Is BP's 'top kill' on the oil well going to work?
Discussion
I think what is becoming a increasingly large issue is just how much BP was wrong in terms of how large the spill is. It started with a estimation of 5,000 Barrels of oil a day but now we find out it's more likely to be between 25,000 and 30,000 barrels. That's 6 times larger!
I really wonder what BP is thinking. When you are in this type of situation you simply cannot attempt to hide the size of your mistake. Was it incompetence? Or did they really think they could hide the size of the spill?
http://www.nytimes.com/2010/06/12/us/12spill.html?...
"A government panel of scientists released findings on Thursday saying that before the stricken well’s riser pipe was cut on June 3, a step needed to fit a containment cap over the leak, crude oil was being released at a rate of 25,000 to 30,000 barrels a day. That range was a substantial increase from the panel’s previous estimate of 12,000 to 19,000 barrels daily, which in turn far exceeded the early 5,000-barrel figure that the Coast Guard proposed, and BP eventually deferred to, for weeks after the accident.
These larger estimates suggest that an amount equivalent to the Exxon Valdez disaster could be flowing into the Gulf of Mexico every 8 to 10 days. "
I really wonder what BP is thinking. When you are in this type of situation you simply cannot attempt to hide the size of your mistake. Was it incompetence? Or did they really think they could hide the size of the spill?
http://www.nytimes.com/2010/06/12/us/12spill.html?...
"A government panel of scientists released findings on Thursday saying that before the stricken well’s riser pipe was cut on June 3, a step needed to fit a containment cap over the leak, crude oil was being released at a rate of 25,000 to 30,000 barrels a day. That range was a substantial increase from the panel’s previous estimate of 12,000 to 19,000 barrels daily, which in turn far exceeded the early 5,000-barrel figure that the Coast Guard proposed, and BP eventually deferred to, for weeks after the accident.
These larger estimates suggest that an amount equivalent to the Exxon Valdez disaster could be flowing into the Gulf of Mexico every 8 to 10 days. "
Should oil companies recompense governments for oil that they waste? The X million gallons that has spilled into the Gulf was an asset of the US Govt and is would have been worth a significant amount of money. If it is spilled should the spiller pay for it (as well as the clean up, etc, etc)?
Just a thought.
Just a thought.
Ayahuasca said:
Should oil companies recompense governments for oil that they waste? The X million gallons that has spilled into the Gulf was an asset of the US Govt and is would have been worth a significant amount of money. If it is spilled should the spiller pay for it (as well as the clean up, etc, etc)?
Just a thought.
they still have it and if anything its easier for the usa to get as they can pick it up off the beach rather than having to drill for it...Just a thought.
Tadite said:
I think what is becoming a increasingly large issue is just how much BP was wrong in terms of how large the spill is. It started with a estimation of 5,000 Barrels of oil a day but now we find out it's more likely to be between 25,000 and 30,000 barrels. That's 6 times larger!
I really wonder what BP is thinking. When you are in this type of situation you simply cannot attempt to hide the size of your mistake. Was it incompetence? Or did they really think they could hide the size of the spill?
I get that at my work, a large american bank, never admit to a customer when a cockup has occured, brush it under the carpet or minimise it. I'm in technical and the people who are telling me this are always in relationship management or sales where they don't care about wrong or right but just the botom $ for the company, sorry, meant their own bonus. It's pandemic.I really wonder what BP is thinking. When you are in this type of situation you simply cannot attempt to hide the size of your mistake. Was it incompetence? Or did they really think they could hide the size of the spill?
Andy
Ayahuasca said:
Should oil companies recompense governments for oil that they waste? The X million gallons that has spilled into the Gulf was an asset of the US Govt and is would have been worth a significant amount of money. If it is spilled should the spiller pay for it (as well as the clean up, etc, etc)?
Just a thought.
Nigeria would be pretty rich under that system.Just a thought.
hairykrishna said:
Ayahuasca said:
Should oil companies recompense governments for oil that they waste? The X million gallons that has spilled into the Gulf was an asset of the US Govt and is would have been worth a significant amount of money. If it is spilled should the spiller pay for it (as well as the clean up, etc, etc)?
Just a thought.
Nigeria's corrupt elite would be even richer under that system Just a thought.
Edited by Magog on Saturday 12th June 00:01
hairykrishna said:
Ayahuasca said:
Should oil companies recompense governments for oil that they waste? The X million gallons that has spilled into the Gulf was an asset of the US Govt and is would have been worth a significant amount of money. If it is spilled should the spiller pay for it (as well as the clean up, etc, etc)?
Just a thought.
Nigeria would be pretty rich under that system.Just a thought.
I think the back handers are a force too strong to resist however!
Ayahuasca said:
Should oil companies recompense governments for oil that they waste? The X million gallons that has spilled into the Gulf was an asset of the US Govt and is would have been worth a significant amount of money. If it is spilled should the spiller pay for it (as well as the clean up, etc, etc)?
Just a thought.
I think BP are on the hook for royalty payments regardless of whether the oil makes its own way to market or opts to ride in a tanker...Just a thought.
http://news.bbc.co.uk/1/hi/business/10318547.stm
The explanation given is they are less confident BP can pay back their debts. Which is stupid, oil compnay=pretty much endless cash supply.
The explanation given is they are less confident BP can pay back their debts. Which is stupid, oil compnay=pretty much endless cash supply.
dpbird90 said:
http://news.bbc.co.uk/1/hi/business/10318547.stm
The explanation given is they are less confident BP can pay back their debts. Which is stupid, oil compnay=pretty much endless cash supply.
Fortunately having an endless supply of money means that their credit rating is pretty irrelevant. The explanation given is they are less confident BP can pay back their debts. Which is stupid, oil compnay=pretty much endless cash supply.
So what if borrowing money is a little harder for them? That's like telling an apple tree that the price of granny smiths are going up.
Ross1988 said:
The relief wells are pretty certain to work. Just another few weeks at worst. But for what ever reason, if they fail, then I have no idea.
If gas migrates up the outside of the casing (as it's starting to do) causing considerable sea-bed 'cratering' before the relief well is drilled, then there could be the situation where nothing will stop it - until the reservoir is fully depleted to the sea. That's the 'nightmare' scenario.jshell said:
Ross1988 said:
The relief wells are pretty certain to work. Just another few weeks at worst. But for what ever reason, if they fail, then I have no idea.
If gas migrates up the outside of the casing (as it's starting to do) causing considerable sea-bed 'cratering' before the relief well is drilled, then there could be the situation where nothing will stop it - until the reservoir is fully depleted to the sea. That's the 'nightmare' scenario.Extinction for a lot of sea life... Sure.
But I think humans will manage without cod for a bit.
If you're interested....
Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Mr. Tony Hayward
Chief Executive Officer BP PLC
1 St. James's Square London SW1Y 4PD United Kingdom
Dear Mr. Hayward:
We are looking forward to your testimony before the Subcommittee on Oversight and Investigations on Thursday, June 17, 2010, about the causes of the blowout of the Macondo well and the ongoing oil spill disaster in the Gulf of Mexico. As you prepare for this testimony, we want to share with you some of the results of the Committee's investigation and advise you of issues you should be prepared to address.
The Committee's investigation is raising serious questions about the decisions made by BP in the days and hours before the explosion on the Deepwater Horizon. On April 15, five days before the explosion, BP's drilling engineer called Macondo a "nightmare well." In spite of the well's difficulties, BP appears to have made multiple decisions for economic reasons that increased the danger of a catastrophic well failure. In several instances, these decisions appear to violate industry guidelines and were made despite warnings from BP's own personnel and its contractors. In effect, it appears that BP repeatedly chose risky procedures in order to reduce costs and save time and made minimal efforts to contain the added risk.
At the time of the blowout, the Macondo well was significantly behind schedule. This appears to have created pressure to take shortcuts to speed finishing the well. In particular, the Committee is focusing on five crucial decisions made by BP: (1) the decision to use a well design with few barriers to gas flow; (2) the failure to use a sufficient number of "centralizers" to prevent channeling during the cement process; (3) the failure to run a cement bond log to evaluate the effectiveness of the cement job; (4) the failure to circulate potentially gas-bearing
Mr. Tone Hayward June 14. 2010 Page 2
drilling muds out of the well: and (5) the failure to secure the wellhead with a lockdown sleeve before allowing pressure on the seal from below., The common feature of these five decisions is that they posed a trade-off between cost and well safety.
