead whales (Balaena mysticetus) are an important component of northern marine ecosystems and are a vital subsistence resource to many communities, especially those adjacent to the Beaufort and Chukchi seas. For millennia, whales have been hunted by Inuit Hunters learned that bowheads were sensitive to anthropogenic sounds and passed that information to succeeding generations. In some cases, villagers even several kilometers from hunting areas were required to whisper and were restricted from making loud sounds. As oil and gas activities increased in the Beaufort and Chukchi seas, hunters expressed concerns that sounds from seismic airgun arrays, drilling, production, and ship traffic would displace bowheads from feeding and resting areas, migratory routes, and areas where whales were hunted. They reported that whales were deflected away from industrial activities at a distance of 30 to 40 km, while the initial scientific results suggested reactions at much closer distances. As scientific observations increased, it became evident that bowheads were quite sensitive to anthropogenic sounds, but that the sensitivity was dependent on the whales' behavior. During drilling, bowheads avoided waters 15 to 25 km from the rig (LGL and Greeneridge 1987; Hall et al.1994; Davies 1997). In the central Beaufort Sea, seismic surveys excluded bowheads from a 15-20 km radius around the source vessel with deflection beginning at greater distances (LGL et al 1999). Ship sounds also deflected bowheads from migratory routes, Ice Engineering for Offshore Operations ICE THICKNESS INFORMATION FOR SAFE AND ENVIRONMENTALLY RESPONSIBLE OFFSHORE OPERATIONS Christian Haas (Christian.Haas@ualberta.ca)' 'University of Alberta 1-26 ESB Edmonton, Alberta, T6G 2E3 Canada such as near BP's Northstar production island in the Beaufort Sea (Richardson 2008). Therefore, traditional knowledge, local observations and scientific studies all indicate that bowheads are sensitive to anthropogenic sounds. Care must be taken to mitigate impacts to bowhead whales that use industrialized areas. Most of these studies focused on only one industrial operation, thus it is unknown how multiple operations may cumulatively impact bowhead whales. ZOOPLANKTON OF THE COASTAL BEAUFORT SEA - PAST, PRESENT AND FUTURE STUDIES. Wojciech Walkusz (Wojciech.Walkusz@dfo-mpo.gc.ca)', Bill Williamsz, Sally Wongz, Joclyn Paulic2, Mike Papstz ' Fisheries and Oceans Canada, Freshwater Institute, 501 University Crescent, Winnipeg MB R3T 2N6 2 Fisheries and Oceans Canada Zooplankton are the passively swimming organisms that play crucial role in the energy/biomass transport by feeding on phytoplankton (plants) and at the same time being grazed by fish, seals and whales. Zooplankton of the Beaufort Sea was intensively studied during NOGAP program in the 80's, however, later there was not major study performed until 2002. Recent years were marked by onset of such programs as the Nahidik, Cases, ArcticNet or CFL that provided broad spectrum of data from the Beaufort Sea region. Most of the aforementioned studies on zooplankton were devoted to basic ecological studies that cover spatial distribution, some seasonal variability and interaction with other food web levels. As a result of these studies we learned that there is strong spatial variability, both in zooplankton abundance and diversity, from the coast to the shelf which is one of many variables that needs to be considered in spatial habitat management There is certainly a gap in knowledge on both ecology and ecotoxicology of zooplankton related to oil production. That should be considered important issue in order to understand and protect the ecosystem and mitigate future industry impacts. Possible scenarios of zooplankton response to potential oil disturbance will be presented. Ice thickness, along with ice drift and concentration, is one of the most important environmental parameters affecting the feasibility and safety of offshore operations, and largely controls the design criteria and operating procedures for offshore structures and ships in ice. Systematic observations of ice conditions and thickness should be performed before, during, and after offshore operations to prevent accidents and to assess the potential impacts of activities. Since many years we have demonstrated the feasibility of electromagnetic induction ice thickness measurements to provide data for ice navigation, ice engineering, and ice management projects, and for long-term monitoring. These 29 • • can be operated from structures or moving platforms including aircraft, and provide high flexibility in their spatial and temporal coverage and resolution. The presentation will review applications and the potential and limitations of the method, and contrast them with other means of ice thickness measurements. It is suggested to create an inter- institutional ice thickness observation system as part of a larger environmental monitoring program to manage oil and gas in the Arctic. This would efficiently provide independent and freely available information and synthesis to balance competing interests among the various stakeholders, and to provide guidelines for future procedures and regulations. RECENT OBSERVATIONS OF MULTI -YEAR ICE IN THE CANADJAN HIGH ARCTIC Humfrey Melling (Humfrey.Melling@dfo-mpo.gc.ca)' 'Fisheries and Oceans Canada Institute of Ocean Sciences 9860 West Saanich Road PO Box 6000, Sidney, BC Canada V8L 4132 The design of offshore structures for oil and gas development in the Arctic is dictated by the maximum loads anticipated from collisions with multi -year ice. From the viewpoint of ice engineering, there are two relevant environmental factors: 1) the extent of multi -year -ice fields; 2) the severity of features embedded within them. The first factor is related to the recurrence of extreme loads; the second is related to their magnitude. A large decrease in the extent of multi -year pack ice in the Arctic since 1990 has encouraged speculation concerning the disappearance of dangerous old ice some time soon. Meanwhile, recent incidental observations have revealed the continued presence of very thick old floes on the North American side of the Arctic. It is not clear at present whether these thick floes are the last stragglers of a lost regime, or normal residents of enduring ice domain that has simply shrunk in area. Only systematic observations of multi -year ice thickness can provide an answer. Upward -looking sonar on sub -sea moorings has a well -established capability to acquire such data at specific sites. However, such installations have been rare in areas dominated by multi- year ice Arctic because of the expense and difficulty of maintaining them. Fortunately since 2003, there have been several logistic opportunities to place moorings with sonar at locations in the Canadian High Arctic where old floes can be measured as they leave the vestigial perennial pack. These include 9.5 site -years in Kennedy Channel viewing ice streaming from the Lincoln Sea, and recently 1 site -year in Penny Strait viewing ice from Prince Gustaf Adolf Sea. Analysis of these observations reveals the present characteristics and occurrence frequency of thick old floes. Dangerous ice clearly remains relatively common in these straits. Quantifying change is, however, a challenge in the absence of comparable data from earlier times. THE IMPACTS OF INCREASED OPEN WATER ON ARCTIC SUMMER STORMS Will Perrie (William.Perrie@dfo-mpo.gc.ca)', J. Gyakum', A. Hoque3, Z. Long', R. Mulligan¢, S. Solomons, C. Tang', B. Toulany', L. Zhang6 'Fisheries and Ocean Canada, Bedford Institute of Oceanography 2McGill University 3Government of Manitoba 4 East Carolina University 5 Natural Resources Canada,1 Challenger Drive, P.O. Box 1006, Dartmouth, Nova Scotia 132Y 4A2 6 University of Nanjing, China Storm activity in the Arctic is a fundamental consideration in studies of Arctic weather, climate and ocean conditions. Developing storm intensities and tracks are influenced by factors such as the initial intensities, their spatial extent, thermodynamic state of the atmosphere, storm propagation speeds, and the sea surface fluxes. Although several of these factors are also known to modulate the strength of mid - latitude cyclone systems, little is known about their impact on Arctic storms. Our investigation uses a state-of-the-art mesoscale atmospheric model coupled to an ice -ocean model. Our case studies are intense summer storms from recent years. In midlatitudes, summer marine storms can encounter a thin ocean mixed layer and produce a cold wake by inducing strong currents, depressing sea surface temperatures and upper -ocean temperatures. Similar effects can be produced in the Arctic. Storm -induced ice movement can be large. In selected storm cases, we show that the impacts of the ocean surface or ice on cyclone strength may be notable, and these effects can also cause changes in the storm tracks, particularly in the decaying stages of the storm life cycle, along the Beaufort Sea coast as they move over the Arctic Ocean and Canadian Archipelago. Shallow water depths and low gradients in bathymetry in the Mackenzie Delta present a variety of challenges in terms of data collection, landfalling storms and model prediction. For instance, our present understanding of processes controlling bottom friction and other forms of energy dissipation are based on parameterizations that are tuned for mid -latitude environments. There have been few calibration studies for the Beaufort Sea and related Arctic seas. In the presentation, we mention the role of these processes based on model experiments in simulations of Arctic storms, in comparison with in situ field data. 30 THE IMPORTANCE OF ICE ISLANDS AND EXTREME ICE FEATURES IN RELATION TO OFFSHORE STRUCTURES Dr. Scott Tiffin', Tyler Sylvestre', Doug Hagen', Robert Pilkington' 'CANATEC Associates International Ltd. Alastair Ross Technology Centre Suite 122, 3553 - 31st Street N.W. Calgary, Alberta, Canada T21, 2K7 Measuring the long and short drift velocity, dimensions, and dynamics of accretion and decay of Ice Islands and Multiyear Hummock Fields (MYHFs) is crucial for offshore petroleum operations in the Beaufort and Chukchi Seas. Little is known about such characteristics of these Extreme Ice Features. Most research on MYHFs ended in the early 1980s and studies of Ice Islands have concentrated on understanding break -off events from Ice -Shelves from Northern Ellesmere Island. Public data reveal they are relatively few in number (especially Ice Islands) during their drift along the coastal Canadian High Arctic Archipelago, but their known characteristics of thickness, shape, size, hardness and integrity, all pose significant risks to offshore operations in the Beaufort and Chucki Seas. Canatec is involved with multi -year, industry research projects on these features. Since they are still in operation, their results are not yet public. However, there are some public data available to sketch the main characteristics of the dynamics of these hazardous drifting Extreme Ice Features. Studies of calving give us estimates of mass, area and timing of Ice Island liberation into the Beaufort Gyre; ice shelf characteristics help us identify the resulting Ice Islands in RadarSat-2 imagery. Some public imagery is available to pinpoint some features and estimate their motion and breakup into fields of hazardous fragments as they move southwest towards the lease areas. Our presentation concludes with recommendations for different types of studies and analyses to fill in the gaps in knowledge that will be critical for regulators, designers and operators in these offshore regions. Interaction of Oil and Gas Activities with Sensitive Coastal Habitats OIL DEVELOPMENT IMPACTS ON SUBSISTENCE: MONITORING AND ASSESSING MITIGATION Stephen R. Braund (srba@alaska.net)' and Jack Kruse' ' Stephen R. Braund & Associates P.O. Box 101480 Anchorage, Alaska 99510 The purpose of this project is to develop a systematic method to monitor and evaluate the success of specific mitigation measures as related to industrial exploration and development of hydrocarbons in the coastal and offshore environment of Alaska, especially as they relate to potential impacts on subsistence hunting activities near Nuigsut The objective is to develop a prototype method based on a review of six North Slope Alaska oil development projects: Alpine (including Alpine Satellites) Endicott, Meltwater, Northstar, Oooguruk, and Tarn. This study, being conducted under contract to the U.S. Department of the Interior, Bureau of Ocean Energy Management, Regulation, and Enforcement, will evaluate the effectiveness of industry's pre -lease mitigation strategies and post -lease operations. This presentation is based on an inventory of concerns and mitigation proposals and requirements associated with the six projects and a descriptive analysis. The inventory, developed through systematic review of federal, state and municipal environmental and permitting documents, identified 303 relevant documents and yielded 1,620 analytic records. The purpose of the analysis is to guide the development of interviews with industry and government informants. Analysis results identify 1,213 mitigation decisions over the six projects covering such mitigation categories as pipeline elevation and placement, aquatic habitat protection, helicopter and airplane management, community consultation, and research on caribou displacement The presentation tracks the incidence of concerns, mitigation ideas, and mitigation decisions by type of impact and mitigation. PROACTIVE MANAGEMENT OF POTENTIAL INTERACTIONS BETWEEN POLAR BEARS AND NORTH SLOPE OIL & GAS DEVELOPMENT - THE POINT THOMSON PROJECT Rachel R. Cox (rachel.r.cox@exxonmobil.com)', Craig Perhamz, Brien E. Reep3, Richard D. Greer4 ' ExxonMobil Development Company, Point Thomson Project, 3700 Centerpoint Drive, Suite 600, Anchorage, Alaska 99503. 2 Department of the Interior, U.S. Fish and Wildlife Service, Marine Mammals Management,1011 East Tudor Road, Anchorage, Alaska 99503. 3 ExxonMobil Development Company, Point Thomson Project, 3700 Centerpoint Drive, Suite 600, Anchorage, Alaska 99503. 4 Golder Associates, Inc., Point Thomson Project, 200 Century Parkway, Mt Laurel, NJ 08054. ExxonMobil has adopted a proactive approach regarding the assessment and management of potential interactions between the activities of the Point Thomson Project (PTP) and polar bears (Ursus maritimus). The PTP, located —60 miles east of Prudhoe Bay, Alaska, will develop a gas condensate field on the Beaufort Sea coast Pregnant female polar bears initiate denning in early winter in drifted snow from bluff habitat throughout the coastal plain of northern Alaska. Cubs and females remain in their dens until they emerge in early spring. Den sites, which 31 • allow the young to acclimate to the arctic environment prior to natural den abandonment, can be problematic if they are discovered near areas of industrial activity, such as ice roads. Therefore, the PTP has worked with the United States Fish and Wildlife Service (USFWS) and its Incidental Take Program to mitigate impacts to polar bears during the denning period if known bear dens exist near its operations. Mitigation measures that have been used by the PTP to minimize impacts to polar bears include Forward -looking Infrared (FLIR) surveys to locate polar bear dens in the vicinity of its ice road. In addition, the USFWS has stipulated that project activities conducted during the winter be kept at least one mile away from any known active polar bear den. The project has also incorporated ice road closure protocols into its site -specific Polar Bear and Wildlife Interaction (PBWI) Plan to define the procedure for closing the ice road in the event of a polar bear sighting. Each winter the project conducts ice road closure drills in accordance with these protocols to prepare the workforce for a polar bear encounter. This preparedness allowed the project to quickly close the ice road for several days in the spring of 2010 to safeguard a mother and cubs that had emerged from a nearby den. POTENTIAL FOR DISPLACEMENT OF WHALES AND SEALS BY SEISMIC AND EXPLORATORY DRILLING ACTIVITY IN THE CANADIAN BEAUFORT SEA - WHAT HAVE RESEARCH AND OBSERVATIONS REVEALED TO DATE Lois Harwood (lois.harwood@dfo-mpo.gc.ca) ',Thomas •Smithz, Amanda Joynt3, Dean Kennedy4, Rob Pitt4, Sue Moores, and Peter Millman6 1 Canada Arctic Aquatic Research Division Dept. of Fisheries and Oceans 300- 5204 50th Avenue Yellowknife, NT X1A 1E2 2 EMC Ecomarine Corporation, Garthby, Quebec, Canada 3 Canada Dept of Fisheries and Oceans, Yellowknife and Inuvik, NT 4 GX Technology Ltd., Calgary, Alta, Canada and Houston, Texas, USA s NOAA, Seattle, Washington USA 6 Devon Canada, Calgary, Alta Canada The Beaufort Sea, shared by Canada and the USA, is important to several species of marine mammals including bowhead whales (Balaena mysticetus), beluga whales (Delphinapterus leucas) and ringed seals (Phoca hispida). Both whale species arrive through offshore leads in ice in the Canadian Beaufort Sea (CBS) in spring, and remain there during the open -water season. Conversely, the ringed seal is resident throughout the year and breeds there in the fast ice. While limited in scope, existing research results obtained while seismic or drilling operations were underway have shown no marked or measurable effects on either the behaviour or distribution of these species by offshore industrial operations in the CBS to date. Differences in behaviour and distribution have been recorded, but were localized and temporary. Current best -practice of shutting •down seismic operations if marine mammals enter the prescribed safety zone (SZ) is in place in the CBS. Aerial survey and shipboard observations reveal that bowheads usually avoid the SZ and immediate area of the seismic activity, but are not displaced for extended distances or periods beyond these proximate areas. The primary activity of bowheads in the CBS is feeding, during which time bowheads appear more tolerant of disturbance and are less likely to be displaced than during migration. In contrast, aerial survey results show beluga whales are widely distributed throughout the offshore during August, yet they are rarely sighted from seismic ships and rarely seen within the SZ. This is interpreted as their tendency to temporarily avoid areas of seismic activity by greater distances, on average, than bowheads. A four-year study of ringed seals prior to (2003-2005) and during the drilling of an offshore test well (2006) in an area of fast ice in the CBS failed to show any significant effects on either the distribution or behaviour of breeding seals in the area potentially affected by the industrial activities. The evaluation of cumulative effects of future offshore development (multiple sources and among jurisdictions) is limited by a dearth of data to assess the biological significance of cumulative exposures. Without a continuing and well designed data base supported by innovation and the latest technology, and with costs incorporated into planning for future offshore developments, it will be difficult to either predict or measure cumulative effects with confidence. ENVIRONMENTAL CONSIDERATIONS ASSOCIA TED WITH OIL AND GAS EXPLORATION AND DEVELOPMENT ON ALASKA S NORTH SLOPE Calyn Rea (caryn.rea@conocophillips.com)1 ' ConocoPhillips Alaska, Inc. P.O. Box 100360, Anchorage, AK 99510. ConocoPhillips Alaska, Inc. (CPAI) is the largest oil and gas operator in Alaska, having operated on the North Slope of Alaska for more than 30 years. Over this period, significant advances in technology have occurred; resulting in the use of ice roads and ice pads to support winter exploratory drilling, and reduced gravel footprints to access key reservoirs as part of development Mitigation measures have been developed in consultation with stakeholders, based on the acquisition of key environmental data sets and traditional knowledge of local residents. CPAI has supported an environmental studies program since the discovery of Prudhoe Bay in the late 1960s. The environmental studies program continues today, providing scientific data to support the development of National Environmental Policy Act (NEPA) documents that evaluate the potential impacts of exploration or development activities and recommend mitigation measures, if necessary. CPAI encourages collaboration with federal, state, and local regulatory agencies, as well as universities to collect data that will assist land managers and regulatory staff with decision making based on sound science. With expansion of activities to the west into the National Petroleum Reserve -Alaska, the importance of collaboration in research is imperative in order for all stakeholders to have the information necessary for development with minimal impacts. This talk will present an overview of the coastal environmental studies program supported by ConocoPhillips in Alaska. 32 • Oil Spill Prevention in the Arctic ARCTIC OIL SPILL PROBABILITIES Frank G. Bercha (berchaf@berchagroup.com)l 1 Bercha Group, P.O. Box 61105 Kensington P.O., Calgary, AB, T2N 4S6 Current catastrophic consequences of the Gulf of Mexico blowout have refocused interest on the probabilities of such events in both temperate and northern regions. In order to adequately reduce the likelihood and impact of oil spills, it is important to understand their chances of occurrence, the principal causal factors contributing to the occurrence, and the probable spill characteristics in terms of location, timing, and volume and rate of spill. This paper reviews both early Beaufort Sea studies on oil spill probabilities with emphasis on oil blowouts, and details more recent comprehensive studies carried out specifically for Beaufort and Chukchi sea locations. Due to the limited history of offshore oil operations in arctic regions, which continues to be the case to the present, it is not possible to base oil spill probability estimates solely on historical empirical data —there have been very few oil spills in the arctic. The early studies in the 70's relied on a detailed fault tree analysis dealing with the 0 Oil Spill Management in the Arctic EARTH OBSERVATION DATA TO SUPPORT EMERGENCY RESPONSE AND WILDLIFE MANAGEMENT IN CASE OF AN OIL SPILL IN CANADA S NORTHERN COASTAL ECOSYSTEMS Jason Duffe Qason.Duffe@ec.gc.ca.)1, Sonia Laforestz and Anne -Marie Demersz 1 Landscape Science and Technology Division, National Wildlife Research Centre, Environment Canada. 1125 Colonel By Drive, Ottawa, ON K1A 01-13. 2 Environmental Emergencies Section, Environment Canada. 105 McGill Street, 4th Floor, Montreal, QC, H2Y 2E7. The eSPACE project (Emergency Spatial Pre -SCAT for Arctic Coastal Ecosystems) is part of a new joint initiative (MORSE) from the Canadian Space Agency. That project is focused on developing a capacity to enhance our state of preparedness for emergencies in case of an oil spill in the North. Baseline coastal information is required for operational prioritization, coordination of on -site spill response activities and wildlife management Traditional data development for shoreline classification and sensitivity analyses include manual interpretation of oblique videotape imagery collected in a helicopter. Earth Observation data from satellites such as RADARSAT-2 and SPOT-5 can potentially be used to identify isand map shoreline characteristics, coastal habitats and resources at risk This project will develop remote sensing classification procedures to support shoreline segmentation and sensitivity analyses in the Arctic. Mackenzie River Delta offshore operations as systems without history. More recent studies, carried out for the Alaska region MMS, use world wide data as a starting point In these studies, statistically significant non -Arctic empirical data from the US Gulf of Mexico and other world-wide sources, together with their variance, were used as a starting point Next, both the historical non -Arctic frequency distributions and spill causal distributions were modified to reflect specific effects of the Arctic setting, and the resultant fault tree model was evaluated using Monte Carlo simulation to characterize uncertainties treated as probability distribution inputs to the fault tree. Numerical values for arctic oil spills of different origins are presented in the paper, together with conclusions and recommendations. It is found that the range of values of exploratory drilling blowout probabilities has not significantly changed between those of the early studies and those based on current data. Based on the ranges of values derived, is recommended that in applications of statistical blowout probabi lity values, it is essential to consider specific operational, reservoir, platform type, environmental, water depth, gas or oil, flow path inside or outside casing, and other factors which can significantly affect the values by one or two orders of magnitude. and Beaufort Sea are one of the pilot study regions. In the summer of 2010, videotapes were collected along coastline from 011ivier Island to Warren Point on the Tuktoyaktuk Peninsula for shoreline segmentation and classification. In the same time, RADARSAT-2 fine quad p ole data were acquired. Images processing such as classifications are now conduct on radar and optical data using ancillary data to investigate the ability to differentiate shoreline properties. Results will be compared with the traditional approach to verify that the products are as reliable. NATURAL RESOURCE DAMAGE ASSESSMENT INARCTIC WATERS Elizabeth Logerwelll, Mary Bakerz and Amy Mertenz 1 Alaska Fisheries Science Center, National Marine Fisheries Service, National Oceanic and Atmospheric Administration 7600 Sand Point Way NE Seattle, WA 98115 2 Office of Response and Restoration, National Ocean Service, NOAA, 7600 Sand Point Way NE, Seattle, WA, 98115, USA. As required by the Oil Pollution Act of 1990, Natural Resource Damage Assessment (NRDA) is a process to determine what restoration actions are needed to compensate for harm to natural resources and their human uses that occur as a result of an oil spill. The process requires natural resource trustee agencies (NOAA, DOI, and state agencies) to assess the transport of oil from the release 33 site, the exposure of natural resources to the oil, and its effects on the biota and human uses. Determining the amount of injury and appropriate restoration requires an understanding of the condition of the natural resources and human uses in the absence of the spill (baseline conditions). Loss of Arctic sea ice suggests that over the next 10 - 20 years ship activity will dramatically increase. Predictions of large reserves of oil and gas are increasing pressure for hydrocarbon exploration and production. One likely result will be the accidental release of petroleum into the Arctic marine environment which would require an NRDA to be initiated. However, little NRDA work has been done in this region. On April 22, 2010, the Coastal Response Research Center (CRRC) and NOAA's Office of Response and Restoration completed a workshop on planning for NRDA in the Arctic. Attendees included natural resource trustees, industry representatives, non -governmental organizations, academic scientists, and Arctic community representatives. This presentation will describe the outcomes of the workshop, highlight challenges particular to the Arctic, and provide suggestions for future research in support of NRDA in the Arctic. IN SITU BURNING IN ARCTICAND ICE -COVERED WATERS. - TESTS OF FIRE-RESISTANT BOOM IN LOW CONCENTRATIONS OF DRIFT ICE Stephen Potter (Steve@slross.com)' and Ian Buistl •1 SL Ross Environmental Research Ltd. 200 - 717 Belfast Rd. Ottawa, ON, Canada, K1G OZ4 Field deployment tests of booms and skimmers in broken ice conditions have highlighted the severe limitations of conventional containment and recovery equipment in even trace concentrations of broken ice. Even small amounts of brash ice concentrated by the containment booms severely affected the effective operation of skimming systems designed for use in ice -affected waters. It is possible, however, that the accumulation of brash ice and small floes in the back of a fire-resistant containment boom would not curtail in situ burning of the oil sandwiched between the ice floes. Field tests have shown that high concentrations of oil in brash/slush between floes can be ignited and burned efficiently. A two-day test program was conducted in the Barents Sea in May 2009 to perform experiments related to in situ burning of oil in open drift ice. The tests were part of a broader program performed over a two -week period that included tests with skimmers, dispersants, and remote sensing systems, and studies of oil -in -ice behaviour. Preliminary tests were performed with the boom in 2008: these tests did not involve oil, but proved the feasibility of several operational aspects of fire -boom use in ice. In the 2009 test program, oil was collected in ice -affected waters and subsequently burned in situ. The primary objective of the tests was to determine whether fire-resistant booms could be used to collect and contain oil in low concentrations of drift ice for burning in situ. This was accomplished with two different booms, the Elastec/American Marine (aka 3M) fire boom and the Applied Fabrics Technologies (AFTI) PyroBoom. The booms were tested in to different ice conditions: the former in a field of 3 to 5/10ths ice, and the latter in trace ice conditions. Both booms proved to be suitable to the task, and were able to contain a modest number of ice floes as would be encountered in a "collect -and -burn" operation in light ice concentrations. In each test, a high percentage of the oil was removed through in situ burning, some 98% in the first test and 89% in the second. The burn in the second test was less effective and took much longer due to the presence of more densely packed brash and frazil ice and due to the presence of waves. BEAUFORT SEA OIL SPILLS STATE OF KNOWLEDGE REVIEW AND IDENTIFICATION OF KEY ISSUES Stephen Potter (Steve@slross.com)', Ian Buistl, Ken Trudell, and Randy Belorel 1 SL Ross Environmental Research Ltd. 200 - 717 Belfast Rd. Ottawa, ON, Canada, K1G OZ4 Exploration activities by Imperial Oil Limited, Dome Petroleum Limited, Gulf Canada Resources Limited, and Panarctic Oils Limited in the 1960s through to the 1980s identified significant oil and gas potential in the Canadian Arctic. With the exception of one tanker of oil from an extended flow test from Gulfs Amauligak discovery in the Beaufort Sea and a few years of seasonal tanker shipments of oil from Panarctic's Bent Horn operation on Cameron Island, these discoveries were not developed and oil and gas activity in the Canadian north stagnated. The issuance of new offshore exploration leases in recent years and changing market conditions have resulted in an increased interest and activity in oil and gas in the Canadian Arctic. Increased exploration activity will bring with it an increase in the risks associated with accidental spills from the operations. The proposed presentation will describe the results of a recently -study commissioned by the Environmental Studies Research Funds (ESRF) with the objectives of. Reviewing the current state of knowledge of oil spills in Arctic waters; Identifying the key issues associated with them; Providing a current reference document for use by industry, regulators and the public; and Preparing a geographic database of coastal resources, vulnerabilities and sensitivities that may influence the choice of oil spill containment and recovery methods. As a culmination to this study, a workshop was held in October 2009 involving representatives of government and oil companies that may be involved in Beaufort Sea exploration and development. At the workshop, members of the study team presented the draft findings of the study. This was followed by a discussion of a number of key issues of concern regarding planning and response to spills in the Beaufort Sea. The proposed presentation will present the findings of the study, with a description of the current state-of-the-art for each of the main categories of countermeasures and a summary of the key issues addressed in the discussion portion of the workshop. 34 • • r� UNDERSTANDING ICE MOVEMENT FOR OIL SPILL MONITORINGAND CLEANUP Roger Pilkington' 1 CANATEC Associates International Ltd. Alastair Ross Technology Centre Suite 122, 3553 - 31st Street N.W. Calgary, Alberta, Canada T21, 2K7 Monitoring and cleanup of oil spilled in the Arctic requires an understanding of the drift patterns of ice at and away from potential spill sites during the winter, and of the open ocean currents after the ice has melted. This information is vital for determination of the movement of contaminated ice, which might result from a spill on the ice (tanker, refuelling, operations) or under the ice surface (subsea blowout or ruptured pipeline). As far as we are aware, no public information has been published on this subject relating to the Beaufort since the 1980s. Significant changes to the ice cover in the arctic have occurred over the past decade, and new information on ice drift and dispersion should be obtained. Ice drift beacons placed in lease areas in the eastern Beaufort Sea came ashore along the coast of the US Beaufort or Chukchi Seas, while others circulated out to sea. A spill or blowout in stable landfast ice would be confined during winter and spread very little. Spills in the moving pack ice present a greater problem, and hazard to personnel during cleanup. In the event of oil coming from the sea -floor (well blowout or ruptured subsea pipeline), it would be necessary to track the oil trapped under the ice by periodic placement of buoys on the ice as it drifts over the site. Such measurements would provide some indication of the accumulation of oil under the ice (form ice drift speed) and where the contaminated ice might end up. Knowledge of locations of high oil accumulation would increase the efficiency of cleanup in the spring, which would assist logistics and HSE planning. A discussion of these and other oil spill issues, as a result of ice drift, will be presented in the presentation. SHORE -BASED, HIGH -FREQUENCY SURFACE CURRENT MEASURING RADARS IN REMOTE ARCTIC SETTINGS Thomas Weingartner (weingart@ims.uaf.edu)1, Hank Statscewich', Rachel Potter', Greg Eaganz, Jeb Timmz, Bruno Grunauz 'Institute of Marine Science, University of Alaska, Fairbanks, AK 99775 2 Remote Power, Inc., Fairbanks, AK 99712 High -frequency shore -based radars (HFR) collect hourly, realtime surface current data over broad areas of open water. Such data provide insights on the time -varying ocean circulation, predict oil spill trajectories, evaluate circulation models, and in the event of a spill, provide responders with realtime data on spill evolution. The radars detect currents from the Doppler shift of the backscattered radar signal. We will show examples of HFR data collected recently on a 3 km grid extending from the coast to 50 km offshore from the central shelf of the Alaska Beaufort Sea and on a 6 km grid extending 170 km offshore over the Northeast Chukchi Sea continental shelf. In addition to showing results from these systems we will discuss HFR limitations with respect to sea ice, ionospheric interference, ambient weather conditions and siting constraints. HFR requires 11kwH/day of AC power but the lack of power availability inhibits HFR use along remote coasts. To circumvent this constraint we developed a modular, autonomous remote power module (RPM) for arctic environments. The RPM design facilitates setup and transport to remote sites using small vehicles. The RPM contains sub -systems that generate power for the HFR and satellite communications and monitor power performance. The HFR, communications, and monitoring systems are powered via a battery bank (with a 4-day power reserve) primarily by wind and solar and secondarily by a bio-diesel generator. The RPM is designed as a stand-alone device for long-term deployments. It minimizes permit issues associated with diesel generators and logistics costs associated with refueling and maintenance. Performance data from a prototype RPM setup in Barrow Alaska in September 2010 will be provided. While our system is designed for high -latitudes, it can be easily modified for remote coasts elsewhere. 35 n U • • ABSTRACTS - POSTER SESSION INFLUENCE OF ENVIRONMENTAL GRADIENTS ON MACROFAUNAL COMMUNITY STRUCTURE IN THE NORTHEASTERN CHUKCHI SEA. Arny L. Blanchard', Hilary Nichols', Carrie Parris' and Jeannette Cochrane 1 Institute of Marine Science, University of Alaska Fairbanks, Fairbanks, AK e School of Fisheries and OceanSciences 141 O'Neill Bldg University of Alaska Fairbanks Office In 2008, a multi -year, interdisciplinary study was initiated in the vicinity of two proposed oil and gas exploration areas in the northeastern Chukchi Sea. This study was sponsored by ConocoPhillips and Shell Exploration and Production Company to collect information on the ecosystem in these areas prior to exploration and provide environmental data useful for permit applications and for post -development comparisons. Sediment -dwelling macrofauna were collected for taxonomic analysis at 52 sites with a van Veen grab in August, 2008 and 2009. Dominant fauna include the crustacean class Ostracoda, the amphipod Paraphoxus spp., the bivalves Astarte spp., Ennucula tenuis, Nuculana pernula, and Macoma calcarea, the peanut worm Golfingia margaritacea, and the large polychaete worms Lumbrineris sp. and Maldane glebifex. The fauna found in 2008 and 2009 were abundant and animals large although abundance, biomass, and the number of taxon found were all significantly higher at Burger compared to Klondike. The faunal communities demonstrated little temporal change as faunal assemblages sampled in 1986 were comparable to those of 2008 and 2009. A gradient in benthic community structure was associated with sediment and physical variables reflecting the geomorphology and hydrography in the study area. The advection of nutrient -rich water from the North Pacific Ocean and eastern Bering Sea contribute to the high abundance and biomass of faunal communities in the study area. WHO NEEDS AN ICE ROAD? Rob Brumbaugh' ' Division of Resources Alaska State Office Bureau of Land Management The BLM was forced to plug the Drew Point well when it was threatened by coastal erosion from the Beaufort Sea. The associated reserve pit threatened release of petroleum contaminated drilling muds into the ocean. The material had to be excavated and hauled to an appropriate site that was 37 miles to the south over barren tundra. The BLM worked with the contractor to use specialized equipment including Steigers and rubber -track modified Sidedumpers. The move to all tracked equipment enabled the BLM to save about 4 million dollars by creating and maintaining a snow trail rather than an ice road. When revisited over the summer, final impacts to the tundra were very similar in appearance to an ice road. The Drew Point well is located north of Lake Teshekpuk in NPRA. MEASURING NATURAL SUBSIDENCE, ENHANCED FLOODING, AND HABITAT LOSS IN THE OUTER MACKENZIE DELTA, WESTERN ARCTIC CANADA D.L. Forbes (dforbes(@nrcan,gc.ca)1, M. Craymere, C. Hopkinson3, T.S. James4, J.-C. Lavergnee, P. Marshs, S.M. Solomon6, D. Whalen6 and H. Wilsons 'Bedford Institute of Oceanography POB 1006 Dartmouth, NS, Canada, 62Y e e Geodetic Survey Division, Natural Resources Canada, Ottawa 3 Applied Geomatics Research Group, Nova Scotia Community College, Middleton NS 4 Geological Survey of Canada, Natural Resources Canada, Sidney BC s National Water Research Institute, Environment Canada, Saskatoon SK 6 Geological Survey of Canada, Natural Resources Canada, Dartmouth NS B2Y 4A2 The outer Mackenzie Delta is a low -relief alluvial plain with large areas <1 in elevation (—MSL datum). Proposed natural gas production is expected to cause subsidence and partial inundation of important avian nesting habitat, but future attribution of induced subsidence requires knowledge of natural rates. Here we evaluate natural subsidence and sea - level rise (SLR) contributing to future flood hazards, which we map using a LiDAR digital elevation model. Semi-annual GPS measurements over 3 to 5 years at a network of nine stations across the delta show vertical motion ranging from - 1.8±1.5 mm/yr to-5.7±1.8 mm/yr (downward) relative to bedrock at Inuvik. Fourteen other stations have short records requiring more epochs to define a reliable trend. The delta subsidence measurements, on monuments extending 10-30 in into frozen ground, do not capture shallow compaction or thaw subsidence. We have initiated work on shallow subsidence and vertical aggradation using measurements of point clusters surrounding GPS monuments and employing artificial horizons to measure sedimentation rates. We consider the gravitational fingerprinting of meltwater contributions from ice sheets, ice caps, and smaller glaciers in an analysis of sea -level rise in the outer delta region. Based on the IPCC (2007) AR4, the computed 20th century SLR in the area averaged +0.08 mm/yr. Projected SLR, using the AR4 upper limit of projections for the A1FI scenario and a recent higher projection and incorporating fingerprinting, is 30-64 cm over 100 years. Combined with delta subsidence of 2-5 mm/yr, projected relative SLR is approximately 30-70 cm over 100 years (9-20 cm over 30 years). This suggests moderate natural inundation potential which will exacerbate gas production impacts. Habitat loss also occurs through 01 • 9 erosion along the delta front, on channel cut -banks, and lake shores, while new habitat is created at depocentres in channels, overbank settings, and locally at the delta front. THE HYDROCARBON IMPACTS DATABASE. YOUR GATEWAY TO NORTHERN CANAD►AN OIL AND GAS ENVIRONMENTAL, SOCIO-ECONOMIC AND REGULATORY PUBLICATIONS A MARINE MAMMAL MONITORING AND MITIGATION PROGRAM FOR OIL AND GAS EXPLORATION ►NARCT►C Ross Goodwin (rgoodwin@ucalgary.ca)l ALASKA Dale W. Funk (dfunk@lgl.com)i and A. Michael Macrander2 1 LGL Alaska Research Associates, Inc. 1101 East 76th Avenue, Suite B Anchorage, AK 2 Shell Offshore Inc. 3600 C Street, Suite 1000, Anchorage, AK 99518 USA. Anthropogenic sounds introduced into the marine environment from oil and gas exploration activities can impact some marine mammals. Impacts can be greatly reduced if appropriate monitoring and mitigation measures are implemented. Effective monitoring provides information on marine mammal distribution around operations, allows for real-time mitigation in critical situations, provides data that furthers our knowledge of various species, and provides feedback on the efficacy of implemented mitigation measures. Pacific walruses, bowhead whales, beluga whales, and gray whales all use the arctic waters offshore of Alaska and all undergo long distance migrations that traverse important areas of offshore oil and gas exploration. These areas are also used extensively by bearded, ringed and spotted seals, polar bears and by smaller numbers of other marine mammal species. To successfully monitor animal movements and distribution over such large areas and effectively institute mitigation a three -tiered monitoring program using dedicated marine mammal observers (MMOs) onboard most vessels, aerial over -flights, and wide - area arrays of acoustic recorders deployed on the seabed was implemented in both the Beaufort and Chukchi seas. The integrated use of these three platforms since 2006 to acquire data on marine mammal movements and distribution has enhanced understanding and detection of natural patterns as well as changes that may be associated with oil and gas exploration. This program has minimized impacts to marine mammal populations and subsistence hunts. It provided data on the unprecedented movement of large numbers of walruses to terrestrial haulout sites along the Chukchi Sea coast in 2007. It showed that bowhead whales will feed in areas near ongoing seismic operations by limiting their exposure to injurious sound levels. It also found that bowhead whales decrease calling near seismic operations. Lastly, it has detected early range expansion of humpback and fin whales into arctic waters that may be associated with climate change. i Arctic Science and Technology Information System (ASTIS), Arctic Institute of North America, University of Calgary, Calgary, AB, Canada T2N 1N4 The Hydrocarbon Impacts (HI) database describes 7000 publications and research projects about the environmental impacts, socio-economic effects and regulation of hydrocarbon exploration, development and transportation in northern Canada. The database is available for free at www.aina.ucalgary.ca/hi, and includes links to PDF files of 1600 online publications. HI is maintained for the Northern Oil and Gas Branch of Indian and Northern Affairs Canada by the Arctic Science and Technology Information System (ASTIS) at the Arctic Institute of North America, University of Calgary. HI includes most of the environmental, socio-economic and regulatory publications about northern Canadian hydrocarbon projects and proposals from the 1970s up to the present day Mackenzie Gas Project and Arctic Offshore Drilling Review. It includes all publications from the Northern Oil and Gas Action Program (NOGAP), all northern Environmental Studies Research Funds (ESRF) reports, and many of the publications from the Northern Oil and Gas Science Research Initiative (NOGSRI). HI also includes an electronic library of key reports for the Beaufort Regional Environmental Assessment (BREA) which was prepared by ASTIS EFFECTS OFAMBIENTARTIFICIAL LIGHT ONARCT►C MARINE FAUNA Richard D. Greer (rgreer@golder.com)1, Robert H. Day2, and Rolf S. Bergman3 1 Golder Associates, Inc., 200 Century Parkway, Mt. Laurel, NJ 08054-1150 2 Environmental Research & Services, P.O. Box 80410, Fairbanks, AK 99708-0410 3 Rolf Bergman Consulting, 3236 Berkeley Avenue, Cleveland Heights, OH 44118-2055 Light radiating outward from structures associated with offshore oil/gas development may affect the marine environment. We conducted a literature review to assess the potential effects of artificial lighting on arctic marine and estuarine species, focusing on the Beaufort and Chukchi Seas during normally -dark periods. Responses to light can vary widely by faunal taxon and environmental conditions. These responses also may be dependent on the type of lighting, its spectral characteristics, and its intensity. In general, marine mammals do not appear to be attracted by artificial lighting but may be locally disturbed. Many species of seabirds are attracted to artificial light, especially during cloudy or inclement weather, with impacts ranging from increased energetic costs to mortality from collision. Birds are 37 • r� U • disoriented by longer wavelength (i.e., red) light, which may interfere with their magnetic compass, whereas recent studies in the North Sea indicate that shorter wavelength (i.e., green) lighting is less attractive to migrating birds. Light is an important, but not the only, factor affecting fish behavior; there appears to be no single combination of spectrum, intensity, or duration that attracts or repels all species of fish. Changing light levels is the most likely stimulus for the diel vertical migration in many invertebrate taxa, but other environmental conditions such as ice cover and hydrographic factors also may contribute in the Arctic. Mitigation measures may be implemented to reduce adverse effects of lighting associated with offshore development on marine fauna. Potential impacts of lighting associated with offshore platforms or support facilities could include the attraction or repulsion of some fauna, resulting in the localized, short-term abundance or dispersal of some species. The potential for ecologically significant or long- term impacts from ambient artificial lighting on regional populations of arctic marine fauna can only be speculated on at this time. USING SAR TO CHARACTERIZE WINTER LIQUID WATER AVAILABILITY IN LAKES ON THE NORTH SLOPE COASTAL PLAIN OFALASiKA A REGIONAL ASSESSMENT Jess Grunblatt (Jess@gina.alaska.edu)land Don Atwoodz 'Geographic Information Network of Alaska, University of Alaska Fairbanks 2 Geophysical Institute, University of Alaska Fairbanks The North Slope coastal plain represents a unique landscape that is characterized by permafrost and an immense number of freshwater lakes of varying sizes and depths. These lakes are an important resource for a range of uses including habitat for fish and bird species, subsistence for local populations, and freshwater supply for industrial development The ability of resource managers to effectively balance these uses depends on our understanding of the