TPH Macondo Blowout Conference Call Dan Pickering, Dave Pursell David Heikkinen, TPH Research Team
May 12, 2010
DAN PICKERING: Good morning. Thanks for joining us. First off, let me direct you to the TPH website to access some slides we will be using for this call today. You can find them at the following address: www.tudorpickering.com/pdfs/TPH.Well.Slides.pdf If that doesn’t work for you, simply email Sarah Farnie at
[email protected] or call her at 713‐333‐ 2967 and she will get you a copy. Our goal for today is to discuss what we think are the most likely scenarios that caused the Macondo well blowout in the Gulf of Mexico on April 20th. We realize there have been numerous sellside calls that have discussed the incident. Until yesterday, we haven’t felt that there was enough information to properly assess what MIGHT have happened on the rig. But, we got significantly more information via the prepared Senate testimony by BP, Transocean and Halliburton. Together with the information we’ve pieced together from our discussions with industry contacts, we now think that we can make a much more educated guess about the events. Times like these are when I am very thankful to have a research team staffed with folks that have technical and engineering backgrounds and industry experience. It makes piecing together the Macondo jigsaw puzzle much easier…and please note I said easier..not easy. Obviously, the stock market is trying desperately to understand the accident in order to assess liability – those liable will have big bills to pay..while those not liable will just have a reputational black eye (along with the entire industry).
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Please note, during this call..we are not trying to address when the spill will stop. We are not specifically trying to assess liability. Inherently, our view is that, in the absence of negligence, the ultimate liability and responsibility is that of the E&P company – in this case BP, Anadarko, and Mitsui. That is the way the business works – the way it has worked for decades..onshore, offshore, deepwater, etc. A service company, whether rig contractor, cement provider, BOP provider, etc..is indemnified by the customer for what happens as the well is drilling. There is ample documentation of this type of indemnification in RIG’s recent 10‐Q disclosure…we encourage you to read it..it will not be the focus of our call today. Nor have we, or will we, try to assess whether there was negligence by anyone associated with this blowout. We simply CAN’T know. Our business is making educated guesses. My personal view (Dan Pickering) is that it is unlikely that parties will be able to prove negligence. Doesn’t mean it didn’t occur, but proving it will be something for lawyers and lawsuits. My own personal view is also that there is a HIGH likelihood that the examination that is coming will highlight that MISTAKES were made. It is unequivocal that there were equipment failures. A blowout can’t occur without the failure of safety systems..like the BOP. However, it is important to remember that well problems, accidents, error and failures do not necessarily mean liability in the oil patch. Well problems, accidents, error and failures do not necessarily mean negligence. Something went horribly wrong. Sadly wrong. The market has taken about $60B out of the market caps of BP, APC, RIG, HAL and CAM. That feels excessive to us. We are buyers on the margin of these stocks..while we recognize that sentiment is horrible and the unknowns are bigger than the knowns. Also, you will note that Dave Pursell and I are choosing our words carefully here. If it sounds like we are reading a script…that’s because we are. Everything about this situation is intense and we want to try and be as clear as possible – conveying what we THINK could have happened and how that could have occurred. Frankly, we hope that this discussion will encourage more answers from the companies involved..as there are still more questions than answers.
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With that preamble, let me turn it over to Dave Pursell and remind you of the slides we are going to use: www.tudorpickering.com/pdfs/TPH.Well.Slides.pdf Dave Pursell, David Heikkinen and myself and our research team will be available to answer questions at the conclusion of our prepared remarks…we know that the market will open during this discussion and we’ll lose some of you..but let’s forge ahead.