Well Design. On April 19. one day before the blowout. BP installed the final section of steel tubing in the well. BP had a choice of two primary options: it could lower a full string of "casing' from the top of the wellhead to the bottom of the well, or it could hang a `liner" from the lower end of the casing already in the well and install a "tieback" on top of the liner. The liner-tieback option would have taken extra time and was more expensive. but it would have been safer because it provided more barriers to the flow of gas up the annular space surrounding these steel tubes. A BP plan review prepared in mid-April recommended against the full string of casing because it would create "'an open annulus to the wellhead" and make the seal assembly at the wellhead the "only barrier" to gas flow if the cement job failed. Despite this and other warnings, BP chose the more risky casing option. apparently because the liner option would have cost $7 to S10 million more and taken longer.
Centralizers. When the final string of casing was installed, one key challenge was making sure the casing ran down the center of the wellbore. As the American Petroleum institute's recommended practices explain. if the casing is not centered, ''it is difficult, if not impossible, to displace mud effectively from the narrow side of the annulus," resulting in a failed cement job. Halliburton. the contractor hired by BP to cement the well. warned BP that the well could have a "SEVERE gas flow problem" if 1W lowered the final string of casing with only six centralizers instead of the 21 recommended by 1-lalliburton. BP rejected Halliburton's advice to use additional centralizers. In an e-mail on April 16, a BP official involved in the decision explained: "it will take 10 hours to install them.... I do not like this." Later that day, another official recognized the risks of proceeding with insufficient centralizers but commented: "who cares, it's done. end of story, will probably be tine."
Cement Bond Log. BP's mid-April plan review predicted cement failure. stating "Cement simulations indicate it is unlikely to be a successful cement job due to formation breakdown." Despite this warning and Ilalliburton's prediction of severe gas flow problems. BP did not rim a 9- to 12-hour procedure called a cement hand log to assess the integrity of the cement seal. BP had a crew from Schlumberger on the rig on the morning of April 20 for the purpose of running a cement bond log, but they departed after BP told them their services were not needed. An independent expert consulted by the Committee called this decision "horribly negligent."
Mud Circulation. In exploratory operations like the Macondo well. wells are generally filled with weighted mud during the drilling process. The American Petroleum Institute (API) recommends that oil companies fully circulate the drilling mud in the well from the bottom to the top before commencing the cementing process. Circulating the mud in the Macondo well could have taken as long as 12 hours. but it would have allowed workers on the rig to test the mud for
Mr. Tony Hayward June 14, 2010 Page 3
gas influxes, to safely remove any pockets of gas, and to eliminate debris and condition the mud so as to prevent contamination of the cement. BP decided to forego this safety step and conduct only a partial circulation of the drilling mud before the cement job.
Lockdown Sleeve. Because BP elected to use just a single string of casing, the Macondo well had just two barriers to gas flow up the annular space around the final string of casing: the cement at the bottom of the well and the seal at the wellhead on the sea floor. The decision to use insufficient centralizers created a significant risk that the cement job would channel and fail, while the decision not to run a cement bond log denied RP the opportunity to assess the status of the cement job. These decisions would appear to make it crucial to ensure the integrity of the seal assembly that was the remaining barrier against an influx of hydrocarbons. Yet, BP did not deploy the casing hanger kickdown sleeve that would have prevented the seal from being blown out from below.
These five questionable decisions by BP are described in more detail below. We ask that you come prepared on Thursday to address the concerns that these decisions raise about 13P's actions.
BP started drilling the Macondo well on October 7. 2009, using the Marianas rig, This rig was damaged in Hurricane Ida on November 9. 2009. As a result, BP and the rig operator. Transocean, replaced the Marianas rig with the Deepwater Horizon. Drilling with the Deepwater Horizon started on February 6, 2010.
The Deepwater Horizon rig was expensive, Transocean charged BP approximately $500,000 per day to lease the rig, plus contractors' fees.' BP targeted drilling the well to take 51 days and cost approximately $96 million.
The Deepwater Horizon was supposed to be drilling at a new location as early as March 8, 2010.' In fact. the Macondo well took considerably longer than planned to complete. By April 20, 2010. the day of the blowout, the rig was 43 days late for its next drilling location, which may have cost BP as much as $21 million in leasing fees alone. It also may have set the context for the series of decisions that BP made in the days and hours before the blowout.
According to the terms of the contract, the daily rate would range from $458,000 in March 2008 to $517,000 in September 2010. See Transocean. Transocean Fleet Update, fn. 11 (Apr. 13, 2010) (online at http:/,!1.waw.deepwater.com!fw/main/Fleet-Update-R...
2 BP. C; OM Exploration Wells MC 252 #1 - Macondo Prospect Well Inforniation (Sept. 2009) (BP-HZN-CEC008714).
Testimony of Steve 'link. BP, Health. Safety and Environmental Manager. before the U.S. Coast Guard!MMS Marine Board of Investigation (May 26, 2010).
Mr Tony Hayward June 14. 2010 Page 4
Well Design
Deepwater wells are drilled in sections. The basic process involves drilling through rock. installing and cementing easing to secure the wellbore, and then drilling deeper and repeating the process. On April 9, 2010, BP finished drilling the last section of the well. The final section of the wellbrn-e extended to a depth of 18,360 feet below sea level, which was L192 feet below the casing that had previously been inserted into the well.-`
At this point, BP had to make an important well design decision: how to secure the final 1.192 feet of the well. On June 3, Halliburton's Vice President of Cementing. Tommy Roth, briefed Committee staff about the two primary options available to BP. One option involved hanging a steel tube called a "liner" from a liner hanger on the bottom of the casing already in the well and then inserting another steel liner tube called a "tieback" on top of the liner hanger. The other option involved running a single string of steel casing from the seafloor all the way to the bottom of the well. Mr. Roth informed the Committee that "Liner/Tieback Casing provides advantage over full string casing with redundant barriers to annular flow. In the ease of a single string of casing, there are just two barriers to the flow of gas up the atmular space that surrounds the casing: the cement at the bottom of the well and the seal at the wellhead. Mr. Roth told the Committee that in contrast, "Liner/Tieback provides four barriers to annular flow,"6 They are (1) the cement at the bottom of the well. (2) the hanger seal that attaches the liner to the existing casing in the well, (3) the cement that secures the tieback on top of the liner, and (4) the seal at the wellhead. The liner-tieback option also takes nwwe time to install, requiring several additional days to complete.
Internal DP documents indicate that BP was aware of the risks of the single casing approach An undated -Forward Plan Review" that appears to be from mid-April recommended against the single string of casing because of the risks. According to this document, "Long string of casing ... was the primary option" but a "Liner ... is now the recommended option."'
BP- PowerPoint Presentation. Washington Briefing, Deepwater Ilari_on Interim Incident Investigation at 4 {May 24, 2010).
Briefing by Tommy Roth, Vice President of Cementing, Hallihurton, to House Committee on Energy and Commerce Staff (June 3, 2010); Hallihurton. PowerPoint Presentation, Energy and Commerce Committee Staff Briefing at 12 (June 3, 2010).
6 Id. at 6.
7 BP, ;IIC 25241 _llneondo, TD Forward Plan Review - Production Casing & TA Options. at 9. (Apr. 2010) (BP-HZN-CEC-22109). The documents provided to the Committee from BP contain three versions of this document. This one and a second nearly identical version (BP, ,1IC 25241 ,llacouclo, TD Forward Plan Review - Production Casing & TA Options (Apr. 2010)) (BP-HZN-CEC-22025) recommend against a single string casing and in favor of a liner
Mr. Tony Hayward June 14. 2010 Page 5
The document gave four reasons against using a single string of casing. They were:
• "Cement simulations indicate it is unlikely to be a successful cement job due to formation breakdown,„
• "Unable to fulfill MMS regulations of 500' of cement above top HC zone."
• "Open annulus to the wellhead, with ... seal assembly as only barrier."
• `Potential need to verify with bond log, and perform remedial cement job(s)."8
In contrast, according to the document, there were four advantages to the liner option:
• "Less issue with landing it shallow (we can also ream it down)."
• "Liner hanger acts as second barrier for HC in annulus,"
• "Primary cement job has slightly higher chance for successful cement lift."