capacity of these lakes for water storage and their function as habitat. During winter, lakes on the coastal plain typically freeze to a depth of about 2m, with deeper lakes retaining liquid water. The identification of deep lakes that contain unfrozen water can help define critical fish overwintering habitat, refine habitat modeling for fish populations and piscivorous birds, and aid in the appropriate selection of lakes as water sources for ice road construction. A wide variety of localized studies have demonstrated the use of synthetic aperture radar (SAR) as an effective tool to identify those water bodies for which the water does not completely freeze to the bottom. However no broad, regional assessment of winter liquid water availability has been conducted. It is the goal of this study to develop a consistent, assessment of winter liquid water availability on the coastal plain of the North Slope using SAR imagery. This presentation will outline an operational methodology for characterizing winter liquid water availability in lakes using C-band SAR imagery from the ERS-2 satellite as provided by the Alaska Satellite Facility. The poster will describe theory and processing sequence by which the SAR data is pre-processed, segmented, and classified in a GIS environment. Results of this work will be incorporated into a public, web based information portal. This work is currently ongoing and final results are expected in December 2011. LAND COVER MAPPING OFALASKA S NORTH SLOPE UTILIZING LANDSAT TM IMAGERY. Scott Guyer (Scott _Guyer@blm.gov)1, Dan Fehringer, Keith Boggs, John F. Payne 1 Alaska State Office, Bureau of Land Management The North Slope Science Initiative (NSSI) has been working with partners to bring Alaska North Slope land cover maps into the digital age. Land cover data needs are not new - since the 1990s, millions of acres across Alaska have been mapped by the BLM, Ducks Unlimited, the U.S. Fish and Wildlife Service and the National Park Service. Mapping and field protocols developed by these agencies have also been adopted for mapping in Canada's Northern provinces. On Alaska's North Slope, over the past forty years approximately 55 different land cover products have been completed by agencies, universities and industry. All of these map products had a common element: no map used a standard protocol that could be used to combine efforts into a single slope -wide land cover map. The NSSI held meetings with agencies and non -government organizations to begin a partnership in support of standard protocols that would be used to develop a slope -wide land cover map. In 2008 and 2010, NSSI directed field collection projects with support from Ducks Unlimited, the Natural Resource Conservation Service and the Alaska Natural Heritage Program. These field efforts collected data from hundreds of locations representing millions of acres across the North Slope region. Image processors are currently using this data to finalize the classified map, which when completed will serve as a baseline from which to detect change in habitat, food sources, hydrology, and wildlife movements. The map will also be used as a planning tool for ice and gravel road construction and well as other infrastructure in support of oil exploration. The land cover map address NSSI emerging issues such as: vegetation change, lake drying, saltwater intrusion, changing fire regimes, wildlife habitat selection/availability, weather and climate. DATA ASSIMILATION OF ROBOTIC AND SATELLITE DATA FOR CHARACTERIZATION OF NORTH SLOPE, ALASKA LAKES Liza K. Jenkins (liza.jenkins@mtu.edu )1, Robert A. Shuchmanl, Jess Grunblattz, Scott Guyer3 John F. Paynez 1 Michigan Tech Research Institute, 3600 Green Court Suite 100, Ann Arbor, MI 48105 2 University of Alaska Fairbanks 3 Bureau of Land Management 4 North Slope Science Initiative Radar and electro-optical remote sensing satellite data have been combined with in situ measurements on the North 38 Slope of Alaska to obtain critical lake data for both the oil and gas industry and resource managers. Information provided includes baseline characterization of these lakes, change detection, salt water intrusion, and ecological habitat preference. This information can help define critical fish overwintering habitat, refine habitat modeling for fish populations and piscivorous birds, and aid in the appropriate selection of lakes as water sources for ice road construction. This multi -faceted program, pioneered by the North Slope Science Initiative, has been aimed at using cost- effective technologies to investigate the remote lakes of the North Slope. Autonomous water quality and bathymetry mapping robots have been used to provide in situ data. Synthetic aperture radar data and electro-optical satellite data have been used to delineate lake boundaries, determine which lakes retain liquid water during the winter months, and map limited depth contours. Robotic and satellite data assimilated within a geographic information systems (GIS) framework has allowed for interpolation between measurements and extension of estimates to lakes that have not been directly sampled. With approximately 2,974 lakes on the North Slope, and approximately 1,659 of these lakes with an area over one square kilometer, efficient and cost- effective methods are needed to provide critical lake data. Example applications and methodologies will be presented, as well as a summary of efforts underway to develop a regional map of winter liquid freshwater availability. THE PEEL PETROLEUM PROJECT . Adrienne LJones (Adrienneaones@gov.nt.ca)' and Kelly L. Pierce 1 Northwest Territories Geoscience Office, Yellowknife, NT The Peel Petroleum Project (2005-2009) was initiated by the Northwest Territories Geoscience Office and involved partners from the Geological Survey of Canada, Yukon Geological Survey, universities, and industry. A study of hydrocarbon potential and regional geology in the Peel Plateau and Plain (Peel area) of the Northwest Territories and Yukon addressed the need for modern petroleum geoscience data and interpretation in this underexplored, yet prospective, area in proximity to the proposed Mackenzie Gas Project natural gas pipeline route. A total of 74 wells have been drilled in Peel Plateau and Plain. None of these wells have been productive, but indications of petroleum systems in the Peel area include petroleum shows in exploration wells, gas seeps, oil stained outcrops, and bitumen occurrences. Fieldwork was conducted on the Phanerozoic succession in the northern Mackenzie Mountains, Richardson Mountains, and Franklin Mountains that expose stratigraphy contiguous with the subsurface of Peel area. The final project volume (Pyle and Jones, 2009) includes structural and seismic interpretation, regional stratigraphy, and a review of petroleum systems elements for the area. A Geographic Information System digital atlas (Pierce and • Jones, 2009) accompanies the project volume and contains all of the spatial data associated with the research. The interactive atlas includes field and core photographs, interpreted seismic profiles, core and measured section descriptions, geochemical analyses, isopach and structural contours, and other related data associated with a spatial database of wells and field localities. The result is a comprehensive body of geoscience work for Peel area which will be useful in oil and gas exploration and for informed regional land use and business planning endeavours, when coupled with other pertinent data. This project's research team has received the 2009 INAC NWT Region Excellence in Science and Technology Award and 2010 NWT Premier's Award for Collaboration. THE ROLE OF SNOW IN ARCTIC TRANSPORTATION NETWORKS: FROM DESIGN TO MANAGEMENT Michael R. Lilly (mlilly@gwscientific.com)', Horacio Tonioloz, Vlad Romanovskyz, Jessica Cherryz, Yuri Shurz, Matthew Brayz, Chien-Lu Pinz, Gary Michaelsonz, Ron Paetzold', Jeffrey Derry', Gerald Sehlke3 ' Geo-Watersheds Scientific, PO Box 81538, Fairbanks, Alaska, 99708 2 University of Alaska Fairbanks 3 Idaho National Laboratory Snow plays many critical roles in Arctic transportation. It is both a construction material and an ecological resource providing recharge to lakes, streams and wetlands. Snow provides a natural covering which helps protect the natural landscape. Collected snow also can be used in building up ice roads and pads. Snow properties can be highly variable over time. Wind redistribution of snow is an important factor, contributing to the formation of more dense snow and snow slabs, however, it can also remove valuable snow from oil and gas operation's areas, which can stop winter transportation, or limit the construction of ice road networks. As part of a larger project developing tools to improve Arctic transportation networks, we are looking at several key issues associated with North Slope, Alaska, oil and gas applications. Standards for making snow measurements and the resulting use by management agencies have been developed and published. These standards are now being used by industry to help develop validation programs. Application of real-time reporting stations for snow depth and the scaling issues with managing larger operation areas are being studied to define the benefits and limitations of this data. We are also investigating applications of various techniques to account for snow redistribution in climate forecast models, primarily the Weather Research and Forecasting (WRF) model. Preliminary project results have shown the benefits of measurement standards and the ability to improve the quality of snow measurements taken by diverse users. Automated measurements are providing useful data to help determine when field conditions may need to be verified, such as the occurrence of wind events, which may impact minimum snow -cover conditions. The development of forecast methods which can predict blowing snow have the potential to provide industry and agencies with better tools to help operations and management of Arctic transportation systems. 39 • • THE ROLE OF SOIL CONDITIONS IN MANAGING ARCTIC TRANSPORTATION ON THE NORTH SLOPE, ALASKA Michael R. Li11y (mlilly@gwscientific.com)', Horacio Toniolo2, Vlad Romanovsky2, Jessica Cherry2, Yuri Shurz, Matthew Bray2, Chien-Lu Pin2, Gary Michaelson, Ron Paetzold', Jeffrey Derry', Gerald Sehlke3 ' Geo-Watersheds Scientific, PO Box 81538, Fairbanks, Alaska, 99708 2 University of Alaska Fairbanks 31daho National Laboratory Arctic transportation networks rely on the frozen state of soils to limit damage to surface vegetation and excessive thermal impacts to permafrost. The Alaska Department of Natural Resources currently uses one standard for the North Slope that requires soil temperatures to be -5°C or colder at a 30 cm soil depth for opening tundra -travel management areas. The standard is applied to any type of ice road and their associated loads, and any type of soils in the transportation corridors without taking into account their differences. This broad approach of the standard is primarily due to the lack of information on engineering properties on soils and the distribution of different soils related to North Slope transportation systems. Our project is part of a larger effort to provide tools for optimizing Arctic transportation networks for the benefit of industry and agencies. Project efforts have characterized soils in key areas related to oil and gas development, adapted soil -freezing thermal models to help generate predictive forecast tools to help industry and agencies better plan for tundra management openings. We are also developing strength of freezing and frozen soil relationships with other soil properties to help evaluate the potential for standards based on ice road usage and planned loads. Prediction (forecast) of soil temperature depends on prediction of the weekly air temperature and snow conditions. Our preliminary evaluations show that soil temperature is less sensitive to daily variability in air temperature. The combined outcome of our studies will help to better define the relationship of soil types and soil properties needed for different transportation applications, and when these conditions are met each season. These combined efforts will help provide better tools for both industry and agencies to design, build, maintain, and regulate Arctic transportation networks over various Arctic soil terrains. THE USE OF LAKES AND RESERVOIRS INARCTIC TRANSPORTATION NETWORKS AND APPLICATIONS OF ADAPTIVE WATER RESOURCES MANAGEMENT TO IMPROVE WATER AVAILAB►LITY WHILE REDUCING ENVIRONMENTAL RISKS Michael R. Lilly (mlilly@gwscientific.com)', Horacio Toniolo2, Vlad Romanovsky2, Jessica Cherry2, Yuri Shurz, Matthew Bray2, Chien-Lu Pin2, Gary Michaelson2, Ron Paetzold', Jeffrey Derry', Gerald Sehlke3 ' Geo-Watersheds Scientific, PO Box 81538, Fairbanks, Alaska, 99708, Tel: 907-479-8891, Fax: 907-479-8893, 2 University of Alaska Fairbanks 31daho National Laboratory Lakes and man-made reservoirs have had a long history of use on the North Slope, Alaska. Management methods and regulatory approaches have primarily taken place in the central coastal plain, which has a high density of natural lakes. These lakes are characteristically shallow thaw lakes, where winter ice formation and protection of overwintering fish habitat are two of the primary factors impacting management and regulatory approaches for industry water use. The general abundance of water led to the development of fairly simple water management approaches. Recent increases in the number of water users, due to exploration by a greater number of companies, exploration in areas outside the central coastal plain, and competing uses for water over the annual water year are increasing the limitations industry has to manage each year they rebuild seasonal ice -road networks. Meanwhile, management agencies are facing new questions associated with climate change and development in areas with poor background data. Through an active program with agencies and industry, we have developed tools and approaches to better manage water resources in Arctic regions. The application of these tools will allow adaptive management to changing conditions, incorporation of new water -resource information, and an increase in the number of water users and competing uses for water over the hydrologic year. These tools include ice -growth calculation schemes designed for industry water use needs, and the application of watershed delineation tools to estimate potential recharge estimates. Continued project efforts are looking at validation methods to continue to the development of these tools and their application to industry and agency users. The incorporation of these tools and evaluation of hydrologic systems in both Canada and the US will help meet the growing needs for water in Arctic transportation systems FISHERIES RESEARCH IN SUPPORT OF FISHERIES AND OCEANS CANADA'S REGULATORY ROLE IN HYDROCARBON DEVELOPMENT IN THE CANADIAN BEAUFORT SEA Andrew R. Majewski' and Jim D. Reist' 'Arctic Aquatic Research Division, Fisheries and Oceans Canada, 501 University Crescent Winnipeg, Manitoba R3T 2N6 The proposed Mackenzie Valley Pipeline Project has sparked renewed intensive oil and gas exploration in the Beaufort Sea. Governmental regulators and resource managers are tasked with assessing the impacts of multiple stressors, including anthropogenic activities, on the region's natural environment, including fish and fish habitat. While proponents are tasked with collecting data in support of Comprehensive Studies under the Canadian Environmental Assessment Act (CEAA), the federal government is mandated to provide unbiased, credible science on behalf of Canadians in order to fulfill its regulatory role. The scope of government science is to conduct regional ecosystem research, and baseline data collection, so Environmental Assessments (EA's) can be cast in the context of the broader ecosystem and the cumulative impacts of multiple stressors. Ere] r1 • Despite considerable research focus on the biological and physical makeup of the Beaufort Sea during the last period of extensive oil and gas exploration in the late 1970s and early 1980s, the complex dynamics of the Beaufort Sea and its biota are still poorly understood. Fisheries and Oceans Canada's (DFO's) Northern Coastal Marine Studies program (NCMS), 2003 - 2009, was a multidisciplinary study aimed at characterizing the physical and biological nature of the Canadian Beaufort Shelf. Marine fish surveys were conducted from the Canadian Coast Guard Ship (CCGS) Nahidik to study the composition and spatial distribution of fish relative to physical and chemical habitat parameters, and to contribute to the general biological and ecological information on offshore fish populations. In 2010, DFO initiated a pilot monitoring study (ACES, Arctic Coastal Ecosystem Studies) in the newly established Tarium Niryutait Marine Protected Area (TNMPA) to update baseline information and assess the feasibility of proposed indicators of ecosystem change. Herein, we provide an overview of these studies as they relate to DFO's role in conducting science to support its regul atory mandate. HYDROLOGYAND NORTHERN PIPELINES: HAZARDS AND ENVIRONMENTAL PROTECTION Philip Marsh (philip.marsh@ec.gc.ca)' and Stefano Endrizzi2 1 National Hydrology Research Centre Environment Canada 11 Innovation Blvd. Saskatoon, SK S7N 3H5 Canada m306-975-5752 306-975-5143 (Fax) 2 University of Zurich, Zurich, Switzerland Development of pipelines in northern Canada will require detailed hydrologic information (may include streamflow, snow cover, soil moisture, lateral surface or subsurface flow, and soil freezing/thawing for example) to ensure appropriate pipeline design and to minimize environmental impacts. Unfortunately, appropriate data is extremely sparse in these frontier areas. Streamflow observations for example are only available for a small percentage of streams that will be crossed by pipelines or used for water supply during construction, and for those streams with observations, the record is often too short for statistically robust estimates of flows. In addition, information on snow cover, soil moisture, frozen soil conditions, or active layer thickness for example are generally not observed on a routine basis. Given this lack of appropriate hydrologic data, observations must be supplemented by model estimates. To help address this issue, Environment Canada has been involved in the testing and development of hydrologic models for use in cold regions through the Mackenzie GEWEX Study (MAGS); Improved Processes, Parameterization, and Prediction (IP3); and the International Polar Year (IPY). These models consider the fully coupled surface/subsurface water and energy budget at spatial resolutions from metres to kilometers over drainage basins ranging in size from a hundreds to thousands of km2. This paper will demonstrate the capability of these models at a small number of sites in northern Canada where pipelines may be constructed in the coming years. We will also discuss the need to test these models in a larger range of vegetation, permafrost, and geological conditions in northern Canada to be useful for future pipeline design and construction. Additionally, since climate change is resulting in data sets that are no longer stationary, we will consider whether these hydrologic models, driven by appropriate regional climate or weather models, can consider the effect of a changing climate on the hydrologic regime. THE U.S MARINE MAMMAL PROTECTION ACT INCIDENTAL TAKE AUTHORIZATION PROCESS: CHALLENGES IN THE ARCTIC Candace Nachman (Candace.Nachman@noaa.gov)', Shane Guan' 1 U.S. National Marine Fisheries Service, National Oceanic and Atmospheric Administration The U.S. National Marine Fisheries Service, Office of Protected Resources (NMFS) is responsible for implementing Sections 101(a)(5)(A) and (D) of the U.S. Marine Mammal Protection Act (MMPA), which allow for the incidental "take" of marine mammals during activities other than commercial fishing, including oil and gas exploration and development activities in the Arctic. In order to issue an incidental take authorization (ITA), NMFS must find that the activity will have a negligible impact on the species or stock(s) and that there will not be an unmitigable adverse impact on the availability of the species or stock(s) for subsistence uses. Additionally, in each ITA, NMFS must set forth the permissible methods of taking and mitigation and monitoring measures to minimize potential impacts on marine mammals. To address these issues, NMFS conducts a thorough review of the proposed action and the potential effects to marine mammals and their habitat and to subsistence activities in the project area, including the applicant's proposed measures to reduce impacts to the species and subsistence hunting. This presentation provides an overview of the following: (1) A summary of NMFS' MMPA ITA process, including the interaction with the U.S. Endangered Species Act and U.S. National Environmental Policy Act; (2) A detailed discussion of the information required from applicants; (3) A discussion of general mitigation and monitoring requirements and some common examples; (4) A discussion of potential conflicts with subsistence users and ways to mitigate such conflicts; and (5) Areas where additional scientific studies could help inform NMFS' analyses on negligible impact, impacts to subsistence uses, and cumulative effects. DISTRIBUTIONS OF EP►BENTHIC MA CROINVERTEBRA TES IN THE NORTHEASTERN CHUKCHI SEA, 2009 Carrie Parris (belben@sfos.uaf.edu) I and Arny L. Blanchard' ' Institute of Marine Science, University of Alaska Fairbanks, Fairbanks, 99775 In 2008, a multi -year, interdisciplinary study was initiated in the vicinity of two proposed oil and gas exploration areas in the northeastern Chukchi Sea. This study was sponsored by ConocoPhillips and Shell Exploration and Production Company to collect information on the ecosystem in these areas prior to exploration and provide environmental data 41 useful for permit applications and for post -development comparisons. Sampling for epibenthic macroi nverteb rates In was included in the science program in August and October, 2009 and September, 2010. Macroinvertebrates were sampled at 26 sites with a 3 in plumb -staff beam trawl with 4 min codend liner. Overall abundance was high in both areas although the Burger study area had significantly higher abundances of epibenthic invertebrates compared to Klondike. Biomass was comparable between the two areas. The most dominant taxa included barnacles (Balanus spp.), snow crab (Chionocetes opilio), brittle stars (Ophiura sarsi), hermit crabs and shrimp belonging to the family Pandalidae. Biomass was also dominated by the sea stars Leptasterias spp. Differences in the macroinvertebrate communities resulting from environmental gradients were reflected in the higher biomass of shrimps and sea cucumbers at Klondike and amphipods and basket stars at Burger. Preliminary results from the 2010 program are also presented. OBSERVING THE SNOW AND ICE PROPERTIES IN THE ARCTIC COASTAL WATERS OF THE CANADIAN BEA UFORT SEA WITH HELICOPTER -BORNE GROUND-PPENETRATING RADAR, LASER AND ELECTROMAGNETIC SENSORS. Simon Prinsenberei, Ingrid Peterson', Scott Hollidayz and Louis Lalumiere3 'Fisheries and Oceans Canada, Bedford Institute of Oceanography, P.O. Box 1006, Dartmouth, N.S., B2Y 4A2 2 Geosensors Inc., 66 Mann Ave., Toronto, Ontario, M4S 2Y3 3 Sensors by Design Ltd.,100 Peevers Crescent, Newmarket, Ontario, L3Y 7T1 A unique data set that was collected with helicopter -borne sensors during April 2010 over the Mackenzie Delta land - fast and mobile ice cover areas. For the first time a Ground - Penetrating -Radar provided in real-time snow depths and ice thicknesses of low saline ice and complemented the Electromagnetic -Laser and Video -Laser data sets to explain the ice and snow properties found in the Mackenzie Delta. In the shallow inshore delta areas where river runoff dilutes the oceanic water such as the Mackenzie Delta, the GPR and EM together can determine the floating, grounded ice conditions from the ice frozen to the bottom where the EM on its own only indicates areas where the ice is attached to the frozen mud layer. In these low saline areas the GPR can measure both the snow depth and ice thickness. The laser brightness when height corrected appears to be an additional observation tool to pin point small young leads and darker ice features (gravel bars). The snow and ice data represents a large spatial distribution to derive ice and snow statistics and to validate ice signatures seen in ASAR imagery in support of Oil & Gas offshore structure designs and navigation. All data and reports are available at: http://www.mar.dfo- mpo.gc.ca/science/ocean/seaice/public.htmI • THE ARCTIC REGULATORYAND STAKEHOLDER EXPERIENCE Gene Pavia (gene.pavia@uicumiaq.com)' and Shannon Blue' 1 Ukpeagvik Inupiat Corporation, Anchorage AK UMIAQ is a member of the Ukpeayvik Inupiat Corporation (UIC) Family of Companies. UIC was incorporated in 1973 pursuant to the Alaska Native Claims Settlement Act as the Village Corporation of Barrow, Alaska. UIC provides social and economic benefits to its more than 2,200 Inupiat shareholders and incorporates the traditions and values of our ancestors into our business practices. UMIAQ technical professionals have decades of experience with strategic planning, permitting, response operations, oilfield services, architecture, engineering and surveying. Our understanding of the Arctic's operating and logistical challenges, federal, state, and local permitting processes integrated with active local, regional, and regulatory stakeholder engagement has played a key role in advancing onshore and offshore energy projects. Alaska hosts a stringent regulatory environment with litigious stakeholders. Understanding the Social, Political, Operational, Regulatory, and Technical (SPORT) drivers that shape onshore and offshore oil and gas projects is imperative to working in the Alaska. Increased regulatory and stakeholder scrutiny is anticipated in the wake of the Macondo Blowout, resulting in additional delays and regulatory burdens here in Alaska as well as in other domestic and international settings. Energy project approvals are negotiated with regulatory decision makers. Laws, regulations, policies, and people dictate successful project approval acquisitions. A regulatory road map that includes front -loading pre -application processes and active approval facilitation surfaces project constraints early, and allows active management of baseline data requirements, project approval criteria, mitigation, and compliance strategies. Refined regulatory approaches and methods have proved successful in securing usable regulatory approvals while minimizing the risk of delays introduced by successful appeals and litigation challenges. Executing a robust regulatory plan that integrates and balances SPORT drivers with proactive stakeholder outreach plays a key role in advancing energy projects in Alaska. USING PASSIVE ACOUSTICS TO MONITOR ANTHROPOGENICACTIVITY IN THE CHUKCHI AND BEAUFORT SEAS Ethan H Roth (ehroth@ucsd.edu)', John A. Hildebrand', and Sean M. Wiggins' ' Marine Physical Laboratory, Scripps Institution of Oceanography, San Diego, California 92093-0205 In recent years, the Western Arctic has been on the verge of a fundamental shift towards seasonal ice cover, which has given way to unprecedented anthropogenic activity offshore of Alaska's North Slope. Since 2006, we have been using a variety of passive acoustic tools to monitor underwater environments across the Arctic in order to characterize the 42 r� �J • r� ambient sound -field, while also observing seasonal fluctuations in anthropogenic noise. Long-term monitoring techniques are providing us with great insight into Arctic acoustic ecology on large spatial and temporal scales. By statistically quantifying the distribution of received noise levels across the sound spectrum, we can examine the cumulative contribution of sound exposure from seismic exploration surveys that have been occurring simultaneously in both the Chukchi and Beaufort Seas over several months of each year. We've also conducted several shipboard experiments in order to characterize the variability of a modern icebreaker's noise signature in several modes of operation. These modes include open water transiting, ice -breaking (backing and ramming) in 10/10's ice cover, and while stationary with the bow thruster in operation. We find that - compared to open water transit - an icebreaker's noise signature can increase approximately 10 dB in the frequency band between 20 Hz and 2 kHz while breaking ice. In addition, while the ship is engaged in backing and ramming maneuvers, the largest modulation in the noise signature results from severe cavitation of the propellers while operating astern. In bands centered near 10, 50, and 100 Hz, source levels were shown to increase 5-15 dB during such modes of propulsion. As trends in Arctic sea ice dynamics continue to shift and allow for increased vessel activity, geophysical exploration, and resource extraction, further monitoring of sound sources and ambient noise is essential when considering sound exposure to marine mammals. DISTRIBUTION AND MIGRATORY TIMING OF THREATENED SPECTACLED EIDERS IN THE BEAUFORT AND EASTERN CHUKCHI SEAS Matt Sexson', Margaret R. Petersenz, and Abby N. Powe113 ' U.S. Geological Survey, Alaska Science Center 4210 University Drive Anchorage, AK 99508 Office Phone: 907- 786-7177 Cell Phone: 907-317-4717 Fax: 907-786-7021 E- mail: msexson@usgs.gov 2 USGS Alaska Science Center, Anchorage, AK 99508 3 USGS Alaska Cooperative Fish & Wildlife Research Unit, and Institute of Arctic Biology, University of Alaska, Fairbanks, AK 99775 The Beaufort and eastern Chukchi seas are important areas for birds that breed in Arctic Siberia, Alaska, and Canada. Spectacled Eiders, large sea ducks listed as 'Threatened' under the U.S. Endangered Species Act, stage and molt in the Beaufort and eastern Chukchi seas annually. To learn more about the distribution and migratory timing of Spectacled Eiders, we implanted satellite transmitters in juvenile (2010, n =13) and adult (2009, n = 21; 2010, n = 16) eiders at nesting areas in northern Alaska. Early results from our ongoing study showed that eiders occupied areas in the eastern Chukchi Sea between the months of May and October, and the Beaufort Sea between June and September. In both seas, the density of eiders was greatest (50% fixed kernel) within 30 km of the coast of Alaska. Eiders were located near (within 25 km) or within active oil and gas leases in both seas (Chukchi, n = 3; Beaufort, n = 36). With abundant natural resources in the arctic, it is critical that we consider the spatiotemporal distribution of Spectacled Eiders and plan industrial activities to allow for the continued recovery of the species. UNDERSTANDING NEARSHORE PROCESSES OF A LARGE ARCTIC DELTA USING COMBINED SEABED MAPPING, IN SITU OBSERVATIONS, REMOTE SENSING AND MODELING Steven Solomon', Nicole Couture, Donald Forbes, Azharul Hoque, Kimberley Jenner, Gwyn Lintern, Ryan Mulligan, Will Perrie, Christopher Stevens, Bechara J. Toulany, Dustin Whalen ' Natural Resources Canada Geological Survey of Canada PO Box 1006 1 Challenger Drive Dartmouth, NS B2Y 4A2 (902) 426-8911 (902) 209-2713 (cell) The Mackenzie River Delta and the adjacent continental shelf are known to host significant quantities of hydrocarbons. Recent environmental reviews of proposed hydrocarbon development have highlighted the need for a better understanding of the processes that control sediment transport and coastal stability. Over the past several years field surveys have been undertaken in winter, spring and summer to acquire data on seabed morphology, sediment properties, sea ice, river -ocean interaction and nearshore oceanography. The timing and location of sediment erosion and deposition is complex, driven by storms during open water and spring flooding during ice break-up. Unlike temperate river deltas, the interaction between the Mackenzie River and the Beaufort Sea during spring freshet is mediated by the presence of ice cover. When the river discharge exceeds the under -ice flow capacity, the ice surface floods, followed by vortex drainage through the ice ("strudel" drainage) which scours the seabed below. Recent surveys have shown that the low gradient inner shelf is composed of extensive shoals where ice freezes to the seabed and intervening zones which are slightly deeper than the ice is thick. The duration of ice contact with the bed determines the thermal characteristics of the seabed which may be underlain by permafrost. Sediment cores and ground penetrating radar surveys over the shoals show that they are composed of well -sorted and cross -laminated silt arranged in seaward dipping foresets indicating an active delta front environment. Measurements of waves, currents, conductivity, temperature and sediment concentration during spring and late summer have been acquired over the past 4 years. During moderate August storm events, wave s attenuate rapidly inshore of the 3 m isobath. Entrainment of fine material and rapid flocculation due to the presence of brackish water may induce the transient formation of high density suspensions near the seabed which contributes to this rapid attenuation 43 CONTROLS ON PERMAFROST DISTRIBUTION WITHIN THE NEAR -SHORE ZONE OF THE MACKENZIE DELTA Christopher W. Stevens', Brian J. Moorman2 and Steve M. Solomon3 1 Department of Geoscience University of Calgary 2500 University Dr. N.W. Calgary, Alberta T2N 1N4 Canada 2 Department of Geography, University of Calgary, Calgary, Alberta 3 Geological Survey of Canada, Dartmouth, Nova Scotia Permafrost presents a significant challenge to proposed oil and gas development in the Mackenzie Delta, due to its influence on the stability of linear infrastructure and foundation conditions. Environmentally safe and economically sustainable development in this region requires an understanding of the spatial variability of ground temperatures and the response of permafrost to natural and human -induced changes of the environment Recent research conducted by the University of Calgary and the Geological Survey of Canada has investigated permafrost beneath shallow -water environments seaward of the modern delta front This work has incorporated the use of field -based temperature, drill and geophysical measurements with numerical thermal modeling and satellite remote sensing. The findings of this study indicate that ground temperatures are mainly controlled by the presence of liquid water or ice at the sediment bed. Where ice freezes to the sediment bed •surface (i.e. becomes bottom -fast) conductive transfer between cold air temperatures and relatively warmer underlying sediments leads to heat loss throughout the winter. Interannual variability in ground temperatures results from changes in on -ice snow thickness, which modifies the duration of bottom -fast ice (BFI) and subsequent heat loss from the ground. Thermal modeling indicates that the critical ice contact time for sustaining permafrost beneath near -shore zones of BFI is 142 days. The integration of this finding with a time -series of synthetic aperture radar images, which defines the timing of BFI across the near -shore zone, produced the first map of shallow -water permafrost for the outer Mackenzie Delta. Permafrost was mapped beneath 393.8 km2 of BFI. These locations typically represent areas where sediment supply exceeds present-day sea level rise. As hydrocarbon exploration and development proceeds in the Mackenzie Delta, the recent advancements in monitoring permafrost beneath shallow water and ice will become critical to the • planning and the regulation of development in this dynamic and climatically sensitive environment USING POSITION BEACONS TO MEASURE ICE MOVEMENT FOR BEAUFORT AND CHUKCHI OFFSHORE PETROLEUM ACTIVITIES Tyler Sylvestrel, Scott Tiffin', Svetlana Machurina', Mauricio Muenos', Roger Pilkington' ' CANATEC Associates International Ltd. Alastair Ross Technology Centre Suite 122, 3553 - 31st Street N.W. Calgary, Alberta, Canada T21, 2K7 Measuring the movement of different types of sea ice in the Arctic is critical for offshore petroleum operations, marine transport and public regulation to mitigate global warming. Beacons using GPS and satellite transceivers are useful to study: drift and disintegration of ice islands and multiyear hummock fields over several years; microdisplacement of shore fast ice; incursions of different ice types into potential shipping lanes; movement of pack ice over wellsites and into seismic exploration areas; drift of oil spill plumes under ice; and ice loads on structures. There are a variety of instruments available on the market for using different locational and transceiving technologies which function in different regimes of ice and water. Extreme temperatures, remote locations, dynamic ice and marine environments, snow cover, polar bears and arctic foxes all impose significant design constraints and limit the functionality on these instruments, often in ways that the manufacturers are unaware or simply cannot cope with yet Delivery by air or surface is expensive and sometimes involves hazardous operations. Beacons are often best used in some combination with satellite imaging; lessons from recent projects are suggested in how to optimize this complementary use in terms of minimum cost, operational reliability and completeness of data acquisition. New beacons are coming on the market with radically improved accuracies, functionality and lower cost New developments in power supplies, software and miniaturization of sensors also offer the possibility of developing more complex instruments with additional sensors which can be air dropped or delivered by drones. The trend to more complete, robotic systems is driven not only by technological opportunities and lowering costs, but by increased concerns of operators about safety to personnel. 44 • • • FORUM SPONSORS Indian and Northern Affairs Canada Environment Canada - Natural Resources Canada North Slope Science Initiative Alaska Natural Gas Projects, Office of the Federal Coordinator BOEMRE 45 • FORUM PARTNERS Thankyou to members of the Executive Committee, the Organizing Committee, and the Facilitators who contributed their time and effort towards making this Forum possible. Executive Committee Mimi Fortier Director General, Northern Oil and Gas Branch, Indian and Northern Affairs Gatineau, QC Dr Holly Bamford A/ Deputy Assistant Administrator, National Ocean Service, National Oceanic and Atmospheric Administration, Washington, DC RADM Chris Colvin Commander of the 17th District, United States Coast Guard, U.S. Department of Homeland Security, Juneau, AK Dr Marc D'Iorio Director General, Natural Resources Canada, Office of Energy and Research Development, Ottawa, ON Dr Martin Fortier Executive Director, ArcticNet, Qu6bec, QC • Julia Gourley Senior Arctic Official for the United States, Bureau of Oceans and International Environmental and Scientific Affairs, U.S. Department of State, Washington, DC Jennifer Loten Consul, Consulate of Canada in Anchorage, Anchorage, AK Marcia McNutt Director, United States Geological Survey, U.S. Department of the Interior Washington, DC Larry Persily Federal Coordinator, Office of the Federal Coordinator, Alaska Natural Gas Transportation Projects Washington, DC Michael Peters Manager, Northern Canada Operations, Canadian Association of Petroleum Producers, Calgary, AB Dr Norm Snow Executive Director, Inuvialuit Joint Secretariat, Inuvik, NWT Dr Robert Steedman Professional Leader, Environment, National Energy Board, Calgary, AB Jeff Wiese Associate Administrator for Pipeline Safety, U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration Washington, DC • 46 Organizing Committee • Michael Baffrey U.S. Department of the Interior, Anchorage, AK Genevieve Carr Indian and Northern Affairs Canada, Gatineau, QC Norman Custard United States Coast Guard, Juneau, AK Jess Dunford National Energy Board, Calgary, AB Martin Fortier ArcticNet, Quebec, QC Mike Fournier Environment Canada, Yellowknife, NT Rachel Halpern U.S. Department of the Energy, Washington, DC Felicia Minotti Department of Foreign Affairs and International Trade, Ottawa, ON Ivana Kubat Canadian Hydraulics Centre, National Research Council, Ottawa, ON Lisa Loseto Department of Fisheries and Oceans, Winnipeg, MB Adrian Manlagnit Natural Resources Canada, Ottawa, ON Tara Paull Indian and Northern Affairs Canada, Gatineau, QC John F Payne North Slope Science Initiative, Anchorage, AK Mike Peters Canadian Association of Petroleum Producers, Calgary, AB • Brenda Pierce U.S. Geological Survey, U.S. Department of the Interior, Reston, VA Pamela Romanchuk National Energy Board, Calgary, AB Brent Sheets National Energy Technology Laboratory, U.S. Department of the Energy, Fairbanks, AK Sharon Smith Geological Survey of Canada, Natural Resources Canada, Ottawa, ON Norm Snow Inuvialuit Joint Secretariat, Inuvik, NT Steve Solomon Geological Survey of Canada, Natural Resources Canada, Dartmouth, NS Jennifer Thompson Office of the Federal Coordinator, Alaska Natural Gas Transportation Projects, Washington, DC Dennis Thurston Bureau of Ocean Energy Management, Regulation and Enforcement, Anchorage, AK Garry Timco Canadian Hydraulics Centre, National Research Council, Ottawa, ON Facilitators Susan Fox Arctic Research Consortium of the US Julie Griswold Bureau of Ocean Energy Management, Regulation and Enforcement, Anchorage, AK • Helen Wiggins Canadian Hydraulics Centre, National Research Council, Ottawa, ON 47 0 0 Ot IN RESTAVRAN- 4 s RR V, I C, F. WASJ IROO-U', FLOORPLAN . I - - -11 REG!S*M%-1": LOBBY ESCALATORS Lui U LEI L.J U Loi UtAIND FOYER A qr Nhr-1,014 2 1 NUL-WJN 3 N E I —IS M 71-7-7- IPIAI C ' WE-tcem ca M&-'FIUAL DJMIAL 11AUTIMM AAHROOV. 2 IMPERIAL. j4p RMjJZ(3O%j BALI ' 3 4 CAULNI) K)- V r-'I Hyatt Regency Calgary 48 • 1-1 • An offshore project saved over $24 million in reduced non productive time by incorporating a wellbore design using solid expandable technology. Expanding well design By ensuring optimal hole size, well designs using solid expandable tubulars have a far-reaching effect on drilling, evaluation, completion and life -of -well solutions. Enventure Global Technology's Kevin Waddell, Jerry Fritsch and Kristaq Mitrushi discuss the growing influence of solid expandables on well design. he challenges of offshore exploration and development drilling require that operators - now more than ever - adopt and implement new technology to mitigate risks and ensure success. A major innovation in achieving these objectives is solid expandable technology and its increasing use as a proactive tool in the design of offshore wells - especially in deepwater. In contrast with its roots as a contingency response in extreme wellbores, the emerging role of expandable technology in well designs is aimed at improving drilling efficiency and enhancing evaluation, completion, and long-term productivity. Instead of a reactive technique for well construction, this planned application focuses on optimizing return on investment. By improving offshore economics, expandable well designs are redefining prospect viability and creating new opportunities for existing assets. Extreme experience Solid expandable tubulars have a long, successful track record. Over 1,000,000ft of pipe have been reliably expanded in over 1100 installations globally, in land and offshore applications. Successful tool performance in these wells, many with very challenging downhole environments, is 95%. With this success and continued technology development, expandable applications have grown from contingency applications to planned solutions. For deepwater wells, this is proving to be an exceptional advantage. Solid expandable tubulars are being used to address risks due to borehole instability, improve zonal isolation, and reach target depth with an optimum wellbore diameter. There is already a high degree of expandable experience in deepwater wells across a range of sizes and applications. Enventure Global Technology has performed 34 installations with an expandable shoe set below 20,000ft - the deepest sitting just shy of 29,000ft. Additionally, expandable liners have been used on rigs water depths in excess of 7000ft and in wellbores with temperatures nearing 400oF. The most common size in these ultra -deep installations is the 95/8 x 11'/4in expandable system, but a range of sizes and depths are found globally. This extreme working environment has provided a substantial school of learning. One of the most important subjects: planning. Big picture Planning is important to meet specific well objectives and address unique challenges. But the repercussions of a less -than -optimal hole size constrains many aspects of the well's success. A smaller wellbore can significantly affect the overall economics of a project. Poor efficiency and degraded capabilities for logging and completion limit asset performance. Reduced production through a restricted wellbore can be a very costly, especially over the life of the well. An expandable has traditionally been used to address problems when they arise; however, design decisions involving expandables are now being made early in the process to optimally integrate performance characteristics with the geology and well objectives. This helps avoid limiting hole size because of reactive decisions made in the drilling process. Instead, a more holistic approach starts with considering what can be done to ensure optimal hole size while balancing risk and benefit. Early planning takes advantage of expandable technology's core value: ensuring the optimal wellbore in the reservoir. In this respect, expandables Conventional 36' 26' 20" 13-5/8' 9-5/8' 7' 4-12' SET® System 36' 26' 20' 13-5/8' 11-7/8' 9-5/8' x 11-7/8" 1 SEr System 9-3/8' 7-5/8" x 9-3/8' SE T1 System are very much a facilitating tool for achieving the appropriate completion. The lithology and the reservoir drive planning considerations: how complex is it, what is its potential and how big does the hole need to be? This doesn't exclude the value within the actual drilling process. Expandables mitigate problems associated with lengthy openhole exposure caused by efforts to reach a planned casing point, or trying to make up for one already lost. In addition, expandables lower costs by reducing the need for a tie -back, and by eliminating the expense and risk of fighting kick/loss scenarios in narrow pore pressure/fracture gradient windows. But more wellbore room also directly impacts the hardware used to drill, evaluate, and complete the well. A larger hole improves efficiency by allowing bigger drilling tools that typically drill farther and faster with fewer failures than smaller systems. Hole diameter also has a major role in how the well is evaluated, completed, and maintained. Size is a significant factor in the capabilities of logging tools and instruments for drill stem tests, vertical seismic profiling, and coring operations. The data acquired from these devices is used to evaluate the well for exploratory, appraisal, and development activities that determine strategies and expenditures of hundreds of millions of dollars. Over the life of the well, a larger Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe.oiIonIino.com For reprints please contact the Publisher. OFFSHORE ENGINEER I november 2010 49 engineers and operations personnel review and evaluate parameters such as wellbore conditions, mud weight, temperatures, inclination and dogleg zs• severity. If the well parameters are closer to the border -line of the operating • 20 envelope, additional evaluations such 16 as torque and drag calculations, and compression forces are performed to 11-3,4' x 133/8' 5ET• System evaluate feasibility. 