DAVID PURSELL: We are basing our analysis based on what we know from the Senate testimony yesterday, media reports, and talking to industry about this for the last two weeks…and there are a lot of pertinent details yet to be discussed or confirmed We are not trying to assess blame in this analysis. Rather, we are attempting to bracket the potential causes to start to understand what happened in the days and hours leading up to the April 20th explosion. We think there are 3 possible scenarios for what happened. In all three scenarios, multiple problems had to occur. We think there had to be a combination of bad luck, physical problems with the well and human and/or procedural error. Something went wrong for hydrocarbons to enter the well, something went wrong when they weren’t detected quickly and something went wrong when they weren’t contained. We know there had to have been a downhole problem because gas and, eventually, oil got into the wellbore (this was either a failed cement job or collapsed casing). There are methods and procedures in the drilling industry to identify when a well is taking a kick – when gas has gotten into the well and pressure is building up. These somehow had to have been missed. Finally, the BOP was unable to contain the blowout…so it did not function as intended.
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We’ll address each of the three scenarios we think were possible, but first let’s discuss what we know about the configuration of the well. This is based on the schematics from Halliburton and Transocean’s senate testimony yesterday, as well as information we’ve gathered from conversations with deepwater industry folks from E&P and service companies. We have received no information from any public company which was material or non‐public. Now, let’s start piecing together the events – refer to Schematic #1 Because the well was deep, there are multiple strings of casing. Each one is cemented in place and drilling continues in with a smaller drill bit. Drilled well to 18,360ft…where it encountered a lost circulation zone (which is essentially a formation that steals drilling mud, making it hard and unsafe to continue drilling lower)…. Drilled with 14.3ppg drilling mud which puts the formation pressure at ~13,000psi. Controlled lost circulation zone, we are assuming with standard lost circulation materials. Spent more than one week testing potential hydrocarbon bearing zone(s) with open hole logs, fluid samples, and rotary sidewall cores. The BOP’s were tested on April 10th and again on April 17th…we have not seen the results of those tests..although Transocean testimony indicated the BOPs were “functional” after the tests. Ran a 9 7/8 x 7” tapered casing string to just over 18,300ft. This is important because we now know that there was a continuous “long string” from the top of the well to the production zone. We will call this the “production casing” going forward. Because there was a lost circulation zone near the bottom of the casing, the cement mixture was reportedly Nitrogen‐based to increase chance that the cement would fill the casing annulus (and was not lost to the thief zone). The
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decision and authority to use this type of mud would have been made by BP, probably in consultation with Halliburton. Halliburton’s testimony indicates only 51bbls of cement slurry was pumped so only a small fraction of the 7” production casing would have been covered with cement…even if the cement job was pumped as designed and there was no loss to the thief zone. Note: this provides approximately 1,000ft of cement coverage from the bottom of the wellbore at 18,360’ up 1000’ or so to around 17,360’ The remainder of the production casing annulus is left open with no cement (per industry practice). But note that this does create an open “back side” of the well…which you can see in both our Schematic 1 and in both HAL and RIG’s schematics. The cement did not move up high enough to connect or cement against the prior string of 9 7/8” casing at 17,168’. After cementing the production casing or “long string”, the casing seal assembly was set in the casing hanger/wellhead, which was provided by Drill‐quip. In other words, the top of the casing is connected into the wellhead to make it one sealed system. Now move to Schematic #2. A positive pressure test was conducted to “demonstrate the integrity of the production casing string”…or make sure that there were no leaks at the top or the bottom of the string The results of this test have not been disclosed (did it pass?) and BP was vague in yesterdays hearings. All that Halliburton said was “the results of the test were reviewed by the well owner and the decision was made to proceed with the well program”. Was the data transmitted off the rig before the accident? This procedure would have tested the casing and the cement around the bottom of the casing shoe…not necessarily the quality of the cement across the hydrocarbon bearing zone. The next step was to ensure the casing seal assembly in the wellhead (the top of the casing) was installed properly and a negative pressure test was performed. HAL recorded the drillpipe pressures. Again, the results of this test have not been disclosed. On this topic, HAL’s testimony says “Halliburton’s cementing personnel