• "Remedial cement job. if required, easier to justify to be left for later." 4
Communications between employees of BP confirm they were evaluating these approaches. On April 14. Brian Morel, a BP Drilling Engineer, e-mailed a colleague, Richard Miller. about the options. His e-mail notes: "this has been [a] nightmare well which has everyone all over the place."10
Despite the risks. BP chose to install the single string of casing instead of a liner and tieback, applying for an amended permit on April 15.11 The company's application stated that the full casing string would start at 9 7/8 inches diameter at the top of the well and narrow to 7 inches diameter at the bottom.12 This application was approved on the same day.''
approach. the third version recommends in favor of the single string of casing and is discussed below.
8 Id. "HC" stands for hydrocarbon.
9 hi. at 10.
10 E-mail from Brian Morel. Drilling Engineer. BP. to Richard Miller. BP (Apr. 15. 2010) (BP-HZN-CEC-21857).
1' BP. Form M11vIS 123.4/1235 - Electronic Version, Application for Revised Bypass (Apr. 15, 2010) (BP-HZN-CEC018357).
12 Id.
13 E mail front Frank Patton, MIDIS, to Heather Powell. IC Connor Consulting ("Modification of Permit to Bypass as Location Surface Lease: G32306 Surface Area: MC Surface Block: 252 Bottom Lease: U32306 Bottom Area: MC Bottom Block: 252 Well Name: 001 Assigned API Number: 608174116901 has been approved. as of 2010-04-15 14:39:39.0") (Apr. 14, 42010). Ms. Powell then forwarded the approval to BP. E-mail from Heather Powell,
Mr. Tony Hayward June 14, 2010 Pagc6
The decision to run a single string of casing appears to have been made to save time and reduce costs. On March 25, Mr. Morel c-mailcd Allison Crane, the Materials Management Coordinator for BP's Gulf of Mexico Deepwater Exploration Unit, that the long casing string "saves a lot of time ... at least 3 days"ra On March 30, he e-mailed Sarah Dobbs. the BP Completions Engineer, and Mark Hafle, another BP Drilling Engineer, that "[n]ot running the tieback ... saves a good deal of timelmoney.'"lOn April 15. BP estimated that using a liner instead of the single string of casing `.will add an additional $7 - $10 MM to the completion cost "r6 The same document calls the single string of casing the "[Nest economic case and well integrity case for future completion operations.'''
Around this time. BP prepared another undated version of its "Forward Plan Review." Notably, this version of the document reaches a different conclusion than the other version, calling the long siring of casing "the primary option'' and the liner "the contingency option.
Like the other version of the plan review, this version acknowledges the risks of a single string of casing, but it now describes the option as the `Best economic case and well integrity case for future completion operations." 19
Centralizers
Centralizers are attachments that go around the casing as it being lowered into the well to keep the casing in the center of the borehole. If the well is not properly centered prior to the cementing process. there is increased risk that channels will form in the cement that allow gas to flow up the annular space around the casing, API Recommended Practice 65 explains: if casing is not centralized, it may lay near or against the borehole wall.... It is difficult, if not
JC Connor Consulting, to Mark Hafle. Senior Drilling Engineer, BP (Apr. 15, 2010) (BP-FIZNCECO21033).
14 E-mail from Brian Morel. Drilling Engineer, BP, to Allison Crane, Materials Management Coordinator, BP Gulf of Mexico Deepwater Exploration (Mar. 25. 2010). (BPHZN-CEC021880).
15 E-mail from Brian Morel, Drilling Engineer. BP, to Sarah Dobbs, Completions Engineer, BP. and Mark Hafle, Senior Drilling Engineer, BP (Mar. 30, 2010) (BP-HPCEC021948).
rb BP, Drilling & Completions MOC Initiate (Apr. 15, 2010) (BP-HZN-CEC021656).
17 Id.
1B BP, TD Forward Plan Review. Production Casing & TA Options at 6-7 (undated) (BPHZN-CEC-022145).
Mr. Tony Hayward June 14, 2010 Page 7
impossible. to displace mud effectively from the narrow side of the annulus if casing is poorly centralized. This results in bypassed mud channels and inability to achieve zonal isolation,"20
On April 15, BP informed Halliburton's Account Representative, Jesse Gagliano. that BP was planning to use six centralizers on the final casing string at the Macondo well. Mr. Gagliano spent that day running a computer analysis of a number of cement design scenarios to determine how many centralizers would be necessary to prevent channeling.` With ten centralizers, the modeling resulted in a "MODERATE" gas flow problem." Mr. Gagliano's modeling showed that it would require 21 centralizers to achieve only a "MINOR" gas flow problem.-3
Mr. Gagliano informed BP of these results and recommended the use of 21 centralizers.21 After running a model with ten centralizers. Mr. Gagliano e-mailed Brian Morel, BP's drilling engineer, and other BP officials, staling that the model "now shows the cement channeling' and that "1'm going to run a few scenarios to see if adding more centralizers will help us or not"Twenty-five minutes later. Mr. Morel e-mailed back:
We have 6 centralizers, we can run them in a row, spread out, or any combination of the two. It's a vertical hole, so hopefully the pipe stays centralized due to gravity. As far as changes, it's too late to get any more product on the rig, our only option[] is to rearrange placement of these centralizers.26
20 API, Recommended Practice 65-Part 2 isolating Potential Flow Zones During Well Construction, 4.6,5,8., at 28.
21 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc Gagliano, at 26 (June 11, 2010).
z' Halliburton, 9 7/8" X 7" Production Casing Design Report (Apr. 15, 7010) (HAL_0010592 ).
Halliburton, 9 7/8"X 7"Production Casing Design Report (Apr. 15. 2010) (IAAL 0010699).
24 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc Gagliano, at 8 (June 11, 2010).
2.- E-mail from Jesse Gagliano, Account Representative. Halliburton. to Mark Valle, Senior Drilling Engineer, BP. Brian Morel, Drilling Engineer, BP. Brett Cocales, Operations Drilling Engineer. BP, and Gregory- Walz, Drilling Team Leader, BP (Apr. 15, 2010) (HAL 0010650).
26 E-mail from Brian Morel. Drilling Engineer. TIP. to Jesse Gagliano, Account Representative. Halliburton, Mark Hafle, Senior Drilling Engineer. BP, -Brett Cocales, Operations Drilling Engineer, BP. and Gregory Walz, Drilling Team Leader. BP (Apr. 15, 2010) (HAL 0010648).
Mr. Tony Hayward June 14, 2010 Page 8
The following day. April 16, the issue was elevated to John Guide, BP's Well Yearn Leader, by Gregory Walz. BP's Drilling Engineering Team leader. Mr. Walz informed Mr. Guide: "We have located 15 Weatherford centralizers with stop collars ... in Houston and worked things out with the rig to be able to fly them out in the morning" The decision was made because "we need to honor the modeling to be consistent with our previous decisions to go with the long string."? Mr. Walz explained: `I wanted to make sure that we did not have a repeat of the last Atlantis job with questionable centralizers going into the hole."`s Mr. Walz added: "I do not like or want to disrupt your operations. ... I know the planning has been lagging behind the operations and I have to turn that around."-9
In his response, Mr. Guide raised objections to the use of the additional centralizers. writing: "it will take 10 hrs to install them.... I do not like this and ... I [am] eery concerned about using them."'''
An e-mail frnm Brett Cocales. BP's Operations Drilling Engineer, indicates that Mr. Guide's perspective prevailed. On April 16, he e-mailed Mr. Morel:
Even if the hole is perfectly straight, a straight piece of pipe even in tension will not seek the perfect center of the hole unless it has something to centralize it.
But. who cares. it's done, end of story, will probably be fine and well get a good cement job. I would rather have to squeeze than get stuck. .. So Guide is right on the risk/reward equation.'
On April 17, Mr. Gagliano, the Hallihurton account representative, was informed that BP had decided to use only six centralizers.'' He then ran a model using seven centralizers and
'' E-mail from Gregory Walz. Drilling Team Leader, BP, to John Guide, Well Team Leader. BP (Apr. 16, 2010) (BP-HZN-CEC0022433).
`' Isl.
29 Id.
3D if.
31 E-mail from Brett Cocales. Operations Drilling Engineer. BP. to Brian Morel. Drilling Engineer, BP (Apr. 16, 2010) (BP-HZN-CEC022670).
32 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc Gagliano, at 40-41 (June 11, 2010).