13-3/8' In the next planning step, operations - associated risks are identified and 113/4' mitigated. For instance, before the expandable system design is generated, all initial risks are identified in a registry, and appropriate preemptive risk mitigation techniques are applied. q.5 8' x 1t•3/4' SET' System An operations installations team then develops detailed job -specific 8 installation procedures. This planning includes all lessons learned from previous similar installations Then both the risk • is 61t, 7• Production string evaluation and installation procedure are reviewed, discussed and agreed By installing a high-performance cased- upon with the operator. The operator hole liner and an open hole liner, an embeds these risk mitigation techniques operator reached total depth using existing and installation procedure into the infrastructure. drilling program. Over time and through lessons learned, completion provides more options for it became apparent that installing an remedial work. Instead of constructing expandable at the last possible moment wells that have limited or no capacity would always present more risks and for an economic workover, the larger create more nonproductive time (NPT). wellbores achieved with expandables To start with, the well conditions are offer new design options for extending the already less than desirable. Second, the asset's productive lifespan. shortness of the planning stage may result in inadequate development of risk De -risking risk mitigation mitigation and installation procedures Solid expandable tubulars continue to with the operator, which can lead to help mitigate the risks and challenges miscommunication. In these scenarios, associated with offshore drilling. But the risk of improper judgments on the rig implementing a new technology in and during installation is often higher than of itself can carry its own risks. Over the necessary. last decade, solid expandable technology An operator in the Gulf of Mexico has undergone its own revolutions of learned this first-hand. Their first sorts - both in operational and technology exploratory well faced one problem after development. another without reaching the target The first years of expandable installations, usually in exceptionally difficult hole conditions, provided a substantial learning curve. That learning curve created a very effective process for ensuring successful expansion and operation of the expandable system. This process starts with evaluating not only the well in question but the actual goals of that well. For instance, evaluating the full scope of unknown and known wellbore risks may result in a decision to install an expandable higher in the well design. This planning decision ensures that more options exist further down the well if additional casing strings are needed. Once the well has been evaluated for design considerations, additional well information is gathered to ensure that the operations are within the expandable's operating parameters. Expandable Content is copyright protected a OFFSHORE ENGINEER I november 2010 For reprints please contact the Publisher. an objective. In the second attempt, two expandables were included in the design - both contingency. One system was planned for just below the 95/8in casing while the second was installed in the Tin. casing. Even though both expandables were successfully installed, a significant amount of NPT continued to plague the well design. In the third well, one expandable section was planned higher in the wellbore, directly below the 11'/8in casing. Then a second expandable was planned as a contingency below the 93/8in casing. Both were installed - at a savings of over $24 million in reduced NPT. An application that offers the most value almost always is associated with close collaboration between the expandable service provider and the operator's reservoir engineering and drilling departments. This allows both parties to evaluate the best solution for maximizing return on investment and long-term sustainability of the reservoir. A better system Over the past decade, solid expandable systems have been enhanced to provide better drill -out, more robust connections and increased burst and collapse rating. These advances have extended the use of expandables to even more demanding applications. A 2006 upgrade to the expansion tool dramatically reduced the amount of material drilled out after expansion. Continuing advances in expandable connections are also pushing the envelope of expandable technology application. Most recently, high-performance expandables in 75/8 x 95/8in (4750psi collapse) and 113/4 x 133/8in (3680psi collapse) systems have been developed and installed. The collapse pressures compare to respective collapse pressures of 2650 and 1190 with standard expandable pipe. Both options were developed for Careful review of projects helps ensure that risks are identified and mitigated prior to installation. This process has led to a 95% reliability rate of expandable systems. provided for personal use only - not for reproduction or retransmission. http://oe.oiIon11ne.com offshore applications and have proven value in domestic and international waters. The first high-performance application was in the North Sea. The goal was to isolate a high-pressure interval to drill '• the next weaker formation with a lower mud weight. Conserving hole size in the high-pressure interval enabled a successful 5 x 41/2in completion and extended the production life of the well an estimated seven years. Most recently, an operator sidetracking out of an existing well was left with severely damaged 133/sin casing due to wear. Since the first sidetrack was not able to reach the target depth, a second sidetrack would require a repair to the 133/8in casing. The operator installed a high-performance 113/4 x 133/8in cased -hole liner to reinforce the casing and repair the damaged section. In addition, the operator chose to plan -in a 91/8 x 113/4in openhole liner to extend the shoe lower in the same wellbore. By incorporating both cased -hole and openhole systems, the operator was able to successfully complete the sidetrack and evaluate the target formation. The future Risk isn't always in the form of success • or failure. It can often take the form of: high NPT, over -exceeded budgets and AFE, poor reservoir evaluation, and/or a less -than -adequately constructed wellbore resulting in an ID that's too small at TD. Today, proactive well design using solid expandable tubulars is a central point of success in a growing number of offshore wells. These applications enhance efficiency and productivity by ensuring an optimal hole size that benefits drilling, evaluation, and completions for lifecycle well management. The result is a significant improvement in the economics of exploration and development assets across the globe. OE Kevin Waddell, a 29-year industry veteran who joined Enventure in 1999, is the vice president of technology and marketing overseeing the strategic planning, development and commercialization of SET technology globally. He has a bachelor's degree in geological engineering from the University of Arizona. Jerry Fritsch, Enventure's global solutions manager, has over 35 years' engineering and operations management experience, first with ConocoPhillips and now at Enventure. He has a bachelor's degree in mechanical engineering from LeTourneau University. • Kristaq Mitrushi is Enventure's senior operations manager, responsible for overseeing operations performance worldwide. Mitrushi, who joined the company in 2001, holds a bachelor's of geology and mining from the Polytechnic University of Tirana, Albania. ,Complete conference,_ lu I I (' ----1 The Drilling &Completing Troub D R I`� I" U & C O M P (E j f Zones conference, held last month T in Galveston, Texas, drew over r° u b e Z o n e s 25 attendees. The three-day event this year included a new feature, .w the Drilling Dynamics Workshop, which about a third of the attendees E '� 9 © X w�' _' participated in. The workshop included presentations like `An integrated approach to drilling dynamics, planning, identification and control' by Mark Dykstra of Shell, `MaxDrill drilling optimization processes' by Graham Mensa Wilmot of Chevron and `The evolution of ExxonMobil FastDrill Process' by Paul Pastusek of rf xonMobil, in addition to esentations by employeesSmith, Baker Hughes, Parker Drilling, and Halliburton. An open forum debate followed. Ray Vanegas, DCTZ event manager, says the workshop was added to the conference because `industry demanded optimal solutions to drilling dynamics and DCTZ is alway looking to bring new, relevant topics to the participants'. Sessions during the DCTZ included presentations on new technologies, land -based case histories, offshore - based case histories, completions, drilling, drilling dynamics, and regulatory issues. The event featured `a pretty heady list of presenters' that includes global experts who can share best practices,' Vanegas says. Another new element of DCTZ this year, Vanegas adds, was an electronic audience response system. `It's been a major hit,' he says, adding next year's advisory board will be used to build the 2011 event's session topics. Next year's DCTZ is slated for 18-20 October 2011 in Galveston. Petrobras has agreed to host the event Following on from this year's hosts ExxonMobil Development and Weatherford. CE Content is copyright protected and provided for personal use 52 OFFSHORE ENGINEER i november 2010 For reprints please contact al This report does nothing to assuage either public opinion or anger. Nothing in it will have persuaded the American public that the BP Macondo well design and execution was anything other than reckless.' Ian Fitzsimmons Macondo—the unfolding aftermath In his think piece for OEs July issue, consultant Ian Fitzsimmons drew parallels between the Deepwater Horizon tragedy and the earlier Titanic, Ixtoc-1, Piper Alpha, Comet and Challengerdisasters in terms of their presumed design infallibility. �01Here he turns his attention to the 200-plus pages of Macondo operator BP's accident report. BP's preliminary Deepwater Horizon —Accident Investigation Report makes uncomfortable reading. I use `preliminary' in the sense that ;5!t " the full facts surrounding the BOP have yet to be revealed, and the final chapter of this report cannot be written until that autopsy has been made public. The BOP is currently impounded, so e autopsy results could be a long time coming. e BP accident report is the first to be published, but it will not be the last. More accident reports prepared by public bodies and learned institutions will soon follow. The definitive account of the Deepwater Horizon accident has yet to be written. • In the meantime, this report is the best version of the events leading to the accident that we have. It has not met with general approval. Persistent claims by BP (repeated in the report) that the Macondo well design was safe have not been endorsed by any other operator in the Gulf of Mexico, including the Macondo joint venture partners. This report does nothing to assuage either public opinion or anger. Nothing in it will have persuaded the American public that the BP Macondo well design and execution was anything other than reckless; driven by cost -saving and schedule constraints, and without due regard for the safety of the rig crew. Figure 1 from BP's accident investigation report shows barriers breached and the relationship c barriers to cry factors (adapj from James Reason 1997). 016 Cc 22 OFFSHORE ENGINEER I november 2010 The report cites eight critical findings said to have contributed to the disaster, but makes no criticism of the well design and planning. Other contributory factors may eventually arise. The following overview covers the most critical aspects of the Macondo disaster, including selected quotes from the report to hopefully provide a better understanding of this terrible tragedy. It is, however, a work in progress. Long string design Summarising the BP position in respect of the long string completion (page 77, section 4.4) the report states: The investigation team determined that using a 91/ein liner x 7in long string production casing was an acceptable decision and provided a sound basisfor design.' Industry data in Mississippi Canyon Block 252 area also indicates that 57% of the wells used long strings, while approximately 36% used liners or liners with tie -backs.' The use of selective statistics to validate the Macondo well design is unacceptable. In the aftermath of this tragedy, the statistics have changed. Much the same could be said for the Wee 6itegrity Hrdroarbons Erieered the 1 Iydrocad*m Blowout Rroventer Was Not WeY tkidetected and Well Ignited on Did Not Sad Established or Control Was lost Do^-AW the Wed Failed Noraon For reprints please contact the Publisher. http:/Ioe.aiIanIine.com • Rated to Working P. R. • • rH P4 U_ Simplified process flow diagram of selected Deepwater Horizon surface equipment reproduced from BP's accident investigation report. Comet disasters. Its design was considered safe until it was demonstrably proved otherwise. In respect of the depth of the cement plug used (p65, s2.6), which should have been 1000ft in accordance with internal BP practice, the report states: `On the Macondo well, 1000ft of cement above the uppermost hydrocarbon sand would have placed the cement inside the previous casing string, potentially creating a trapped annulus and causing problems with annular pressure build up.' `The BP Macondo well team decided to place the TOC 500ft above the uppermost hydrocarbon -bearing sand, Per MMS regulations.' The following concerns arise: • The most popular response to the foregoing is that BP did not follow its own 1000ft cement guideline. The casing design was such that it was not possible to put 1000ft of cement in place. • Since the Macondo casing design did not permit compliance with the 1000ft BP recommendation (Section 5 ETP, GP 10.60 Zonal Isolation Requirements), it is difficult to understand how BP can claim that the well design was not at fault. 0 In mitigation of the foregoing, the same BP document states that if any reduction in the 1000ft requirement is planned, then TOC must be determined by a `proven cement evaluation technique, such as a cement evaluation log'. But no such log was performed. The foregoing appears to suggest that the well design limited the ability to run a full 1000ft plug and to run a full cement bond log. This claim has been repeated in the press and before public hearings. It remains to be seen if any operator, including BP, will elect to use this well design again. That will be the acid test for the Macondo well design. Cement testing The cement used for isolating the reservoir was not qualified for application on Macondo. You will not find these exact words anywhere in the report, but they are implied under the heading `Work that the investigation team was unable to conduct' (p189, s7): `Test nitrified cement slurry at downhole temperature and pressures.' Following the tragedy, BP carried out laboratory testing on the cement type used for Macondo. The results of the cement slurry tests, carried out at ambient surface pressure and temperature, clearly demonstrated this cement was neither suitable nor qualified for Macondo. Given that the cement plug was the primary barrier to isolate reservoir hydrocarbons from the wellbore and the environment, the decision to use this product for Macondo application was inexcusable. It was a reckless decision and it is obvious that the cement plug failed. The report is critical of those rig personnel (including BP) involved in the decision making process. Negative pressure test The purpose of the `negative' pressure test is to test the cement plug as the primary barrier to hydrocarbons. To generate the `negative' pressure required for the test, the drilling mud providing a stable, overbalanced, well condition, was partially replaced by seawater. As a result, the well became under - balanced (reservoir pressure exceeded hydrostatic pressure), thereby testing the integrity of the cement plug from below. The negative pressure test failed and the well began to flow. According to the report, this went unnoticed by the rig personnel. Not only had the cement plug failed, but the two flapper (check) valves in the cement shoe/float collar must also have failed. The following quotes refer to the observations made in the report: ... abnormal pressures observed during the negative - pressure test were indicative of a jailed or inconclusive test; however, the test was deemed successful.' (Hydrocarbons entered the well, p79, Analysis 5B) `The negative pressure test was accepted although well integrity had not been established. ' (p80, Key Finding 3) `The investigation team could not identify any established industry standards for conducting negative - pressure test, this is supported by expert testimony during the July 23 2010, MBI hearings.' (Conducted the negative -pressure test, p85, 2.4) Notwithstanding the foregoing, we find that subsequent displacement of the well to seawater again put the well in an underbalanced condition, allowing the well to flow (p89, s3). In light of the report extracts, we can only assume that supposedly competent rig personnel were responding to pressure from their managers. If you listen carefully, you can hear a faint echo from the Challenger tragedy. Mud gas separator (MGS) When control of the well had been lost, the diverter was closed, and for some incomprehensible reason, well fluid was diverted through the mud gas separator (MGS). A process flow schematic of the low pressure diverter system can be found on page 114 of the report. The MGS is part of the diverter system and, as its name suggests, conditions drilling mud returns. The schematic also illustrates the two large diameter vent lines (port and starboard) that should have been used to divert gas and well fluid overboard and freely vent to the environment. But that did not happen. Overwhelmed by gas and well fluid, the low pressure MGS exploded, resulting in the death of 11 crew members and eventually sinking the Deepwater Horizon. Executive summary I have read the BP report several times with growing discomfort. Its executive summary contains the saddest words I have ever encountered in an accident report (p104, paras 5-6): 'If the decision had been made to directflow low overboard rather than to the MGS, the subsequent diversion of flow overboard may have provided the rig crew more time to respond to the well control situation, and the consequences of the event would likely have been reduced.' > overleaf Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe.aiIanIine.com For reprints please Contact the Publisher. OFFSHORE ENGINEER I november 2010 23 z 0 z • • Cos nq CCemnm Lauer This quiet explanation confirms that even after the blowout, all was not lost and 11 men might have been saved. They still had a sporting chance. We will never know why the rig crew took their fateful decision. But it is easy to say that sitting in front of a computer in a comfortable study room. Within the offshore drilling community, there is a clear understanding that when well control is lost you vent the gas and fluid overboard and head for the lifeboats. No written procedure is required when faced with an obviously life - threatening danger; you just think about your loved ones and jump. The executive summary identifies eight major contributory factors that came together to cause the Deepwater Horizon tragedy. It is not possible to argue with those findings. But there is one glaring omission: the planning and design of the well is not mentioned as a contributory factor - quite the opposite. Considering the self-evident outcome, this is a shocking omission, and the one most likely to give rise to public anger. However, the published contributory factors as we currently understand them, are self-evident. We may find other contributory factors, but those already identified are sufficient to explain the tragedy. Partial conclusion Similarities with the tragic loss of the Titanic, and the destruction of the Comet and Challenger shuttle can be found Photograph taken by ROV of the lower end of the riser after it was cut, showing two sections of pipe inside. Well design options considered for the Macondo well. By comparison with the `liner' and `liner with tieback' options, the absence of conventional casing packers and bridging plugs iW from the from the `long string' design is obvious. echoing throughout Deepwater Horizon: accident investigation report. I have reviewed all eight contributory factors described in the executive summary. For the purposes of this article, I have only highlighted the most critical contributory issues as I see them. This does not mean I either disagree with, or have disregarded in any way, the other issues. Other contributory factors, for example well design, commercial/schedule considerations and management pressure, will surely be added to those listed. That process is already well under way. If I have anything to add to the debate, it concerns training - training people to expect both the unthinkable and failure; teaching them to cope with, and adapt to, both situations, and trying to rid them of the smug paradigm of familiarity. Long before pilots can fly and astronauts lift-off, they are trained in flight simulators. Thereafter they enter the simulator for testing on a yearly basis. Part of that training involves being fed with unpredictable events - curve balls and reverse swing, as some would say. Some of these events are non -recovery situations. Very few pilots, if any, have never crashed in a simulator under dire conditions. It occurs to me that we have something to learn from NASA and aircraft manufacturers. We should train our drilling crews in simulators, and on a regular basis. Such simulators already exist but are not mandatory for drilling crews. In return, we should present them with a safe well design, qualified cement, mandatory casing hanger lockdown assemblies, proven mechanical bridging plugs, massive deluge systems, high volume overboard vents, and improved BOP/ LMRP configurations and systems. I have not forgotten the BOP, our ultimate bulwark against loss of well control. Why did it fail the Deepwater Horizon? That story has still to be told. We do not know the full operational and service history of the Deepwater Horizon BOP. Perhaps it does not exist. BOPs may be big and ugly, but they still deserve respect and careful maintenance. They need health checks on an annual basis. Not just a strength test, but a system test. If only they could talk. OE © Ian Fitzsimmons I October 2010 Ian Fitzsimmons, a regular contributor to OE, is an independent consultant with more than 30 years' offshore industry experience. He has worked for major operators around the world and major subsea hardware/ drilling equipment contractors, and has extensive due diligence and expert witness experience. He was chief engineer for RJ Brown & Associates in London. The views expressed in this article are the author's own and do not necessarily reflect OEs position. ALL FIGURES REPRODUCED FROM DEEPWA TER HORIZON: ACCIDENT INVESTIGATION REPORT, SEPTEMBER 2010. COURTESY BP Content is copyright protected and provided for personal use only - not for reproduction or retransmission. 24 OFFSHORE ENGINEER I november 2010 For reprints please contact the Publisher. http://oe.oiIan11ne.com • • E Containment capability in the cross -hairs efforts and design of a containment Post-Macondo to improve well assembly, manifold, control containment capabilities umbilicals, accumulator, on both sides of the Atlantic dispersant injection moved into higher gear last equipment, risers and month. flowlines. Scheduled for a 2012 In the US it was confirmed completion, the containment that Technip will handle front- system will be 10,000ft water end engineering and design depth rated and capable of of a proposed subsea well capturing up to 10,0001o/d of containment system that could oil. be used to respond to another blowout in the deepwater Gulf Learning lessons of Mexico. Meanwhile the UK oil spill ExxonMobil, which prevention and response and is responsible for the advisory group (Osprag), set engineering, procurement and up in May to bring Macondo construction of the system incident learnings back to said Osprag chairman Mark McAllister, chief executive of Fairfield Energy. `Time is of the essence for minimising environmental impacts when bringing a well under control,' stressed Oil & Gas UK's Brian Kinkead, who leads the Osprag technical review group responsible for developing the capping concepts. `The cap design therefore needs to be compact, relatively low weight and flexible for ease of handling and installation in short operational weather windows.' on behalf of the Marine Well the UKCS, is commissioning Containment Company, did detailed designs for a full/ not disclose the value of the partial pressure capping Technip contract in a device. 7 October announcement. After evaluating three The organization's founding design concepts put forward members - ExxonMobil, by Wood Group Kenny, the Chevron, ConocoPhillips and group opted to progress with a Shell - have pledged an initial modular device it considered investment of $1 billion to best suited to typical UK develop the rapid -response continental shelf metocean system (OE August). The constraints, particularly four founding companies the severe wind and sea collectively have dedicated 100 conditions encountered West employees to work full-time on of Shetland. The detailed the project. design and procurement phase BP said last month it would will be project -led by BP, join the group and make working closely with Osprag available the equipment used and other UK operators. in its effort to contain and cap Manufacturing time is the Mississippi Canyon block currently estimated at around 252 Macondo well following 11 months. the 20 April explosion of `The design allows the Deepwater Horizon. The installation at various points equipment will be available to of the subsea wellhead, the respond to a potential blowout blowout preventer or lower while the new containment marine riser assembly to system is in development, stop the flow of oil and buy ExxonMobil said. valuable time for engineers The scope of the Technip to develop a permanent contract includes engineering solution for killing the well,' Short windows According to Kinkead, the approach is likely to utilise a variety of adapters, connectors, a main body incorporating two gate valves, choke and kill manifolds and a variable flow ported sub/cap with an overall system rating for 15,000psi working pressure. Such a device could be deployed in sea states of up to 5m, depending on the vessel used, and capping could be achieved within 20-30 days of the incident, depending on weather and well site conditions. McAllister added: `This work can also help inform the development of a longer -term regional or global (non -US) response which is being co-ordinated by the Global Industry Response Group under OGP [the International Association of Oil & Gas Producers].' Russell McCulley & Jennifer Pallanich un analysis of current rig market data is updated monthly using statistics provided by Rigzone.com Rig market Worldwide utilization for the mobile offshore drilling fleet is tracking at 74%; holding steady for the last three months at the bottom of a tight 74%-76% band that has now been in place for 14 months. Compared to levels achieved one year ago, global utilization has fallen 150 basis points. Floating rig types improved slightly versus the prior month with drillships at 87% and semisubs at 84% utilization rates. Jackups on the other hand showed some slight weakness against the prior month falling 100 basis points to 68.5%. Southeast Asia supports drilling with 64 mobile offshore units. By type, jackup rigs dominate the region comprising 70% of the total, 45 units. This past April the region saw overall utilization break 80% levels; it has continued climb throughout the summer months. Currently, Southeast Asia is hovering at 84% utilization. Breaking down Southeast Asia by rig type, the jackup market had the strongest results at nearly 89% utilization. Utilization for the remaining rig types is roughly 67% for drillships and 77% for semisubmersibles in the region. Southeast Asia rig utilization Jackup 75% 65% DrtllShip Semi 55% 45% g Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe. a itonIIne.com For reprints please contact the Publisher. OFFSHORE ENGINEER I november 2010 15 0 • 'The big thing that's different [in the new drilling safety rule] is the requirement for independent engineer and third -party certifications.' Steve Kropla, IADC Cana Li New drilling ■ package. The role requires floating drilling rigs to have an ROV and trained ROV crew onboard, mandates auto shear and deadman systems for DP rigs, and makes mandatory a range of tests and documentation. Salazar, while announcing the drilling moratorium's early end, said the administration was taking 'a cautious approach when it regs challenge comes to deepwater drilling' and alluded to 'a regulatory environment that will remain d i t' t and sometimes confound already aplemen d'. o build on the reforms we have already implemented'. The new drilling safety rule The US lifted the six-month moratorium on deepwater exploration in October, while codifying new rules 'is a little more prescriptive governing drilling safety and well control. Russell McCulley looks at what the new regulations could with some of the requirements mean for oil & gas companies doing business in the Gulf of Mexico. it places on operators, as far as their cementing procedures The Drilling Safety Rule, part of a broader package of regulations put in place by the US Bureau of Ocean Energy Management, Regulation & Enforcement after the Deepwater Horizon disaster, includes provisions addressing wellbore integrity and requirements for subsea blowout preventers and related control systems. The rule makes mandatory the recommended practices set forth in the American Petroleum Institute standards for isolating potential flow zones during well construction, and require a professional engineer's certification of cementing and casing plans. The BOEM rule requires 'two independent test barriers across each flow path during well completion activities,' permission from the agency to replace a heavier drilling fluid with a lighter one, and enhanced well control training for rig personnel. The new rule, issued as an interim measure in late September, includes a number of recommendations regarding BOPs that were part of Interior secretary Ken Salazar's 27 May safety report to President Obama (OE July). Operators will be required to submit to the BOEM documentation and schematics of all control systems, get third party verification that a BOP's blind shear rams are capable of severing any drill pipe present in the hole, and equip the subsea BOP stack with ROV intervention capability, including the ability to close one set of pipe rams, one set of blind shear rams and unlatch the well's lower marine riser and completion procedures and well design go,' says Steve Kropla, group VP of operations and accreditation at the International Association of Drilling Contractors. 'What it mainly did was codify a number of provisions that were already in place, particularly under BOEM Notice to Lessees 2010-N05. The big thing that's different is the requirement for independent engineer and third -party certifications. There really was no requirement previously for independent certification. Content is copyright protected and provided for personal use only - not for reproduction or retransmission. http://oe.oiiloniIne.com For reprints please contact the Publisher. OFFSHORE ENGINEER I november 2010 13 • Industry scores another victory Litigation continues in US courts over the Obama administration's Gulf of Mexico deepwater drilling moratorium, despite the early lifting of the six-month drilling ban in October. In a 19 October decision, US District Court judge Martin Feldman - the same judge who in June struck down the initial drilling ban in a suit filed by Hornbeck Offshore Services - ruled in favor of Ensco Offshore, which had challenged the Bureau of Ocean Energy Management's notice to lessees (NTL 05) implementing new safety requirements and the administration's follow-up moratorium, issued as a 22-page decision memorandum. Ensco, claiming that the moratorium had caused direct harm to its business and employees, filed suit 9 July challenging NTL 05 and the second moratorium partly on the grounds that US Interior secretary Ken Salazar had implemented the rules without first allowing a public comment period. Feldman agreed with Ensco's argument that NTL 05 was a'substantive' rule and not an interpretive rule, as the government had maintained, and was thus subject to the public notice and comment period requirements set forth in the Administrative Procedure Act. 'Essentially, the decision invalidates NTL 05 due to the lack of notice and availability for public comment before its issuance,' National Ocean Industries Association director of government relations Jeff Vorberger said in a letter to members after the decision. 'As NTL 05 has effectively been implemented as an Interim Final Rule on Drilling Safety, NOIA will continue to monitor the decision's practical impact during the Interim Final Rule's public comment period that concludes on 13 December and on which NOIA will be commenting.' The government filed a motion to have Ensco's challenge to the second moratorium rendered moot after the early lifting of the ban. Feldman denied the motion and was scheduled to rule on the matter at a separate hearing 3 November. RM That was the responsibility of the operator, in the case of well design, and contractor, in case of the BOP, to make sure their equipment was functioning properly and capable of performing under the conditions that would be required.' Oil & gas companies have been'somewhat troubled', he says, by the rule's'lack of definition and specificity on what exactly satisfies a number of things', including who would be a qualified to certify casing and cementing plans. The trade organization National Ocean Industries Association took issue with Salazar's promise of a 'dynamic' regulatory environment. 'That sounds good,' NOIA president and former Minerals Management Service director Randall Luthi said in a statement released shortly after the moratorium was lifted. 'In reality, however, it introduces another level of uncertainty to a regulatory process that has come to be less predictable than in many under -developed nations around the globe.' The BOEM - formerly MMS - has released a set of FAQs to help clear up uncertainty over new regulations, and will likely refine the definitions further as the drilling permit approval process picks up speed. But some requirements remain vague: 'The new rule puts emphasis on making sure ROV operators are properly trained,' Kropla says. 'Again, that's not that well defined.' The FAQs did indicate that BOP certification cannot be done by a contractor's in-house engineering staff, Kropla says. 'It could be done by one of the classification societies like DNV or ABS; it could be done by someone who is an API -authorized service center.' DNV did step forward in October to issue a 'recommended practice' for the recertification of subsea BOP stacks that offers a guide through requirements and technical details. The company has had a similar set of guidelines for recertification of well control equipment on the Norwegian OCS for several years. The auto -shear and deadman systems requirements for dynamically positioned rigs may not be that onerous. 'A lot of DP rigs have these already,' Kropla says. One provision that has generated a lot of concern, however, is the requirement for blind shear cutting capabilities. There was speculation early in the BP Macondo disaster that the shear ram may have struck the tool joint in the drillstring and thus been unable to sever the pipe. 'The industry's looking at different ways to identify where tool joints are in a drilling string, but that technology is not commonly used in drilling operations right now,' he says. As the rule stands now, 'it doesn't appear that [BOP] configurations will have to be altered much,' Kropla says. 'If [contractors] can show through some testing procedures that the BOP is capable of shearing the drill pipe that is to be used in the project, and they have an independent third -party certification of the equipment, they should be okay right now. What the future holds, we're not entirely sure.' Several items that were in Salazar's 27 May safety report were not included in the new regulations, but could emerge in later refinement of the rules, he says. One major change could be a requirement for double shear rams to provide a guard against tool joint interference; if future regulations require a considerable amount of space between the rams, the added weight and size could strain the hoisting and deck space capacity of some rigs, Kropla says. 'For some of the older rigs, it's going to be quite a bit of an issue to accommodate that extra space,' he says. 'If you do have a rather large [double shear ram] spacing requirement, that can cause real estate problems, especially on older rigs. You're adding additional weight to the subsea stack that could affect the working deck load of the vessel and its hoisting equipment. And you may need a place to store the thing or otherwise accommodate it. The newer rigs are not going to have such a problem with this, because they are larger and were designed with bigger stacks in mind, but rigs built prior to late or mid-1990s might have an issue with it. If it becomes a regulation, it could prompt the exodus of older rigs.' The safety rules make mandatory a previously voluntary option of having a safety case for floating drilling operations on the outer continental shelf - essentially, a risk management program that goes beyond the required safety and environmental management system (Sems), Kropla says. The joint industry task force set up after the Macondo incident recommended a companion document to the safety case, a well construction interface document: 'a sort of risk management program for the well itself,' Kropla says, and similar to what is required in the UK. 'We anticipate that that's one of the things that will probably be included in future rulemaking,' he says. In the end, the BP disaster's legacy could include the move toward a more standardized approach to safety and regulation around the world. 'One of the issues for contractors is that this is not really just a Gulf of Mexico situation,' Kropla says. 'A lot of international regulators and operators are taking a look at what is happening here in the Gulf of Mexico, and what happens here could frame the requirements for operating elsewhere.' (3E • Macondo - the unfolding aftermath, seepage 22. Content is copyright protected and provided for personal use only - not for reproduction or retransmission. 14 OFFSHORE ENGINEER I november 2010 For reprints please contact the Publisher. http://oo.oilonline.com VRA 24 November 2010 i A n A MARTIN FERGUSON Minister for Resources and Energy Minister for Tourism FINAL REPORT OF THE MONTARA COMMISSION OF INQUIRY RELEASED Following a period of detailed consideration the Government has today released the Report of the Montara Commission of Inquiry and a draft Government response. The Inquiry was set up to investigate the likely causes of the uncontrolled release of oil and gas into the Timor Sea from the Montara Wellhead Platform on 21 August 2009 and make recommendations to the Government on how to prevent future incidents. The Report contains 100 findings and 105 recommendations, which have implications for governments, regulators, and the offshore petroleum industry. The Government proposes accepting 92, noting 10, and not accepting three of the Report's recommendations. Outlining the Government's draft response, Minister for Resources and Energy noted that it . provides a comprehensive plan to tackle head on the tough policy challenges posed by the Montara incident. "The fact is that we were lucky with Montara — no lives were lost, there were no serious injuries and the quick, coordinated response from governments, regulators and industry meant that the impact on the marine environment was minimal,' Minister Ferguson said. "Montara was the first major loss of well control in 25 years of safe offshore petroleum operations. "Our challenge — collectively — is to minimise the risks of any future incidents. That is why I set up the Montara Commission of Inquiry. "We can't just turn our backs on this industry — it is too important to Australia's economic and energy security. What we can do — working together — is make Australia's offshore safety regime the best and safest in the world. "The report recognises that while there is room for some improvements, our regulatory regime is good — it is effective. "At the heart of this matter is the failure of the operator and the failure of the regulator to adhere to this regime. "Montara was preventable. • "If either - or preferably both — PTTEP AA or the Northern Territory Designated Authority had done their jobs properly and complied with requirements, the Montara Blowout would never have happened. "I have already taken action on the most pressing issues arising from the Montara Commission of Inquiry. "We will now commence a period of consultation with industry, community and other key stakeholders to inform the Government's final response. "A key aspect of this will be the Government's intention to move toward a single national offshore regulator — consistent with the Report's recommendations. "In line with the Commissioner's recommendations the Government will also move to legislate the polluter pays principle and the requirements for environmental monitoring, further strengthening environmental safeguards "I am confident that by working methodically and diligently through the implementation of the remaining recommendations we will achieve a result that benefits all and maintains the industry's social licence to operate." The Report of the Montara Commission of Inquiry Report, the Government's draft response, information on how to make submissions and other supporting documents are available at www.ret.gov.aL1/montarahiqL1 nqu i ryresponse Media contact: Fiona Scott — 0457 542 330 • E National scientific academies criticize Macondo well procedures - Oil & Gas Journal Pagel of 3 WPM Ewa — Home General Interest Exploration & Development Drilling & Production Processing Transportation Blogs Research & Data Site License Bookstore TechnologyInternational Petroleum News and H nee > Article Display ADVERTISEMENT 8 Print S& Email 81 Savt FICA A I C A ILA Share National scientific academies criticize Macondo well procedures Nov 17. 2010 Note: This story was updated on Nov. 18 with additional information Nick Snow Washington Editor WASHINGTON, DC, Nov. 17 — Numerous technical and operation breakdowns that contributed to the Macondo well accident and subsequent crude oil spill in the deepwater Gulf of Mexico suggest there was no suitable approach for managing the inherent risks, uncertainties, and dangers associated with deepwater drilling, a National Academy of Engineering and National Research Council joint committee said in an interim report on Nov. 17. BP PLC, Macondo's operator, and its offshore drilling contractor and service and supply companies failed to learn from previous "near misses," the interim report said. It also suggested that there were not sufficient checks and balances for critical decisions affecting the schedule for abandoning the exploratory well and for considering safety. "Important decisions made to proceed toward well abandonment despite several indications of potential hazard suggest an insufficient consideration of risks," said Donald Winter, former US Navy secretary, professor of engineering practice at the Joersity of Michigan, and chairman of the study committee. also important to note that these flawed decisions were not identified or corrected by BP and its service contractors, or by the oversight process employed by the US Minerals Management Service and other regulatory agencies," Winter said. US Interior Sec. Ken Salazar, who requested the study, and Bureau of Offshore Energy Management, Regulation, and Enforcement Director Michael R. Bromwich welcomed the interim report from the two National Academies of Science divisions. Salazar said it would guide efforts by BOEMRE, the restructured MMS, to improve offshore oil and gas operations and safety, and assist other ongoing investigations. 'Important questions' "The interim report by the NAE and NRC team raises important questions they will be exploring further in their ongoing review" said Bromwich. "Their work will help guide our continuing efforts to strengthen standards and oversight and underscores the importance of our ongoing efforts to build a strong and independent agency with the resources, training, and expertise to provide aggressive oversight of offshore oil and gas operations." The joint committee said it expects to complete its work by June 2011. It said it may not be possible to definitively establish which mechanisms caused the well to blow out and Transocean Ltd.'s semisubmersible Deepwater Horizon drilling rig to explode on Apr. 20, given the deaths of 11 witnesses on board, the loss of the rig and important records, and the difficulty in obtaining reliable forensic information at the Macondo well's depth. "In addition, no information is available yet from the recovered blowout preventer," the report stated. "Nonetheless, the committee believes it has been able to develop a good understanding of a number of key factors and decisions that may have contributed to the blowout of the well, including engineering, testing, and maintenance procedures; operational oversight; regulatory procedures; and personnel training and certification." A spokeswoman for the BOEMRE-US Coast Guard joint investigation said on Nov. 16 that the static testing phase of the Deepwater Horizon's recovered BOP's forensic test has begun at the National Aeronautics and Space Administration's Michoud facility in New Orleans. Det Norske Veritas personnel are conducting the examination in consultation with experts from Cameron International Corp., the BOP's manufacturer; Transocean; BP; and experts representing the US Department of Justice; the US Chemical Safety Board; and plaintiffs in multidistrict litigation in New Orleans, she said. The scientific academies' interim report concluded that the accident apparently was precipitated by the decision to proceed with temporary abandonment of the Macondo well despite indications from several repeated well integrity tests that the cementing process following the installation of a long -string production casing failed to provide an effective barrier to hydrocarbon flow. Compounding actions That decision's impact was compounded by delays in recognizing that hydrocarbons were flowing into the well and riser, and 0es failure to take timely and aggressive well -control actions, it continued. "Furthermore, failures and/or limitations of the wit was hen actuated, inhibited its effectiveness in controlling the well," it said. e failures and missed hazard indications were not isolated incidents, the report said. "Numerous decisions to proceed toward abandonment despite indications of hazard, such as the results of repeated negative -pressure tests, suggest an insufficient consideration of risk and a lack of operating discipline," it said. "The decisions also raise questions about the adequacy of operating knowledge on the part of key personnel. The net effect of these decisions was to reduce the available .v........... ..4 .... f.-1.. H -.... L.- :.N.- .-.....-. m1 ........J.... A:.-.- .-1 -.- 1-...1..-.-.-.L-.-.- .-.--n..-;_ -.-d ....-II .....J....,. A; --......—A Nvn—k http://www.ogj.com/index/article-display/1846819682/articles/oil-gas journal/general-interest-2/hse/201... 