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were advised by the drilling contractor that the negative pressure test had been completed”. With the long string of production casing in place and the 51bbls of cement pumped across the formation and up perhaps as high as 1000’, we now have a large open annulus between the production casing and previously cemented casings…this runs all the way up from around 17,000 feet to the top of the wellhead on the ocean floor. Remember, this is what we are calling the “back side” and we’ve pointed to it on our Schematic 1. Prior to running the final cement plug at 8,000ft to temporarily abandon the well, BP circulated out heavy drilling mud (14.3ppg) and replaced it with 8.4ppg seawater. Often, the final cement plug is set before replacing the drilling mud with sea water. According to press reports, drilling rig personnel claim that BP received a waiver from the MMS to change the order of the procedure. We haven’t gotten anyone at the MMS to confirm this, but assume that is correct. We don’t know, but suspect that this procedure might have been done to allow for faster re‐entry of the well when the operator returned to put the well back into production. This would have avoided the time of pumping out drilling mud on reentry. It is also worthwhile to point out that a workboat was offloading drilling mud from the rig when the blowout occurred. More on that in a second. Note also that at this point, it appears there had not been any actual test of the cement job. The positive and negative pressure testing are being done to make sure that the top and the bottom of the production casing are “tight”, but there was no backside test or cement bond logs or temperature logs done..so the integrity of the cement job across the formation had not been determined at this point. What we also don’t know is what actual procedure was being conducted at the time of the blowout. From various witness accounts, there was drill pipe in the hole – so there was likely some sort of circulation – but we don’t know if that
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circulation was happening with drill pipe down into the well / production casing string…or if the drill pipe was simply in the riser. Now let’s move on to our 3 potential scenarios for the blowout – Schematic 3 We label this scenario “backside blow out”. It would occur with a cement failure which would allow oil and gas to migrated from ~18,100 ft up the casing annulus and collect below the casing seal assembly (top of the casing) in the wellhead…just below the BOP…only 5,000ft below the rig. In this scenario, the casing seal assembly failed when the pressure in the annulus, below the seal assembly, became too great and the casing seal assembly failed. The pressure below the seal assembly, from a natural gas inflow, could have been 8,000psi or higher (reservoir pressure is ~13,000psi) and the pressure above the seal assembly was ~2,500psi….the weight of the seawater. If the seal assembly failed with this pressure differential, the failure could have been catastrophic. Almost instantly putting a large, violent upward pressure on the column of seawater in the drilling riser and quickly causing 1) the reported water shooting above the drilling derrick and 2) the lack of significant warning. Easy to see how the well could quickly get away from rig personnel. A common theme from talking to eyewitness accounts has been “there was no warning”. This scenario does not explain (and therefore creates questions we still have) about the following: 1. why the cement job did not completely seal off the oil and gas interval. 2. why the BOP did not shut‐off the flow. The BOP sits on top of the wellhead and catastrophic failure in the wellhead may have damaged the BOP (imagine pieces of metal from the wellhead being blown into the BOP and “gumming up the works”). Even so, both the annular and shears would have failed. Was the pipe being blown out of the hole so the BOP could not close properly? Did the shear rams attempt to close on a tool joint? We simply don’t know.