Mr. Tony Hayward June 14, 2010 Page 9
found this would likely produce channeling and a failure of the cement job." His April 18 cementing design report states: "well is considered to have a SEVERE gas flow problem."'4 Mr. Gagliano said that BP was aware of the risks and proceeded with knowledge that his report indicated the well would have a severe gas flow problem."
Mr. Gagliano's findings should not have been a surprise to BP. As noted above, BP's mid-April plan review found that if BP used a single string of casing, as BP had decided to do. --Cement simulations indicate it is unlikely to be a successful cement job,"'6 Nonetheless, BP ran the last casing with only six centralizers*
Cement Bond Log
A cement bond log is an acoustic test that is conducted by running a tool inside the casing after the cementing is completed. The cement bond log determines whether the cement has bonded to the casing and sunTounding formations. If a channel that would allow gas flow is found. the casing can be perforated and additional cement injected into the annular space to repair the cement job.
Mr. Roth. the Halliburton Vice President of Cementing, informed the Committee staff that BP should have conducted a cement bond log. According to Mr. Roth, --If the cement is to be relied upon as an effective barrier. the well owner must perform a cement evaluation as part of a comprehensive systems integrity test."'s
" Id. at 8. Mr. Gagliano told the Committee that at the time he ran a model with seven centralizers, he knew of BP's decision to use only six. He told the Committee that running a model with seven centralizers demonstrated that the difference between six and seven centralizers would be unlikely to affect the outcome of the modeling,
3a Halliburton, 9 7/8 ' X 7" Production Casing Design Report (Apr. 18. 2010) (HAL0010955).
3' House Committee on Energy and Commerce. Transcribed Interview of Jesse Marc Gagliano, at 43-45 (June 11. 2010).
36 BP, MC 252y1 acundo, TD Forward Pion Review - Production Casing & TA Options, at 9. (Apr. 2010) (BP-HZN-CEC-22109).
37 BP. Doily Operations Report - Partners (Completion) (Apr. 18. 2010) (HAL 0028210).
Briefing by Tommy Roth, Vice President of Cementing, Halliburton, to House Commit-tee on Energy and Commerce Staff (June 3. 2010): Halliburton. PowerPoint Presentation; Energy and Commerce Committee Staff Briefing at 12 (June 3. 2010).
Mr. Tony Hayward June 14, 2010 Page 10
Minerals Management Service ()`FINS) regulations also appear to direct a cement bond log or equivalent test at the Macondo well. According to the regulations, if there is an indication of an inadequate cement job. the oil company must "(1) Pressure test the casing shoe; (2) Run a temperature survey; (3) Run a cement bond log; or (4) Use a combination of these techniques.'"`' In the case of the Macondo well, the Halliburton and internal BP warnings should have served as an indication of a potentially inadequate cement job.
On April 18, BP flew a crew from Schlumberger to the rig. As described in a Schlumberger timeline, "BP contracted with Schlumberger to be available to perform a cement bond log ... should BP request those services."'40 But at about 7:00 a.m. on the morning of April 20, BP told the Schlumberger crew that their services would not be required for a cement bond log test.41 As a result, the Schlumberger crew departed the Deepwater Horizon at approximately 11:15 a.m. on a regularly scheduled BP helicopter night.' The Schlumberger crew was scheduled for departure before pressure testing of the well had been completed. indicating that the results of those tests were not a factor in BP's decision to send the crew away without conducting a cement bond log.43
BP's decision not to conduct the cement bond log test may have been driven by concerns about expense and time. The cement pond log would have cost the company over Sl 28,000 to complete.44 In comparison, the cost of canceling the service was just $10.000.41 Moreover, Mr. Roth of Halliburton estimated that conducting the test would have taken an additional 9 to 12 hours.46 Remediating any problems found with the cementing job would have taken still more time.47
39 30 CFR § 250.428.
4° Schlumhcrgcr, Mississippi Canton Block 252 l'imeline (undated) (SLB-EC-000002).
41 Id.
42
Id.
43 Briefing by Mark Bly; Group Vice President for Safety & Operations. BP, to House Committee on Energy and Commerce Staff (May 25, 2010).
44 Schlumberger, Estimated Costs of Equipment/Labor to Perform the Contingent Services Identified by BP and the Actual Costs Upon Cancellation (SLB-EC-000909).
45 Id.
1' Briefing by Tommy Roth, Vice President of Cementing, Ialliburtoni to House Committee on Energy and Commerce Staff (June 3. 2010).
17 A BP document indicates that the company would rely on lost mud "returns" during the cementing process as a trigger for conducting a cement bond log. BP, GUM Exploration Wells MC 252 #1STOUBPU1- Macorido Prospect 7".x 9-7/8" Interval at 3 (Apr. 15, 2010) (BP-
IVlr. Tony Hayward June 14, 2010 Page 11
The Committee staff asked an independent engineer with expertise in the analysis of well failure about BP's decision not to conduct a cement bond log. The engineer, Gordon Aakcr_ Jr., PE, a Failure Analysis Consultant with the firm Engineering Services, LLP, said that it was "unheard of not to perform a cement bond log on a well using a single casing approach. and he described RP's decision not to conduct a cement bond log as "horribly negligent."48 Another independent expert consulted by the Committee, John Martinez. F.E., told the committee that "cement bond or cement evaluation logs should always be used on the production string."49
Mud Circulation
Another questionable decision by BP appears to have been the failure to circulate hilly the drilling mud in the well before cementing. This procedure, known as "bottoms up." involves circulating drilling mud from the bottom of the well all the way to the surface. Bottoms up has several purposes: it allows workers on the rig to test the mud for influxes of gas; it permits a controlled release of gas pockets that may have entered the mud; and it ensures the removal of well cuttings and other debris from the bottom of the well, preventing contamination of the cement.
API's guidelines recommend a full bottoms up circulation between running the casing and beginning a cementing job. The recommended practice states that "when the casing is on bottom and before cementing, circulating the drilling fluid will break its gel strength. decrease its viscosity and increase its mobility. The drilling fluid should be conditioned until equilibrium is achieved.... At a minimum, the hole should be conditioned for cementing by circulating l .5 annular volumes or one casing volume. whichever is greater."'0
HZN-CEC017621). Mr. Gagliano of Halliburton told the Committee that lost returns are not a reliable indicator of channeling: "the amount of returns would not tell you if there's channeling or not. Full returns, just indicates the amount of fluid you're pumping into the wellbore, you're getting the equal or very close to equal volume back at surface, which is telling you that you're not fracturing any fluids into the formation or losing any fluids. It's not really an indication of channeling." House Committee on Energy and Commerce. Transcribed Interview of Jesse Marc Gagliano, at 86 (June 11. 2010).
rs Briefing by Gordon Aakcr. Tr.. RE, Failure Analysis Consultant with Engineering Services, L.P. (Houston), to House Committee on Energy and Commerce Staff (June 10_ 2010).
49 E-mail fiom John Martinez, P.h., an independent production specialist on wcllborc construction. to House Committee on Energy and Commerce Staff (June 10, 2010).
50 API. Recommended Practice 65-Part 2. Isolating Potential Flow Zones During Well Construction. 4.8.4., at 36-37.
Mr Tony Hayward June 14, 2010 Page 12
BP's April 15 operations plan called for a full bottoms up procedure to "circulate at least one (1) casing and drill pipe capacity, if hole conditions allow."'' Halliburton Account Representative Jesse Gagliano said it was also Halliburton's recommendation and best practice to at least circulate one bottoms up on the well before doing a cement job.'2 According to Mr. Gagliano, a Halliburton engineer on the rig raised the bottoms up issue with BP.i3
Despite the BP operations plan and the Halliburton recommendation, BP did not fully circulate the mud. Instead, it chose a procedure "written on the rig" which Mr. Gagliano "did not get input in..54 BP's final procedure called for circulating just 261 ban-els of mud, just a small fraction of the mud in the Macondo well,'' Mr. Roth of Halliburton told the Committee that one reason for the decision not to circulate the mud could have been a desire for speed, as fully circulating the mud could have added as much as 12 hours to the operation.' Mr. Gagliano expressed a similar view, saying, "the well probably would not have handled too high of'a rate. So it would take a little bit ... longer than usual to circulate bottoms up in this case.'"57
Lockdown Sleeve
A final question relates to RP's decision not to install a critical apparatus to lock the wellhead and the casing in the seal assembly at the seafloor. When the casing is placed in the wellhead and cemented in place, it is held in place by gravity. Under certain pressure conditions, however, the casing can become buoyant, rising up in the wellhead and potentially creating an opportunity for hydrocarbons to break through the wellhead seal and enter the riser to the surface. To prevent this, a casing hanger lockdown sleeve is installed.