11/29/2010 National scientific academies criticize Macondo well procedures - Oil & Gas Journal Page 2 of 3 drilling and the subsequent changes in the execution of the well plan." whir decisions may have contributed to the accident, including changing key supervisory personnel on the Deepwater on just prior to critical temporary abandonment procedures; attempting to cement the multiple hydrocarbon and brine Wes in the well's deepest part in a single operational step despite the zones' markedly different fluid pressures, and the small difference in the cement's density needed to prevent inflow from its density at which an undesirable hydraulic fracture might be created in a low-pressure zone; and choosing to use a long -string production casing in a deep, high-pressure well instead of a cement liner over the well's uncased section. Deciding that only six centralizers would be needed despite modeling results to the contrary; limiting bottoms -up drilling mud circulation prior to cementing, which increased the possibility that debris in the well would contaminate the cement; not running a bond log after cementing to assess the cement's integrity despite anomalous results of repeated negative -pressure tests; not incorporating a float shoe at the bottom of the casing as an additional hydrocarbon flow barrier; and proceeding to remove the mud from the well without installing the lockdown sleeve on the production casing wellhead seals to ensure that pressure buildup could not shift the seals also may have led to the blowout and subsequent explosion, according to the report. Checks and balances "Available evidence suggests there were insufficient checks and balances for decisions involving both the schedule to complete well abandonment procedures and considerations for well safety," it said. "The decisions mentioned above were not identified or corrected by the operating management processes and procedures of BP or those of their contractors or by the oversight processes employed by MINIS or other regulators." It noted that there are conflicting views among experts familiar with the incident regarding the type and volume of the cement which was used to prepare for the well's temporary abandonment, as well as the adequacy of the time provided for the cement to cure. "These factors could have had a material impact on the integrity of the well," the report said. It noted that the BOP did not control, or recapture control of, the well once personnel at the site realized that hydrocarbons were flowing into the well. Both the emergency disconnect system designed to separate the lower marine riser from the rest of the BOP and automatic sequencers controlling the shear ram and disconnect also failed to operate, it said. "Given the large quantity of gas released onto the [mobile offshore drilling unit] and the limited wind conditions, ignition was most likely," the report said. "However, the committee will be looking into reports (such as testimony provided at the Marine Board of Inquiry hearings) that various alarms and safety systems on the Deepwater Horizon failed to operate as intended, potentially affecting the time available for personnel to evacuate." It said the various failures mentioned show there was not a suitable approach for anticipating and managing inherent risks, uncertainties, and dangers associated with deepwater drilling, and a failure to learn from previous near misses. No systems approach "Of particular concern is an apparent lack of a systems approach that would integrate the multiplicity of factors potentially ,dQctmg the safety of the well, monitor the overall margins of safety, and assess the various decisions from perspectives of integrity and safety," it said. "The 'safety case' strategy required for drilling operations in the North Sea and elsewhere is example of such a systems approach." BP said in a written statement that the interim report addresses issues similar to what US President Barack Obama's independent commission and BP's internal investigation discussed, but reaches no conclusion. "The report makes clear that the committee is continuing to investigate and has not yet considered evidence that has surfaced since Oct. 1," it continued. "Such evidence includes the cement tests conducted independently for the Presidential Commission suggesting that Halliburton's cement slurry was unstable. We will continue to cooperate with the committee to provide information and evidence to assist in its review." Halliburton Co., which provided the Macondo well's cementing services, said in a Nov. 18 statement that it continues to review the National Academies' interim report which, the company noted, said that decisions by BP may have contributed to the accident. It said that these decisions included not running a cement bond log test, not using 21 centralizers, not running a proper negative pressure test, and misreading the results of more than one negative test. Transocean and Weatherford did not respond immediately to the interim report's findings. National Ocean Industries Association President Randall B. Luthi, who was MMS director from July 2007 through January 2009, did. "The interim report corroborates the findings of earlier investigations into the potential causes of the Deepwater Horizon accident," he said. "With the blowout preventer currently being examined and other investigations still under way, technological failure cannot be completely ruled out at this point. However, today's findings and previous reports point to human error and a series of questionable decisions as being the leading contributing factor to the accident. "This is precisely why it is so important to find the root cause of the accident, before mandating wide -scale legislative or administrative fixes that may not have any direct correlation to the cause," Luthi added. "The good news is that industry has conducted its own investigations and reviews, and through the use of task forces has already begun to implement improved safety procedures and preparedness and response systems to help prevent and respond to any future such incidents." Positive recommendations Erik Milito, the American Petroleum Institute's upstream operations group director, noted that API and the rest of the oil and gas industry created four task forces shortly after the accident which provided positive recommendations to the federal government on how to improve offshore oil and gas safety through a systems -based approach. "API and the International Association of Drilling Contractors are jointly developing well construction interface document guidelines, which will help improve safety by linking the management systems of offshore operators with those of drilling contractors," he said. "Furthermore, API is developing a standard on deepwater well design, which will provide practices that are intended to achieve a high level of total system reliability." Milito said that significant enhancements have been made to prevent and respond to an offshore spill, and the industry will 8 roue to seek ways to enhance safety. Companies and their employees look forward to getting back to work in the Gulf of ico, he indicated, adding: "Thousands of jobs and billions of dollars of revenue depend on it." "With the safety measures already in place or under way, it is important to concentrate on getting permits for exploration under way to secure American jobs and energy security," Luthi observed. http://www.ogj.com/index/article-display/1846819682/articles/oil-gas journal/general-interest-2/hse/201... 11/29/2010 National scientific academies criticize Macondo well procedures - Oil & Gas Journal Page 3 of 3 ple who read this article also read the following: Iacondo partners parry payment claims from BP for oil spill ARKET WATCH: Crude prices slip lower; cold weather outlook hikes gas price • New decommissioning requirements will lower Gulf of Mexico production • ExxonMobil rig attacked in Nigeria; production shut in • Tullow looking to expand production off Ghana after Jubilee Oil & Gas Journal Topic and Resource Categories: General Interest Drilling & Production Transportation Current Issue Exploration & Production Processing Site License Archives http://www.ogj.com/index/article-display/1846819682/articles/oil-gas journal/general-interest-2/hse/201... 11/29/2010 Print Story: White House edits stain its reliance on science - Yahoo! News Page 1 of 3 VA- 140 !@ NEWS PRINT Back to story White House edits stain its relianceAarmxLitod New on science By DINA CAPPIELLO, Associated Press 37 mins ao( WASHINGTON — The oil spill that damaged the Gulf of Mexico's reefs and wetlands is also threatening to stain the Obama administration's reputation for relying on science to guide policy. Academics, environmentalists and federal investigators have accused the administration since the April spill of downplaying scientific findings, misrepresenting data and most recently misconstruing the opinions of experts it solicited. Meanwhile, the owner of the rig that exploded in the Gulf of Mexico, Transocean Ltd., is renewing its argument that federal investigators are in danger of allowing the blowout • preventer, a key piece of evidence, to corrode as it awaits forensic analysis. Testing had not begun as of last week, the company says, some two months after it was raised from the seafloor. The blowout preventer could be a key piece of evidence in lawsuits filed by victims, survivors and others. Transocean was responsible for maintaining it while it was being used on BP's well. Investigators agreed to flush the control pods with fluid on Sept. 27 to prevent corrosion. But a Transocean lawyer wrote in his Nov. 3 letter that there have been no further preservation steps on the blowout preventer since then. The latest complaint from scientists comes in a report by the Interior Department's inspector general, which concluded that the White House edited a drilling safety report in a way that made it falsely appear that scientists and experts supported the administration's six-month ban on new deep -water drilling. The AP obtained the report early Wednesday. The inspector general said the editing changes by the White House resulted "in the implication that the moratorium recommendation had been peer reviewed." But it hadn't been. Outside scientists were asked only to review new safety measures for offshore drilling. • "There are really only a few people that know what they are talking about" on offshore drilling," said Ford Brett, managing director of Petroskills, a Tulsa, Okla. -based petroleum training http://news.yahoo.com/s/ap/201011 11/ap_on_bi_ge/us_gulf oil spill/print 11/10/2010 Print Story: White House edits stain its reliance on science - Yahoo! News Page 2 of 3 organization. "The people who make this policy do not... so don't misrepresent me and use • me for cover," said Brett, one of seven experts who reviewed the report. In a statement issued Wednesday, the White House insisted the review was properly coordinated and pointed to the inspector general's findings. "Following a review that included interviews with peer review experts, the Inspector General found no intentional misrepresentation of their views ... The decision to implement a six-month moratorium on deep -water drilling in the Gulf of Mexico was correctly based on the need for adequate spill response, well containment and safety measures, and we stand behind that decision," White House deputy press secretary Bill Burton said. Last month, staff for the presidential oil spill commission said that the White House's budget office delayed publication of a scientific report that forecast how much oil could reach the Gulfs shores. Federal scientists initially used a volume of oil that did not account for the administration's various cleanup efforts, but the government ultimately cited smaller amounts of oil. The same report said that President Barack Obama's energy adviser, Carol Browner, mischaracterized on national TV a government analysis about where the oil went, saying it showed most of the oil was "gone." The report said it could still be there. It also said that Browner and the head of the National Oceanic and Atmospheric Administration, Jane Lubchenco, contributed to the public's perception the report was more exact than it was by emphasizing peer review. The new inspector general report said Browner's staff implied that scientists had endorsed the drilling moratorium, by raising a reference to peer review in the drilling safety report. At least one outside expert who was involved said he was convinced afterward that it wasn't a deliberate deception, and Interior Department officials told the inspector general they didn't deliberately make changes to cause confusion. "There was no intent to mislead the public," said Kendra Barkoff, a spokeswoman for Interior Secretary Ken Salazar, who also recommended in the May 27 safety report that a moratorium be placed on deep -water oil and gas exploration. "The decision to impose a temporary moratorium on deep -water drilling was made by the secretary, following consultation with colleagues including the White House." •After one of the reviewers complained, the Interior Department promptly issued an apology during a conference call, in a formal letter and during a personal meeting in June. All seven experts asked to review the Interior Department's work expressed concern about the http://news.yahoo.com/s/ap/20101111/ap_on bi_ge/us_gulf oil spill/print 11/10/2010 Print Story: White House edits stain its reliance on science - Yahoo! News Page 3 of 3 change made by the White House, saying that it differed in important ways from the draft they had approved. "We believe the report does not justify the moratorium as written, and that the moratorium as changed will not contribute measurably to increased safety and will have immediate and long- term economic effects," the scientists wrote earlier this year to Louisiana Gov. Bobby Jindal and Sens. Mary Landrieu and David Vitter. "The secretary should be free to recommend whatever he thinks is correct, but he should not be free to use our names to justify his political decisions." Those complaints were similar to those of other scientists. "Their estimates always seemed to be biased to the best case," said Joseph Montoya, a biology professor at Georgia Tech. "A number of scientists have experienced a strong push back." The inspector general's report said the administration did not violate federal rules because the executive summary did not say the experts approved of the moratorium and because the department publicly clarified what the experts said and had offered a formal apology. �-M Associated Press writers Seth Borenstein in Washington and Harry R. Weber in New Orleans contributed reporting. Copyright © 2010 Yahoo! Inc. All rights reserved. Questions or Comments • Privacy Policy About Our -ads - Terms of Service • Copyright/IP Policy http://news.yahoo.com/s/ap/20101111/ap_on_bi_ge/us_gulf oil_spill/print 11/10/2010 Print Story: Report: White House altered drilling safety report - Yahoo! News Page 1 of I Y,AHoo!. N E WS PRINT Back to story Report: White House altered A5��P drilling safety report By DINA CAPPIELLO, Associated Press 8 mins aqo WASHINGTON — The Interior Department's inspector general says the White House edited a drilling safety report in a way that made it falsely appear that scientists and experts supported the idea of the administration's six-month ban on new drilling. The inspector general says the editing changes resulted "in the implication that the moratorium recommendation had been peer reviewed." But it hadn't been. The scientists were only asked to review new safety measures for offshore drilling. "There was no intent to mislead the public," said Kendra Barkoff, a spokeswoman for Interior Secretary Ken Salazar, who also recommended in the May 27 safety report that a moratorium • be placed on deepwater oil and gas exploration. "The decision to impose a temporary moratorium on deepwater drilling was made by the secretary, following consultation with colleagues including the White House." The Interior Department, after one of the reviewers complained about the inference, promptly issued an apology to the reviewers during a conference call, with a letter and personal meeting in June. The inspector general's report, which was originally requested by Louisiana Sen. David Vitter and Rep. Steve Scalise in June, said the administration did not violate federal rules because the executive summary did not say the experts approved the recommendations and the department offered a formal apology and had publicly clarified the nature of the expert review. But Louisiana Rep. Bill Cassidy, a Republican, said in a statement that the investigation proved "that the blanket drilling moratorium was driven by a politics and not by science." "Candidate Obama promised that he would guided by science, not ideology," Cassidy said. Cassidy said if that were true thousands of jobs and billions in economic activity would have been preserved on the Gulf coast. • The Web site Politico was first to report the inspector general's findings. The Associated Press on Wednesday obtained a copy of the report, which has not been publicly released. http://news.yahoo.com/s/ap/us_gulf oilspill/print 11/10/2010 V ROCKY -•i MINERAL LAw ►Z�FOUNDATION Volume XXVII, Number 3, 2010 FEDERAL - MINING PATRICIA J. WINMILL — REPORTER — NINTH CIRCUIT UPHOLDS BLM'S APPROVAL OF "PHASED" EXPLORATION PLAN OF OPERATIONS In Te-Moak Tribe of Western Shoshone of Nevada v. U.S. Department of the Interior, 608 F.3d 592 (9th Cir. 2010), the Ninth Circuit upheld a Bureau of Land Management (BLM) deci- sion approving an exploration plan of operations even though the proposed plan did not identify the specific locations of drill sites or roads that may be built under the plan. The court adopted the reasoning from an earlier decision of the Interior Board of Land Appeals (IBLA), Great Basin Watch, 159 IBLA 324 (2003), and agreed with IBLA that, in some cases, BLM "may adapt its as- sessment of environmental impacts when the specific locations of an exploration project's activities cannot reasonably be ascer- tained until some time after the project is approved." Te-Moak, 608 F.3d at 600. The court acknowledged that "[ajn exploration project ... inherently involves uncertainties; if mining companies knew the precise location of mineral deposits before drilling, ex- ploration would not be required." Id. In approving mineral ex- ploration projects, the court concluded that BLM could balance the uncertainties with its other duties under federal law. continued on page 2 FEDERAL - OIL & GAS GREGORY R. DANIELSON — REPORTER — D.C. CIRCUIT AFFIRMS ROD FOR COALBED METHANE PROJECT The Theodore Roosevelt Conservation Partnership (TRCP) and various other environmental groups challenged the validity of the Atlantic Rim Natural Gas Field Development Project (Atlantic Rim Project) Record of Decision (ROD) and Final Environmental Impact Statement (FEIS). In Theodore Roosevelt Conservation Partnership v. Salazar, Nos. 09-5162, 09-5193, 2010 WL 2869778 (D.C. Cir. July 23, 2010), the D.C. Circuit affirmed the district court holding that the Bureau of Land Management's (BLM) deci- sions related to the Atlantic Rim Project were not an abuse of its discretion. In 2001, BLM began the review and approval process for the Atlantic Rim Project. The Atlantic Rim Project was approved by a ROD issued in March 2007. The ROD anticipated BLM ap- proval of approximately 2,000 new natural gas wells over a period of 30-50 years and surface disturbance of approximately 13,600 acres. To mitigate the environmental damage of the project, the ROD outlined conditions of approval for any proposal to drill. Overall surface disturbance in the project area could not exceed ENVIRONMENTAL ISSUES STEVEN E. MARLIN — REPORTER — TENTH CIRCUIT VACATES EPA'S DETERMINATION THAT MINE PROPERTY IS INDIAN LAND FOR SAFE DRINKING WATER ACT UIC PERMITTING AUTHORITY On June 15, 2010, a sharply divided full Tenth Circuit re- versed a Tenth Circuit Panel's decision and vacated the U.S. En- vironmental Protection Agency's (EPA) determination that mine property qualifies as Indian land and is subject to EPA permitting authority under the Safe Drinking Water Act (SDWA). Hydro Resources, Inc. v. U.S. Environmental Protection Agency, 608 F.3d 1131 (1Oth Cir. 2010). The majority of the court held that the mine property is not Indian land and, as a result, the New Mexico En- vironment Department (NMED) is the proper agency to issue an continued on page 4 underground injection control (UIC) well permit for the mine project under the SDWA. Hydro Resources, Inc. (HRI) is developing a uranium mine project on property located in the vicinity of the Navajo Reser- vation in northwest New Mexico. Uranium will be extracted using an in situ leaching process that entails pumping and circulating water underground to force the uranium to the surface for re- covery. Such a process requires a UIC permit under the SDWA, a federal statute enacted to protect underground drinking water sources by regulating injection of fluids into wells that may impair aquifers.42 U.S.C. §§ 300h-300h-8. Under the SDWA, EPA may continued on page 5 page 6 MINERAL LAW NEWSLETTER ized EPA's decision as a determination that the mine property tself qualifies as Indian country simply because a sufficiently igh but unspecified percentage of land in proximity of the mine property is Indian country. Instead, EPA should have applied the Venetie test, focusing only on the mine property itself and not sur- rounding land, to answer two questions: first, has the mine prop- erty itself been explicitly set aside by Congress (or the Executive pursuant to delegated authority) for use by Navajos as Indian land; and second, is the mine property itself under the federal govern- ment's superintendence? The court held that because the mine property does not satisfy either of these criteria, as the parties in this case agreed, the mine property cannot be part of a dependent Indian community, and therefore, is not Indian country. Id. at 1166. The court also noted that, in the future, EPA could consider classifying "Indian lands" for purposes of UIC permitting juris- diction based on a mechanism other than the definition of"Indian country" from the federal criminal jurisdiction code. This in turn might result in the mine property qualifying as Indian land and becoming subject to EPA's or even the Nation's UIC permitting authority. Until then, the mine property is subject to the NMED's UIC administrative authority. Id. This case also produced two separate dissenting opinions that rejected the majority's ruling that a land status determination should focus only on the property in question, rather than considering the character of the surrounding land. In disputing that Venetie abro- gated the Watchman "community of reference" balance test, the issenters identified various factors supporting the mine prop- rty's classification as a dependent Indian community, including the impracticality of addressing groundwater contamination on a parcel -specific basis, the history of land usage and extent of fed- eral government and Nation involvement in the vicinity of the mine property, and the need for applying the "community of reference" test to mitigate checkerboard jurisdictional disputes. The dissenters also disagreed with the majority's observation that the ruling brings the Tenth Circuit in line with other circuits with respect to how Indian country is determined. The splintered hold- ing in this case, as well as the majority's conclusion that EPA was free to modify its reliance on the federal criminal code for de- fining "Indian lands," suggests that the issues addressed in this are far from settled, generating ongoing uncertainty for companies erating in the vicinity of Indian country. CONGRESS / FEDERAL AGENCIES GENERAL ROBERT C. MATHES - REPORTER -:- MINERALS MANAGEMENT SERVICE OFFICIALLY RENAMED On June 18, 2010, Secretary of the Interior Ken Salazar of- ficially renamed Minerals Management Service (MMS) the Bu- reau of0cean Energy Management, Regulation, and Enforcement (BOEMRE). BOEMRE, which is currently vested with the same authority and responsibilities as was MMS, will be headed by a director under the supervision of the Assistant Secretary -Land and Minerals Management. See Order No. 3302 (June 18, 2010), available at http://www.doi.gov. The Assistant Secretary has been 10 directed by the Secretary to (1) change to BOEMRE all former references to MMS in the Department of the Interior's Depart- mental Manual, (2) promulgate rules in the Federal Register chang- ing all MMS references to BOEMRE in the Department's regu- lations, and (3) notify Congress of the name change. In response to the significant spill in the Gulf of Mexico, Sec- retary Ken Salazar has also promised to divide BOEMRE into three separate agencies with different responsibilities. Bills pro- posing similar changes currently are pending before Congress, but have not yet been finally or fully implemented by either a Secre- tary or Congress. See Order No. 3299 (May 19, 2010), and Order No. 3299, Amendment No. I (June 18, 2010), available at http:H www.doi.gov. ALABAMA - OIL & GAS EDWARD G. HAWKINS - REPORTER - PRELIMINARY BP OIL SPILL PROCEEDINGS In the cases of Hopkins v. Transocean Ltd., Civ. No. 10- 022 1 -WS-C, 2010 WL2104548 (S.D. Ala. May 25,2010); Billy's Seafood, Inc. v. Transocean Holdings, Inc., Civ. No. 10-0215- WS-B, 2010 WL 2104610 (S.D. Ala. May 25, 2010); Trahan v. BP, PLC, Civ. No. 10-0 1 98-WS-B, 2010 WL 2104613 (S.D. Ala. May 25, 2010); Fishburn v. BP, PLC, Civ. No. 10-0248-WS-C, 2010 WL 2104624 (S.D. Ala. May 25, 2010); Paul v. BP, PLC, Civ. No. 10-0245-WS-N, 2010 WL 2104626 (S.D. Ala. May 25, 2010); Marine Horizons, Inc. v. BP, PLC, Civ. No.10-0227-WS-N, 2010 WL 2104629 (S.D. Ala. May 25, 2010); Barber v. BP, PLC, Civ. No. 10-0263-WS-B, 2010 WL 2266760 (S.D. Ala. June 4, 2010); and Sunrise Rentals Enterprises v. BP, PLC, Civ. No. 10-026 1 -WS-M, 2010 WL 2266772 (S.D. Ala. June 4, 2010), the U.S. District Court for the Southern District of Alabama de- nied attempts by BP Exploration & Production, Inc.; BP Products North America, Inc.; and Transocean Ltd. to stay various class actions pending transfer of those cases to a single U.S. district court in a multidistrict litigation. All the cases arose from the April 20, 2010, explosion onboard the Deepwater Horizon drilling rig in the Gulf of Mexico. As of June 4, 2010, 31 Deepwater Horizon -related lawsuits had been filed in the U.S. District Court for the Southern District of Alabama. By transfer order dated August 10, 2010, the U.S. Judicial Panel on Multidistrict Litigation ordered seventy-seven cases transferred to U.S. District Judge Carl J. Barbier of the Eastern District of Louisiana. In re Oil Spill by the Oil Rig "Deepwater Horizon" in the Gulf of Mexicio, On April 20, 2010, MDL No. 2179, 2010 WL 3166434 (J.P.M.L. Aug. 10, 2010). The cases transferred to Judge Barbier were: 31 actions in the Eastern Dis- trict of Louisiana, 23 in the Southern District of Alabama, 10 in the Northern District of Florida, eight in the Southern District of Mississippi, two in the Western District of Louisiana, two in the Southern District of Texas, and one in the Northern District of Alabama. The order referenced by footnote more than 200 addi- tional related actions that "are potential tag -along actions." Id. at 1 •I MINERAL LAW NEWSLETTER page 7 11 n.1. In another order issued the same day, the U.S. Judicial Panel on Multidistrict Litigation ordered investor lawsuits against BP transferred to United States District Judge Keith P. Ellison of the Southern District of Texas. In re BP P.L.C. Securities Litigation, MDL No. 2185, 2010 WL 3238321 (J.P.M.L. Aug. 10, 2010). ARKANSAS - OIL & GAS THOMAS A. DAILY — REPORTER — EIGHTH CIRCUIT COURT OF APPEALS AFFIRMS DISTRICT COURT'S STROHACKER RULING —GIVES GUIDANCE FOR FUTURE CASES Arkansas' rule regarding the interpretation of generic mineral grants and reservations is known as the Strohacker Doctrine. A nonspecific grant or reservation of"minerals" includes only those substances that, in legal and commercial usage, were generally regarded as minerals at the time and place of the grant or reserva- tion. Thus, Arkansas has numerous reported decisions concerning whether oil and gas were "minerals" on a particular historical date, in a particular Arkansas county. Most of these involve the period from 1890 through 1910. The recent intense development of Arkansas' Fayetteville Shale gas reservoirs almost entirely involves counties with no prior history of oil or gas production. As a side effect, there has been a new round of Strohacker Doctrine litigation. All of these cases to date have been decided by federal courts under diversity of citizenship jurisdiction and, unlike the earlier cases, all have involved generic mineral reservations made in the 1930s. The parties seeking to defeat the reservations have thus contended that the legal and commercial meaning of"minerals" in their counties did not include oil and gas until more recently than that decade. The U.S. district courts' opinions in some of those cases were briefly discussed in Vol. XXVII, No. 1 (2010) of this Newsletter. Griffis v. Anadarko E&P Co., L.P., No. 4:08CVO 1974 WRW, 2009 WL 2601371 (D. Ark. Aug. 24, 2009), involved a generic reservation by Anadarko's predecessor in a 1936 deed of land located in White County, Arkansas. The district court granted summary judgment to Anadarko, holding, in effect, that by 1936, oil and gas were regarded as minerals throughout the entire state. On appeal, the Eighth Circuit affirmed Griffis v. Anadarko E&P Co., L.P., 606 F.3d 973 (8th Cir. 2010). The initial appeals court opinion appeared to be narrowly based on a 1939 Arkansas Supreme Court case, Sheppard v. Zeppa, 199 Ark. 1, 133 S. W.2d 860 (Ark. 1939). According to the appeals court opinion, Zeppa construed a 1935 reservation and "flatly held that a reservation of `the mineral rights in, upon and under' the relevant tract `was ef- fective to withhold oil, gas, and other minerals from the convey- ance.' " Griffis, 606 F.3d at 974. The appeals court was wrong about one thing. The deed construed in Zeppa was actually exe- cuted in 1937, rather than 1935. Zeppa, 133 S.W.2d at 862. Griffis' petition for rehearing, citing the above mistake, was denied. In a supplemental opinion the court clarified that it was holding that the Strohacker Doctrine applied only to very early (pre-1910) grants or reservations, as far as oil and gas are con- cerned. In that supplemental opinion the federal appeals court also predicted that the Arkansas Supreme Court would reach the same result. ARKANSAS SUPREME COURT INTERPRETS THE STATE'S AMBIGUOUS STATUTORY PUGH CLAUSE The pertinent text of Ark. Code Ann. § 15-73-201, referred to as the Statutory Pugh Clause is as follows: (a) The term of an oil and gas, or oil or gas, lease exten- ded by production ... shall not be extended in lands in sections or pooling units under the lease where there has been no production or exploration. (b) This section shall not apply when drilling operations have commenced on any part of lands in sections or pooling units under the lease within one (1) year after the expiration of the primary term, or within one (1) year after the completion of a well on any part of lands in sec- tions or pooling units under the lease. In Snowden v. JRE Investments, Inc., 2010 Ark. 276, No. 09- 1149, 2010 WL 2210644 (Ark. June 3, 2010), the Arkansas Su- preme Court affirmed the trial court's summaryjudgment favoring Chesapeake. Chesapeake Exploration, LLC, the assignee of the original lessee of a multi -section lease, drilled three wells during the lease's primary term, all within a single section containing 158 acres of the 1,250-acre lease. Snowden, the lessor, contended that the lease expired with the primary term as to the remaining leased lands. According to the court, Snowden's interpretation would render subsection (b) meaningless. Further, subsection (b) should be literally read. Production anywhere on the lease holds the lease as long as there is no cessation of operations longer than one year. Then, and only then, does the lease reduce to include only the lands where there has been production or exploration. ANNETTE M. KOVAR — GUEST REPORTER — EVIDENCE OF MINERAL INTEREST VALUE DEEMED INSUFFICIENT In Usery v. Anadarko Petroleum Corp., 606 F.3d 1017 (8th Cir. 2010), the plaintiffs had filed a lawsuit in Arkansas state court to quiet title to a mineral interest. The defendant energy compa- nies removed the case to federal court claiming the value of the mineral interest exceeded the minimum jurisdictional amount of $75,000 required for removal based on diversity jurisdiction. The defendants in support of the removal presented the affidavits of a petroleum engineer and a reservoir engineer who stated generally that the right to the natural gas covered by the mineral interest would be worth at least $400,000 over its productive life. In seek- ing remand, the plaintiffs argued that they were only asking the court to determine ownership through a quiet title action and no money had been demanded. The Eighth Circuit remanded the case to the Arkansas state court finding the evidence insufficient to support removal. The Eighth Circuit said: "We have held repeatedly that in a suit for declaratory or injunctive relief, the amount in controversy World Oil Pagel of 8 . World 0'0 1:: COPYING AND DISTRIBUTING ARE PROHIBITED WITHOUT PERMISSION OF THE PUBLISHER Vol. 231 No. 10 SPECIAL FOCUS: ADVANCES IN DRILLING Drilling hazard management: The value of risk assessment Part 2 of 3: Correctly interpreting drilling dynamics enables operators to make the right proactive decisions during operations. David Pritchard, Successful Energy Practices International; Patrick L. York, Scott Beattie and Don Hannegan, Weatherford Intl. Attaining success with drilling hazard management (DHM) depends on recognition of the project's risks. If executed effectively, the process yields a comprehensive awareness that provides a foundation not only to mitigate risk but also to optimize operations. Risk assessment can be conducted for any operation. This article presents a flexible, iterative process that allows evaluation of planned mitigations that may create further risks. The implementation of this process can be used to critically challenge each facet of the well design. Risk assessment should be applied at the following stages of the well planning process: . Analysis: Evaluating design alternatives for potential risks, hazards and benefits facilitates selection of the • best approach. Design: The "basis of design" document provides specifics of the selected alternative and requires more focused evaluation. . Execution: Risk assessments of all procedures, logistics, communications, etc., should be conducted to ensure that all risks are managed, to help minimize non -productive time and to sustain performance. . For any change in the scope of the operation, the "management of change" document should be accompanied by a risk assessment of any new procedures, practices or technologies. (Within this article, we will deal only with risk of mechanical success and efficiency risk, not risks associated with health, safety and the environment.) Three alternative responses succinctly sum up how risk can be managed: accept, mitigate or avoid. Accepting a risk means that the likelihood and consequence of the risk event actually happening ranks so low that it is an acceptable risk to undertake. This likelihood is commonly referred to as "as low as reasonably practical" (ALARP). Mitigating means that the risk, as currently understood, is not acceptable and requires new or additional intervention. These new mitigations can come in the form of best practices, policies, procedures, techniques and technologies that better manage the risk. Avoiding usually requires revising the well design or mitigant in place or eliminating a step or task. Using a risk matrix as a guidance tool enables the team to select any action that it determines to be reasonable and appropriate for the operation. A matrix provides a vehicle for documenting and organizing what is important to better understand the risk profiles of the operations and manage accordingly. Decisions are guided by company policies, rules or regulations, as well as those of the relevant regulatory authorities. •PREPARATION Factual information, a clear scope and well-defined objectives are needed to conduct a focused risk assessment. The first step of the process is to perform due diligence and collect all pertinent data available. Adequate data collection should include the most current information from all sources and stakeholders. Data can come from http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 World Oil Page 2 of 8 multiple sources including, but not limited to, local, regional and global well histories, reports, studies and 40 personal experiences. Risk assessment success depends on the quality and range of the participants' knowledge and experience. A broad knowledge base and a wide range of expertise produce better results. Drilling engineering peers and personnel of other disciplines, such as geoscientists and reservoir and production engineers, should be integral sources of input during discussion and planning. Providers of critical services should also be included in the process. The degree of rigor applied to the risk assessment process should be commensurate with the complexity of the well. Although the process can be tedious, it begins by defining the scope of each separate risk assessment session, the sum of which make up the process. All stakeholders involved need to provide their expertise; it is important for the stakeholders of various disciplines to fully understand the impact of their own objectives, procedures and requirements and to be prepared to brainstorm on any given operational task. Understanding the scope of each session allows the stakeholders to use their own experiences and knowledge to discern possible and probable risks and hazards. Asking "what if' opens the session to speculative scenarios. If, for example, the session scope is risk assessment of tripping the drillstring, the "what ifs" would include such risks as stuck pipe, loss of circulation and swabbing. Participants prepared to bring their experiences and knowledge to identify risks and hazards help the team use time efficiently, stay within the scope, and compile a comprehensive assessment. CONDUCTING RISK ASSESSMENT SESSIONS The initial risk assessment session should be conducted in a multidisciplinary environment to collect risks and associated consequences from the stakeholders. All participants should be given an opportunity to identify their 40 risks and consequences, which can be accomplished through simple brainstorming. Once the "what ifs" are identified, consequences can be determined by asking "so what." Identification of potential risks and their consequences constitutes the risk register—i.e., the full list of "what ifs" and "so whats" associated with all operations. Adherence to a few basic rules can help ensure an effective session. They include appointing an unbiased facilitator and an excellent scribe; reviewing the risk assessment tool and its capabilities; and defining and communicating the session's scope before beginning. In addition, it is important to maintain reasonable time limits for sessions; experience suggests that anything over two hours can be counterproductive. The risk register should be completed offline by the engineer or another person responsible for the project or well. Do not debate or wordsmith the brainstorming session; simply allow each person to offer his or her ideas and record them in the register. Work out granularity and details offline. The idea of a brainstorming session is to record, simply and concisely, the risks and associated consequences that collectively constitute the risk register. RISK ASSESSMENT PROCESS The risk assessment process is dynamic and should be continually reviewed and updated with the most current information. Because a consequence can also become a new risk, the assessment process can be somewhat circular in nature. For example, if the risk is fluid loss and the consequence is stuck pipe, this consequence becomes a new risk that generates a new consequence, such as that the pipe becoming irretrievably stuck. The key to addressing circular issues is managing the worst -case risk event first. This approach usually resolves circular issues and the original risk itself. The risk then eventually becomes mitigated and thus managed. • Sometimes risk can be superfluous, or deemed so by some of the stakeholders. For example, a driller might be concerned about the risk of sticking a wireline tool given hole conditions, while a geologist might not think it is a problem. Nevertheless, these risks should always be recorded and evaluated. The process, particularly if the worst -case risk events are evaluated first, often removes the superfluous issues by default. http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 World Oil Page 3 of 8 ofAnother issue that sometimes arises focuses on the costs used to determine the risk -adjusted value of a new mitigant. This issue should be raised in the early, brainstorming risk assessment sessions, but only using rough numbers, since these sessions should be high-level discussions. Dwelling on minutia at this point leads to losing sight of the scope. If more granularity is required, a subsequent risk -assessment session can be scoped, communicated to all stakeholders, and conducted on that singular focus. Over time, granularity and objectivity improves, but keeping the multidisciplinary brainstorming sessions at a high level is necessary to establish an initial baseline. rI The risk assessment process should also determine and justify tradeoffs among geoscientists, reservoir engineers, production engineers and drilling engineers. Accommodating stakeholders from each of these disciplines is fundamental to the process and one of the reasons why it is necessary to assess any risk mitigant. Total cost of ownership means that the various disciplines understand the tradeoffs that occur in well planning designs and, ultimately, execution of the well. For example, directional well targets in slimhole profiles have specific risks associated with hole cleaning. The geoscientists need to understand this issue and how the associated risks impact the cost of the well. Risk assessments become a decision quality tool and therefore assist in evaluating alternative well models. The risk matrix. Acceptable forms of risk matrices can range from a very simple categorization of risk by high, medium and low risk of occurrence to a more granular tabular matrix for probability on one axis and severity of consequence on the other. In general, the more granular the matrix, the more valuable it is in terms of defining, ranking and managing risks. Table 1 depicts a typical industry risk matrix. The risk matrix can be adjusted for levels of likelihood or probability and costs. Identifying costs associated witl• consequences is important to evaluate the added value and risk -adjusted costs of any new mitigant. The only exception is for health, safety and environmental (HSE) risk, because it is not possible to monetize the value of human life. Adjustments to the matrix axis should be based on relevant best fits for any given project. For example, if an operation is in deep water, costs should be those that are relevant to the operation itself. Probabilities are more subjective, but percentages of occurrence should be based on the experience and knowledge of, and agreed to by, the team conducting the risk assessment. In general, the same matrix should be used for successive operations at a given project or well, to provide continuity, so long as the relative values remain representative of the project or well over time. If these values change significantly, then a new matrix may be warranted. The risk assessment process tool. It is important to capture risks in a tool that can be used to conduct and record the entire risk assessment process. The process must be auditable and sustainable. Table 2 represents a typical industry risk assessment tool populated with step -wise aspects of the process. The table uses actual examples to illustrate key points. http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 World Oil Page 4 of 8 - =A�=� �_ EXECUTION PHASE AND WELL LISTENING In the execution phase of well operations, DHM begins with understanding and making the correct proactive decisions regarding the totality of the drilling dynamics. The art of "listening to the well" involves simply recognizing, integrating and correctly interpreting all drilling dynamics —weight on bit, drillstring rotational speed, equivalent circulating density (ECD) and shale shaker cuttings —to assist in making the correct decision while executing drilling operations. For example, indicators that the ECD is too low include the following: Unexpectedly high rate of penetration (ROP). A mud weight that is too low can have the net effect of removing the force at the bit, allowing the formation being drilled to fail more easily, thus increasing ROP. Torque/drag increase. Removal of mud weight force can cause the formation to collapse inward, thereby . creating lateral forces on the bit, BHA and drillstring. Cavings (particularly concave or splintered). Recognizing the types of cuttings over the shaker is critical to drilling data interpretation. Cuttings from a shale section where the wellbore is approaching failure will characteristically appear concave (the shape of the hole) or splintered. Flowrate increase. Decreased force of the mud weight can create underbalanced conditions, allowing fluid influx into the wellbore. Shut-in drill pipe pressure and/or well control. This is an obvious condition of well control events or formations trying to feed into the wellbore. Drilling break gas failing to "fall out" after circulating. This indicates in situ gas feeding into the wellbore from a permeable gas horizon. BHA drift (principal stress vectors). Pseudo -induced stress can be caused by tectonics, salt diapers, faults, etc. Stress can be quite different from pore pressure in magnitude and is a vector. This phenomenon can have the net effect of trying to force the BHA in a principal direction if not correctly balanced with mud weight. Recognizing the difference between stress and pore pressure while drilling is crucial to interpreting dynamic drilling data. Hole fill -up (sloughing or collapsing hole). Hole collapse can result in fill when off bottom and is quite common in softer formations. Indicators of excessively high ECD include the following: ig Unexpectedly low ROP. If the mud weight is too high, it can have the net effect of adding confining force at the bit, making the formation being drilled more difficult to penetrate; thus the ROP decreases with poor performance. High bit wear. Extraordinary mud weight force creates more confining stress on the rock, making the rock more difficult to drill. http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 World Oil Page 5 of 8 Overly wet shale. Mud weight that is too high increases the instability of the shale section. Shale is not permeable but does respond to wetting through ionic exchange, much the same as clay on the ground that cracks when dry, then swells when hydrated. Overly wet shale reduces the net effect of inhibition, regardless of the drilling fluid. Even oil -based systems are never 100% water free. Fluid loss. Mud weight that is too high creates unnecessary fluid losses and differential sticking, and exacerbates the risk of fracturing softer formations. Indicators of other hazards include the following: D exponents (changing drillability trends). This quantity represents real-time drilling analogs of specific energy applied to the bit or formation drillability. This data is normally and routinely compiled in the mud log and can represent shifts in drilling trends from a normal to a stressed environment. Trend shifts are very reliable predictors of changes in the drilling environment. This data compiled with other interpretations can be a clear indictor of the need to increase mud weight, especially in light of other interpreted data. A common misunderstanding in the industry is that D exponents have no value with fixed cutters, when quite the opposite is true. This engineering -specific energy algorithm is independent of bit type. Another value of these as trend predictors is that they can help forecast changes in wellbore stresses, which pressure -while -drilling (PWD) tools cannot. PWD tools measure only the net balance in the static and dynamic states. Elliptical hole (principal stress vectors). An elliptical hole is normally an after -the -fact indicator, but recognizing this stress -induced hazard can help plan the next well to identify wellbore stability issues and assist in directional planning. This data can also be used to compare conventional pore pressure predictions to stress both in direction and in magnitude and to better deliver a reliable mud weight schedule and help improve predictions. Fluffy, wetted shales (chemical instability). Chemical instability is common in shale. Cuttings characteristics can be exhibited as "fluffy" or, in the worst case, gumbo. This phenomenon can happen in any mud balance condition and is exacerbated if the mud weight is too high. If wetting occurs with mud weight too high, reducing the mud weight can create further instability because wetted shale will relieve stress. Newly exposed shales undergo ionic exchange and are re -wetted. Once the applied mud weight is too high, it can be nearly impossible to correct this condition, as the hazard will compound itself. LIMITS OF REAL-TIME DATA The advent of real-time technologies facilitates accurate decisions and best practices for any operation. However, the industry's growing dependence on real-time data can foster a singular focus that sometimes results in misinterpretation of issues. For example, operators often respond to the commonplace occurrence of background gas by weighting up drilling systems arbitrarily. This reaction —or a reaction stemming from misinterpretation of any of the above dynamics —is counterproductive to performance and can also induce dangerous drilling conditions. Good drilling practices revolve around interpretation of the totality of the data to make the correct decision while drilling; singular interpretation of conditions associated with any of the drilling dynamics can be counterproductive to maintaining a safe and stable wellbore, as illustrated with the following examples. Ballooning (wellbore breathing). Ballooning is a phenomenon that often occurs as a consequence of excessively high ECD. Resultant flowback when pumps are shut down can often be confused with influx caused by a pore pressure that is greater than mud balance. This interpretation is often further complicated by gas entrained in shale, common especially in mottled shale. "Weighting up" the mud to counter the shale gas can further complicate ballooning. Arbitrarily increasing mud weight in the presence of shale gas alone can result in the extension of natural fractures or fracturing of the formation below or at the shoe, sometimes with catastrophic consequences. Failure to distinguish ballooning from a well control event is a common mistake made in drilling operations. It is http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 World Oil Page 6 of 8 • also one of the leading causes of unnecessarily expending casing strings in narrow -margin drilling operations such as occur in high-pressure/high-temperature and deepwater environments. In a typical case in an actual well, high ECD resulted in ballooning, and a subsequent increase of the mud weight resulted in the extension of existing fractures. The higher ECD further exacerbated wellbore instability by increasing the cyclic bleed -offs. Ultimately, the mud weight increase fractured the formation, and massive and unsafe fluid losses were sustained before control of the well was regained. The sequence of events began with the setting of casing at 11,370 ft with 1.7-sg mud weight. This mud weight was arbitrarily increased in the shoe track to 1.9 sg before drilling ahead. ECD management became difficult, with frequent ballooning events. Frequently conducted flow checks showed no flow. All other drilling dynamics were normal; there was no torque or drag, and cuttings appeared normal. As background gas increased in the shale interval, the mud was weighted up several times without conducting any flow checks. Gas alone is not a reason to increase mud weight; since shale does not have transmissibility but does have porosity, entrained gas is common and cannot be weighted out, especially in highly mottled shale. Entrained gas always arrives with the cuttings and expands according to Boyle's law, no matter the mud weight. Drilling in shale continued from 13,300 ft to 14,000 ft, with increasing background gas. The well was circulated and conditioned with no fill. The BOP was closed with no flow and no pressure observed, and control was circulated through the choke. No torque spikes, drag or fill were observed, and cuttings still appeared normal. Mud weight was increased to 2.0 sg while circulating on the choke. The shut-in drill pipe pressure of 340 psi was bled back with no further flow or pressure. The BOP was closed with 340 psi, then opened. The well briefly had a small initial flow and then shut in with no pressure. The well was opened and found to be stable with no flow. Shut-in pressure was not measurable. The well was circulated and conditioned, and the mud weight was further increased to 2.3 sg, and later to 2.45 sg with immediate and massive fluid losses. Ballooning -induced fracturing occurred after the mud weight increase. Three days of circulating and conditioning back to 2.1 sg was necessary to stabilize the well. A decision was made to run liner once the well was stable. The pore pressure/fracture gradient curves were observed to be normal. It was determined that, other than background and connection gas, which bled off, there had been no reason initially to increase the mud weight. In this well, properly managing ECD and recognizing ballooning as a consequence of high ECD could have allowed the well section to be drilled deeper. The misinterpretation of ballooning required the setting of a liner before planned and caused the loss of a casing point. The consequences could have been much worse— wellbore collapse or even a shallower formation influx from an underbalanced formation. When ballooning is recognized, care must be taken to avoid unnecessarily weighting up. Instead, trapped pressure must be bled back. Figure 1 represents an actual case where ballooned pressure was recognized and successfully bled back. 1e.e 16.8 Ckafdte to redo® aid wow tran 16 3 W 17,6 qq heeeue�tPMde4i� 16.0 v 17.6 17.66 M9 g ,76 o ,7.7 Bkcdoff flu 17.6 ld -17,76� W 17.5 H711 17.E %Wk0 , 7.3 6i rLa pi CbN9 1A rum" swc. swesm BIL a r, SK MM, 191v http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 World Oil Page 7 of 8 • Fluid loss. Fluid losses can range from slight to catastrophic and result in wellbore failure or well control events. They primarily occur because the ECD is outside the safe drilling margin defined by the overburden fracture gradient on the high side and the in situ pore pressures and stress of the formations on the low side. These boundaries can be exceeded as a result of ballooning or, in porous formations, because an unnecessarily high mud weight is applied. Maintaining the ECD low enough to ensure fluid volume integrity yet high enough to maintain wellbore integrity is critical, and requires well listening. Sometimes losses can be acceptable and sustained. In these cases, recognizing the types, relative volumes, classes of lithology, and placement of proper lost -circulation material (LCM) is critical to the successful management of fluid losses. The best practice and first line of defense is to avoid overweighting the hole and thereby prevent ballooning events. Typical fluid loss decision tree processes can and should be created. Table 3 is an example of the foundation of a fluid -loss control application process. Solution set 1, Avoid applying excessive mud weight; improve hydraulics and overall ECD including improved hole cleaning and controlled drilling_ 2. Flush or spot 1 3% fibrous and/or flaked LCM pill, or add 1 3% fibrous and/or flaked LCM to circulation mud. 3. Flush or spot 1-3% sized calcium carbonate pill, or add 1-3% sized calcium carbonate to circulation mud. 4. Spot andJor squeeze 8 12% LCM pill (mixture of fibrous, flaked and granular LCM). 