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3. Why a pressure buildup in the annulus went undetected? The wellhead contains a port to monitor annular pressure…was it connected? Was the pressure gauge working and not noticed/addressed by rig personnel? There has been much discussion that the drilling mud was replaced with lighter seawater before setting the final cement plug(s). In this scenario, the plug would not have controlled a backside blowout as shown in Schematic #4. The plug is designed to be a level of protection for flow UP the casing…not in the annulus. Scenario 2 A second scenario involves the potential for casing collapse…as shown in schematic #5. This would most likely have occurred when the drilling mud was being circulated out of the production casing and being replaced with seawater. As the seawater replaced the heavy mud, the pressure in the bottom of the well would have been ~3,000 psi less than the formation pressure outside the casing. As the casing was still unperforated, this would have created collapse force on the outside of the casing. We are not sure of the casing grade specified…but certainly the casing had a collapse rating of well above 3,000psi. It is our understanding the casing was made by Sumitomo and the RIG testimony indicated it was run in the hole by Weatherford. Assuming the casing had a defect (either from the manufacturer or in handling) and did collapse across the oil and gas bearing formation, this could have created a large, sudden inflow of oil and gas into the production casing. This scenario does not explain 1. Why did the casing collapse? 2. Why was the kick not detected earlier? A gas bubble under pressure (at 18,000ft) if fairly small but rapidly increases in size as it approaches the surface (you scuba divers out there understand this). This expansion forces more drilling fluid out of the well and into the mud pits than is being pumped into the well. Why was this not detected sooner? Were safety
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system all hooked up and functioning? Was the offloading of cement onto the work boat diverting attention away from rig operations? 3. Why did the BOP not work? With drillpipe in the hole circulating out seawater, the BOP annular and ram preventers should have functioned. Perhaps pipe was blowing out of the hole so quickly that the rams could not “grab on”..or perhaps the shears went up against a tool joint in the BOP and couldn’t close..or perhaps the BOP just simply didn’t work (even though it was tested several days before the incident). Scenario 3‐ Shown in schematic #6 – this scenario would have occurred if the mud had already been displaced in the wellbore and the crew was then clearing the riser. This would have involved setting a plug in the wellhead (below the BOP) while the seawater was circulated out of the drilling riser….prior to setting the final cement plug. This scenario would have isolated the casing from the lower hydrostatic pressure in riser. Once the plug was pulled, either a gas bubble had built up below the plug…due to collapsed pipe or failed cement job. This scenario is not materially different than Scenario 1 ‐ the gas kick would have been severe and sudden as the pressure had time to build while the plug was set. However, this may offer a plausible scenario for why the BOP did not close as there may have been a landing tool at the bottom of the drill string that would have been in/near the blowout preventer shortly after the plug was removed. The BOP rams may not be equipped to shear a large diameter, thick walled landing tool. This scenario still does not explain why a buildup in pressure was not recorded, or why the casing/cement failed.
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Based on our review of these scenarios, there are a few things we would like to ask the companies involved. More detail around the lost circulation and the seemingly small amount of cement applied to the production casing string. Given the tough wellbore conditions (lost circulation zone at the bottom of the casing string), was there adequate testing of the cement and was a cement bond log planned? More detail in the specific well operations between the cementing and the blowout (i.e, was seawater circulated to the mudline….or to 8,000ft). Was there a landing tool on the drill string and was it close to the BOP? Was all safety equipment (on rig and sub‐sea) hooked up and functioning just preceding the accident? Data on the BOP test April 10 and April 17? Was there indication that the backside blowout scenario occurred? We think that this information will get pieced together over the next few months. Retrieval of the BOP will be an important component of answering which of the scenarios we described might have occurred. At this time, we’ll take questions.