On June 8. 2010. Transocean briefed Committee staff on its investigation into the potential causes of the explosion on board the Deepwater Horizon. In the presentation, Transocean listed the lack of a lockdown sleeve as one of its "areas of investigation." Slide
BP, GOM Exploration Wells, lIC'252 #IST00PBPOI - Macondo Prospect 7"X 9 7/8" Interval, Rev. 11.2 at 6 (Apr. 15, 2010) (BP-HLN-CEC-017621).
- House Committee on Energy and Commerce. Transcribed Interview of Jesse Marc Cagliano. at 57 (June 11, 2010).
Id. at 61.
Id. at 57.
7; Id. at 60.
56 Briefing by Pommy Roth. Vice President of Cementing, Halliburton, to House Committee on Energy and Commerce Staff (June 3. 2010).
House Committee on Energy and Commerce, Transcribed Interview of Jcssc Marc Gagliano. at 65-66 (June 11, 2010).
Mr. Tony Hayward June 14, 2010 Page 13
seven of Transocean's presentation asks: "Were Operator procedures appropriate?" A subpoint details: "Operator did not run lock down sleeve prior to negative test or displacement."'x Mr. Roth of Halliburton raised a similar concern in his June 3 briefing for Committee staff.59
In BP's planned procedure for the well BP describes two options involving the lockdown, sleeve. BP was seeking permission from MMS to install the final cement plug on the well at a lower depth than previously approved. If permission was granted, BP's plan was to displace the drilling mud in the riser with seawater and install the cement plug prior to installation of the casing hanger lockdown sleeve. BP's alternative plan, if MMS did not approve the proposed depth of the final cement plug. was to run the lockdown sleeve first, before installing the cement plug at a shallower depth." On April 16, Brian Morel, BP's drilling engineer, e-mailed BP staff that: We are still waiting for approval of the departure to set our surface plug.... If we do not get this approved, the displacement/plug will be completed shallower after running the LDS."61 The LDS stands for the lockdown sleeve.
Conclusion
The Committee's investigation into the causes of the blowout and explosion on the Deepwater Horizon rig is continuing.. As our investigation proceeds, our understanding of what happened and the mistakes that were made will undoubtedly evolve and change. At this point in the investigation, however, the evidence before the Committee calls into question multiple decisions made by BP. Time after time, it appears that BP made decisions that increased the risk of a blowout to save the company time or expense. If this is what happened. BP's carelessness and complacency have inflicted a heavy toll on the Gulf, its inhabitants, and the workers on the rig.
's Transocean. PowerPoint Presentation, Deepo'atcr Horizon Incident Internal Ln'estigationn.: In'est gcrtion Update - Interim Report at 7 (June 8. 2010).
'9
Briefing by Tommy Roth, Vice President of Cementing, Halliburton, to House
Committee on Energy and Commerce Staff (June 3, 2010).
HP. COW Exploration d'''ells MC 252 #ISTOOBPOI- Macondo Prospect 7"x 9-7/8" Interval at 8 (Apr. 15, 2010) (BP-HZN-CECO17521).
G1 E-mail from Brian Morel. Drilling Engineer. BP, to Ronald Scpulvado ct al. (Apr. 16. 2010) (BP-HZN-CEC022821).
Mr. Tony Hayward June 14, 2010 Page 14
During your testimony before the Committee, you will be asked about the issues raised in this letter. This will provide you an opportunity to respond to these concerns and clarify the record. We appreciate your willingness to appear and your cooperation in the Committee's investigation.
Sincerely,
Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Mr. Tony Hayward
Chief Executive Officer BP PLC
1 St. James's Square London SW1Y 4PD United Kingdom
Dear Mr. Hayward:
We are looking forward to your testimony before the Subcommittee on Oversight and Investigations on Thursday, June 17, 2010, about the causes of the blowout of the Macondo well and the ongoing oil spill disaster in the Gulf of Mexico. As you prepare for this testimony, we want to share with you some of the results of the Committee's investigation and advise you of issues you should be prepared to address.
The Committee's investigation is raising serious questions about the decisions made by BP in the days and hours before the explosion on the Deepwater Horizon. On April 15, five days before the explosion, BP's drilling engineer called Macondo a "nightmare well." In spite of the well's difficulties, BP appears to have made multiple decisions for economic reasons that increased the danger of a catastrophic well failure. In several instances, these decisions appear to violate industry guidelines and were made despite warnings from BP's own personnel and its contractors. In effect, it appears that BP repeatedly chose risky procedures in order to reduce costs and save time and made minimal efforts to contain the added risk.
At the time of the blowout, the Macondo well was significantly behind schedule. This appears to have created pressure to take shortcuts to speed finishing the well. In particular, the Committee is focusing on five crucial decisions made by BP: (1) the decision to use a well design with few barriers to gas flow; (2) the failure to use a sufficient number of "centralizers" to prevent channeling during the cement process; (3) the failure to run a cement bond log to evaluate the effectiveness of the cement job; (4) the failure to circulate potentially gas-bearing
Mr. Tone Hayward June 14. 2010 Page 2
drilling muds out of the well: and (5) the failure to secure the wellhead with a lockdown sleeve before allowing pressure on the seal from below., The common feature of these five decisions is that they posed a trade-off between cost and well safety.
Well Design. On April 19. one day before the blowout. BP installed the final section of steel tubing in the well. BP had a choice of two primary options: it could lower a full string of "casing' from the top of the wellhead to the bottom of the well, or it could hang a `liner" from the lower end of the casing already in the well and install a "tieback" on top of the liner. The liner-tieback option would have taken extra time and was more expensive. but it would have been safer because it provided more barriers to the flow of gas up the annular space surrounding these steel tubes. A BP plan review prepared in mid-April recommended against the full string of casing because it would create "'an open annulus to the wellhead" and make the seal assembly at the wellhead the "only barrier" to gas flow if the cement job failed. Despite this and other warnings, BP chose the more risky casing option. apparently because the liner option would have cost $7 to S10 million more and taken longer.
Centralizers. When the final string of casing was installed, one key challenge was making sure the casing ran down the center of the wellbore. As the American Petroleum institute's recommended practices explain. if the casing is not centered, ''it is difficult, if not impossible, to displace mud effectively from the narrow side of the annulus," resulting in a failed cement job. Halliburton. the contractor hired by BP to cement the well. warned BP that the well could have a "SEVERE gas flow problem" if 1W lowered the final string of casing with only six centralizers instead of the 21 recommended by 1-lalliburton. BP rejected Halliburton's advice to use additional centralizers. In an e-mail on April 16, a BP official involved in the decision explained: "it will take 10 hours to install them.... I do not like this." Later that day, another official recognized the risks of proceeding with insufficient centralizers but commented: "who cares, it's done. end of story, will probably be tine."
Cement Bond Log. BP's mid-April plan review predicted cement failure. stating "Cement simulations indicate it is unlikely to be a successful cement job due to formation breakdown." Despite this warning and Ilalliburton's prediction of severe gas flow problems. BP did not rim a 9- to 12-hour procedure called a cement hand log to assess the integrity of the cement seal. BP had a crew from Schlumberger on the rig on the morning of April 20 for the purpose of running a cement bond log, but they departed after BP told them their services were not needed. An independent expert consulted by the Committee called this decision "horribly negligent."
Mud Circulation. In exploratory operations like the Macondo well. wells are generally filled with weighted mud during the drilling process. The American Petroleum Institute (API) recommends that oil companies fully circulate the drilling mud in the well from the bottom to the top before commencing the cementing process. Circulating the mud in the Macondo well could have taken as long as 12 hours. but it would have allowed workers on the rig to test the mud for
Mr. Tony Hayward June 14, 2010 Page 3
gas influxes, to safely remove any pockets of gas, and to eliminate debris and condition the mud so as to prevent contamination of the cement. BP decided to forego this safety step and conduct only a partial circulation of the drilling mud before the cement job.