5. Apply cement spot and at squeeze. 6. Specialty techniques such as chemical pig or gunk squeeze. 7, Blind drilling. 8. Improve mud cake by adding asphaltic material. Application Type off ormation Sandstone Coal Shale Med. Frac• Small Frac- Type of loss Congl, for silty Low par por High par, tured fissured lured shale) Seepage 12 1 only Small 1,2 1,2 losses Medium 14 1,4 losses High 1,4,5 1,7,4,5 losses Uncontrolled 17,4,5,6 1,7,4,5,E losses 1,3 1,3 13 13 1.3 1,8 1.8 1,3 1,3,2 1,3,2 1,8,2 t,8,2 1,16 1,125 1,3,2,5 1,3,2,4,5 1,2,4 1,2,4,5 1,3,5,6 1,3,5,E 1,4,5,E 1,4,5 1,4,5 - - 1,7,4,5,E 1,7,4,5,6 1,4,5,E 1,4,5,6 Stuck pipe. Stuck pipe is a drilling hazard that can be associated with ballooning and fluid losses. Recognizing and avoiding stuck pipe requires some of the same well listening techniques as used for other hazards. Generally, stuck pipe is avoidable if drilling margins are honored and listening guidelines are observed. Some causes of stuck pipe that might have little to do with the drilling margin are coal sections; shale welling http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 World Oil Page 8 of 8 (gumbo); hole packoffs around the BHA; under -gauge hole; wellbore geometry (such as hole restriction in highly permeable sections with high fluid loss); collapsed casing; cement blocks; junk; green cement; cuttings beds or buildup, especially in high -angle holes; and salt, causing plastic flow. Prevention of stuck pipe in each of these scenarios requires an awareness of overall hole conditions; of course, some are unavoidable, such as unknown collapsed casing. Nonetheless, they should all be considered as potential risks and assessed. The best practices to avoid stuck pipe are much the same as for ballooning and fluid loss —recognizing the conditions within the drilling margins and events and reacting correctly. Other factors that should be considered include BHA and drillstring configuration, as well as the inhibitive characteristics of the formations being drilled. NEXT INSTALLMENT Part 3 addresses the integration of mitigation into the well design. Managing drilling hazards requires understanding how practices and technologies can improve the risk profile and add value—i.e., demonstrate a positive cost -benefit balance from a risk -adjusted perspective. Any new mitigant must decrease the likelihood of the risk event occurring, and the risk adjusted cost should be financially beneficial to the overall operation. It is therefore important to understand how various technologies can improve the ability to mitigate and manage risk and improve the ultimate value of the well. IVO THE AUTHORS David Pritchard is a petroleum engineer with 40 years of industry experience, including management and supervision of worldwide drilling and production operations. He has consulted for an array of national and • international independents, major companies and service providers. As owner of Pritchard Engineering and Operating, Mr. Pritchard developed, participated in and operated a number of oil and gas properties in the ArkLaTex region of the US. He holds a BS degree in petroleum engineering from the University of Tulsa. • Pat York is the Director of Commercialization and Marketing for Weatherford Intl.'s Solid Expandables and Drilling Hazard Mitigation product/service lines. He has 38 years of oil and gas industry experience. Before joining Weatherford, Mr. York was Vice President of Commercialization and Marketing for Enventure Global Technology after tenures with Halliburton and Dresser Atlas. He earned a BS degree in electrical engineering at Northwestern State University in 1972 and pursued his MBA degree there before launching his oilfield career. Scott Beattie has 22 years of oilfield service experience. After spells with Halliburton and Baker Oil Tools, he has spent the past 14 years with Weatherford Intl. in various roles, primarily supporting drilling technologies. Mr. Beattie's latest assignment is in Kuala Lumpur, Malaysia, as Global Business Unit Manager for Drilling with Casing. He is a key member of Weatherford Intl.'s Drill Hazard Mitigation team. Don Hannegan is the Drilling Hazard Mitigation Technology Development Manager for Weatherford Intl. He received World Oil's 2004 Innovative Thinker Award for his role in conceiving and developing specialized equipment and concepts applicable to managed pressure drilling of challenging and complex wells. He was recently appointed by the University of Texas Petroleum Engineering Extension Service (PETEX) to serve as lead author of a textbook to be titled Drilling Hazard Mitigation Tools & Technology. http://www.worldoil.com/Drilling-hazard-management-The-value-of-risk-assessment-octo... 11 /3/2010 Offshore Previous Page � Contents I Zoom In � Zoom Out � Front Cover I Search Issue � Next Page C&_�w • • DEEPWATER HORIZON INCIDENT Top, bottom kill prospects leave Macondo just a nasty memory Despite some cohesive collaboration with even competitors, BP seems ready to endure the brunt of post -spill reproach as anti -offshore forces gather their traps F. Jay Schempf Contributing Editor he custom -designed "capping stack" installed by BP over the damaged sea - floor wellhead at the Macondo prospect in the Gulf of Mexico was removed in early September, with a switch -out of BOP stacks the next move in the company's nearly five -month battle to combat what many have called the worst oil spill in U.S. history. But even with the nightmarish experi- ence of dealing with death, destruction, and pollution, BP plc, the main character in the so-called "Deepwater Horizon Explosion and Oil Spill" has a long way to go before things get right. The capping stack — a temporary flow con- trol mechanism placed atop the well's origi- nal seafloor BOP in about 5,000 ft (1,524 m) of water — was installed in mid July. It suc- cessfully stopped oil and natural gas produc- tion that had leaked at a rate that some esti- mates argue reached up to 60,000 b/d. The incident at the well site killed 11 workers and sunk Transocean's fifth -generation ultra- deepwater semisubmersible rig, Deepwater Horizon. It occurred in Mississippi Canyon block 252 about 52 mi (84 km) southeast of Venice, Louisiana. The water depth involved is a record for such an incident. Super -cautious, painstakingly deliberate action has dominated the work by BP and its contractors/subcontractors to tame the long -time -uncontrolled oil and gas flow from the well. Under the oversight of a federal response task force headed by retired U.S. Coast Guard Rear Admiral Thad Allen — along with other federal and private watchdogs — BP made several unsuccessful "quick fix" attempts to gain control of the well in the weeks just after the spill. However, this cul- minated in the capping stack installation, which did the trick. Meanwhile, two relief wells were being drilled. With the leak stopped, however, even 50 Offshore October 2010 • wwwoffshore-mag.com The Blue Dolphin and HOS Centerline were used to pump mud to the 04000 for the "static kill." on MC 252 in the Gulf of Mexico. (U.S. Coast Guard Photo) more vigilance prevailed as leaders of the joint initiative decided not only to ultimately "kill" the flow at the reservoir level via the relief well, but also to ensure no unchecked flow was possible at the top -of -the hole area by achieving a "static" kill with drilling mud and a cement plug there, as well. With the static kill accomplished in late August, the BP/federal response team then elected to ensure total overall control by re- moving the capping stack and the Deepwa- ter Horizon's damaged BOP, replacing them with a second full BOP stack supplied by Transocean's mobile drilling/completion rig, Development Driller II. This rig had been drilling the second re - fief well but had interrupted its work as the first relief well, being drilled by its twin, the Development Driller III, neared its final inter- ception point. The relief well successfully penetrated the Macondo well's casing to pump still more drilling mud and cement to stop any pressur- ized leaks from the formation into the hole, thereby concluding mechanical control of the 18,500-ft (5,639-m) ultra-deepwater well. Smoke signals beckon Retrieval of the damaged Macondo BOP may be tatamount to finding one of what could be several "smoking guns" implicated in the Deepwater Horizon blowout/fire and oil spill. That spill led to leaking oil stretch- ing across large sections of the U.S. Gulf of Mexico, including numerous spots along the shorelines of at least three states — Louisi- ana, Mississippi, and Alabama. Both civil and criminal charges could re- sult from close inspection of the retrieved BOP and other Macondo equipment, and from testimony in a number of current and future hearings by a special panel created by US President Barack Obama, as well as by committees and subcommittees in both houses of Congress. The rhetoric coming from this jumble of independent investiga- tions combines for a promise to get "to the bottom" of how the Macondo incident could have happened. Even the President said he was looking for whom to kick visa vis its causes — both mechanical and personal. It was no surprise that Gulf of Mexico exploration and development, particularly Offshore Previous Page Contents � Zoom In I Zoom Out I Front Cover I Search Issue Next Page �1 J Offshore Previous Page � Contents � Zoom In � Zoom Out � Front Cover � Search Issue � Next Page C&k& • DEEPWATER HORIZON INCIDENT in deep and ultra-deepwater, would be cur- tailed — or even stopped — for a while as the blame game blossomed. However, when the President ordered Interior Secretary Ken Salazar to declare a six-month drilling mora- torium in the Gulf in the early aftermath of the spill, the reaction by the industry came as no surprise either. Anti -moratorium ap- peals to both federal and state courts were filed by various industry groups, and then upgraded to cover changing specifications made by Salazar to outmaneuver them. The industry challenges — backed stiffly by Gulf state governors, congressmen, and senators — predicted a disastrous backlash made up of delayed offshore production, lost jobs, and a mass exodus of deepwater drilling and support equipment to other pro- ducing regions of the world. Many producing companies, they pointed out, would cancel their immediate plans for Gulf development in favor of onshore work or for offshore activity in more industry - friendly areas. About that moratorium... The moratorium, ordered in May, appar- ently had not resulted in such dire down- turns, at least at press time. In fact, many producers as well as drilling and production services contractors anticipate that the stop - drilling order may be lifted earlier than in No- vember, and a number of them have held on to their field personnel in anticipation of a re- turn to pre -spill activity. Paint sales along the Gulf Coast likely have skyrocketed as com- Karmsund Maritime The damaged Macondo BOP. along with the lower marine riser package (LMRP) cap, have been removed from the Gulf of Mexico. Con- sidered evidence in a Justice Dept. investiga- tion, the entire package was moved to a secure onshore storage area for inspection. (U.S. Coast Guard photo) parties create "busy work" for their people to keep them around at full (or partial) pay. Additionally, much of the oil spilled into the Gulf apparently has either been collected by skimmers on the surface and by workers on beaches and coastlines; has been burned; has been chemically dispersed; has evaporat- ed; or is being consumed by bacteria, leaving a much less deleterious effect than fast pre- dicted on Gulf states residents and on region- al industries, including fishing and tourism. What's more, BP plc, operator at Macondo for minority partners Anadarko Petroleum and MOEX Offshore 2007, a unit of Mitsui Oil Corp., has pledged to "be there" for the entire life of the spill and its after-effects, having set up a $20 billion fund (with a partial recoup via asset sell -offs) from which legitimate claims of damages suffered by businesses and individu- als will be paid out by an independent settle- ment organization administered by presiden- tial appointee Kenneth Feinberg. ■■•.ra KaMOV Gaskets verifies correct installation by pressure testing the ring room in flanges. Selected references: BP, ExxonMobil, Total, Saipem, Shell, J.Ray McDermott, Hyundai, ConocoPhillips, Chevron, PTTEP, Halliburton • "KaMOS" Gaskets to be used, when having too many leakages in flanged connections..." Offshore Previous Page Contents � Zoom In � Zoom Out Front Cover Search Issue Next Page cnffo�� Offshore Previous Page � Contents � Zoom In I Zoom Out � Front Cover � Search Issue � Next Page - o t • DEEPWATER HORIZON INCIDENT = C • The petroleum industry, in general, seems to have recognized the perils hidden within the business of technology -hungry deepwa- ter exploration and production. Some com- panies already have reconstituted their in- house safety and training programs, and all of them seem to be quickly making changes ordered by the Interior Dept.'s Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), the successor to the Minerals Management Service. Everybody wants to help In the wake of the blowout/spill, BP itself has partaken in a colloquy of new ideas from which both present and future offshore op- erations within the entire offshore industry perhaps stand to benefit. While working closely with its contractors and subcontractors at Macondo, the com- pany acknowledged that it also has worked openly with its competitors in the Gulf to help enhance technology targeted at stop- ping a spill at the wellhead, and cleaning up its effects in open water, the transition zone, and along the shoreline. From the outset, BP's website included a toll -free telephone number to which interested parties — that is anyone — could offer general assistance and/or submit alternative response technology, services, or product ideas. Mike Utsler, COO for BP's Gulf Coast Res- toration Organization, formed to oversee the company's long-term commitment to return- ing spill -affected area to its former condition, said more than 120,000 ideas were submitted to the telephone number by a range of indus- try members, as well as from scientific and environmental organizations, and even from private citizens. "About two-thirds were focused on how to shut off the well and the rest were ideas on everything else regarding cleanup ac- tivities," Utsler said in an unusual Aug. 31 question/answer session on Facebook. A team of scientists and subject matter experts reviewed the ideas and separated them into short-, medium- and long-term solutions, he added. From those, novel solution ideas were singled out for more intense study. "We have actually converted hundreds of those ideas into solutions," he said, including as examples the conversion of new barges into skimmers for use in both deep and shal- low water; different tar ball recovery devices for both beaches and in tidal zones; and di- verse technologies for source control below the water line, many of which were intro- duced into cleanup processes. "We continue to accept and take all ideas, evaluate them, and look for those that can be turned into solutions to support the response," he said. Litigation looms The murky subtext beneath the whole Macondo universe, despite the good news, reads plain: The "blame game." So: • There are lots of allegations from many quarters • There are many vengeful anti -oil sena- tors and congressmen • There are uncountable litigious attor- neys • There will be lawsuits and other court battles • There may be mergers and acquisitions • And there will even be more crazy stuff like movie actor Sean Penn's pronounce- ment that the death penalty be invoked when dealing with any proof of criminal behavior in connection with the incident. Onlookers can only wait, however, until the after effects make themselves known. O PROCEED WITH CONFIDENCE — QUICKLY www.oHshore-mag.com • October 2010 (Nfshm c 53 Offshore Previous Page Contents 1 Zoom In Zoom Out Front Cover Search Issue Next Page C&)ff& V11Ln.11V1C I IUVIUUJ I Q9C I ',JUIILUIIW I LUUM III I LUUIII '.JUL I I IUIIL \JUVGI I %JGQILH IJJUU I Ivcnt I QI,G Why � = DRILLING & PRODUCTION • • • More information on Macondo The reports are coming, as we expected they would, and not surprisingly, they don't agree in every detail. We're referring, of course, to ongoing inves- tigations into the possible contributing factors - and measures to prevent future similar events - regarding the Macondo well explosion and fire in the US Gulf of Mexico earlier this year. A joint industry task force has made some equipment and procedural recommenda- tions, without attempting to determine cause by specific party. Almost on the same day, BP released a report that concludes that the ac- cident was the result of a number of failures, shared by many of the companies participat- ing in the Macondo project The Joint Industry Task Force to Address Subsea Well Control and Containment, chaired by Charlie Williams of Shell and with over 30 participants, says that the primary focus of its investigation is and will be on single wells in deepwater and on operations that can occur af- ter a BOP has failed and ROV shut-in attempts have failed or are not possible. The task force addresses five key areas of focus for GoM deepwater operations: • Well containment at the seafloor • Intervention and containment within the subsea well • Subsea collection and surface process- ing and storage • Continuing R&D • Relief wells. The task force has made 29 recommenda- tions, and says that the industry must: • Own and provide containment technol- ogy and capability • Develop capability to remove the lower marine riser platform (LMRP) from the blowout preventer (BOP) using a sur- face intervention vessel and remotely operated vehicle (ROV) • Develop new methods to release the LMRP without riser tension • Develop the capability to remove a dam- aged BOP for installation of a new BOP in special situations • Develop the capability to regain full functionality of the BOP stack. The JITF also recommended that the in- dustry: • Be able to repair or replace non-func- tioning control pods to be able to regain full functionality of BOP stack (ROV intervention provides limited function- ality). • Provide additional and more effective methods of connecting to and control- ling BOPs with ROVs. • Assess industry capability and conduct in -situ testing to determine what new technology and capability needs to j Eldon Ball • Houston be developed to remove a debris field and cut equipment like risers. Develop new equipment and capability as deter- mined by testing. • Assure necessary wellhead structural support via design and practices in the event of strong side forces from drifting connected rigs and riser collapse from rig sinking. • Evaluate new and evolving ideas for subsea containment including open cap- ture devices that would have separation capability. R&D should be a key part of the containment company in which all industry can participate. All the R&D programs will work collaboratively with appropriate organizations like RPSEA and Deepstar to ensure maximum le- verage in the R&D program. In future investigations, "Consideration will also be given to containment of open casing or casing leaks," the group says. "Although some technical solutions can be applied to subsea producing wells and templates, these will be focused on in future work. The review will not include blow out preventers and con- trol systems such as emergency disconnect systems, autoshear systems, and deadman systems, all of which are covered in the Off- shore Equipment task force." Participating in the Subsea Well Control and Containment Task Force were AM- POL, Apache, API, Anadarko, ATP, Baker Hughes, BHP Billiton Petroleum, Chevron, Cobalt, ConocoPhillips, Delmar Systems, Diamond Offshore Drilling, Dorado Deep, ENI, ExxonMobil, FMC Technologies, GE Oil and Gas, Halliburton, Helix, IPAA, Mc- MoRan Exploration, Newfield, NOV, Petro - bras, Schlumberger, Shell, Statoil, USOGA, and Wild Well Control. The complete report can be viewed at www.noia.org. BP says: 'Series of failures' Meanwhile, a report released by BP con- cludes that decisions made by "multiple com- panies and work teams" contributed to the Macondo well explosion and fire. According to the report, the accident arose from "a complex and interlinked series of mechanical failures, human judgments, engi- neering design, operational implementation and team interfaces." BP says the report was based on informa- tion available to the investigating team It notes that additional relevant information may be forthcoming -for example, when Halliburton's samples of the cement used in the well are re- leased for testing, and when the rig's blow-out preventer is fully examined after it has been recovered from the seabed. There will also be additional information from the multiple ongo- ing US government investigations. The report is based on a four -month inves- tigation led by Mark Bly, BP's head of Safety and Operations, and conducted independently by a team of over 50 technical and other spe- cialists drawn from inside BP and externally. Commenting on the report, which he commissioned immediately after the Ma - condo explosion, BP s outgoing chief execu- tive Tony Hayward said: "It is evident that a series of complex events, rather than a single mistake or failure, led to the tragedy." The investigation report is available on- line at www bp.com, together with an accom- panying video. O 30 Offshore October 2010 • www.offshore-mag.com • Panel Says Firms Knew of Cement Flaws Before Spill by JOHN M. BRODER Published: October 28, 2010 WASHINGTON — Halliburton officials knew weeks before the fatal explosion of the BP well in the Gulf of Mexico that the cement mixture they planned to use to seal the bottom of the well was unstable but still went ahead with the job, the presidential commission investigating the accident said on Thursday. Gerald Herbert/Associated Press The Deepwater Horizon oil rig is seen burning in Venice, La., Tests performed before the deadly blowout of BP's oil well in the Gulf of Mexico • should have raised doubts about the cement used to seal the well, but the company and its cementing contractor used it anyway. Multimedia 3 Interactive Feature A Flawed Cement Recipe Related • Inquiry Puts Halliburton in a Familiar Hot Seat (October 29, 2010) • Times Topic: Gulf of Mexico Oil Spill (2010) Readers' Comments Readers shared their thoughts on this article. • Read All Comments (326) » In the first official finding of responsibility for the blowout, which killed ii workers and led to the biggest offshore oil spill in American history, the commission staff 0 • determined that Halliburton had conducted three laboratory tests that indicated that the cement mixture did not meet industry standards. The result of at least one of those tests was given on March 8 to BP, which failed to act upon it, the panel's lead investigator, Fred H. Bartlit Jr., said in a letter delivered to the commissioners on Thursday. "There is no indication that Halliburton highlighted to BP the significance of the foam stability data or that BP personnel raised any questions about it," Mr. Bartlit said in his report. Another Halliburton cement test, carried out about a week before the blowout of the well on April 2o, also found the mixture to be unstable, meaning it was unlikely to set properly in the well, but those findings were never sent to BP, Mr. Bartlit found after reviewing previously undisclosed documents. Although Mr. Bartlit did not specifically identify the cement failure as the sole or even primary cause of the blowout, he made clear in his letter that if the cement had done its job and kept the highly pressurized oil and gas out of the well bore, there would have been no accident. • We have known for some time that the cement used to secure the production casing and isolate the hydrocarbon zone at the bottom of the Macondo well must have failed in some manner," he said in his letter to the seven members of the presidential commission. "The cement should have prevented hydrocarbons from entering the well." The failure of the cement set off a complex and ultimately deadly cascade of events as oil and gas exploded upward from the 18,000-foot-deep well. The blowout preventer, which sits on the ocean floor atop a well and is supposed to contain a well bore breach, also failed. In an internal investigation, BP identified the faulty cement job as one of the main factors contributing to the accident and blamed Halliburton, the cementing contractor on the Macondo well, as the responsible party. Halliburton has said repeatedly in public testimony that it tested and used a proper cement formula and that BP's flawed well design and poor operations caused the disaster. Jesse Gagliano, a Halliburton technical adviser, told federal investigators in Houston • in August that the company was confident of the cement job and said that BP's • decision to use six well -stabilizing devices known as centralizers contributed to the failure of the cement work. Another Halliburton official, Thomas Roth, told a National Academy of Engineering panel last month that Halliburton's cement met industry standards and that it had been successfully used at more than 1,000 other wells. Mr. Roth said BP ignored "multiple red flags" in the drilling and completion of the well. The Deepwater Horizon drilling rig was operated by a third company, Transocean. Cathy Mann, a Halliburton spokeswoman, said the company was reviewing the panel's findings. A BP spokesman said the company would have no comment. Halliburton, a major oil field services company and one of the nation's largest defense contractors, was once led by former Vice President Dick Cheney. Mr. Bartlit's law firm, Bartlit Beck Herman Palenchar & Scott, has done legal work for Halliburton in the past but has not represented the company since 2005, the firm said. • The commission obtained from Halliburton samples of the same cement recipe used on the failed well, including the same proportion of nitrogen used as a leavening agent and a number of chemicals used to stabilize the mixture. The slurry was sent to a laboratory owned by Chevron for independent testing. Chevron conducted nine separate stability tests intended to reproduce conditions at the BP well and the cement failed them all, the staff report said. "Although laboratory foam stability tests cannot replicate field conditions perfectly," Mr. Bartlit's letter said, "these data strongly suggest that the foam cement used at Macondo was unstable." One and a half gallons of the actual mixture used on the doomed BP well survived and are being held as evidence in criminal and civil investigations. Shortly before technicians began pumping cement slurry down the well on April ig, Halliburton conducted one last test of the mixture. The company changed some of the conditions of the test and appeared satisfied with the result, although those findings were not communicated to BP until after the well explosion, the commission found. • The commission concluded, "Halliburton may not have had — and BP did not have — the results of that test before the evening of April 19, meaning that the cement job may have been pumped without any lab results indicating that the foam cement slurry would be stable." Further, the panel found, "Halliburton and BP both had results in March showing that a very similar foam slurry design to the one actually pumped at the Macondo well would be unstable, but neither acted upon that data." The commission, appointed by President Obama in May, is led by Bob Graham, the former senator and governor of Florida, and William K. Reilly, a former administrator of the Environmental Protection Agency. The commission is scheduled to present its interim findings on Nov. 8-9 and its final report to the president in mid -January. It released this report early, it said, because other wells may be planning to use similarly flawed cement. Mr. Bartlit, who conducted a much -praised investigation of the 1988 Piper Alpha blowout in the North Sea off Britain that killed 167 workers, said the flawed cement • was not the whole story. Many human and mechanical failures combined to create the disaster, he said, and backup procedures were skipped or ignored. "Because it may be anticipated that a particular cement job may be faulty, the oil industry has developed tests, such as the negative pressure test and cement evaluation logs, to identify cementing failures," he wrote. "It has also developed methods to remedy deficient cement jobs. BP and/or Transocean personnel misinterpreted or chose not to conduct such tests at the Macondo well." In its investigation, BP said that on the morning of April 20, its team decided not to conduct a cement evaluation log. It said that in relying on other types of assessments, the team ignored BP's own guidelines. Robbie Brown contributed reporting from Columbia, S.C., and Henry Fountain from New York. 0 PRESS RELEASE Oct. 28, 2010, 10:54 p.m. EDT ©v� Halliburton Comments on National Commission Cement Testing BusinessWire HALLIBURTON HOUSTON, Oct 28, 2010 (BUSINESS WIRE) -- (HAL 31.70, +0.01, +0.03%) --On May 22, 2010, President Obama established the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (the "Commission") to examine the facts and circumstances to determine the cause of the Deepwater Horizon Oil Disaster, develop options for guarding against future oil spills associated with offshore drilling and submit a final public report to the President with its findings within six months of the Commission's first meeting. • On October 28, 2010, the Commission released results of cement testing Chevron recently conducted on behalf of the Commission utilizing the Chevron cement testing facility in Houston, Texas. In addition, on October 28, 2010, the Deputy Chief Counsel of the Commission sent a letter to the commissioners of the National Commission that describes the results of nine tests on Halliburton's cement design that were performed on behalf of the Commission by Chevron and describes certain testing performed by Halliburton. The letter states that Chevron's laboratory personnel were unable to generate stable foam cement using the materials Halliburton provided and suggests that the foam cement used on the Macondo well was unstable. The letter states that this may have contributed to the incident. Halliburton has only recently received and is continuing to review the results, which it believes raises a number of questions. Halliburton is issuing this press release to provide information about the content and its preliminary views regarding Chevron's cement testing report and the letter. Halliburton believes that significant differences between its internal cement tests and the Commission's test results may be due to differences in the cement materials tested. The Commission tested off -the -shelf cement and additives, whereas Halliburton tested the unique blend of cement and additives that existed on the rig at the time Halliburton's tests were • conducted. Halliburton also noted that it has been unable to provide the Commission with cement, additives and water from the rig because it is subject to a Federal Court • preservation order but that these materials will soon be released to the Marine Board of Investigation. Halliburton believes further comment on Chevron's tests is premature and should await careful study and understanding of the tests by Halliburton and other industry experts. With respect to Halliburton's internal tests, the letter concludes that "only one of the four tests" showed a stable slurry. Halliburton noted that two of those tests were conducted in February and were preliminary, pilot tests. As noted in the letter, those tests did not include the same slurry mixture and design as that actually used on the Macondo well because final well conditions were not known at that time. Contrary to the letter, however, the slurry tested in February was not "a very similar foam slurry design to the one actually pumped at the Macondo well...." Additionally, there are a number of significant differences in testing parameters, including depth, pressure, temperature and additive changes, between Halliburton's February tests and two subsequent tests Halliburton conducted in April. Halliburton believes the first test conducted in April is irrelevant because the laboratory did not use the correct amount of cement blend. Furthermore, contrary to the assertion in the letter, BP was made aware of the issues with that test. The second test conducted in April was run on the originally agreed upon slurry formulation, which included eight gallons of retarder per 100 sacks of cement, and showed a stable foam. • BP subsequently instructed Halliburton to increase the amount of retarder in the slurry formulation from eight gallons per 100 sacks of cement to nine gallons per 100 sacks of cement. Tests, including thickening time and compressive strength, were performed on the nine gallon formulation (the cement formulation actually pumped) and were shared with BP before the cementing job had begun. A foam stability test was not conducted on the nine gallon formulation. The Commission letter concludes by summarizing a widely known industry fact regarding cementing: Cementing wells is a complex endeavor and industry experts inform us that cementing failures are not uncommon even in the best of circumstances. Because it may be anticipated that a particular cement job may be faulty, the oil industry has developed tests, such as the negative pressure test and cement evaluation logs, to identify cementing failures. It has also developed methods to remedy deficient cement jobs. Halliburton believes that had BP conducted a cement bond log test, or had BP and others properly interpreted a negative -pressure test, these tests would have revealed any problems • with Halliburton's cement. A cement bond log test is the only means available to evaluate the integrity of the cement bond. BP, as the well owner and operator, decided not to run a • cement bond log test even though the appropriate personnel and equipment were on the rig and available to run that test. BP personnel have publicly testified they intended to conduct the cement bond log test at a later date and to perform any necessary remedial work at that time. The negative -pressure test evaluates the integrity of the production casing to provide a barrier to the reservoir. A successful test is realized when an applied differential pressure is released and no flow is observed from the system. BP has admitted in its Deepwater Horizon Investigation Report (the "BP Report") that the negative tests were not successful and that the results of those tests were misinterpreted by its own and Transocean's employees on the rig. Had they accurately interpreted the negative tests, remedial action, if necessary, would have been possible. In discussing its preliminary views with regards to the Commission letter, Halliburton emphasized other factors contributing to the Macondo well incident and that BP's well design decisions have been broadly criticized. BP's decision to run a long string rather than a liner and tieback reduced the number of barriers to annular flow to only two, the cement and the seal assembly. The barriers to flow inside the casing include the float equipment and cement. • In addition, according to the BP Report, the float collar in the casing required nine attempts to convert and set and required an unusually high amount of pressure. Public testimony has revealed that BP personnel on the rig were concerned with the high amount of pressure needed to convert the float collar and that the float collar and/or the casing could have been damaged in that process. Despite the extraordinary pressure necessary to convert the float collar, rig operations continued and Halliburton was directed to run the cement job on the production casing. Halliburton also reiterated that it had warned BP engineers that its selection of only six centralizers on the casing string would lead to channeling of the cement in the annulus and the casing shoe track. BP made the decision to use only six centralizers though an additional fifteen were sent to the rig prior to running the casing. Halliburton predicted that the cement job would channel and provide a flow path for hydrocarbons. Whether the hydrocarbons escaped through the annulus or the casing, the decision to use an inadequate number of centralizers remains relevant because cement channeling can provide a flow path of hydrocarbons into the wellbore. According to the BP Report, the Transocean-maintained blowout preventer, which would is have stopped hydrocarbon flow to the surface, failed to operate. In addition, according to the • BP Report, Transocean failed to maintain safety shut-off equipment which might have prevented the incident. Well logs and rig personnel confirm that the well was not flowing after the cement job. BP and/or others, following the misinterpreted negative tests conducted after the cement job, proceeded to displace mud in the production casing and riser with lighter seawater, allowing the well to flow. Given these numerous intervening causes, Halliburton does not believe that the foam cement design used on the Macondo well was the cause of the incident. Halliburton does not believe the issues relating to cement testing invalidates BP Exploration's indemnification obligations as discussed in Halliburton's Form 10-Q for the quarter ended September 30, 2010. Halliburton's contract with BP Exploration relating to the Macondo well is available on its website at www.halliburton.com. About Halliburton Founded in 1919, Halliburton is one of the world's largest providers of products and services to the energy industry. With more than 55,000 employees in approximately 70 countries, the company serves the upstream oil and gas industry throughout the lifecycle of the reservoir -- from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Visit the company's Web site at www.halliburton.com. NOTE: The statements in this press release that are not historical statements, including statements regarding potential reasons for differing cement test results, results of any future testing of cement used on the Macondo well, whether other tests would reveal problems with that cement, the ultimate cause of the Macondo well incident, potential losses from the incident and whether Halliburton will be indemnified for any such losses, are forward -looking statements within the meaning of the federal securities laws. These statements are subject to numerous risks and uncertainties, many of which are beyond the company's control, which could cause actual results to differ materially from the results expressed or implied by the statements. These risks and uncertainties include, but are not limited to: results of litigation and investigations; actions by third parties, including governmental agencies; changes in the demand for or price of oil and/or natural gas which has been significantly impacted by the worldwide recession and by the worldwide financial and credit crisis; consequences of audits and investigations by domestic and foreign government agencies and legislative bodies and related publicity and potential adverse proceedings by such agencies; indemnification and insurance matters; protection of intellectual property rights; compliance with environmental • laws; changes in government regulations and regulatory requirements, particularly those related to offshore oil and gas exploration, radioactive sources, explosives, chemicals, • hydraulic fracturing services and climate -related initiatives; compliance with laws related to income taxes and assumptions regarding the generation of future taxable income; risks of international operations, including risks relating to unsettled political conditions, war, the effects of terrorism, and foreign exchange rates and controls, and doing business with national oil companies; weather -related issues, including the effects of hurricanes and tropical storms; changes in capital spending by customers; delays or failures by customers to make payments owed to us; execution of long-term, fixed -price contracts; impairment of oil and gas properties; structural changes in the oil and natural gas industry; maintaining a highly skilled workforce; availability of raw materials; and integration of acquired businesses and operations of joint ventures. Halliburton's Form 10-K for the year ended December 31, 2009, Form 10-Q for the quarter ended September 30, 2010, recent Current Reports on Form 8-K, and other Securities and Exchange Commission filings discuss some of the important risk factors identified that may affect Halliburton's business, results of operations, and financial condition. Halliburton undertakes no obligation to revise or update publicly any forward -looking statements for any reason. SOURCE: Halliburton • Halliburton Investor Relations: Christian Garcia, +1-281-871-2688 Corporate Affairs Cathy Mann, +1-281-871-2601 Copyright Business Wire 2010 is U.S. Woks at UK plan on drilling regulation SAFETY: North Sea accidents, spills have been cut drastically. By NEELA BANERJEE Tribune Washington Bureau WASHINGTON — Even as the Obama administration al- lows offshore oil and gas oper- ations to resume, government officials are working on a new safety strategy modeled after a British system that has sub- stantially reduced oil spills in the United Kingdom. Washington has long sought to head off disasters such as the BP Gulf oil spill by drafting and trying to enforce hundreds of detailed rules and regulations. Not only has that approach proved cumbersome and often ineffective, it has run the risk of failing to identify po- tential problems. The British system, by con- trast, puts the burden and ultimate legal and financial re- sponsibility — on oil and gas companies to figure out the 41110 myriad ways something could go wrong on a drilling rig or production platform, then show regulators the practic- es and technologies that would be used to avoid or deal with the mishap. The safety record of Brit- ish operations in the often - turbulent North Sea suggests 0 0 0 A-8 Monday, October 25, 2010 SPILL: British process makes indust develo scenarios ContinuedfromA-I �� p this way of doing things can have major advan- tages. With the British approach, "you as the oper- ator have to make sure you catch everything," said John Crum, who has worked on offshore oil and gas projects in the UK and who is pres- ident of the North America unit of the indepen- dent oil company Apache. "There's no excuse for you if things go wrong, because you're the one who wrote the plan," he said. `SAFETY CASE' REGIMEN Versions of the approach, known as "safe- ty case," are used by oil -producing countries around the world, from Norway to Austra- lia, and many others are considering its adop- tion. Over the last decade, the safety case reg- imen in the UK has led to a reduction in major offshore leaks by "a factor of 10," according to Robin Pitblado of the risk management firm Det Norske Veritas. The system was developed after a 1988 di- saster in which a natural gas production plat- form called Piper Alpha blew up and sank off the Scottish coast, killing 167 men. A compre- hensive three-year investigation led the British government to overhaul its regulation of off- shore oil and gas, beginning in the early 1990s. According to industry and government of- ficials, the Obama administration is studying this overhaul as a possible template for the United States. Industry and administration officials say the U.S. may emerge with a hybrid system of traditional prescriptive regulations and safety case standards, creating a system that in many "It requires (the well operator) to write the rules and figure out the chance of this happening or that and this is what you would do to prevent against it. What I like about it is that it makes you plan very well, makes you look at every aspect of what could potentially happen out there. " — John Crum, president of the North America unit of the Independent oil comparry Apache ways will demand more from regulators and oil companies alike. Advocates predict that safety case would significantly reduce the danger of spills. And records indicate it could bring big gains in worker safety.. COMPARING INJURIES About 27,000 people work in the UK section of the North Sea, and in 2008-09 there were 20 major injuries and no fatalities. In comparison, about 35,000 people work in the Gulf of Mexi- co and over the same period there were four deaths and 285 injuries; the U.S. does not break down major and minor injuries. The oil and gas industry, through a joint task force pulled together after the BP disaster, rec- ommended the adoption of a safety case regi- men in the U.S., as have two industry groups, the International Association of Drilling Con- tractors and the American Petroleum Insti- tute. More recently, however, some companies have expressed reservations, fearing that any major change in the safety system could lead to long delays in bringing new wells on line. Yet many companies long active in the North Sea, such as Royal Dutch Shell, use the approach in business units worldwide, and all but one of the 10 international drilling contrac- tors in the Gulf of Mexico has worked in safety case regimens, said Alan Spackman, vice pres- ident of offshore technical and regulatory af- fairs at the International Association of Drill- ing Contractors. Under the current U.S. system, before a company gets permission to drill, it must sub- mit reams of technical information about its plans. Critics say that exercise may fail to an- ticipate all the risks and it does not necessari- ly get those involved to communicate with one another. THEORY AND PRACTICE Any safety system's effectiveness depends heavily on how well it's implemented, which de- pends on whether government agencies have the resources to keep a close eye on offshore operations. On that point, the U.S. record is not encour- aging. For instance, the Gulf of Mexico has 3,400 responses production platforms, most of we in shallow waters. That's about 10 times as many as the British have in their section of the North Sea. In the UK, the ratio of inspectors to oil and gas installations is about 1 to 3. In the U.S., it is 1 to 56. Proponents of the safety case model say it pushes companies to think harder about worst - case scenarios and to upgrade their safety technology and practices to keep up with the evolving risks of ever -deeper drilling. "It's harder on the well operator," Crum said. "It requires you to write the rules and fig- ure out the chance of this happening or that and this is what you would do to prevent against it. What I like about it is that it makes you plan very well, makes you look at every aspect of what could potentially happen out there." UK VS. US In the North Sea, after oil companies come up with their scenarios, UK regulators chal- lenge assumptions the companies made for their disaster scenarios and spend days on the rigs reviewing the way a site is managed. The penalties for safety violations under the British system are also levied more swiftly, and they can turn severe quickly, veterans of the system say. In the U.S., the process takes longer and the oil industry has pressured inspectors, through their supervisors, to set aside violations — a possibility that a new system would not neces- sarily prevent. Still, says North Sea veteran Crum, "Ob- viously, we need to change something, and I think this has a better chance of protecting the environment and people's lives." See Page A-8, SPILL Salazar: Deepwater Drilling May Resume for Operators Who Clear Higher Bar for Safety... Page 1 of 2 4IFY101 tW Tt1F -I.t: WTAXV U.S. Department of the Interior News Release Salazar: Deepwater Drilling May Resume for Operators Who Clear Higher Bar for, Safety, Environmental Protection 10/1212010 Contact: Kendra Barkoff, DOI (202) 208-6416 Melissa Schwartz, BOEM 202-208-3985 WASHINGTON, DC — Secretary of the Interior Ken Salazar has determined it is appropriate that deepwater oil and gas drilling resume, provided that operators certify compliance with all existing rules and requirements, including those that • recently went into effect, and demonstrate the availability of adequate blowout containment resources. Secretary Salazar reached his decision after reviewing a report from Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEM) Director Michael R. Bromwich and considering other information on the progress of offshore oil and gas safety reforms, the availability of spill response resources, and improved blowout containment capabilities. "In light of the Deepwater Horizon oil spill, we must continue to take a cautious approach when it comes to deepwater drilling and remain aggressive in raising the bar for the oil and gas industry's safety and environmental practices," said Salazar. "We have more work to do in our reform agenda, but at this point we believe the strengthened safety measures we have implemented, along with improved spill response and blowout containment capabilities, have reduced risks to a point where operators who play by the rules and clear the higher bar can be allowed to resume. The oil and gas industry will be operating under tighter rules, stronger oversight, and in a regulatory environment that will remain dynamic as we continue to build on the reforms we have already implemented." "There has been significant progress over the last few months in enhancing the safety of future drilling operations, and in addressing some of the weaknesses in spill containment and oil spill response," said Director Bromwich. "More needs to be done — and more will be done to continuously improve the safety of deepwater drilling and to bolster the ability of the government and industry to respond in the case of a major blowout. But we believe the risks of deepwater drilling have been reduced sufficiently to allow drilling under existing and new regulations." Secretary Salazar based his decision to lift the deepwater drilling suspensions on information gathered in recent months, including a report from Director Bromwich on October 1, that shows significant progress in reforms to drilling and workplace safety regulations and standards, increased availability of oil spill response resources since the Macondo well was contained on July 15 and killed on September 19, and improved blowout containment capabilities. Director Bromwich prepared his October 1 report and recommendations based on extensive public outreach and information gathering, including the eight public forums he held around the country to assess safety, spill response, and • blowout containment issues. In his decision today, Secretary Salazar directs BOEM to require the following before approving drilling in deepwater that would have been subject to suspension under his July 12 Decision Memorandum: http://www.doi.gov/news/pressreleases/Salazar-Deepwater-Drilling-May-Resume-for-Op... 10/12/2010 Salazar: Deepwater Drilling May Resume for Operators Who Clear Higher Bar for Safety... Page 2 of 2 Pursuant to applicable regulations, each operator must demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout, regardless of the company or • operator involved. The Department of the Interior has a process underway regarding the establishment of a mechanism relating to the availability of blowout containment resources, and Secretary Salazar said he expects that this mechanism will be implemented in the near future. That the CEO of each operator seeking to perform deepwater drilling certify to BOEM that the operator has complied with all regulations, including the new drilling safety rules. Director Bromwich said that before deepwater drilling will resume, BOEM intends to conduct inspections of each deepwater drilling operation for compliance with regulations, including but not limited to the testing of BOPs. In addition to the recently issued Drilling Safety Rule, Secretary Salazar said he anticipates the Department and BOEM will undertake further rulemaking that considers additional safety measures — such as redundant blind shear rams, remote activation systems for BOPS, and enhanced instrumentation and sensors on BOPs — to further enhance recent safety improvements. Future rulemakings may take into consideration information developed by ongoing investigations into the Deepwater Horizon oil spill, or as a result of public comments on the recently issued Drilling Safety Rule. On July 12, Secretary Salazar suspended certain deepwater drilling activities based on his authorities and responsibilities under the Outer Continental Shelf Lands Act (OCSLA) to ensure safe operations on the OCS. The decision was supported by an extensive record of information supporting his determination that certain deepwater drilling posed a threat of serious, irreparable, or immediate harm or damage to the marine, coastal, and human environment. For a fact sheet on recent offshore oil and gas drilling reforms, click here. For a fact sheet on the requirements operators must fulfill before resuming deepwater drilling operations, click here. • For a signed copy of Secretary Salazar's decision memorandum, lifting the deepwater suspensions, click here, or click here for an unsigned text PDF. • For Director Bromwich's report on safety practices, spill response resources, and blowout containment capabilities, click here. http://www.doi.gov/news/pressreleases/Salazar-Deepwater-Drilling-May-Resume-for-Op... 10/12/2010 • THE SECRETARY OF THE INTERIOR WASHINGTON OCT i 2 2010 DECISION MEMORANDUM TO: Director Bureau of Ocean Energy Management, Regulation and Enforcement FROM: Secretary;, S SUBJECT: Termination of the suspension of certain offshore permitting and drilling • activities on the Outer Continental Shelf On October 1, you delivered to me your report (the October 1 Report) regarding the status of drilling and workplace safety, blowout containment, and spill response, which also included options regarding the potential modification or lifting of the deepwater drilling suspension.' In that report, you recommended that I proceed with Option 2, which would lift the current suspension of deepwater drilling completely.2 Based on my multiple reviews of the October 1 Report and further deliberations since October 1, I have decided to accept your recommendation and to lift the suspension of deepwater drilling. Therefore, I direct you to lift the current deepwater drilling suspension as to all deepwater drilling activity, as recommended in your October I Report. Even though I am terminating the suspension as to all deepwater drilling effective immediately, I further direct you, consistent with your statutory and regulatory authority, to require the following before the BOEMRE approves the drilling of any well in deepwater that would have been subject to suspension under my July 12 Decision Memorandum': ' The discussion contained in the October 1 Report is incorporated by reference into this Decision • Memorandum. Z Deepwater drilling, as defined by my July 12 Decision Memorandum suspending certain offshore drilling activities, refers to dulling operations involving the use of a subsea blowout preventer (BOP) or a surface BOP on a floating facility. See, e.g., 43 U.S.C. §§ 1331 et seq.; 33 U.S.C. §§ 1321 et seq.; 30 C.F.R. Parts 250 and 254. • • Each operator must demonstrate that it has in place written and enforceable commitments, pursuant to applicable regulations, that ensure that containment resources are available promptly in the event of a deepwater blowout. The Department of the Interior has a process underway regarding the establishment of an enforceable mechanism relating to the availability of blowout containment resources, and I expect that this mechanism will be implemented in the near future. • That the CEO of each operator seeking to perform deepwater drilling certify to BOEMRE that the operator has complied with all applicable regulations, including the new drilling safety rules. RATIONALE FOR MODIFICATION OF THE SUSPENSION As described in the October 1 Report, there has been significant progress in addressing drilling safety, blowout containment, and spill response, such that I find that the threat to life and the marine and coastal environments has been sufficiently reduced to allow shortening of the duration of the suspension as to deepwater drilling activities. To summarize, these developments include: Drilling and workplace safety. We have raised the standards with respect to the safety of offshore drilling. On September 30, we announced two major rulemakings — the • Safety Interim Final Rule and the Workplace Safety Rule — that impose new, and further codify existing, safety measures that directly address the suspected root causes of the Deepwater Horizon accident. The Safety Interim Final Rule includes new standards and requirements relating to: • the design of wells and testing of the integrity of wellbores; • the use of drilling fluids; and • the functionality and testing of well control equipment including blowout preventers (BOPs). The Workplace Safety Rule provides for the development of workplace safety and environmental management system (SEMS) programs, which represent significant progress in the development of performance -based systems for managing the various hazards and risks associated with offshore drilling operations. Many deepwater operators already have SEMS programs in place, which will have to be revised and enhanced to comply with the Workplace Safety Rule, and all operators are required to have these programs in place within a year. Moreover, we are actively considering alternatives to encourage industry to demonstrate voluntary compliance with this rule in advance of the one-year deadline. We also anticipate further rulemaking with respect to safety measures — such as redundant blind shear rams, remote activation systems for BOPs, and enhanced instrumentation and sensors on BOPs — to provide additional marginal improvements in • safety and that may take into consideration information developed by ongoing 2 • investigations into the Deepwater Horizon accident, or as a result of public comments to the Safety Interim Final Rule. Although we expect these and other safety measures to be introduced over time, the new drilling safety standards established in the Safety Interim Final Rule represent a raising of the bar with respect to primary safety features related to well design and integrity, as well as with respect to secondary well control measures such as BOPs. Therefore, I find that sufficient progress has been made since the Macondo well blowout to address the threats to life and the environment posed by each of the suspected root causes of the Deepwater Horizon accident and other fundamental safety issues. Before resuming drilling, each operator must comply with the requirements of the Safety NTL (NTL 2010-N05), the Safety Interim Final Rule, and the Environmental NTL (NTL 2010-N06). BOENIRE also intends to (1) conduct inspections of each deepwater drilling operation for compliance with regulations, including but not limited to the testing of BOPS, before drilling resumes, and (2) monitor high -risk phases of drilling operations through the on -site observation of operations by qualified personnel and the real-time review of electronic drilling data. Well containment. During the process of containing the Macondo blowout, significant developments and improvements have been made in the areas of deepwater well containment technology and equipment; the use of remotely operated vehicles (ROVs) and remote sensing technology, including the development of flow rate estimates; the • management and coordination of containment operations and logistics; and the drilling of relief wells. BP has agreed to make technology and equipment developed in response to the Macondo blowout available in the event of another loss of well control. The major oil companies have committed to investing $ l billion in designing and developing a multi -scenario, multi -component containment system. BOEMRE is in the process of establishing enforceable mechanisms to ensure the availability of blowout containment resources. Spill response. The Macondo well has been contained since July 15 and was killed on September 19. Compared to the situation that existed when I decided to suspend drilling operations, substantially fewer spill response and cleanup resources are engaged in the BP Oil Spill response effort and more resources are now available should another oil spill occur. In addition, response to the BP Oil Spill has led to substantial improvements in the use of spill response resources and oil detection systems. On the basis of this information, I conclude that at present there are sufficient safety measures, including well control measures involving the functionality and testing of BOPs, and well containment and spill response resources available to address the threat that led to my imposition of the original suspension of certain types of deepwater drilling activities. Although I find that the threats posed by deepwater drilling have been reduced sufficiently to allow for the suspension to be lifted early, I believe that goverment and • industry must do additional work to establish the necessary procedures and structures to • address containment in the case of a blowout. Members of industry have stated that they would make containment resources available in the event of another blowout, and BOEMRE is establishing an enforceable mechanism whereby the government can ensure that all operators working in deepwater have prompt access to containment equipment and processes in the event of a blowout. It is critical that government and industry ensure that, in the event of a blowout, containment resources are immediately available, regardless of the owner or operator involved. U • Finally, I also believe that on -going research and development — in areas such as improving well condition sensor capabilities and remote BOP activation, among other things — are necessary to develop cutting -edge well containment capabilities and that we must institutionalize government, industry, and other stakeholder cooperation in this effort. These are goals that we must pursue aggressively. In making this decision, I considered the environmental assessment that accompanies this Decision Memorandum. In addition, I note that BOEMRE has complied with the Endangered Species Act by reinitiating consultation following the Deepwater Horizon accident and documenting that this action, among others, does not constitute an irretrievable and irreversible commitment of resources that has the effect of foreclosing the formulation or implementation of any reasonable and prudent alternative measures that may result from that consultation. 4 Safety Officials Rarely Did Surprise Inspections of Gulf Rigs - WSJ.com Page 1 of 3 • World • U.S. • New York • Business Markets • Tech • Personal Finance • Life & Culture • Opinion Careers . Real Estate • Small Business • Ib I Dow Jones Reprints: This copy is for your personal, non-commercial use only. 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WS OOM BUSINESS I OC1OBER 11, 2010 Inspectors Rarely Surprised Oil Rigs 3y RUSSELL GOLD Surprise inspections of deepwater drilling rigs in the Gulf of Mexico dwindled to about three a year over the past lecade, even as exploratory drilling far from shore increased, according to federal data analyzed by The Wall Street Journal. knd since 2004 federal authorities haven't made a single surprise inspection on any of the 50 or so deepwater natural ;as and oil production platforms in the Gulf, despite a law requiring periodic unannounced inspections. Like rigs, • hese semi -permanent structures also handle enormous amounts of oil and natural gas and are at risk for oil spills and Norker fatalities. this dearth of surprise visits to deepwater operations reduced the likelihood that inspectors would find individual ,afety violations, industry experts and inspectors say. 'You're more apt to see what actual operations are with a surprise inspection," said Perry Jennings, who heads the anion local that represents federal offshore inspectors. "And if something's going on that's inappropriate, that's the pest time to catch it." Since the explosion of a BP PLC well in the Gulf of Mexico on April 20 that led to ii deaths and the worst offshore oil ,pill in U.S. history, the Minerals Management Service, the agency that monitors offshore drilling, has been the subject A withering criticism for what many described as lax oversight and enforcement of regulations. Zegulators in the U.S. and around the globe routinely use surprise inspections in such operations as airplane naintenance and oil refining. Ts impossible to know if a surprise inspection would have prevented the deadly explosion aboard the Deepwater 3orizon, the rig drilling the BP well, owned and operated by Transocean Ltd. The last unannounced visit was in Jctober 2oo6. 3owever, inspectors can request records on the condition of the blowout preventer, a mammoth set of valves designed :o shut down the well in an emergency. Some of the functions on the blowout preventer failed to work on the :)eepwater Horizon. • Federal inspectors spent 62 hours aboard the rig in 2009 in announced visits. And an announced inspection this year about three weeks before the blowout lasted about two hours, but no citation was issued. http://online.wsj.com/article/SB 10001424052748703358504575544294191404032.html?... 10/11 /2010 Safety Officials Rarely Did Surprise Inspections of Gulf Rigs - WSJ.com Page 2 of 3 Still, unannounced inspections are seen as so critical to ensuring safe mining that Congress is considering a bill, • drafted in the wake of a recent deadly West Virginia coal mine explosion, to make it a felony punishable by five years in prison to tip off an operator about an unannounced inspection. Regulators with the Mine Safety and Health Administration said it was during a surprise inspection on Sept. 28 that they found safety violations at a West Virginia mine owned by Massey Energy Co. that could have caused an explosion. Massey, the owner of the separate West Virginia mine where 29 workers were killed after an April 5 explosion, said it fired three workers and suspended nine others over the recent inspection results. "If you have zero unannounced visits and if the industry knows there will be no unannounced visits, that changes the incentive to be vigilant," said Cary Coglianese, a law professor at the University of Pennsylvania who specializes in regulatory issues. But officials with the MMS, recently renamed the Bureau of Ocean Energy Management, Regulation and Enforcement, say surprise inspections were a low priority in deepwater energy operations. "It was not what anybody wanted," said Elmer P. Danenberger III, the longtime head of the agency's offshore regulatory programs who retired in December. Mandatory annual inspections of 3,800 offshore facilities, responding to hurricane and collecting royalties were deemed more urgent, he said. Interior Secretary Kenneth Salazar has promised extensive reforms in the agency and named a new director with a broad mandate to overhaul policies and enforcement practices. A recent report said the agency's policy about surprise inspections must be clarified. Interior spokeswoman Kendra .Barkoff promised "to determine the appropriate actions to take as we reorganize the agency." A Journal analysis of inspection data from 2000 through July 2010 showed an agency that had significantly reduced unannounced inspections in the Gulfs deep waters, which the agency defines as 1,000 feet or deeper. In 200o, about one in nine inspections of deepwater facilities were unannounced, according to the Journal's analysis; by 2009, that rate had dropped to about one in 80. Meanwhile, the number of deepwater wells pumping oil and gas more than doubled over the decade to 602 from 256, according to federal data. Some companies, such as Transocean, almost never had a helicopter carrying an inspector appear on the horizon to check on them. Surprise inspections accounted for less than i% of total inspections for the Switzerland -based company between 20oo and 2010, the lowest among large drilling companies. A Transocean spokesman said that drillers don't determine "the number or frequency of government inspections." Inspectors arrive offshore via government -leased helicopters usually with a computer -generated random list of safety and antipollution components. The inspector can issue a warning, or order the shutdown of a single component, or the entire facility. The third option was a rare occurrence. In fact, the government and inspectors have been faulted by internal investigators for being too close to oil companies, sometimes even allowing company employees to fill out inspection reports. •An April 2005 memo prohibited certain unannounced inspections. In the memo, Donald Howard, a former regional supervisor for MMS, required inspectors to give a 24-hour notice before inspecting many of the largest offshore platforms. He cited new security regulations imposed after the terrorist attacks of 9/11. http://online.wsj.com/article/SB 1000 1 424052748703358504575544294191404032.html?... 10/11 /2010 Safety Officials Rarely Did Surprise Inspections of Gulf Rigs - WSJ.com Page 3 of 3 1 • NUMBER OF Platforms UNANNOUNCED INSPECTIONS Drilling rigs 34 13 1 3 1 0 0 0 0 0 8 4 0 0 0 3 15 31 1 4 spa No Surprise 400 While the number of deepwater 300 walls in the Gulf of Mexico has increased, the number of surprise 200 Inspections of platforms and drilling rigs in these depths has 100 dwindled. 0 2000 '01 '02 '03 '04 '05 '06 ro7 '08 Note: Deem-atei dri llin7 6-is include all drillships and 54misubmersibles. Fixed platforms include all facilities in more than 1,000 feet of water. source: Wall Street lwrnal anaiyis of Bureau of Owen Eiwgy Vanagommt. Regulation and Enforcement data branch. "I am not exactly sure where that is coming from." 109 But the U.S. Coast Guard, which oversees these security rules, said it could find no justification for a 24- hour notice. "I haven't found anything that requires an advanced notification to conduct an inspection," says Lt. Commander Kevin Lynn, chief of the Coast Guard's offshore facility security Mr. Howard couldn't be reached for comment. The agency fired him in 2007, and he later pleaded guilty to failing to disclose gifts from an offshore drilling company. The policy was reiterated in 2007 by Joe Gordon, who subsequently left the agency to work for Chevron Corp. He declined requests for an interview. Last month, an Interior Department Inspector General report found employees felt pressured to notify Royal Dutch Shell PLC before traveling to its offshore facilities. Shell spokesman Bill Tanner said: "If we did request additional notice, it was purely a safety matter in our mind." A separate Interior Department internal report released last month noted that individual district MMS offices seemed to have different interpretations of agency policy about when and if surprise inspections could be done or even what constituted one —something the department said needed to be clarified. The report also noted some companies had "special notification arrangements." The Interior Department declined to elaborate. Oil and gas companies have generally favored scheduled inspections over unannounced ones. Allen Verret, executive director of the Offshore Operators Committee, an industry group, said scheduling inspections helps avoid congestion — and potential danger —if a helicopter appears unexpectedly. Most inspectors, however, felt handcuffed by the arrangement. A recent survey by a federal safety oversight board convened by the Interior Department found that go% of inspectors said there was a "critical need for more unannounced inspections." —Leslie Eaton and Tom McGinty contributed to this article. Write to Russell Gold at russell.gold@wsj.com Copyright 2009 Dow Jones & Company, Inc. All Rights Reserved This copy is for your personal, non-commercial use only. Distribution and use of this material are governed by our Subscriber Agreement and by copyright law. For non -personal use or to order multiple copies, please contact Dow Jones Reprints at 1-800-843-0008 or visit • www.djreprints.com http://online.wsj.com/article/SB 100014240527487033 58504575544294191404032.html?... 10/11 /2010 Doubts Raised About BP Study October 8, 2010 • Some Experts See a Legal Motive in Internal Investigation of Gulf Oil Disaster By BEN CASSELMAN HOUSTON—BP PLC's lawyers helped prepare its internal investigation into its Gulf of Mexico drilling disaster, according to the report's lead author, raising questions about the study's impartiality. The report, led by Mark Bly, was presented by BP as an impartial investigation into what caused the April 20 explosion, which killed 11 workers and caused the worst offshore oil spill in U.S. history. But outside experts have been skeptical, saying its conclusions seemed convenient for BP's legal position. The 300-plus-page report was the first in-depth attempt to explain what caused the Deepwater Horizon disaster and will likely be a key document in the hundreds of lawsuits filed against the companies involved. Mr. Bly, who was recently promoted by new BP Chief Executive Bob Dudley to oversee a new safety division at the company, said in an interview Wednesday that lawyers assigned to the investigation team helped "with the logic of the writing" but didn't influence his conclusions. "They were actually quite effective at making sure that our thought logic was good," Mr. Bly said. He said the team was careful not to have its "insights influenced, even subtly" by outside concerns. Immediately after the report was released on Sept. 8, a BP spokesman said that lawyers "reviewed" it and provided "legal advice and counsel to the [investigative] team," but wouldn't elaborate on what that entailed. At that time, some outside experts questioned the report's conclusions. "It certainly raises a question of whether [the lawyers] considered the legal implications of the report," before releasing it, Mark Brown, a partner at Bristows, a U.K. law firm, said at the time. Mr. Bly's report rejected several criticisms leveled against the company by outside experts and pinned much of the blame for the disaster on BP's contractors, especially rig owner Transocean Ltd. and cementing contractor Halliburton Co. Transocean and Halliburton have both defended their work and said BP, as the well's owner, made most of the decisions. They have dismissed Mr. Bly's report as part of BP's legal strategy. Richard Nagareda, a law professor at Vanderbilt University, said companies usually have lawyers involved in such internal reports to make sure the language doesn't go beyond laying out facts and into making legal arguments. He said the lawyers were likely careful not to interfere in the investigators' work, but that doesn't mean the investigation was neutral. "An internal investigation is always internal," Prof. Nagareda said. "You always have people who are very much a part of the culture of the organization. ...That's not easy to put aside." Outside experts have pointed out that team's findings seemed helpful to BP. The report, for example, played down what experts had identified as one of the most damning pieces of evidence against BP: the company's decision not to use more pipe -centering devices despite Halliburton's warnings that these were necessary to ensure a good cement seal. The Bly team criticized the way the decision about these devices was made but said it didn't contribute to the disaster. Robert Mackenzie, an analyst with FBR Capital Markets in Washington, said BP appeared to be laying the groundwork for its legal defense by trying to demonstrate that responsibility for the disaster was shared and that none of the parties involved were "grossly negligent" —which could lead to much higher liability for all the companies involved. "BP's trying to avoid any indication that anyone was negligent," Mr. Mackenzie said. But Mr. Bly said such concerns didn't influence the work of his team, which was simply trying to find the disaster's true causes. "There's a lot of my own integrity in this, actually," he said. "I was really concerned about it." Many outside experts, despite their doubts about the team's independence, have accepted most of its key findings about how explosive natural gas entered the well and traveled up to the rig. But instead of shifting focus away from BP, the report has renewed attention to decisions made by the company and its workers that had previously drawn little scrutiny, such as the decision to remove protective drilling fluid before setting a final cement plug. • Had it been set, the plug might have stopped the flow of gas before it could get to the rig. That and other issues aren't addressed in BP's investigation. —Spencer Swartz contributed to this article. Printed in The Wall Street Journal, page A6 V1511 DNV to investigate the Deepwater Horizon blowout preventer Page 1 of 1 E C J DNV to investigate the Deepwater Horizon blowout preventer Press release. Houston: DNV has been contracted by the Joint Investigation Team (JIT) of the departments of the Interior and Homeland Security for the forensic examination of the blowout preventer (BOP) and lower marine riser package that was fitted to the Macondo well in the Gtilf of Mexico, the site of the Decpwatcr Horizon disaster and oil spill. The BOP, a 50 foot - 300 ton assembly has been raised and taken to NASA's secure facility in Michoud, Lousiana where it is in the custody of the JIT. Chain of custody and evidence preservation protocols to ensure the proper handling of all evidentiary material have been in effect since the BOP was first retrieved in August. The final forensic testing protocol will be developed by DNV, in consultation with various commercial, academic, and governmental organizations, and will be approved by the JIT prior to the start of testing. DNV is utilizing its forensic investigation expertise from the Columbus, Ohio office and its subsea equipment (BOP) expertise from the Houston, Texas office in the project. http://www.epmag.com/article/print/69537 10/7/2010 Page 1 of 4 I n� k i VOW09 Close Alaska offshore plans should reflect conditions there, panel told Nick Snow OGJ Washington Editor WASHINGTON, DC, Oct. 4 -- Concerns raised following the Apr. 20 Macondo well accident and subsequent oil spill in the Gulf of Mexico may not fully apply to activity off Alaska, witnesses told US President Barack Obama's independent oil spill commission. They agreed that conditions are different that far north, but disagreed on whether to go ahead or wait. • "It was because of the lack of sufficient science in the Arctic and the reality of oil -spill response capabilities caused us to defer sales there," US Interior Sec. Ken Salazar said on Sept. 27, adding that he has tried to take a slow and thoughtful overall approach there. "The reality of the Arctic is that you don't have the kind of US Coast Guard response we had in the Gulf of Mexico," he told the committee. "You're also operating in frigid conditions with floating ice in very narrow windows. On the other hand, you are dealing with depths that are much less than what we were dealing with in the Gulf of Mexico, with depths of 100-150 ft." The gulf accident which claimed 11 lives and massive spill which took months to contain and clean up clearly showed that better offshore workplace safety and environmental regulations are needed, US Sen. Mark Begich (D-Alas.) testified. "Unfortunately, the Obama administration's moratorium in the Gulf of Mexico has had collateral impacts on Alaska, where exploration the Chukchi Sea has been delayed again," he said. Almost all of Alaska's offshore oil resources are in relatively shallow water, and the amount of environmental review before work proceeds is tremendous, Begich declared. "In Alaska, we have a very robust state procedure and litigation procedure. At the end of the day, we've gone through enormous environmental reviews," he said. "I sometimes joke that before the oil and gas industry does anything in Alaska, it is going to get sued." `Important to decide' Work in Alaska, where 80% of the government's revenue streams are related to oil and gas, has slowed down while various commissions investigate the gulf accident and spill, he continued. The problem is that as we move into winter, companies are going to make decisions about what they'll be doing next year," Begich said. • "As we move through the next 60-90 days, the amount of oil going through [the Trans -Alaska Pipeline System] continues to decrease and the volumes could get critically low. It's important to decide whether new exploration will take place." http://www.ogj.com/indexlarticle-tools-template/printArticle/articles/oil-gas journal/drilli... 10/7/2010 Page 2 of 4 Pete Slaiby, vice-president of exploration at Shell Alaska, said the company plans to drill two wells on its •Arctic offshore leases in 2011. "We also will be doing a large body of work which has absolutely nothing to do with drilling, but everything to do with developing a scientific baseline," he told the commission. "We will be looking at shallow hazards, continuing to gather ecological data to develop a flora and fauna baseline, continuing to develop ice currents, and understanding the creatures which inhabit the Arctic." Shell has always tried to prepare for low -probability, but high -impact, events, he said. "We will put in a place a plan which will be ready from the moment we start drilling. That doesn't mean we won't have other assets we can call up, but these will be ready from the moment the well is spudded," Slaiby said. "Our oil -spill contingency plan has been reviewed by a number of people and meets their exacting standards. It has been exposed to the public through the coastal zone management process, where it has been extensively reviewed by North Slope Borough residents. We will keep our resources in place and exceed those standards." The North Slope Borough's overriding concern continues to be the possibility of an oil spill and the resulting recovery work which would need to be done, Mayor Edward Itta indicated. "Our problem is that the equipment and technology that have been mentioned have never been tested up here in the Arctic under real conditions," he said via telephone hookup from his office in Barrow. "There has never been any real exercise involving broken ice conditions and the recovery of oil. Neither has any burning been done up here." More baseline science Specifically, Itta said more scientific research has been done on the Beaufort Sea than on the Chukchi Sea, where there has been "virtually none." There hasn't been enough baseline science to understand the impacts of oil and gas activity, Itta said. "The bowhead whales' migration route goes right over the proposed wells. We have a pretty good count of the whales, but not of the walruses or seals," he said. •Commission member Frances G. Beineke, president of the Natural Resources Defense Council, noted that proposals have been made to require 3 years of baseline data before allowing oil and gas activity in frontier areas. Ocean Conservancy Executive Vice-Pres. Dennis Takahashi -Kelso, who was an Alaska state government official when the tanker Exxon Valdez ran aground in Prince William Sound in 1989, said that 3 years of current data "are absolutely essential to assure that decisions about Arctic OCS development are better, and that we have the capacity to respond to spills and other emergencies." Severe Arctic conditions make it likely that a response gap exists there for most of the year, he testified. "Rapid changes in sea ice and weather conditions may impose severe restrictions on response options. Questions persist about the effects of dispersants on Arctic ecosystems, and the Arctic lacks facilities and equipment to respond," he said. Takahashi -Kelso identified two basic problems: Despite broad claims of being able to mobilize resources, there has never been a realistic test of the ability to respond. And the body of Arctic marine science is so limited and out of date that it's impossible to understand what actually would happen to the environment, he said. "Sec. Salazar has taken a valuable step in asking the [US Geological Survey] to study the situation, but that agency has not historically dealt with ocean conditions," the Ocean Conservancy official said. "Oil and gas activities on the Arctic [Outer Continental Shelf) should be part of a broader effort such as that of the National Ocean Council, whose planning program provides a robust opportunity to consider these issues." USCG's strategy Capt. John R. Caplis, deputy commander of the US Coast Guard's incident preparedness office in Long Beach, Calif., said USCG's Alaska North Slope subarea contingency plan addresses three issues. USCG has been working with DOI, Alaska's state government, and area residents and governments to make sure that resources • are aligned, environmental impacts are recognized, and research and development keeps pace, he told the commission. http://www.ogj.com/indexlarticle-tools-template/_printArticle/articles/oil-gas journal/drilli... 10/7/2010 Page 3 of 4 "I agree that it will require a joint effort. Industry will need to have a baseline to respond," Caplis said. "The Coast Guard can respond when called. We have been doing a number of things through something called •Operation Arctic Crossroads looking at other locations throughout the state. We do have tools and we are actively testing those to see how they perform. We also have a high latitudes operations study which we are in the process of completing." USCG helped Shell Alaska develop its plan, Slaiby said. "We work in probably 50 other countries in [exploration and production]. Many have regulations. Many do not," he told the commission. "We know the Coast Guard will be ready to come in and take its place at the center of the unified command structure. In the meantime, we would begin to prepare to drill a relief well and otherwise respond to a spill." He said Shell Alaska has proposed a containment system which would not be as large as would be used in the gulf, but would be readily available with blowout preventer testing every 7, instead of 14 days. Shell also has raised the research bar by participating with other major US oil companies in a consortium to develop and build better spill containment systems, he added. "We agree that to put more development in, you need more science. But we also believe the existing science supports exploration drilling," Slaiby said. "I think it's important to not confuse the commitment to respond with the effectiveness," responded Takahashi - Kelso. "The issue is what [an offshore well operator] actually does in the spill in producing recovery. Exxon committed a substantial amount of resources to recovering oil in Prince William Sound and recovered only about 10% of the oil." Able to respond "We've been working in the Arctic for half a decade to address these questions," Slaiby said. "We support the Coast Guard's presence, but believe it can discharge its responsibility under [the 1990 federal Oil Pollution Act] because its base in Kodiak is only 4 hr away by plane. We also have demonstrated we can drill fewer •wells to produce more oil." He said that Shell Alaska does not expect its wells to be the size of those in the Gulf of Mexico, but it does expect to comply with Notice to Lessees No. 6 which DOI issued in June and have the capacity to respond to the worst scenario that the regulation requires. is Shell Alaska also has designed its spill response to tackle a spill at its source, he continued. "With respect to ice, there have been a series of ice tests, unfortunately not in this country but in Norway. In the event of this unlikely event, all gloves will come off and we would deploy all of our oil spill and icebreaker technology to keep the oil away from the area. We would apply booms where applicable and burning otherwise. Colder temperatures also make it easier to ignite oil in the Arctic," Slaiby said. "In Alaska, the response plans that have been laid out go through several components," said Begich. "I don't question that the Coast Guard is an important factor, but it facilitates responses which came primarily from the industry. There's no question that the requirements they have and will have will be more significant than what's required in the gulf. But it also is dealing with shallower depths." If the oil and gas industry knows what the regulations are, it can make the necessary plans, the federal lawmaker continued. "At the rate the administration is going, it will be March of next year before it will know," he said. "All we ask is that if there's a different approach in the Beaufort and Chukchi seas, lay it out. These are companies that can go elsewhere if they don't have an idea of what's expected." Slaiby reminded the commission that the resources which are at stake off Alaska are substantial. "The prize is about 25 billion bbl of oil and 25 tcf of natural gas," he observed. Contact Nick Snow at nicks ennwell.com. To access this Article, go to: http://www.ogj.com/indexlarticle-tools-template/printArticle/articles/oil-gas journal/drilli... 