DISCLAIMER
Copyright 2010, Tudor, Pickering, Holt & Co. Securities, Inc. This information is confidential and is intended only for the individual named. This information may not be disclosed, copied or disseminated, in whole or in part, without the prior written permission of Tudor, Pickering, Holt & Co. Securities, Inc. This communication is based on information which Tudor, Pickering, Holt & Co. Securities, Inc. believes is reliable. However, Tudor, Pickering, Holt & Co. Securities, Inc. does not represent or warrant its accuracy. This message should not be considered as an offer or solicitation to buy or sell any securities. Analyst Certification: We, Dan Pickering, Dave Pursell, Jon Mellberg, Jeff Tillery, Joe Hill, David Heikkinen, Mike Jacobs, Becca Followill, Brandon Blossman, Brian Lively, Brad Pattarozzi, Jessica Chipman, Max Barrett, George O’Leary and Oliver Doolin do hereby certify that, to the best of our knowledge, the views and opinions in this research report accurately reflect our personal views about the company and its securities. We have
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not nor will we receive direct or indirect compensation in return for expressing specific recommendations or viewpoints in this report. Important Disclosures: The following analysts were involved in creating or supervising the content of this message; Dan Pickering, Dave Pursell, Jon Mellberg, Jeff Tillery, Joe Hill, David Heikkinen, Mike Jacobs, Becca Followill, Brandon Blossman, Brian Lively, Brad Pattarozzi, Jessica Chipman, Max Barrett, George O’Leary and Oliver Doolin. One or more of these analysts (or members of their household) have a long stock position in Allis-Chalmers Energy, American Oil & Gas, Anadarko Petroleum Corp., Antares Energy, Bristow Group, Carbo Ceramics, Chesapeake Energy, Complete Production Services, ConocoPhillips, Copano Energy, Deep Down, Inc., Dynegy, El Paso, El Paso Pipeline Partners, Endeavour International Corp., Enterprise Products Partners, EXCO Resources, ExxonMobil, Far East Energy Corp., Halliburton, Hugoton Royalty Trust, iShares MSCI Brazil Index, Key Energy Services, Kodiak Oil & Gas, Magellan Midstream Partners, McMoRan Exploration, Mirant Corp., Occidental Petroleum, Omni Energy Services, ONEOK Partners, Pacific Rubiales, Petrohawk Energy Corp., Plains All American, Plains Exploration & Production, Reliant Energy, Southern Co., Southwestern Energy, Spectra Energy, Spectra Energy Partners, T-3 Energy Services, Tag Oil Ltd., Total SA, Transatlantic Petroleum, Weatherford, Williams Companies, Williams Partners and ExxonMobil. One or more of these analysts (or members of their household) have an Interoil Corp. short put position. One or more of these analysts (or members of their household) have an Interoil Corp. short call position. Analysts’ compensation is not based on investment banking revenue and the analysts are not compensated by the subject companies. In the past 12 months, Tudor, Pickering, Holt & Co. Securities, Inc. has received investment banking or other revenue from Berry Petroleum, Boardwalk Pipeline Partners, Brigham Exploration, Cobalt International, Concho Resources, Constellation Energy, Direct Drive Systems, El Paso Pipeline Partners, Enerplus Resources, Gastar Exploration, Legacy Reserves, Magellan GP, LLC, Magellan Midstream Partners, Mariner Energy, Newfield Exploration, NuStar Energy, ONEOK, Petrohawk Energy, Plains Exploration & Production, Range Resources, Regency Energy Partners, Rosetta Resources, SandRidge Energy, Inc., Stone Energy, Superior Well Services, Targa Resources, Western Gas Holdings, and Williams Companies. In the next three months we intend to seek compensation for investment banking services from the companies mentioned within this report. This communication is based on information which Tudor, Pickering, Holt & Co. Securities, Inc. believes is reliable. However, Tudor, Pickering, Holt & Co. Securities, Inc. does not represent or warrant its accuracy. The viewpoints and opinions expressed in this communication represent the views of Tudor, Pickering, Holt & Co. Securities, Inc. as of the date of this report. These viewpoints and opinions may be subject to change without notice and Tudor, Pickering, Holt & Co. Securities, Inc. will not be responsible for any consequences associated with reliance on any statement or opinion contained in this communication. This communication is confidential and may not be reproduced in whole or in part without prior written permission from Tudor, Pickering, Holt & Co. Securities, Inc. For detailed rating information, distribution of ratings, price charts and other important disclosures, please visit our website at http://www.tudorpickering.com/Disclosure/ or request a written copy of the disclosures by calling 713-333-2960. It should be noted that this presentation and comments depict TPH’s assessment of possible scenarios
that might have occurred on the Macondo blowout. They are not facts and should not be interpreted as such. [Type text]