Lockdown Sleeve. Because BP elected to use just a single string of casing, the Macondo well had just two barriers to gas flow up the annular space around the final string of casing: the cement at the bottom of the well and the seal at the wellhead on the sea floor. The decision to use insufficient centralizers created a significant risk that the cement job would channel and fail, while the decision not to run a cement bond log denied RP the opportunity to assess the status of the cement job. These decisions would appear to make it crucial to ensure the integrity of the seal assembly that was the remaining barrier against an influx of hydrocarbons. Yet, BP did not deploy the casing hanger kickdown sleeve that would have prevented the seal from being blown out from below.
These five questionable decisions by BP are described in more detail below. We ask that you come prepared on Thursday to address the concerns that these decisions raise about 13P's actions.
BP started drilling the Macondo well on October 7. 2009, using the Marianas rig, This rig was damaged in Hurricane Ida on November 9. 2009. As a result, BP and the rig operator. Transocean, replaced the Marianas rig with the Deepwater Horizon. Drilling with the Deepwater Horizon started on February 6, 2010.
The Deepwater Horizon rig was expensive, Transocean charged BP approximately $500,000 per day to lease the rig, plus contractors' fees.' BP targeted drilling the well to take 51 days and cost approximately $96 million.
The Deepwater Horizon was supposed to be drilling at a new location as early as March 8, 2010.' In fact. the Macondo well took considerably longer than planned to complete. By April 20, 2010. the day of the blowout, the rig was 43 days late for its next drilling location, which may have cost BP as much as $21 million in leasing fees alone. It also may have set the context for the series of decisions that BP made in the days and hours before the blowout.
According to the terms of the contract, the daily rate would range from $458,000 in March 2008 to $517,000 in September 2010. See Transocean. Transocean Fleet Update, fn. 11 (Apr. 13, 2010) (online at http:/,!1.waw.deepwater.com!fw/main/Fleet-Update-R...
2 BP. C; OM Exploration Wells MC 252 #1 - Macondo Prospect Well Inforniation (Sept. 2009) (BP-HZN-CEC008714).
Testimony of Steve 'link. BP, Health. Safety and Environmental Manager. before the U.S. Coast Guard!MMS Marine Board of Investigation (May 26, 2010).
Mr Tony Hayward June 14. 2010 Page 4
Well Design
Deepwater wells are drilled in sections. The basic process involves drilling through rock. installing and cementing easing to secure the wellbore, and then drilling deeper and repeating the process. On April 9, 2010, BP finished drilling the last section of the well. The final section of the wellbrn-e extended to a depth of 18,360 feet below sea level, which was L192 feet below the casing that had previously been inserted into the well.-`
At this point, BP had to make an important well design decision: how to secure the final 1.192 feet of the well. On June 3, Halliburton's Vice President of Cementing. Tommy Roth, briefed Committee staff about the two primary options available to BP. One option involved hanging a steel tube called a "liner" from a liner hanger on the bottom of the casing already in the well and then inserting another steel liner tube called a "tieback" on top of the liner hanger. The other option involved running a single string of steel casing from the seafloor all the way to the bottom of the well. Mr. Roth informed the Committee that "Liner/Tieback Casing provides advantage over full string casing with redundant barriers to annular flow. In the ease of a single string of casing, there are just two barriers to the flow of gas up the atmular space that surrounds the casing: the cement at the bottom of the well and the seal at the wellhead. Mr. Roth told the Committee that in contrast, "Liner/Tieback provides four barriers to annular flow,"6 They are (1) the cement at the bottom of the well. (2) the hanger seal that attaches the liner to the existing casing in the well, (3) the cement that secures the tieback on top of the liner, and (4) the seal at the wellhead. The liner-tieback option also takes nwwe time to install, requiring several additional days to complete.
Internal DP documents indicate that BP was aware of the risks of the single casing approach An undated -Forward Plan Review" that appears to be from mid-April recommended against the single string of casing because of the risks. According to this document, "Long string of casing ... was the primary option" but a "Liner ... is now the recommended option."'
BP- PowerPoint Presentation. Washington Briefing, Deepwater Ilari_on Interim Incident Investigation at 4 {May 24, 2010).
Briefing by Tommy Roth, Vice President of Cementing, Hallihurton, to House Committee on Energy and Commerce Staff (June 3, 2010); Hallihurton. PowerPoint Presentation, Energy and Commerce Committee Staff Briefing at 12 (June 3, 2010).
6 Id. at 6.
7 BP, ;IIC 25241 _llneondo, TD Forward Plan Review - Production Casing & TA Options. at 9. (Apr. 2010) (BP-HZN-CEC-22109). The documents provided to the Committee from BP contain three versions of this document. This one and a second nearly identical version (BP, ,1IC 25241 ,llacouclo, TD Forward Plan Review - Production Casing & TA Options (Apr. 2010)) (BP-HZN-CEC-22025) recommend against a single string casing and in favor of a liner
Mr. Tony Hayward June 14. 2010 Page 5
The document gave four reasons against using a single string of casing. They were:
• "Cement simulations indicate it is unlikely to be a successful cement job due to formation breakdown,„
• "Unable to fulfill MMS regulations of 500' of cement above top HC zone."
• "Open annulus to the wellhead, with ... seal assembly as only barrier."
• `Potential need to verify with bond log, and perform remedial cement job(s)."8
In contrast, according to the document, there were four advantages to the liner option:
• "Less issue with landing it shallow (we can also ream it down)."
• "Liner hanger acts as second barrier for HC in annulus,"
• "Primary cement job has slightly higher chance for successful cement lift."
• "Remedial cement job. if required, easier to justify to be left for later." 4
Communications between employees of BP confirm they were evaluating these approaches. On April 14. Brian Morel, a BP Drilling Engineer, e-mailed a colleague, Richard Miller. about the options. His e-mail notes: "this has been [a] nightmare well which has everyone all over the place."10
Despite the risks. BP chose to install the single string of casing instead of a liner and tieback, applying for an amended permit on April 15.11 The company's application stated that the full casing string would start at 9 7/8 inches diameter at the top of the well and narrow to 7 inches diameter at the bottom.12 This application was approved on the same day.''
approach. the third version recommends in favor of the single string of casing and is discussed below.
8 Id. "HC" stands for hydrocarbon.
9 hi. at 10.
10 E-mail from Brian Morel. Drilling Engineer. BP. to Richard Miller. BP (Apr. 15. 2010) (BP-HZN-CEC-21857).
1' BP. Form M11vIS 123.4/1235 - Electronic Version, Application for Revised Bypass (Apr. 15, 2010) (BP-HZN-CEC018357).
12 Id.
13 E mail front Frank Patton, MIDIS, to Heather Powell. IC Connor Consulting ("Modification of Permit to Bypass as Location Surface Lease: G32306 Surface Area: MC Surface Block: 252 Bottom Lease: U32306 Bottom Area: MC Bottom Block: 252 Well Name: 001 Assigned API Number: 608174116901 has been approved. as of 2010-04-15 14:39:39.0") (Apr. 14, 42010). Ms. Powell then forwarded the approval to BP. E-mail from Heather Powell,
Mr. Tony Hayward June 14, 2010 Pagc6
The decision to run a single string of casing appears to have been made to save time and reduce costs. On March 25, Mr. Morel c-mailcd Allison Crane, the Materials Management Coordinator for BP's Gulf of Mexico Deepwater Exploration Unit, that the long casing string "saves a lot of time ... at least 3 days"ra On March 30, he e-mailed Sarah Dobbs. the BP Completions Engineer, and Mark Hafle, another BP Drilling Engineer, that "[n]ot running the tieback ... saves a good deal of timelmoney.'"lOn April 15. BP estimated that using a liner instead of the single string of casing `.will add an additional $7 - $10 MM to the completion cost "r6 The same document calls the single string of casing the "[Nest economic case and well integrity case for future completion operations.'''
Around this time. BP prepared another undated version of its "Forward Plan Review." Notably, this version of the document reaches a different conclusion than the other version, calling the long siring of casing "the primary option'' and the liner "the contingency option.
Like the other version of the plan review, this version acknowledges the risks of a single string of casing, but it now describes the option as the `Best economic case and well integrity case for future completion operations." 19
Centralizers
Centralizers are attachments that go around the casing as it being lowered into the well to keep the casing in the center of the borehole. If the well is not properly centered prior to the cementing process. there is increased risk that channels will form in the cement that allow gas to flow up the annular space around the casing, API Recommended Practice 65 explains: if casing is not centralized, it may lay near or against the borehole wall.... It is difficult, if not
JC Connor Consulting, to Mark Hafle. Senior Drilling Engineer, BP (Apr. 15, 2010) (BP-FIZNCECO21033).