10/7/2010 GENERAL INTEREST • • US agencies treated spill as catastrophe from outset, panel told Nick Snow Washington Editor US departments and agencies responding to the major oil spill in the Gulf of Mexico treated it as a catastrophe from the beginning, officials told the independent commission established by US President Barack Obama to investigate the event and its implications on federal offshore oil and gas policies. Initial estimates of oil flowing from the Macondo well that were provided by well operator BP PLC have been criti- cized as being misleading, but did not affect federal strate- gies, they told the commission as it began its second hearing in Washington on Sept. 27. The hearing focused on government responses to the massive oil spill that started 2 days after the well blew out on Apr. 20, causing an explosion that destroyed Trans - ocean Ltd.'s Deepwater Horizon semisubmersible and killed 11 workers. Leaks began after the rig sank on Apr. 22 and connections ruptured deep below the surface. US Interior Sec. Ken Salazar said he quickly determined that science would have to play a dominant role in combat- ing what he felt was "probably the worst oil invasion in the nation's history." He told the commission that he met im- mediately with US Energy Sec. Steven Chu to begin a coor- dinated effort, and conferred often with US Environmental Protection Agency Administrator Lisa P. Jackson and Na- tional Oceanic and Atmospheric Administration Adminis- trator Jane Lubchenco. "From the onset, over 200 staff members from EPA worked on the response," Jackson testified later in the com- mission's hearing. "We quickly stood up a process of rigor- ous testing of air and water quality, and of sediments, and began working immediately with other federal agencies and departments." Nationally significant Edwin M. Stanton, the US Coast Guard's New Orleans sector commander, said the US Department of Homeland Security division also initially responded with a maximum effort be- cause it recognized that the spill was a nationally signifi- cant event. "You can always pull resources back if they're not needed," he observed. NOAA also took the spill seriously from the beginning, added Bill Lehr, a senior scientist at the US Department of Commerce agency. "We think anything over 5,000 bbl is sig- nificant," he said. Oil & Gas loumal I Oct. 4, 2010 Retired USCG Adm. Thad W. Allen, who became the na- tional incident commander, said it quickly became apparent that this spill posed significantly greater problems than the one in 1989 that resulted from the tanker Exxon Valdez run- ning aground in Prince William Sound off Alaska. Congress passed the Oil Pollution Act the following year in response, but programs established under that law clearly wouldn't work this time, he said. "There was not an overall sufficient knowledge of how the national contingency plan was structured, particularly the relationship and role of the responsible party," Allen testified. Many of the affected parties had not participated in the last spill response drill in the gulf in 2002, he con- tinued. It helped that the USCG had a unified Gulf Coast com- mand with experienced members in New Orleans, Houston, and Mobile, Ala., but it became necessary to adopt a fire- fighter's approach in attacking the Macondo well spill be- cause it involved several leaks. What the nation expected in a federal response could not be accomplished with OPA 1990 programs, Allen said. "They did not cover issues such as potential seafood contamination. New programs had to be created," he said. Local impacts A coordinated response was critical, but this was the first time that a unified command was needed to respond to an oil spill, according to Doug Suttles, chief operating of- ficer for BP Exploration & Production. "Impacts obviously were local. It became necessary to work more closely with local governments to speed up responses," he said. "We learned that it was crucial to provide space and support to front-line responders so they could respond quickly and effectively." State and local officials quickly felt excluded, however. "I'm angry that we're talking about the successful things that happened," said William (Billy) Nungesser, president of Plaquemines Parish in Louisiana. "We should have had a seat at the table from Day 1. The berms were approved and we are picking up oil. But here, this late in the game, I still can't tell you who's in charge" Nungesser said federal officials did not recognize the importance of keeping spilled crude out of coastal marshes until Obama came to the area for a visit and local officials complained. "Had we used the word 'emergency' earlier, we would have kept a lot more oil out of the marshes and pro- tected more of our seafood resources," he declared. Richard Harrell, a Mississippi Department of Environ- mental Quality environmental permitting official, said many officials in Gulf Coast states quickly realized that contingen- cy plans had not kept up with oil and gas production growth offshore. Shoreline response and cleanup operations went well, while near -shore operations, skimming, and contain- ment control did not, he indicated. 31 • • WATCHING GOVERNMENT Next steps on spills As US President Barack Obama's com- mission investigating the Gulf of Mex- ico oil spill began its Sept. 27 hearing, it became apparent that its work was entering a new, and potentially impor- tant, phase. Much of the information has been gathered and problems are being iden- tified, the commission's co-chairmen said. "It was clear at our meeting last month that our regulatory approach did not keep up with technology," said former Florida Gov. and US Sen. Bob Graham. "I remain concerned that sci- ence apparently does not have a place at the table," he said. Graham continued, "Just 5 years after the gulf suffered the devastation of Hurricane Katrina, many have the same questions about whether the federal government moved quickly enough to respond to a major disaster." William K. Reilly, a former US En- vironmental Protection Agency ad- ministrator, observed, "As someone in- timately acquainted with the response following the spill in Prince William Sound, I continue to be amazed at the limitations of our response tech- nology, particularly since our drilling and production technology has moved ahead so quickly." Reilly noted that as he observed the number of skimmers that were deployed, he was particularly disap- pointed that only 3% of the spilled crude was recovered. 'Uneasy partnership' "In many cases, the response dis- played tremendous credit and inge- nuity which revealed the dedication of the people involved. But it was still very limited and raised serious ques- tions," Reilly continued. "This uneasy partnership between the government and the responsible party raises im- portant questions about the flow of in- formation, for example." The nation learned a lot from the 1989 Exxon Valdez tanker spill in Prince William Sound, and the 1990 Oil Pollution Act reflects those lessons, he said. "Tanker transportation is safer than it was, but that law has been crit- icized as responding to the last war," Reilly said. "I hope that what we learn this time creates a better legislative re- sponse." Retired US Coast Guard Adm. Thad W. Allen, who was national in- cident commander in the Macondo spill response, agreed that OPA 1990 was "tanker -centric." But he also said the law worked well for 20 years with small offshore spills by helping federal and state governments work together. The biggest problem was that the federal response could not match pub- lic expectations in a significantly big- ger incident, he added. "We learned that the public's tolerance with the responsible party is inversely propor- tionate to the spill's size," Allen said. BP and the federal government had sufficient financial resources to han- dle the spill, but a better understand- ing of their roles would have helped, he told the commission. "I think the plan worked better than many people believed," he maintained. = "Mississippi declared an emergen- cy mainly to bring certain assets from our national guard and make sure county emergency operations were funded and adequately staffed," he said. "One of the biggest issues which can be improved is managing expec- tations. We had 3,000 volunteers sign up who couldn't be used because of various laws. Our county and local officials didn't know how they could contribute or understand what was going on" State coordinators As more government and company of- ficials arrived from outside the region, Mississippi found that it was necessary to acquaint new response participants with local problems, Harrell said. The situation improved dramatically when BP assigned state coordinators in early June. USCG saw what had happened and quickly followed suit, he said. Jackson said EPA quickly learned the importance of speaking with people in the local communities, and responded by conducting tests at sites they recommended. "As the re- sponse wore on, one of our strengths was our good relationship with non - government organizations and other government agencies,' she told the commission. "Yet there still was a lot of skepticism. I spent hours with fishermen and other groups assuring them I wasn't going anywhere and that I was concerned about condi- tions there." The situation was not helped when politicians in Washington began to question the idea that coastal restora- tion should be a part of the long-term response, Nungesser said. "For some- one so far away to throw rocks at a plan our parish spent millions of dol- lars developing was dispiriting. They should at least be willing to sit down at the table and show us their data," he said. "If we don't start restoring the barrier islands, we're not going to have an oil and gas industry in Loui- siana" Salazar said coastal restoration defi- Oil & Gas journal I Oct. 4, 2010 Previous Page I Contents I Zoom In I Zoom Out I Front Cover I Search Issue I Next Page gMags joURNAL GENERALINTEREST i- 0 • nitely needs to be part of the federal government's long-term response. "In my view, what happened in the post -Exxon Valdez period over several administrations dealt with finite amounts of spilled oil. We very quickly found with this one that bigger challenges existed," he said. "The last 6 months have been a laboratory of learning. There are testing require- ments for blowout preventers that were never required be- fore. The lessons we've learned will be applied in the new regulatory framework that [US Bureau of Ocean Energy Management, Regulation, and Enforcement Director Mi- chael R.[ Bromwich will initiate in the days ahead" Allen said the federal response this time was better than many people believe despite its challenges and problems. "I'd say OPA 1990 worked pretty well, even with all the bumps and grinds," added Stanton. "I would call it a good, if somewhat ugly, response." = Government, industry examine oil spill preparedness Paula Dittrick Senior Staff Writer The oil and gas industry developed containment technology to deal with an oil spill in the deepwater Gulf of Mexico, and new collaboration between industry and the US government is needed to assure an adequate response system in the fu- ture, speakers agreed at a meeting in Washington, DC. Regulators, government scientists, and industry execu- tives met at a forum hosted by the departments of the In- terior and Energy. An Apr. 20 blowout of the Macondo oil and gas well on Mississippi Canyon Block 252 resulted in a massive spill in the gulf. BP PLC operated the Macondo well. The blowout caused an explosion and fire on Transocean Ltd.'s Deepwater Horizon semisubmersible, killing 11 peo- ple. The Deepwater Horizon sank on Apr. 22. Energy Sec. Steven Chu said he sees the need for a rede- sign effort focused on diagnostic tools, warning systems, in- strumentation and sensors, and other equipment to improve the safety of offshore drilling. Engineers and scientists spent time, especially early in the response efforts, trying to figure out the state of valves in the failed Deepwater Horizon blowout preventer, he said. "A reengineering job could have saved 10 days of angst," Chu said. "This is an industrywide issue.... There was no indicator on the BOP that said what's the condition of all the valves." Chu advised the oil and gas industry to look toward the weapons industry and the aviation industry for ideas. "One doesn't really have to reinvent a lot of things." 34 Spill preparedness Interior Sec. Ken Salazar said efforts to kill the Macondo well involved "the best and brightest minds" from across industry and government. "It required trial and error where there was little room for error," he said. "Neither industry or the government had the prepared- ness to deal with the disaster in the gulf," Salazar said. ExxonMobil Corp. Chairman and Chief Executive Offi- cer Rex Tillerson said government and industry need to de- velop more -effective ways to work together. He said industry is dedicated to operational safety and integrity. "There is a need to enhance preparedness," Tillerson said. ExxonMobil is operator of the Marine Well Containment Co. (MWCC), a nonprofit joint venture that is building an equip- ment inventory and a rapid response system for future gulf oil spills (OGJ Online, July 21, 2010). ExxonMobil, Chevron Corp., ConocoPhillips, and Roy- al Dutch Shell PLC pooled $1 billion to form MWCC. BP joined MWCC and agreed to make its underwater well con- tainment equipment available to all oil and gas companies operating in the gulf (OGJ Online, Sept. 20, 2010). National Incident Commander and retired US Coast Guard Adm. Thad Allen said the government and industry need to jointly design containment systems that can be inte- grated with the way the oil is produced in the gulf. Floating production, storage, and offloading vessels along with floating risers and shuttle tankers had to be brought from other countries to help divert oil from spilling into the gulf. This equipment had to be obtained from elsewhere to deal with the Maconodo spill because oil production in the gulf typically is delivered to shore by pipelines. "We are going to be working in various depths," Allen said of gulf drilling efforts. "We need to have flexibil- ity in response systems that can adjust to different water depths." Allen also called for renewed investments in oil spill re- search and development efforts, adding that industry and the government allowed investments in oil spill research to wither years after the Exxon Valdez tanker ran aground in Alaska's Prince William Sound in 1989. He was involved in setting up procedures and an inven- tory of oil spill equipment as required by the Oil Pollution Act of 1990. "We basically got complete amnesia about R&D —to re- ally fund it and stay ahead at the same time that deepwater drilling" technology progressed, Allen said. BP's experience Andrew Inglis, chief executive officer of BP Exploration & Production, said containing the Macondo blowout presented "a huge challenge" even though BP had spill response plans in place that conformed to regulatory requirements. "However, no one anticipated an event where this partic- ular series of mechanical and human failures would occur," Oil & Gas journal I Oct. 4, 2010 Previous Page I Contents I Zoom In I Zoom Out I Front Cover I Search Issue I Next Page gMags GENERALINTEREST 11 ILJ • Inglis said. "The Macondo well is at a water depth of 5,067 ft. This is by no means the deepest water depth that has been drilled in the Gulf of Mexico, but it did pose a unique set of logistical and operational challenges —temperatures are less than 40' F., and seafloor pressures greater than 2,200 psi. At these pressures and temperatures, methane gas flowing from the well was transformed into ice -like crystals known as hydrates, which complicated containment efforts." He said a 5,000-ft riser connecting the well to the Deep - water Horizon fell to the seabed and was bent and breached in several locations. "The first challenge in the early days of the response was to survey the status of this equipment and locate the source of the oil and gas flowing into the sea," Inglis said. He said industry has now assembled subsea contain- ment equipment that it did not have in place for the gulf on Apr. 20. Inglis said industry also gained experience in using these key elements, which include: • An inventory of immediately deployable open and closed containment systems proven at depth with associated operating procedures. • Proven systems for processing and transporting con- tained oil including FPSOs, free-standing risers, and flexible subsea flowlines. This includes equipment to reduce down- time in the event of hurricanes. • Demonstrated methods to mitigate hydrate formation. • Techniques for system diagnostics and advanced sur- veillance (for instance, digital radiography at depth). • Plans and organizational models for source contain- ment. • Enhanced technologies and procedures to drill deep - water relief wells. Halliburton officials defend Macondo well's cement job Nick Snow Washington Editor Cementing of BP PLC's ill-fated Macondo well in the Gulf of Mexico took place after extensive tests, followed the opera- tor's specifications, and showed no signs of problems in the hours before the well blew out on Apr. 20 and its semisub- mersible exploded, killing 11 workers, Halliburton Co. of- ficials told a federal panel on Sept. 26. They said BP's internal investigation has provided the most information so far, but disagreed with its conclusion, announced on Sept. 8, that problems began with a bad ce- ment job. The event caused a massive oil leak into the gulf which has taken months to stop and clean up. "There were a number of red flags which should have giv- Oil & Gas journal J Oct. 4, 2010 en pause to BP, as the well operator. Notwithstanding mul- tiple signals of problems, it did not adjust its operations," Thomas Roth, Halliburton's vice-president of cementing, told the National Academy of Engineering's committee that is examining the accident and spill and preparing a report for US Interior Sec. Ken Salazar. Roth said Halliburton, as one of several contractors work- ing for BP at the well site, did not have access to all the in- formation about what was going on there. "We knew the mechanics of the well and its depth, but not specific reser- voir information. We were provided specific details of the tubulars," Roth said. Halliburton also knew that BP was sus- pending drilling before it hit the well's planned 19,000 ft depth, he said. Problems with the cement could have been traced to its possible contamination, incomplete laboratory testing be- forehand, or use of an unstable foam slurry which would have resulted in nitrogen breakout, none of which apparent- ly occurred, he explained. Roth said Halliburton supplied the cement based on BP's specifications, tested it in its own laboratory, and recommended a formulation based on that information. Tests took more than 400 hr and indicated that the foam system was stable on delivery, he said. Series of tests "When cement is prepared on location, we go through the actions of foaming, starting with the base slurry;" Roth said. "We measure the density to determine the cement -water ra- tios are appropriate for the design and the foam system is consistent over the cement. We also monitor the nitrogen pressure and nitrogen rate to provide assure that the job is executed according to the design. The material balance is identified ahead and after the job to identify what's used in the job. This analysis shows that the materials used followed the plan at the Macondo well" Halliburton performed three tests on the cement which would be used in the Macondo well and discussed the re- sults with BP, Roth said. The foam stability test used a sam- ple of the cement slurry, which was mixed in a high-speed Waring blender to compare it to test specifications, then cured in a water bath for 48 hr, where the cement hydrated. A specimen was gathered and examined to see if there is any separation, settling, or breakup. "On the identified speci- men, there was good stability," Roth said. BP said in the report of its investigation that it had to simulate the cement's condition because Halliburton would not provide samples. Roth said that the independent labora- tory's conclusions were inaccurate because of this, and be- cause the lab used a 3-blade blending system instead of one with 5 blades as specified in American Petroleum Institute standards. Indications of channeling from using only six centralizers did not cause alarm at the Macondo well, he said. "We end up with channeled cement jobs in many instances, which 35 "I R Previous Page I Contents Zoom In Zoom Out Front Cover Search Issue I Next Page gMags GENERAL INTEREST ICJ • are not inherently unsafe in the Gulf of Mexico," said Roth. "They commonly exist on work provided in the field. It's not seen as a red flag going forward." John Gisclair, in -site support coordinator for Hallibur- ton's Sperry Drilling division that also worked on the Ma - condo well, said that while various contractors are not re- quired to share information, they often do "because we want to get the job done well" He said, "Typically, they share criti- cal data. The Horizon had a closed-circuit TV system with a number of cameras throughout the rig so it was possible to see Sperry's mud -logging displays on one channel and Transocean's data on another." Sensors bypassed Multiple activities aboard a rig during a planned shutdown can keep some on board from knowing what's going on ev- erywhere, Gisclair continued. "Because multiple rig activi- ties affect the same data, it can become impossible to deter- mine which activities are affecting the data and which are affecting the hole condition," he said. Once BPS crew deter- mined there was a problem, it shut down the well's pumps, determined that the fluid inside the annulus could accept- able be dumped, and began that process, which bypassed several sensors, Gisclair said. Sperry's mud loggers could no longer see what was hap- pening because another crew was displacing sea mud from a pit which is normally not monitored, Gisclair said, add- ing, "Pit volume changes are typically the primary indica- tor of fluid movements. This is critical information to help mud loggers identify problems which may be occurring on the rig. They also didn't know about other activities, such as moving fluids from a boat onto the rig" Gisclair said in one 30-min period the day of the ac- cident, various contractors were dealing with dumping of the sand tanks, trip tank gains and losses, crane operations which are obscuring flow -out sensors, balancing operations moving light seawater from one part of the rig to another, and taking on heavy mud at another area. "All of this can make it impossible to determine what flow -out was coming from the hole, what flow -out was coming from the trip tank, and what was coming from the sand trap," he said. Roth noted that on deepwater wells, float chutes are used to provide a redundant device independent of the float col- lar. This was not part of the Macondo well's design, he not- ed, which actually prevented the meaningful placement of cement bond logs to determine whether good zonal isolation was achieved. "BP did not elect to run cement bond logs, with the understanding that it had equipment on board to handle that," Roth said. "It would have been difficult but not im- possible." 36 More dispersants research needed despite success in gulf, panel told Nick Snow Washington Editor More research into the long-term effects of chemical disper- sants is needed despite their apparently successful use in fighting the massive oil spill from BP PLC's Macondo well in the Gulf of Mexico, US Environmental Protection Agency Administrator Lisa P. Jackson said on Sept. 27. "We were in a position with no perfect solution," Jackson told US President Barack Obama's independent commission investigating the spill and its implications for US offshore oil and gas policy. "Preventing the oil from reaching the shore- line was the No. 1 goal. Still, we must learn from our experi- ence with this tragic event. I am fully committed to revisit- ing the regulations surrounding EPAs response, particularly regarding dispersant registration under the National Con- tingency Plan" Dispersant research so far has focused mostly on imme- diate effects and not long-term impacts, according to Nancy E. Kinnear, co -director of the Coastal Response Research Center at the University of New Hampshire. "Very little is known about chronic toxicity, biodegradability, and other consequences," she testified. Initial conclusions show that no combination of resources can fully contain a spill the size of what leaked from the Ma - condo well, that mechanical recovery is preferable but not always possible the sort of high seas and winds which oc- curred once these leaks began, and using dispersants was preferable to letting crude oil migrate into sensitive habitats, Kinnear said. "Dispersants can have a role in responding to a massive offshore spill when climate conditions prevent a strong me- chanical response," she said. "There is a pressing need for independent R&D funded through a rigorous grants process to evaluate the long-term impacts of spilled oil in a variety of environments. We should also evaluate impacts under re- alistic scenarios." Risk protocols Specifically, she said protocols need to be developed to eval- uate risks in using dispersants. "First, we need to start us- ing relevant species. We need to think about the relative life stages, which is why assessing risks and keeping it going through the spill is so important," Kinnear said. "The other thing is that when we do these tests, we tend to look at 96- hr exposures. That's the standard, but it may not apply if we look harder at acute and chronic toxicity." Jackson noted that from the response's early stages, EPA recognized the need to be vigilant and cautious with the use of dispersants, which it is why, along with the US Coast Oil & Gas journal I Oct. 4, 2010 GENERALINTEREST Guard, it ordered BP to limit its use and volume of the chem- icals that are designed to break up spilled crude. "Specifically, EPA and the Coast Guard issued a direc- tive on May 26 instructing BP to significantly scale back the subsurface use of dispersants to only what was needed to be effective, and to halt use of surface dispersants unless conditions on the ground limited the use of other mechani- cal means," she told the commission. BP's use of dispersants fell 75% from their peak levels after the directive was issued, and while some days showed increases, "the significant de- creasing trend line was undeniable," Jackson said. EPA knew, based on previous surface dispersant applica- tions, that they were generally less toxic than crude, they decreased the risks to the shorelines and to organisms on the water's surface, and they biodegraded over weeks or days instead of years as oil does, she noted. "However, all the potential long-term effects of the dispersant application on aquatic life, and the unprecedented volume applied in this response —almost 1.8 million gal —certainly warranted caution," she said. BP initially asked EPA on Apr. 30 to use dispersants in a novel manner —underwater, at the leak's source, Jackson told the commission. "The goal of this approach was to break up and degrade the oil before it reached the water's surface and came closer to our shorelines, our estuaries, and our marine nurseries," she said. Steps to approval Since this approach had never been tried, Jackson said that EPA asked BP to provide specific scientific data proving that such an application would actually be effective. Once it de- termined that the process was working, EPA then ordered BP to implement a rigorous monitoring system and track measurable environmental impacts by monitoring dissolved oxygen and toxicity, she said. It conditionally approved BP's request on May 14 after making clear to the company that EPA reserved the right to withdraw its approval if environ- mental impacts outweighed benefits of dispersing the oil. USCG approval of the subsea application was based on conditions resulting from only having the dispersant option on some days, combined with trying to secure the source of the crude oil release, according to Rear Adm. Mary E. Landry from the US Department of Homeland Security agency's eight district in New Orleans. When we approved the subsea injection, we felt there could be a reduction in the amount of dispersants used," she told the commission. "In the final weeks of May, trying to secure the source was critical for the workers' health and mitigating the impacts on the shoreline" Landry said she was aware of the obligations imposed on BP by requiring it to ask daily for permission to use the dis- persants, but added: "We had an overall goal of reducing the amounts used and accomplished this over time" "The good news is that we did not see significant short- 38 term environmental impacts of using dispersants," Jackson said. "We did not, and continue to not see, diminished lev- els of dissolved oxygen. This is a good indicator of overall aquatic health and we saw normal levels in testing near the rig site, where subsurface dispersants were applied. We also saw no significant toxic effects on rotifers, which are sensi- tive organisms that act as the 'canary in the coal mine' for water health." Water monitoring continues to indicate that dispersants have not been found in waters on or near the shoreline, she continued. Of more than 2,000 samples generated by the Na- tional Oceanic and Atmospheric Administration and nearly 1,200 generated by EPA, Jackson said that only two were above the method detection limit but well below health lim- its. "While these detections were likely caused by problems with the testing devices, they were immediately investigated and the areas re -sampled," she said. "In both cases, follow- up testing indicated a 'nondetection' of dispersant" M ConocoPhillips's Mulva: Natural gas a job -creation machine' Paula Dittrick Senior Staff Writer Growing natural gas consumption can help drive US eco- nomic recovery and job creation, ConoccPhillips Chairman and Chief Executive Officer James Mulva said Sept. 27 at Rice University's Baker Institute for Public Policy. "Natural gas in an overlooked job -creation machine," Mulva said. "Let's crank it up and step on the accelerator." He spoke during a 2-day Baker Institute conference at which numerous papers were released that analyze potential US carbon management policies. Calling for a "balanced energy policy," Mulva called upon US lawmakers to develop a comprehensive energy policy "that allows all sources to compete on the basis of abun- dance, cost, efficiency, and environmental merit." He said, "We don't have that today.... Current policies stack the deck in favor of coal and renewable sources" Energy from renewable sources cannot be provided fast enough to instantly replace the energy currently provided by fossil fuels, he said. The oil and gas industry currently supports 9.2 million US jobs, Mulva said, and he acknowledged that all energy sources will be needed in the future. "So yes, bring on the green jobs. But in doing so, don't destroy the real jobs that we have today in the oil and gas industry." He recommended state and US lawmakers carefully ex- amine renewable electricity standards, noting that some states require utilities to use renewable sources for part of Oil & Gas journal I Oct. 4, 2010 • From budsoffshoreenergy October 4, 2010 • While unveiling their "Guiding Principles," Kathryn Klaber, Executive Director of the Marcellus Shale Coalition. said this: We're all in this together. We're all only as good as whoever had a mistake this morning. That this statement also applies to offshore oil and gas operations should now be painfully obvious to all. Each company's success is dependent upon every other company's performance, not just in your region, but anywhere in the world. The offshore industry needs to clearly and succinctly describe its universal commitment to safety and environmental protection. Sweeping principles that guide all operations should be developed and endorsed by every operator and contractor. The Marcellus document is a good starting point, but more details may be needed. Commitments to sharing and analyzing verified incident data, participating in standards development, assessing new technology, and sponsoring safety and environmental research should be included. Now is the time to act. Who will provide the regional and international • leadership? • We, the members of the Marcellus Shale Coalition, embrace and operate by the following guiding principles: • We provide the safest possible workplace for our employees, with our contractors, and in the communities in which we operate; • We implement state-of-the-art environmental protection across our operations; • We continuously improve our practices and seek transparency in our operations; Goo• We strive to attract and retain a talented and engaged local workforce; 0 • We are committed to being responsible members of the communities in which we work; • We encourage spirited public dialogue and fact - based education about responsible shale gas development; and • We conduct our business in a manner that will provide sustainable and broad -based economic and energy -security benefits for all. We recognize that to succeed in business, we not only embrace these principles, we live by them each and every day. This will be our legacy. MARCELLUS SHALE COALITION www.MarcellusCoalition.org 9 Bud's Offshore Enemy (BOE) Energy Production, Safety, Pollution Prevention, and More Several interesting items! September 30, 2010 by offshoreenergy • The Canada -Newfoundland and Labrador Offshore Petroleum Board unveiled their new website. Very impressive! • Jane Cutler, CEO of NOPSA (Australia), made an outstanding (must -view) presentation on Safety Priorities for 2010. My favorite quote: Safety culture is how the organization behaves when no one is watching. Also, NOPSA's September Newsletter has some interesting updates including information on the jackup failure offshore China. • Joel Achenbach, a verb good reporter, wrote an excellent Washington Post article on that addresses some of Macondo's human and organizational factors. I do disagree with the deepwater emphasis, particularly his BOP comments. As we have noted on several occasions, subsea BOPs have a far better performance record than surface BOPs. Also, having the stack right at the surface is a hindrance, not a benefit, if the rig is on fire. And how does a reporter question the humility of engineers? Q Engineers do amazing things, but they aren't always as smart as they think, nor their systems as robust as they seem on paper. 0 • Joel Achenbach, a very good reporter, wrote an excellent Washington Post article on that addresses some of Macondo's human and organizational factors. I do disagree with the deepwater emphasis, particularly his BOP comments. As we have noted on several occasions, subsea BOPS have a far better performance record than surface BOPs. Also, having the stack right at the surface is a hindrance, not a benefit, if the rig is on fire. • And how does a reporter question the humility of engineers? "Engineers do amazing things, but they aren't always as smart as they think, nor their systems as robust as they seem on paper." Freak accident or frontier enterprise? Deep -water drilling is still a big unknown. BP's internal report on the causes of the Deepwater Horizon blowout, released earlier this month, summarized the calamity as the result of eight separate breaches of physical and operational barriers, any one of which could have, and should have, stopped the • unfolding disaster. The blowout, in the BP scenario, was very much a freak event. A long shot. THIS STORY Concerns about the Biq Spill might already be drying up Special report: Energy Is Urgent Graphic: Shell tension -leg production platform in the Mars Basin View All Items in This Story A graphic in the report showed the barriers arrayed like eight slices of Swiss cheese. All the holes, the report states, "lined up" to enable the blowout: "[A] complex and interlinked series of mechanical failures, human judgments, engineering design, operational implementation and team interfaces came together to allow the initiation and escalation of the accident." There is a different, and simpler, way to describe what happened: They weren't careful enough. For the can -do culture of petroleum engineers, this catastrophe should heighten respect for the way bad things can happen to what looks like proven technology. Oil drilling is a • risky business, and deep -water drilling is riskier still. Depth matters. And as the industry • went deeper, it didn't commensurately increase its safety margin -- or prepare for the worst -case scenario. On land, on sea, in the air, in space, in our laboratories, on our farms, we are surrounded by technologies of increasing complexity, all of them vulnerable, at some level, to catastrophes of human origin. Engineers do amazing things, but they aren't always as smart as they think, nor their systems as robust as they seem on paper. The more complex the job, the more potential infiltration points for gremlins. "We believed that the blowout preventer was the ultimate fail-safe mechanism," BP CEO Tony Hayward testified before Congress in June, bringing to mind the captain of the Titanic, believing that his ship was unsinkable. Charles Perrow, in his seminal book on technological disasters, "Normal Accidents," writes, "We have produced designs so complicated that we cannot anticipate all the possible interactions of the inevitable failures; we add safety devices" -- think blowout preventers -- "that are deceived or avoided or defeated by hidden paths in the system." His argument is that such accidents, though rare, are integral characteristics of the system, with its interlinked components. That's what happened here. • The pivotal moment came late on the afternoon and into the early evening of April 20. The Horizon crew conducted two pressure tests to look for any signs of hydrocarbons flowing in the well, which had already been cemented. For reasons that remain somewhat murky -- most of the key figures either have refused to testify or died in the explosion -- the BP "company man" and the Transocean crew decided that the results of the pressure tests were benign. As in many industrial accidents involving complex technology, they were trying to interpret something they couldn't see directly -- what was happening below the bottom of the sea. The critical hardware, the blowout preventer, was a mile deep. The pressure tests showed pressure on the drillpipe, a strong sign of a possible leak in the cement job. But when another valve was opened, on what is known as the "kill line," nothing flowed out of the well. That seemed like a good result. Except the kill line could merely have been clogged with gunk. The gunk was "spacer fluid" sent down the well to flush out heavy mud and allow seawater to replace it. That's a normal procedure -- except this time, a double "pill" of spacer was used, twice as much as is standard. BP approved the plan by the mud engineer to send down this double -size batch of goo. It appears that the huge amount of spacer fluid was a classic shortcut: The fluid had already been mixed, and under the environmental regulations any fluid not used would have to be hauled to shore for proper disposal -- unless it was used • in the wellbore. Down the well it went, so that, when it came back up, it could be dumped into the Gulf of Mexico. • The spacer, BP said in its report, might have clogged the kill line and created a confusing pressure reading. Whether BP (and/or its contractors) were criminally negligent is the subject of a Justice Department investigation. BP made much -criticized decisions in well design but maintains that the design was not a factor in the blowout. A BP spokesman said last week that all the information about the well obtained through efforts to kill it "leads us to believe conclusively that the well design did not contribute to this accident." BP also decided against running a time-consuming "cement bond log" test that might have detected flaws in the cement job. The company's report acknowledges that the well team should have done more risk analysis. BP's industry competitors will favor the simple explanation that this was a catastrophe caused by a single bad actor, a company with a sketchy safety record. These companies spent the summer throwing BP under a bus as though it were a boardwalk game. They want to get back to deep -water drilling. Policymakers will have to ponder the fact that these other companies use the same contractors as BP, the same kind of technology, the same line of blowout preventers, etc. Bob Dudley, BP's incoming CEO, said to NPR this summer, "We have been drilling for 20 years in the Gulf of Mexico without an accident." But past performance does not • guarantee future results. And deep -water drilling is still a frontier enterprise. There are 37,441 wells in the Gulf of Mexico, about two-thirds of which have been permanently abandoned, according to the Bureau of Ocean Energy Management, Regulation and Enforcement. Of those, only 2,089 wells are in water 1,000 feet or deeper. The Macondo well was drilled in 5,067 feet of water, putting it in what is known, bureaucratically, as "ultra -deep water" -- anything deeper than 5,000 feet. There are only 410 ultra -deep -water wells in the gulf, according to the federal government. That's not a huge number. In shallow water wells, the blowout preventer often sits on the rig during the drilling process. In deep -water wells, the BOP is on the seafloor. You can't put on scuba gear and dive to 5,000 feet. The only way to tinker with the BOP is with remotely operated vehicles, but that's not the same as being able to walk right up and fiddle with the kill line to see if it's clogged with gunk. "We have found no evidence in our assessment and investigation of this accident to suggest that costs were any part of how this occurred," Hayward said Sept. 15. But all decisions in the drilling business are made with cost in mind. 0 Wr • "We're a business," BP executive David Sims testified this summer before a government investigative panel. "We have shareholders. Our job responsibility is to be fiscally responsible.... Every decision has some cost factor." Edward Tenner, a historian of technology and author of "Why Things Bite Back," said in an interview that BP's own report acknowledges multiple failures of design, organization, maintenance and judgment. "As with every other major disaster, identifying these flaws will help define a new set of best practices," Tenner said. "The real question is whether the new rigor will be sustained and enhanced after the outrage fades." What we thought we were seeing, in the summer of the spill, was a worst -case scenario unfolding in front of us. But there are even more dire scenarios out there. Blowouts can happen in many ways, some of them creating, potentially, multiple leaks from the seafloor, a situation not readily fixed. It's not inconceivable that an oil field deep in the rock could effectively bleed out. Unlikely, sure. But catastrophes are always hard to imagine until the very moment you are up to your eyeballs in one. • 0 • New rules to reflect legacy from spill Interior secretary is expecting 'the gold standard' for safe drilling By JENNIFER A. DLOUHY Copyright 2010 Houston Chronicle Sept. 29, 2010, 10:45PM WASHINGTON — The Obama administration is paving the way for an early end to its deep -water drilling moratorium by imposing new safety rules governing everything from the design of wells to the equipment used to control them. Interior Secretary Ken Salazar is expected to outline the mandates today after reviewing fresh recommendations from his top drilling regulator on how to lift the ban on deep -water exploration. The regulations aim to prevent a repeat of the Deepwater Horizon disaster by addressing vulnerabilities revealed by the April 20 blowout at BP's Macondo well. Salazar said the rules reflect lessons learned during BP's five -month fight to rein in the runaway well in the Gulf of Mexico. "The legacy of the BP oil spill will be to create the gold standard for safe drilling and production of oil and gas in the outer continental shelf - and to do so in a manner that is safe and that protects our environment," Salazar said. • Michael Bromwich, the director of the federal Bureau of Ocean Energy Management, Regulation and Enforcement, said the mandates "will have an immediate and quite substantial impact on what companies will need to do" before they can begin drilling again. "There are a significant number of additional requirements that industry is going to have to comply with," Bromwich added. Bromwich was set to give Salazar his recommendations on the moratorium and the future of deep -water drilling today, a month ahead of schedule. Bromwich has repeatedly said he believes the ban would be lifted when it expires Nov. 30, if not sooner. Foreshadowed in May Many of the drilling mandates - such as requirements that engineers sign off on well casing designs and cementing procedures - were foreshadowed by a May 27 Interior Department report on offshore drilling safety. That 44-page document recommended dozens of changes to the way offshore wells are designed, drilled and controlled. Other requirements The administration's rules also incorporate other requirements imposed on all offshore drilling in June. Although they applied broadly, in practice, the requirements have so far only governed new shallow -water projects that were allowed to continue during the ban. i� • Companies with deep -water drilling projects frozen by the moratorium have been working to comply with those standards and have been lining up engineers to inspect their plans, said Erik Milito, the American Petroleum Institute's upstream director. "The companies have gone back and reviewed their internal practices, reviewed the equipment that they have in place (and) they've been looking at making sure they have independent third - party verifiers and certifiers and special engineers lined up," Milito said. "Our understanding is they are ready to go. It's just a matter of getting the clarity from the government and getting the approvals once those permits are submitted." Blowout preventers A main focus of the new rules are blowout preventers - the massive stacks of pipe -cutting and hole -closing rams designed as a final safeguard to prevent oil and natural gas from escaping wells. It was unclear Wednesday whether the administration's new rules would adopt the May 27 report's recommendations to require that blowout preventers include redundant, adequately spaced shear rams to slash through drill pipe and casing - upping the odds that at least one of them would work in an emergency. At BP's Macondo well, that didn't happen, despite at least three attempts to activate the rams. However, the administration is set to require rigorous new testing of the devices under a variety of conditions. • Stepped -up testing Salazar said the stepped -up testing requirements build off the way BP examined the blowout preventers that were used when drilling relief wells to kill the Macondo gusher. "As the two relief wells were being drilled ... there were testing requirements that were placed on the BOPs that had never been put on before," Salazar said. "And they gave us information on what to do with respect to blowout preventers, relative to the testing protocol that will be required." jennifer.diouhy@chron.com C. 0 • 'If we want to have a genuine effect on the risk of accidents, we all need to concentrate much more on the immensely complex interactions between human beings.' 