14 E-mail from Brian Morel. Drilling Engineer, BP, to Allison Crane, Materials Management Coordinator, BP Gulf of Mexico Deepwater Exploration (Mar. 25. 2010). (BPHZN-CEC021880).
15 E-mail from Brian Morel, Drilling Engineer. BP, to Sarah Dobbs, Completions Engineer, BP. and Mark Hafle, Senior Drilling Engineer, BP (Mar. 30, 2010) (BP-HPCEC021948).
rb BP, Drilling & Completions MOC Initiate (Apr. 15, 2010) (BP-HZN-CEC021656).
17 Id.
1B BP, TD Forward Plan Review. Production Casing & TA Options at 6-7 (undated) (BPHZN-CEC-022145).
Mr. Tony Hayward June 14, 2010 Page 7
impossible. to displace mud effectively from the narrow side of the annulus if casing is poorly centralized. This results in bypassed mud channels and inability to achieve zonal isolation,"20
On April 15, BP informed Halliburton's Account Representative, Jesse Gagliano. that BP was planning to use six centralizers on the final casing string at the Macondo well. Mr. Gagliano spent that day running a computer analysis of a number of cement design scenarios to determine how many centralizers would be necessary to prevent channeling.` With ten centralizers, the modeling resulted in a "MODERATE" gas flow problem." Mr. Gagliano's modeling showed that it would require 21 centralizers to achieve only a "MINOR" gas flow problem.-3
Mr. Gagliano informed BP of these results and recommended the use of 21 centralizers.21 After running a model with ten centralizers. Mr. Gagliano e-mailed Brian Morel, BP's drilling engineer, and other BP officials, staling that the model "now shows the cement channeling' and that "1'm going to run a few scenarios to see if adding more centralizers will help us or not"Twenty-five minutes later. Mr. Morel e-mailed back:
We have 6 centralizers, we can run them in a row, spread out, or any combination of the two. It's a vertical hole, so hopefully the pipe stays centralized due to gravity. As far as changes, it's too late to get any more product on the rig, our only option[] is to rearrange placement of these centralizers.26
20 API, Recommended Practice 65-Part 2 isolating Potential Flow Zones During Well Construction, 4.6,5,8., at 28.
21 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc Gagliano, at 26 (June 11, 2010).
z' Halliburton, 9 7/8" X 7" Production Casing Design Report (Apr. 15, 7010) (HAL_0010592 ).
Halliburton, 9 7/8"X 7"Production Casing Design Report (Apr. 15. 2010) (IAAL 0010699).
24 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc Gagliano, at 8 (June 11, 2010).
2.- E-mail from Jesse Gagliano, Account Representative. Halliburton. to Mark Valle, Senior Drilling Engineer, BP. Brian Morel, Drilling Engineer, BP. Brett Cocales, Operations Drilling Engineer. BP, and Gregory- Walz, Drilling Team Leader, BP (Apr. 15, 2010) (HAL 0010650).
26 E-mail from Brian Morel. Drilling Engineer. TIP. to Jesse Gagliano, Account Representative. Halliburton, Mark Hafle, Senior Drilling Engineer. BP, -Brett Cocales, Operations Drilling Engineer, BP. and Gregory Walz, Drilling Team Leader. BP (Apr. 15, 2010) (HAL 0010648).
Mr. Tony Hayward June 14, 2010 Page 8
The following day. April 16, the issue was elevated to John Guide, BP's Well Yearn Leader, by Gregory Walz. BP's Drilling Engineering Team leader. Mr. Walz informed Mr. Guide: "We have located 15 Weatherford centralizers with stop collars ... in Houston and worked things out with the rig to be able to fly them out in the morning" The decision was made because "we need to honor the modeling to be consistent with our previous decisions to go with the long string."? Mr. Walz explained: `I wanted to make sure that we did not have a repeat of the last Atlantis job with questionable centralizers going into the hole."`s Mr. Walz added: "I do not like or want to disrupt your operations. ... I know the planning has been lagging behind the operations and I have to turn that around."-9
In his response, Mr. Guide raised objections to the use of the additional centralizers. writing: "it will take 10 hrs to install them.... I do not like this and ... I [am] eery concerned about using them."'''
An e-mail frnm Brett Cocales. BP's Operations Drilling Engineer, indicates that Mr. Guide's perspective prevailed. On April 16, he e-mailed Mr. Morel:
Even if the hole is perfectly straight, a straight piece of pipe even in tension will not seek the perfect center of the hole unless it has something to centralize it.
But. who cares. it's done, end of story, will probably be fine and well get a good cement job. I would rather have to squeeze than get stuck. .. So Guide is right on the risk/reward equation.'
On April 17, Mr. Gagliano, the Hallihurton account representative, was informed that BP had decided to use only six centralizers.'' He then ran a model using seven centralizers and
'' E-mail from Gregory Walz. Drilling Team Leader, BP, to John Guide, Well Team Leader. BP (Apr. 16, 2010) (BP-HZN-CEC0022433).
`' Isl.
29 Id.
3D if.
31 E-mail from Brett Cocales. Operations Drilling Engineer. BP. to Brian Morel. Drilling Engineer, BP (Apr. 16, 2010) (BP-HZN-CEC022670).
32 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc Gagliano, at 40-41 (June 11, 2010).
Mr. Tony Hayward June 14, 2010 Page 9
found this would likely produce channeling and a failure of the cement job." His April 18 cementing design report states: "well is considered to have a SEVERE gas flow problem."'4 Mr. Gagliano said that BP was aware of the risks and proceeded with knowledge that his report indicated the well would have a severe gas flow problem."
Mr. Gagliano's findings should not have been a surprise to BP. As noted above, BP's mid-April plan review found that if BP used a single string of casing, as BP had decided to do. --Cement simulations indicate it is unlikely to be a successful cement job,"'6 Nonetheless, BP ran the last casing with only six centralizers*
Cement Bond Log
A cement bond log is an acoustic test that is conducted by running a tool inside the casing after the cementing is completed. The cement bond log determines whether the cement has bonded to the casing and sunTounding formations. If a channel that would allow gas flow is found. the casing can be perforated and additional cement injected into the annular space to repair the cement job.
Mr. Roth. the Halliburton Vice President of Cementing, informed the Committee staff that BP should have conducted a cement bond log. According to Mr. Roth, --If the cement is to be relied upon as an effective barrier. the well owner must perform a cement evaluation as part of a comprehensive systems integrity test."'s
" Id. at 8. Mr. Gagliano told the Committee that at the time he ran a model with seven centralizers, he knew of BP's decision to use only six. He told the Committee that running a model with seven centralizers demonstrated that the difference between six and seven centralizers would be unlikely to affect the outcome of the modeling,
3a Halliburton, 9 7/8 ' X 7" Production Casing Design Report (Apr. 18. 2010) (HAL0010955).
3' House Committee on Energy and Commerce. Transcribed Interview of Jesse Marc Gagliano, at 43-45 (June 11. 2010).
36 BP, MC 252y1 acundo, TD Forward Pion Review - Production Casing & TA Options, at 9. (Apr. 2010) (BP-HZN-CEC-22109).
37 BP. Doily Operations Report - Partners (Completion) (Apr. 18. 2010) (HAL 0028210).
Briefing by Tommy Roth, Vice President of Cementing, Halliburton, to House Commit-tee on Energy and Commerce Staff (June 3. 2010): Halliburton. PowerPoint Presentation; Energy and Commerce Committee Staff Briefing at 12 (June 3. 2010).
Mr. Tony Hayward June 14, 2010 Page 10
Minerals Management Service ()`FINS) regulations also appear to direct a cement bond log or equivalent test at the Macondo well. According to the regulations, if there is an indication of an inadequate cement job. the oil company must "(1) Pressure test the casing shoe; (2) Run a temperature survey; (3) Run a cement bond log; or (4) Use a combination of these techniques.'"`' In the case of the Macondo well, the Halliburton and internal BP warnings should have served as an indication of a potentially inadequate cement job.