0 n 26 April 1986 a nuclear reactor exploded and caught fire at the Chernobyl nuclear plant in the Ukraine. Some 30 firefighters died from radiation, and hundreds of others suffered illness. A cloud of fallout spread across much of Europe. Although the Russian authorities kept quiet, the incident was first detected by monitors in Sweden, and then rapidly publicised. The damage was worse than it might have been if the Russian authorities had been less cynically irresponsible. One component of fallout was radioactive iodine "'I, which is rapidly taken up by children's thyroids, particularly in areas where the customary diet is iodine -deficient. Fortunately, "'I has a short eight -day half-life. In Poland the public authorities immediately advised mothers not to give their children milk for several weeks: no Polish children suffered from thyroid cancer. In the former Soviet Union, no warning was issued, and about a thousand children developed thyroid cancer, though happily thyroid cancer is operable. Chernobyl did immense harm to the nuclear industry, and the damage it did continues to this day. Chernobyl is brought up in every argument about nuclear power, or indeed about nuclear anything. (H is not an accident that discussion of medical scans takes care never to use the words `nuclear' or 'radiation', even though the radiation dose to one person from one CT scan is hundreds of times larger than the accumulated dose to the same person from 50 years of nuclear power.) In vain is it pointed out that the Chernobyl reactor was atypical, that its primary purpose was the production of military plutonium rather than electricity; that its design was poor; that it had no containment structure; and that it was operated in a country where free discussion was suppressed. The operators were engaged in a foolish experiment, whose first step was to turn off almost all the safety systems. Modern-day reactors are quite different, but the word'Chernobyl' wins many arguments, even though it can sensibly be pointed out that more than 400 nuclear power plants supply a significant fraction of the world's electricity, and that a 'nuclear renaissance' is under way, led by China and Korea. with only Europe and the US lagging behind. Is the Chernobyl argument fair to the nuclear industry! Absolutely not. Does it help to point out how unfair it is? No. Now, in the summer of 2010, the offshore industry is trying to face up to the Macondo well catastrophe, which is far from finished with. At the time of writing, the inquiry is in progress. It is premature to jump to conclusions, but if a fraction of the gossip that circulates on the net is to be believed, the results of the inquiry will be very damaging indeed. > oaerleaj 0 0 hllp:l(oe.oiIonline .com orfstioRE ENGINEER I august 2010 27 • • • The parallels are far from exact, but it is not fanciful to conclude that the Macondo incident will have at least as damaging and persistent an impact on the offshore industry as Chernobyl does on the nuclear power industry. Will that be fair to the industry? No. Will it help to point out that thousands of wells are drilled into the sealioor, that millions of barrels are produced every day, and that leaks and spills are very rare? Not much. Will it help to point out that after the Piper Alpha disaster in 1988, the regulatory environment was dramatically altered, and that the industry cleaned up its act and learned lessons? Very little, and indeed that last argument might be counter -productive, because it can be pointed out that some of the changes made in the North Sea were not adopted in the Gulf of Mexico, and that conflict is inevitable if the same agency has responsibilities both for safety and environmental protection and for development of the industry. What is to be done? All of us will have to live with the consequences of Macondo for the rest of our careers. There are no easy answers. There must be a temptation to imagine that the incident will blow over as soon as the relief well is effective and as the oil on the beaches and in the water column slowly degrades and disappears, though the experience of the Exxon Valdez disaster is scarcely encouraging. In some quarters there might also be an illusion that the consequences can be smoothed over by some clever combination of public relations, appeals to 'common sense', political donations, and manipulation of the interests of those economically engaged. The argument that PR can meet the problem is particularly unconvincing. A positive outcome might be an overdue recognition that almost all accidents result from human decisions (as Piper Alpha certainly did). This has been obscured by naive applications of reliability theory, which purport to be able to demonstrate that some probability of failure is smaller than 10•n/year, where n is some arbitrary number fossilised into a code. So-called reliability theory is an academic diversion essentially irrelevant to the real problem. There is nothing wrong with the mathematical theory as such, but the fundamental and inescapable difficulty is that the data needed to demonstrate the intended results are never available (and can never be available). If we want to have a genuine effect on the risk of accidents, we all need to concentrate much more on the immensely complex interactions between human beings. If reports are to be believed, the wives of at least two of the men tragically lost on the Deepwater Horizon say that their late husbands complained about safety issues, and that they reported that corners were being cut in the interests of completing the well rapidly. If that should turn out to be correct - and we must not rush to judgement until all the facts are assembled - we might guess that they did not feel able to speak up loudly on the rig, perhaps for fear of a macho 'can -do' culture that would run them off as troublemakers. The offshore industry needs to follow the nuclear, health and aviation industries, where systems formally protect whistleblowers against retaliation. tE • L he views expressers in this article are the author's own and do not necessarily reflect OE'sposition. Andrew Palmer has divided his career equally between preelioe as a consulting engineer and university leaching. In 1975 he joined RJ Brown & Associates, and in 1985 he founded Andrew Palma & Associates. a company of consulting engineers. In 1996 he returned to research and university teaching as research professor of petroleum engineering at Cambridge University. W is currently Keppel Professor at the National University of Singapore. Prof Palmer is the auliuor of three books and more than 200 papers on pipelines, offshore engineering, geotechnics and ice. OFwelcumes letters reflecting all shades c of offshore industry opinion but reserves the right r to edit and condense. 4jr mailbag Macondo matters Sir. OEs article by Ian Fitzsimmons on preventing future Macondo spills ('Macondo and other titanic struggles', OEJuly) was excellent and I distributed a copy to my colleagues both in EIA and DOE. The recommendations made regarding developing better cements and longer curing limes, BOP/riser modularity, and BOP ram spacing are indisputable. Articles I have read in the various media lead me to believe that the BOP might have been nearing the end or past its useful life, given the operating problems that were experienced. Consequently, the industry might also need to embrace a more conservative/aggressive preventative maintenance and retirement policy regarding offshore BOPS. Ian Fitzsimmons' comments regarding the oil containment problems being more severe if the riser pipe had collapsed on the wetlhead made me wonder how much worse the nil containment problem would have been if Ore drilling semisubmersible had come to rest on the wellhead after sinking. I am glad to see that the oil industry is putting together a consortium to deal with deepwater oil spills in the future. Philip Budzik (by email) Sir, Excellent amide by Ian Fitzsimmons in OEJuly. It hit the nail on the head. Robert Margolis (by email) Sir, Ian Fitzsimmons opinion piece on the Macondo blowoul slates: 'Those who are familiar with BOPs know that they can slice through a drill pipe collar with ease and seal — time after lime.' According to a 2OD4 report, standard blind -shear (BS) rams can only cut through drill pipe, and will not cut through the threaded joints in a drill string, (httpJAvww.mms.gov/tarprojects/463.htm, attachment AA). As far as I can determine, no supplier is yet able to offer BS rams that will cut through a drill pipe joint and then seal off. Cauerun ullers Super Shear Rams, which can cut through a drill collar, large diameter casing, heavy wall drill pipe and threaded joints, but will not seal. Keith Shotholt (by email) Ian Fitzsimmons responds: Mr Shotbolt acknowledges that qualirred shear rrtrns exist that can shear drill collars. However, '7 it may well be that not all current operational BOPS have that capability That may be a matter for a separate debate. As jar as Macondo is concerned, it is irrelevant. There was no drill pipe inside the well at the time of the blowout. The BOP str otegy that I laid out in OE Julypresumes esumes at the outset that a single pair of shear rams will fail in do their joh, whatever the cause, and whatever thole eta,imed capability, and that the BOP and LMRP should be con igured accordingly. My strategy is based on the presumption of failure of a singlepair of shear ramsfrom the outset, regardless of cause. When an internal obstruction of anvdescription prevents a pair of shear ramsfronr doing its jobs my pmpacal provides for another two Imirs of shear rams to be mlled up, which twoe a high probabiltty of beingclear of the inte-rnal obstniction. A revised BOP configuration is required, which will help to avoid another Macondo, and which can he. applied equally to both old and new RO^. The sin ugparadignr that a BOP is too bog O fail, and that only onepair or shear rams is required, tsfiindamentallyflaumd. Chinese puzzle Sir, i loved Michael Economides' piece on China ('Ebb and Flow, OEJuly). It seems hard to think that he was really tongue-tied, just unable to understand and explain the ravings of our current C-i-C. If the Chinese really want the world to notice, they probably should invest more in USA, though the Saudis have all but purchased Colorado, and no-one takes any notice. Perhaps if they buy a few good oil shale fields, then install a nice LPG export facility, someone would raise an eyebrow! Pickard Mirfak (by email) Sit, Please corNey my gratitude to Professor Michael J Economides for his lucid, eloquent, and meaningful account (OEJuly) as to how and why the US is seemingly destined, by Its own actions, to become a third world power, while China sees the relationships between energy and economic growth quite dearly and is taking the necessary steps to corainue its amazing economic development. I will be sending copies of this dissertation to President Obama. Secretary of Energy Chu, and to my senators and my US representative. Arlie M Skov (by email) 28 OFFSHORE ENGINEER I august 2010 http://oe.oilonline.cum • �:1�� �'e�tr�oxk �iine� http://www.nytimes.com/2010/08/17/us/1 7transocean.html After Another Close Call, Transocean Changed Rules By ROBBIE BROWN Published: August 16, 2010 Four months before the Deepwater Horizon explosion in the Gulf of Mexico, another oil rig owned by the same company faced a strikingly similar emergency in the North Sea that was contained only because its safety equipment functioned properly, according to confidential internal documents. In response to the near disaster, Transocean, the world's largest offshore drilling company, ordered critical changes to its own policies for handling oil well safety. But it is not clear whether those policy changes reached the Deepwater Horizon crew • before that rig exploded. Like the disaster in the gulf, the North Sea emergency involved dangerous pressure levels, a failure to detect those pressures in time, a risky plan for sealing the well and an emergency order for the crew to evacuate to lifeboats. "In this case, they were lucky," said Satish Nagarajaiah, a professor of civil and mechanical engineering at Rice University in Houston. "It's strikingly similar, but this time, the emergency equipment functioned." The internal reports, obtained by The New York Times, offer a stark comparison to the Deepwater Horizon incident, in which a crew facing similar circumstances could not regain control of the well, leading to an explosion that killed ii men and unleashed the largest oil spill in United States history. The reports also demonstrate the significance of a safety device called a blowout preventer, which failed in the Deepwater Horizon disaster. In the North Sea incident, as crew members were preparing to possibly abandon the rig, the blowout preventer was activated and successfully closed the oil pipe, averting a spill. The incident • occurred on Dec. 23 aboard a rig called Sedco yli at an oil well being leased by the Shell Oil Company. • The 19 pages of Transocean documents obtained by The Times add to the growing perception that Transocean, which leased the failed well in the gulf to BP, has had a history of safety problems. In March, an independent audit of the company described "a series of serious accidents and near -hits within the global organization" and found widespread safety concerns among crew members. But in the case of the North Sea emergency, human error, not mechanical failure, put the crew at risk, according to an April 14 report summarizing an investigation by Transocean. On the evening of the incident, workers failed to detect a powerful surge of gas that resulted from an equipment failure in the well. The surge, called a kick, eventually sent oil and mud flying onto the rig, at which point workers activated the emergency equipment and sealed the well, the report states. The incident resulted in a loss of ii days of work, more than $8 million and a "significant loss of reputation to Transocean," the report concludes. Three barrels of oil leaked into the water. A separate Transocean presentation, which was provided to rig workers after the • incident, cited a "lack of clear" procedures for controlling well pressure, "weakness in planning" the job's risk assessment and an absence of data about conditions in the well. In response, another internal document states, Transocean amended a safety manual called the Well Control Handbook to require new cautionary steps for all crew members replacing the heavy drilling mud with a lighter seawater solution — one of the procedures investigators believe contributed to the Deepwater Horizon disaster. The amendment also instructed crew members not to be "complacent" after conducting pressure tests like those the Deepwater Horizon crew believed had functioned, but investigators believe may have failed. It is not known whether these changes to the safety manual were received by the Deepwater Horizon before the disaster. "If this policy had been in place and had been followed, the Horizon incident might not have happened," said John Konrad, a maritime expert who is writing a book about the disaster. "They would have realized a lot sooner that the well was getting out of control." 0 In a statement Monday evening, Transocean said that it had issued the safety advisory after the near disaster in the North Sea "to restate and emphasize portions of Transocean's existing well control manual, and it reflects the company's commitment to best operational practices." The Deepwater Horizon's drill crew, the statement continued, "had more than go years of experience among them and — as the evidence demonstrates — were alert and monitoring the well at all times under procedures confirmed by BP company men on the rig and onshore." The role that Transocean's safety protocols played in the Deepwater Horizon accident is likely to be a focus for federal officials who are continuing investigative hearings in Houston into the cause of the disaster. The company's mixed safety record was documented in a confidential audit of the Deepwater Horizon conducted by BP seven months before the explosion and reviewed by The Times. According to that document, Transocean had left 3go repairs undone, including many that were "high priority," and would require a total of more • than 3,5oo hours of labor. It is unclear how many of the problems remained by the day of the catastrophe. 0 0 MARITIME LAWYER NEWS Maritime Law Blog and The Jones Act http://www.offshoreinjuries.com/blog/l 268/transocean-withheld-internal-report-that- proved-fatal-for-deepwater-horizon-11 / Transocean Withheld Internal Report That Proved Fatal For Deepwater Horizon 11 am August 16th, 2010 1 ZAuthor: Maritime Law Staff Confidential internal documents from Transocean reveal that on December 23, 2009 there was a blowout on one of their drilling rigs in the North Sea at 5:10 pm that was eerily similar to the Deepwater Horizon disaster. Drilling mud was being replaced by seawater when the blowout occurred. Fortunately, in that incident, the Blowout Preventer (BOP) worked when it was activated, the rig was spared and the crew was safely evacuated. The incident occurred at the Sedco 711 location in the North Sea. At that well, Transocean made a decision to displace the mud with seawater and had a blowout. This was the same thing that happened on the Deepwater Horizon prior to the explosion that destroyed it along with 11 lives 0 • A full investigation into the incident was conducted by Transocean following the mishap along with a report detailing all the necessary recommendations to prevent such incidents from recurring. Unfortunately, the Deepwater Horizon never received the report. But that is not the only similarity with the Deepwater Horizon disaster. These drilling rigs are equipped with a general alarm designed to go off and signal an evacuation if two or more sensors are triggered within a zone. On the Deepwater Horizon, the general alarm had been intentionally "inhibited", in essence, it was disabled for well over 8 months prior to the April 20th event. In the North Sea incident, alarms were also being continually activated until they were disabled as well. The main point that was addressed in the North Sea incident was lack of well control at the time of well completion when the drilling mud was being displaced with sea water. This situation was exactly the same on the Deepwater Horizon. Early in the day on April 20th a controversial decision was made by BP and agreed upon by Transocean to displace the drilling mud with salt water. This decision directly lead to the Deepwater Horizon disaster. So what went wrong with management? The North Sea incident occurred about 4 months prior to the Deepwater Horizon disaster. Transocean's internal report on the incident was dated April 14, 2010 — 6 days prior to the disaster on April 20, 2010 in the Gulf of Mexico at the Macondo well. . Had the report and subsequent recommendations from the North Sea incident been disseminated to the drilling management for the Gulf of Mexico operations, then it is likely that the Deepwater Horizon disaster would have been completely avoided. Transocean is the world's largest offshore drilling company with three main divisions — North Sea, Asia and North America. It is management's responsibility to coordinate the various activities under one's charge. There is no excuse for poor coordination at management level especially when it comes to safety. Transocean discovered vital information from the North Sea incident that would have prevented a disaster and saved lives. How could the largest oil drilling company in the world be so lax on such critical safety issues as to repeat the same mistakes just four months later? It was their duty to demand that this information be known and proper procedures followed throughout all their locations. Further, they were lucky in the North Sea incident that the Blowout Preventer worked and prevented a similar disaster. Relying on the Blowout Preventer to do its job should be a last resort measure only as an emergency. The engineering requirements, in the oil field industry, require that there at least be two "barriers", e.g., mud and cement, mud and annular, etc. Transocean operates as if the BOP is a barrier when, in fact, it is an emergency device. 0 • Transocean was very aware of loss to its reputation after the North Sea incident. The report stated that the incident resulted in 11.1 days of lost time at a cost of approx £5.2M (approx $8.1M) and "significant loss of reputation to Transocean". The April 14th report was limited to the North Sea Division, as opposed to distributing the information to all three major Divisions. These are fundamental problems that should have applied to all drilling locations. The fact that their report predates the Deepwater Horizon disaster, coupled with the fact that it was intentionally limited in its distribution, reveals a corporate lack of continuity in its safety policies and programs. Had they decided to correct the problems company -wide rather than trying to treat the one incident in the North Sea as an isolated incident, then it is likely that the Deepwater Horizon disaster would have never occurred. Although the North Sea Division is a separate division, it is the responsibility of upper management to coordinate all areas under their charge. This failure to do so, resulted in death, injury, and destruction of four state's eco-systems. • 0 titanic struggle The Titanic, Columbiaspace shuttle and ©eepwater#l, span a period of almost 100 years but A e might at first be apparent. All thr wer g"oI&N misguided belief in their indes"ctibility, says consult. Ian Fitzsimmons in the latest of his think pieces for ii*T, V. 4111MOYc� :. 2�0 MEN; TITANIC Sgs *I AND CHILDREN SAVED — 1�0•'-" �,,.,.-.�Hrrrcicss Flaah�'T' i. yarReutShiD'n tVJ�rSd''... ••+r M� �;.� _. cr Cas9r'�:tu ` str+lw iccbcrR �� ll$1 d{ iNBS[ ` y:;rst voY�" P WNB At BtEti Ole p1l tgANvg99 ♦a NdT t r.` • yn...r wY* — v r rMti —� 'From the Ranicto Ixtoc-1, the Comet, Piperkpha, Ocean Odyssey, the NASA shuttles and now Macondo, we can detect the paradigm of design infallibility. It is a dangerous frame of mind that smugly congratulates itself on having attained perfection beyond improvement.' Ian Fitzsimmons The Macondo well blowout and the loss of the semisubmersible Deepwater Horizon represent a huge blow to the morale of the offshore oil and gas industry globally. The tragic loss of life and ensuing environmental damage serve to remind us of the inherent risk associated with drilling for hydrocarbons, either offshore or onshore. Sadly, this disaster now heads the list of offshore rig blowouts recorded since 1970. The infamous Ixtoc-1 blowout occurred 3 June 1979 and was not capped until 23 March 1980. The public is right to wonder how far we have come since then and why we are still so ill prepared for the obvious risks associated with drilling offshore. Unfortunately, there is nothing new under the sun. Aside from the plagues of the Middle Ages, the age of man-made disasters probably began on 15 April 1912 with the sinking of RMS Titanic. For the UK, at the time leading the world in shipbuilding technology, it was a national disaster. Harland & Wolff had convinced themselves that Titanic was unsinkable. It is now generally accepted that more than one contributory defect was necessary to cause such an awful tragedy. In the Titanic's now legendary case, we can find six such causes: • The designers considered the vessel to be unsinkable due to the series of watertight bulkheads. Unfortunately they did not extend to the full height of the main deck level. • The provision of lifeboats was hopelessly inadequate for the number of passengers - because the vessel was considered unsinkable. • The Titanic should have been on a more southerly course considering the time of year, which was known to produce icebergs set adrift from Davis Strait and Baffin Bay. • When the iceberg was spotted, the vessel should not have steered either to port or starboard thereby exposing its flanks (beams) to the iceberg. • An experienced captain would have reversed the engines, steered straight at the iceberg and met it head on. This would have maintained the integrity of all the bulkheads aft of the bow. The vessel would then not have sunk. • Unfortunately the captain of the Titanic had not been trained for this eventuality. Later in the century came the NASA shuttle disasters - Challenger in 1986 and Columbia in 2003. Without going into too much detail, most engineers at the time were astounded to discover that neoprene rings had been used to seal Challenger's solid booster segments together. They were further astounded to discover that the shuttle crew module could not be detached and ejected from the main fuselage in the event of an emergency. In the wake of the Columbia disaster seven years later, it was discovered that a small piece of insulating foam from the main fuel tank was able to rip away most of the shuttle's wing. The public wanted to know about Plan B - could the lives of the crew have been saved in spite of the damage? There was no Plan B at the time. Subsequent events demonstrated there were in fact several Plan Bs available. They came too late for Columbia. These disasters have two things in common: they could have been avoided at the outset, and the designers thought their creations were indestructible. Today we have the Macondo/Deepwater Horizon disaster on our hands. It is worth taking a look to see if we can find similar faults. What is clear from the outset is that the drilling engineers were convinced their designs and equipment were indestructible. We know that because, faced with a major disaster, they did not have a recovery plan ready. We have watched in bewilderment as they searched for a temporary remedy. But could they have been better prepared with a magical kit of parts? Sadly, the answer is no - not with the equipment and systems they were using. They put all their faith in a single pair of shear rams, which failed to close when they should have done. The shears can both cut and seal, and of course there are the back-up blind/pipe rams if needed. We know that the shears' ROV override facility was unable to activate the shears and stem the blowout. Those who are familiar with BOPs know that they can slice through a drill pipe collar with ease and seal - time after time. It is obvious, therefore, that something much bigger is inside the BOP and it probably has the same internal diameter as the BOP. That can only be a wellhead casing hanger - either the 95/sin casing hanger or a 133/8in casing hanger. And that is probably what has prevented the BOP shears from closing. If this proves to be the case, then it is also obvious that the 95/8in (or 133/8in) casing hanger lock down seal failed - permitting the hanger to be displaced vertically upwards by pressure from below. That would also mean that the casing shoe cement job was inadequate. It may seem strange for engineers to learn that we still use Portland cement for sealing the well casings against the predrilled formation. Of course it comes with all manner of additives, but it still remains ordinary Portland cement. Surprisingly, there is no universally accepted standard for its manufacture and application. As far as I can ascertain, very little research has been undertaken to either improve or replace it - a situation that has in my opinion existed for too long. But another larger risk exists in the form of the 21in marine drilling riser -just like the one that was hanging off the lower marine riser package (LMRP) on the Macondo well. If a semi is going to sink - for any reason - then, apart from the potential and actual loss of life, the greatest risk to a subsea well is the collapse of the marine riser. This is a particular risk in deepwater - in this case some 1500m (5000ft) of riser collapsed to the seafloor. It was fortunate (if that is the right word) that the entire riser did not collapse over the well when its tethers separated from the semi. Had that been the case, access to the LMRP would have been nearly impossible. The riser in question clearly folded over and buckled at the LMRP junction, which could be seen to comprise a bolted, flanged connection. Under those circumstances, it was necessary to saw through the riser in order to open access to the LMRP. The temporary funnel was then placed over the remains of the flanged connection. And here is the very nub of the problem - the permanent flanged connection between the LMRP and the LP marine http://oe.oiIonIine.com OFFSHORE ENGINEER I july 2010 23 • drilling riser. Had the riser been connected to the lower package using either a mechanical clamp or a hydraulic connector, this disaster would have been curtailed at a much earlier stage. The riser connector could have been released by RO V and the blowout curtailed with the introduction of a temporary HP drill stem riser, complete with an 183/4in hydro/mechanical connector. The surface termination would typically comprise a surface test tree. It is unfortunate that some time will always elapse between a blowout and subsequent recovery of the situation. The sinking of the operating semi will obviously exacerbate the delay caused by the time it takes to mobilise a replacement. But no great mobilisation of additional equipment would be required, just drill stem and a hydro/mechanical connector. The need to learn is often forgotten by the very institutions that are supposed to regulate the oil industry. Other industry sectors such as shipping, submarine, space, aeronautical and structural are similarly exposed. In some respects it is a matter of deliberate neglect and acceptable risk, ie a two -winged aircraft cannot incorporate a spare wing, just in case. But when a piece of foam insulation breaks from the hull of a space shuttle fuel tank and rips open its wing it is surely a matter of criminal neglect. From Titanic to Ixtoc-1, the Comet, Piper Alpha, Ocean Odyssey, NASA shuttles and now Macondo, we can detect the paradigm of design infallibility. It is a dangerous frame of mind that smugly congratulates itself on having attained perfection beyond improvement. If we are to learn from the Deepwater Horizon disaster, then the following points may illustrate the research and work that needs to be done to avert any such reoccurrence - so far as is humanly possible. Cement This is a general problem for the oil and gas industry both onshore and offshore, and has been for a very long time. The Macondo blowout is unusual in that it did not occur during drilling operations. It occurred while the well was being suspended for future conversion to a production well. That makes it unusual, and explains why suspicion has fallen on the cement job as one likely reason for the genesis of the blowout. To the best of my knowledge, a fully qualified cement type does not exist for the Macondo well. The word here is `qualified', ie strength tested under the same conditions of temperature and pressure seen in the well. Of paramount importance is the setting required to achieve the specified strength. Pure cement paste is not very nice. Those who would dispute this fact should prepare a glass beaker full of cement grout and watch the paste settle, leaving a layer of clear water above it. Civil engineers are aware of this fact - drillers may not be so • aware. Cement pastes also benefit from the inclusion of reinforcing fibres. Some cement is offered with this addition, but more detailed research and qualification is required. Most importantly, and until the full facts about Macondo emerge, and a suitably qualified cement emerges, the cement - - BYO' MmT en S*C+fS 3o ra f .� L. f/sx .fJ i IR Ca. _xl ntc mi' IY`L rn�wk r Btu. ..4 J sr.V-C- Av1- A typical BOP/LMRP stack -up as employed for example in the North Sea and offshore Australia. job at every casing shoe should be allowed to set for 48 hours before being pressure tested from above (except where a cement plug has been capped with a mechanical plug). Such pressure tests should last for 12 hours. I can already hear the howls of protest. But the facts are there for all to see. The dayrate for a deepwater semi is colossal - sitting and waiting for cement to set represents a horrendous cost. But compare that to the cost of the Macondo clean-up. Casing hanger lockdown seal assembly It has to be said at the outset that these items are usually foolproof, provided they are set properly and tested by overpull. But only with static, gradual applications of pressure. To the best of my knowledge no casing hanger lockdown seal has ever been tested under dynamic applications. The dynamic referred to is the `kick' received from a blowout. Remembering that F = mass x acceleration it can be readily demonstrated that the dynamic application of force from an accelerating fluid column will be far greater than the static application of an overpull from a semi. From an energy point of view, E='/2MV2 applies. I appreciate the difficulties in qualifying casing hanger lockdown seals under dynamic conditions caused by `kicks'. Those who would protest should remember what a small piece of insulating foam did to the wing of Columbia. 60P shears Everyone expects the BOP shears to be the final defence/barrier against a potential well blowout. We expect the shears to perform as promised, activated by direct hydraulic pressure applied to either side of the ram piston - always provided the two hydraulic ports are free to charge and discharge freely. The shears can tackle drill collars without problem, but not casing hangers. The problem with most BOP shears (and there should be two such pairs in every BOP stack) is they are located too close together. A typical BOP stack will have its shears rams placed with about 8ft separation depending on the BOP configuration. This is too close. A single internal obstruction could obstruct both sets of shears. Spacing of shears should be increased to 16ft minimum More howls of protest? I appreciate the need for compact BOP layouts, a need born of weight and height concerns when handling BOPs in the moonpool. But one thing is absolutely certain: the configuration of BOPS has to be scrutinised as never before. I believe Harry Cameron would agree. LMRP The current configuration of the LMRP has an Achilles heel. It is a simple fault - the 21in marine riser is flanged and bolted to the flexjoint assembly. When such a riser collapses from above - as it did from the Deepwater Horizon (and the Ocean Odyssey) - it buckles at the flange interface. This presented a major obstruction to the Macondo well. Subsequently we witnessed an ROV sawing the riser in order to gain access of sorts to the LMRP/BOP. > overleaf 24 OFFSHORE ENGINEER I july 2010 http://oe.oilonline.com • • (�td'1r4 4P.a4'- [n:, .. Ppnntc `ol' � uuY/�Jbil�.e intT Ott ) V v 'S i�i�/ C'Ml -f -• ee 1 ,F,i%hnnuta/' BO P �P 1 �T � �.. � " h7n n ti �a► r i�a� PiEt «S F.. 1 J P,& v . J I • COIL Gr i1FF _ _T_ &A-,v y� A Plan B' deepwater stack -up, as suggested by Ian Fitzsimmons. The subsequent funnel -down scavenging device has been partially successful under very difficult circumstances. The LMRP is of course a very heavy item. It is installed over the BOP using the marine drilling riser. Without the benefit of an alternative lifting arrangement, it will have to remain stuck on the BOP. This may be the reason why BP did not attempt to recover the LMRP from the BOP to gain access to the well. Had the marine drilling riser been connected to the LMRP with a detachable hydro/mechanical connector, with ROV override, then immediate access would have been possible. Furthermore, the lowest riser joint should have at least double the moment of resistance as the LMRP/BOP connector, thereby ensuring that the riser buckled well above the LMRP - not at the LMRP interface. In addition, the LMRP should be run with preinstalled lifting strops to enable recovery (with ROV hook-up assistance subsea) to the surface. The foregoing details ensure that there will always be two solutions available to disconnect and recover the drilling riser - from the LMRP itself, and from the BOP while still connected to the LMRP. Plan B Given the foregoing provisions are in place, and that the drilling riser has been disconnected from the LMRP (or the LMRP disconnected from the BOP), access is available to contain the blowout from the well. Plan B requires an HP riser comprising readily available onboard drill pipe, and an 183/4in hydro/mechanical connector. The inclusion of a failsafe retainer valve (or two) above the tC-�r� Pl.r ••- � _hf.drkri� ri c 5�i j� � .• - � RoPul„r I � -I "A- to r fibs) • I S3tc� III • } w!i [ �,F,! rN T tC' V E A,/ T' /& �. The author's proposed `Plan B' intervention system using drill pipe and a retainer valve block, following disconnection of a collapsed/buckled drilling riser. connector would be advisable (separate control umbilical from the surface). The use of a SSTT would be even better provided early mobilisation was possible. The topside equipment will comprise a typical STT/flowhead, hard piped to the flare. Plan B is not perfect. When the operating semi is lost after a kick, together with the drilling riser (as per the Deepwater Horizon), hydrocarbons will escape until another semi can be mobilised. But compared with the current nightmare, it is the blink of an eye. Where only the drilling riser is lost, the remedial action will be rapidly implemented. Summary All rig crews and operator personnel are under pressure from the MBAs in respect of costs. Modern deepwater semis are expensive tools and tripping (for any reason) in deepwater is an expensive activity -`waiting for cement paste to harden is an irritation - testing Portland cement paste is unnecessary'. I can hear them now. Time for them to listen and reflect. Some of the Macondo answers may be found in this brief piece - perhaps none at all. Perhaps this piece is just a small, irrelevant piece of insulation colliding with a NASA shuttle wing. OE Ian Fitzsimmons, a regular contributor to OE, is an independent consultant with more than 30 years' offshore industry experience. He has worked for major operators around the world and major subsea hardware/drilling equipment contractors, and has extensive due diligence and expert witness experience. He was chief engineer for RJ Brown & Associates in London. The views expressed in this article are the author's own and do not necessarily reflect OEs position. 26 OFFSHORE ENGINEER I july 2010 http://oe.oilonline.com 0 Bud's Offshore Energy (BOE) Energy Production, Safety, Pollution Prevention, and More Deep Water is Not the Problem http://budsoffshoreenergy wordpress.coml2010/07/27/deep-water-is-not-the-problem/ July 27, 2010 by offshoreenergy In the Gulf of Mexico, deepwater drilling is more risky because that is where the high - rate wells are, not because the water is deep. • Water depth had little to do with the well integrity problems at Macondo. Similar errors in planning and execution would have yielded similar results in any water depth or on land. Has Montara already been forgotten? • Subsea BOP stacks have a much better performance record than the surface stacks used in shallow water drilling (more on this later in the week). • Historical data indicate that blowouts occur less frequently in deep water, not more frequently (more to follow). • Obviously, blowouts involving high -rate wells are likely to do more damage. • This applies regardless of the water depth. You can reduce the spill risk by prohibiting drilling in the areas with the highest production potential, but that wouldn't be very sound energy policy and you won't find many buyers for the leases. • It is safer to conduct intervention and capping operations on subsea wells. Regulators would not even allow surface capping to be considered at Montara because of the high risk to workers. The subsurface ROV work is perhaps the biggest Macondo success story. • If the Macondo well was in shallow water (with the wellhead above the water surface), and well integrity concerns precluded a risky surface capping operation, how would the flow have been contained and collected? • Other things being equal, the environmental risk is less at deepwater locations which tend to be farther from shore. Water depth is just one well planning consideration. Abnormal pressures and temperatures, shallow gas, hydrogen sulfide, ice, permafrost, storms, currents, extended reach targets, and horizontal completions are some of the others. To prevent another Macondo, in the US or anywhere else in the world, we need to focus our attention on the 3 categories of issues listed below. These issues are important in all water depths and in all environments. 1. Well integrity including design, construction, barriers, verification, and • monitoring. • 2. BOPE performance and reliability under all conditions. 3. Capping, containing, and collecting oil in the event of a blowout. Deep water is not the problem — Update September 28, 2010 by offshoreenergy As previously posted (July 27, 2010), deep water had little to do with the well integrity problems and other contributing factors leading to the Macondo blowout. The Bly (BP) report further confirms this position. Of the eight key findings in the Bly report (listed below), only number 4 could be considered to be more of a deepwater issue. The BOP failures may also have been influenced by deepwater factors. However, as previously noted, surface BOPs have a much higher failure rate than subsea stacks. While the Montara blowout was in relatively shallow water, slight variations of findings 1 through 4 were the primary causes of that accident. Is BP findings: 1. The annulus cement barrier did not isolate the hydrocarbons. 2. The shoe track barriers did not isolate the hydrocarbons. 3. The negative -pressure test was accepted although well integrity had not been established. 4. Influx was not recognized until hydrocarbons were in the riser. 5. Well control response actions failed to regain control of the well. 6. Diversion to the mud gas separator resulted in gas venting onto the rig. 7. The fire and gas system did not prevent hydrocarbon ignition. 8. The BOP emergency mode did not seal the well. Possibly related posts: (automatically generated) • Nobody Could Have Predicted • Three Ingredients of Disaster • Open Call for Assistance in Deepwater Case is • Posted in accidents, well control incidents I Tagged drilling, safety, accidents, blowouts, well control, offshore oil, Montara, Deepwater Horizon, Gulf of Mexico, macondo, BOE, bp, bly, Deepwater I 1 Comment One Response 1. on September 28, 2010 at 7: 59 am I Reply I=Colin Leach The Bly report (page 70) noted some significant "inconsistencies" in the operation of the float shoe/float collar (see below). This is so similar in nature to the "inconsistencies" in the 9 5/8" cement job on the Montara well to be scary. The bottom line is that both disasters could have been prevented if these "inconsistencies" had been recognised and additional barriers placed above the float collar. In fact even if there are no "inconsistencies", the placing of an additional barrier or so seems like an exceptionally prudent step, which would not take that much time or effort. Except from Bly (Page 70) "Based on information that Weatherford supplied to the investigation team, the float collar conversion should have occurred with a differential pressure between 400 psi to 700 psi. Using the Weatherford flow equation, this would have required a flow rate of 5 bpm to 7 bpm. When the conversion is completed, the two check valves can move into a closed position, which should prevent flow up the casing. When circulation was attempted on this well, either the float collar or the reamer shoe was plugged. The rig crew made nine attempts to establish circulation by increasing pressure on the casing. Circulation was finally established with 3,142 psi. It was not clear to the investigation team whether this pressure converted the float collar, or if it simply cleared a plugged shoe. If the shoe was plugged, the float conversion may not have occurred. Circulation rates throughout the rest of cement placement and displacement did not exceed 4.3 bpm, which was below the specified conversion flow rate. The second issue concerned another event that may have affected the float collar. This occurred when the Weatherford bottom wiper plug landed on the float collar. This wiper plug separated the cement from the fluids ahead of the wiper plug to prevent cement contamination. When the wiper plug landed on the float collar, pressure was applied to a burst disc in the wiper plug, which allowed circulation to continue. This burst disc was designed to rupture between 900 psi and 1,100 psi. The burst disc did not rupture until 2,900 psi was applied, and cement displacement continued." • • The Tress ad �-]Journal E E kGY THE VOICE Of ENERGY IN SCOTLANi Macondo, Montara, Gullfaks C - unacceptable By Jeremy Cresswell Published: 06/12/2010 http://energy. pressand i oumal. co. uk/Article. aspx/2025 770/?U serKey= One wonders how many other "accidents" are waiting to happen, especially offshore More Pictures • I had intended to pay a lot of attention to the Atlantic Frontier in this issue of Energy ... as I generally do at this time of year. However, with two major oilfield disasters, a serious North Sea near miss and milestone research by The Robert Gordon University on behalf of OPITO on international health and safety standards across upstream petroleum, safety dominates this issue and the Atlantic Frontier is postponed. I make no apology, especially given the damning observations made over the past couple of weeks or so by senior figures/bodies engaged with investigating the very serious Macondo (US Gulf of Mexico), Montara (Timor Sea) and Gullfaks C (Norwegian North Sea) incidents, all of which took place within the space of barely a year, albeit Montara started to unravel some months earlier. Indeed, given the backgrounds to each, the unravelling process started a long time previous with all three ... in the procedures and practices that paved the way to the inevitable. One wonders how many other "accidents" are waiting to happen, especially offshore, whether on rigs or production installations. I am struck by the severity of the comments to emerge from the inquiry process regarding each of the three. Montara The inquiry report states that the manner in which the operator PTTEPAA operated the Montara oilfield "did not come within a `bull's roar' of sensible oilfield practice". "The blow-out was not a reflection of one unfortunate incident, or of bad luck. What happened with the H1 Well was an accident waiting to happen. The company's systems and processes were so deficient and its • key personnel so lacking in basic competence that the blow-out can properly be said to have been an event waiting to occur," says the report. "Indeed, during the course of its public hearing, the inquiry discovered that not one of the five Montara wells • currently complies with the company's well construction standards. So poor has PTTEPAA's performance been on the Montara oilfield, the Inquiry considers it is imperative that remedial action be instituted." As for the regulator's role, the following speaks volumes. "The approach taken by the Northern Territories Department of Resources in part reflective of a profound misunderstanding of what is required of a regulator under the modern-day objective (as opposed to prescriptive) approach to regulatory oversight." "The Inquiry has been struck by the substantial divergence within Australia in regulatory practices, with all jurisdictions purporting to follow the objective, non -prescriptive approach to regulation." In my view, this shows how little attention may have been paid internationally to the outcomes of the UK's Piper Alpha Inquiry 21 years ago. Macondo This was and remains the headline grabber. Hardly surprising given the deaths and the fact that the BP - operated Macondo-1 well was being drilled just a few miles off the US coast and not out of Western sight and Western mind in the Timor Sea. As we report on Page Three, Bill Reilly, a co-chair of the Commission of Inquiry into the loss of the Deepwater Horizon drilling rig, which is due to report next month, calls for a "top -to -bottom" reform within the three companies at the heart of this affair: BP, Halliburton and Transocean. He talks of a "sweep of bad decisions" and a culture of complacency — indeed that there was "not a culture of safety on that rig". • Interestingly, Reilly notes that the investigators didn't rule out a cost dimension (bear in mind BP has a reputation for cost-cutting zeal) but that they weren't prepared to attribute mercenary motives to the men killed on the rig and who therefore cannot speak for themselves. Reilly didn't mince his words and perhaps more than hinted that Macondo was not necessarily a one-off, rather it might indicate something larger, a "systemic problem in the oil and gas industry". In my view, there is certainly a systemic problem in the US and I believe this is reflected in the hasty reorganisation of the regulatory machinery that supposedly governs the American industry and ensures it conducts its business safely. Gullfaks C Turning to Gullfaks C, I, like many others, nurse a belief that Statoil is among the most responsible players in the offshore industry. But is that faith in fact misplaced? Perhaps. For sure, the Norwegian authorities are not at all happy with Statoil right now, not given the remarks made by the Petroleum Safety Authority last month. As our headline states on Page Five, only luck saved Statoil from a major disaster in the North Sea just one month after the Deepwater Horizon blow-out. The incident, which led to an evacuation of the Gullfaks C platform after loss of well control, was judged by the PSA to be "very serious". Indeed I would argue that the Gullfaks C incident is especially serious as it was allowed to happen against • the backdrop of probably the most rigorous national safety regime anywhere. The PSA report tells just how close Statoil came to disaster. "Only chance averted a sub -surface blowout and/or explosion, and prevented the incident from developing into a major accident. "Serious deficiencies have been identified in Statoil's planning of this Gullfaks well and in management checks that the work was being done in an acceptable manner." The PSA and union leaders have now warned of a maintenance backlog in Norwegian operations. That is unacceptable. And, by the way, it is unacceptable in the UK sector too. It is clear that even Statoil has been dragging its heels given that the PSA has questioned why measures implemented after a gas blow-out on the Snorre platform in 2004 had failed to prevent the latest incident and gave Statoil until this month to come up with a plan. Montara, Macondo, Gullfaks C. What next from an industry that asks us to trust it? However, as the Aberdeen Business School at Robert Gordon University's research on behalf of OPITO tells, there appears to be a genuine will within the upstream sector worldwide to at the very least establish a decent set of baseline safety and environment standards. Both OPITO and ABS are to be congratulated on this pathfinding work and I hope that both will be able to expand and build on it. There will be much more on safety in the January edition of Energy. Speak next year. • Read more: http://energy.pressandjournal.co.uk/Article.aspx/2025770/?UserKey=#ixzzlG8GhWnxR 0