On April 18, BP flew a crew from Schlumberger to the rig. As described in a Schlumberger timeline, "BP contracted with Schlumberger to be available to perform a cement bond log ... should BP request those services."'40 But at about 7:00 a.m. on the morning of April 20, BP told the Schlumberger crew that their services would not be required for a cement bond log test.41 As a result, the Schlumberger crew departed the Deepwater Horizon at approximately 11:15 a.m. on a regularly scheduled BP helicopter night.' The Schlumberger crew was scheduled for departure before pressure testing of the well had been completed. indicating that the results of those tests were not a factor in BP's decision to send the crew away without conducting a cement bond log.43
BP's decision not to conduct the cement bond log test may have been driven by concerns about expense and time. The cement pond log would have cost the company over Sl 28,000 to complete.44 In comparison, the cost of canceling the service was just $10.000.41 Moreover, Mr. Roth of Halliburton estimated that conducting the test would have taken an additional 9 to 12 hours.46 Remediating any problems found with the cementing job would have taken still more time.47
39 30 CFR § 250.428.
4° Schlumhcrgcr, Mississippi Canton Block 252 l'imeline (undated) (SLB-EC-000002).
41 Id.
42
Id.
43 Briefing by Mark Bly; Group Vice President for Safety & Operations. BP, to House Committee on Energy and Commerce Staff (May 25, 2010).
44 Schlumberger, Estimated Costs of Equipment/Labor to Perform the Contingent Services Identified by BP and the Actual Costs Upon Cancellation (SLB-EC-000909).
45 Id.
1' Briefing by Tommy Roth, Vice President of Cementing, Ialliburtoni to House Committee on Energy and Commerce Staff (June 3. 2010).
17 A BP document indicates that the company would rely on lost mud "returns" during the cementing process as a trigger for conducting a cement bond log. BP, GUM Exploration Wells MC 252 #1STOUBPU1- Macorido Prospect 7".x 9-7/8" Interval at 3 (Apr. 15, 2010) (BP-
IVlr. Tony Hayward June 14, 2010 Page 11
The Committee staff asked an independent engineer with expertise in the analysis of well failure about BP's decision not to conduct a cement bond log. The engineer, Gordon Aakcr_ Jr., PE, a Failure Analysis Consultant with the firm Engineering Services, LLP, said that it was "unheard of not to perform a cement bond log on a well using a single casing approach. and he described RP's decision not to conduct a cement bond log as "horribly negligent."48 Another independent expert consulted by the Committee, John Martinez. F.E., told the committee that "cement bond or cement evaluation logs should always be used on the production string."49
Mud Circulation
Another questionable decision by BP appears to have been the failure to circulate hilly the drilling mud in the well before cementing. This procedure, known as "bottoms up." involves circulating drilling mud from the bottom of the well all the way to the surface. Bottoms up has several purposes: it allows workers on the rig to test the mud for influxes of gas; it permits a controlled release of gas pockets that may have entered the mud; and it ensures the removal of well cuttings and other debris from the bottom of the well, preventing contamination of the cement.
API's guidelines recommend a full bottoms up circulation between running the casing and beginning a cementing job. The recommended practice states that "when the casing is on bottom and before cementing, circulating the drilling fluid will break its gel strength. decrease its viscosity and increase its mobility. The drilling fluid should be conditioned until equilibrium is achieved.... At a minimum, the hole should be conditioned for cementing by circulating l .5 annular volumes or one casing volume. whichever is greater."'0
HZN-CEC017621). Mr. Gagliano of Halliburton told the Committee that lost returns are not a reliable indicator of channeling: "the amount of returns would not tell you if there's channeling or not. Full returns, just indicates the amount of fluid you're pumping into the wellbore, you're getting the equal or very close to equal volume back at surface, which is telling you that you're not fracturing any fluids into the formation or losing any fluids. It's not really an indication of channeling." House Committee on Energy and Commerce. Transcribed Interview of Jesse Marc Gagliano, at 86 (June 11. 2010).
rs Briefing by Gordon Aakcr. Tr.. RE, Failure Analysis Consultant with Engineering Services, L.P. (Houston), to House Committee on Energy and Commerce Staff (June 10_ 2010).
49 E-mail fiom John Martinez, P.h., an independent production specialist on wcllborc construction. to House Committee on Energy and Commerce Staff (June 10, 2010).
50 API. Recommended Practice 65-Part 2. Isolating Potential Flow Zones During Well Construction. 4.8.4., at 36-37.
Mr Tony Hayward June 14, 2010 Page 12
BP's April 15 operations plan called for a full bottoms up procedure to "circulate at least one (1) casing and drill pipe capacity, if hole conditions allow."'' Halliburton Account Representative Jesse Gagliano said it was also Halliburton's recommendation and best practice to at least circulate one bottoms up on the well before doing a cement job.'2 According to Mr. Gagliano, a Halliburton engineer on the rig raised the bottoms up issue with BP.i3
Despite the BP operations plan and the Halliburton recommendation, BP did not fully circulate the mud. Instead, it chose a procedure "written on the rig" which Mr. Gagliano "did not get input in..54 BP's final procedure called for circulating just 261 ban-els of mud, just a small fraction of the mud in the Macondo well,'' Mr. Roth of Halliburton told the Committee that one reason for the decision not to circulate the mud could have been a desire for speed, as fully circulating the mud could have added as much as 12 hours to the operation.' Mr. Gagliano expressed a similar view, saying, "the well probably would not have handled too high of'a rate. So it would take a little bit ... longer than usual to circulate bottoms up in this case.'"57
Lockdown Sleeve
A final question relates to RP's decision not to install a critical apparatus to lock the wellhead and the casing in the seal assembly at the seafloor. When the casing is placed in the wellhead and cemented in place, it is held in place by gravity. Under certain pressure conditions, however, the casing can become buoyant, rising up in the wellhead and potentially creating an opportunity for hydrocarbons to break through the wellhead seal and enter the riser to the surface. To prevent this, a casing hanger lockdown sleeve is installed.
On June 8. 2010. Transocean briefed Committee staff on its investigation into the potential causes of the explosion on board the Deepwater Horizon. In the presentation, Transocean listed the lack of a lockdown sleeve as one of its "areas of investigation." Slide
BP, GOM Exploration Wells, lIC'252 #IST00PBPOI - Macondo Prospect 7"X 9 7/8" Interval, Rev. 11.2 at 6 (Apr. 15, 2010) (BP-HLN-CEC-017621).
- House Committee on Energy and Commerce. Transcribed Interview of Jesse Marc Cagliano. at 57 (June 11, 2010).
Id. at 61.
Id. at 57.
7; Id. at 60.
56 Briefing by Pommy Roth. Vice President of Cementing, Halliburton, to House Committee on Energy and Commerce Staff (June 3. 2010).
House Committee on Energy and Commerce, Transcribed Interview of Jcssc Marc Gagliano. at 65-66 (June 11, 2010).
Mr. Tony Hayward June 14, 2010 Page 13
seven of Transocean's presentation asks: "Were Operator procedures appropriate?" A subpoint details: "Operator did not run lock down sleeve prior to negative test or displacement."'x Mr. Roth of Halliburton raised a similar concern in his June 3 briefing for Committee staff.59
In BP's planned procedure for the well BP describes two options involving the lockdown, sleeve. BP was seeking permission from MMS to install the final cement plug on the well at a lower depth than previously approved. If permission was granted, BP's plan was to displace the drilling mud in the riser with seawater and install the cement plug prior to installation of the casing hanger lockdown sleeve. BP's alternative plan, if MMS did not approve the proposed depth of the final cement plug. was to run the lockdown sleeve first, before installing the cement plug at a shallower depth." On April 16, Brian Morel, BP's drilling engineer, e-mailed BP staff that: We are still waiting for approval of the departure to set our surface plug.... If we do not get this approved, the displacement/plug will be completed shallower after running the LDS."61 The LDS stands for the lockdown sleeve.
Conclusion
The Committee's investigation into the causes of the blowout and explosion on the Deepwater Horizon rig is continuing.. As our investigation proceeds, our understanding of what happened and the mistakes that were made will undoubtedly evolve and change. At this point in the investigation, however, the evidence before the Committee calls into question multiple decisions made by BP. Time after time, it appears that BP made decisions that increased the risk of a blowout to save the company time or expense. If this is what happened. BP's carelessness and complacency have inflicted a heavy toll on the Gulf, its inhabitants, and the workers on the rig.
's Transocean. PowerPoint Presentation, Deepo'atcr Horizon Incident Internal Ln'estigationn.: In'est gcrtion Update - Interim Report at 7 (June 8. 2010).
'9
Briefing by Tommy Roth, Vice President of Cementing, Halliburton, to House
Committee on Energy and Commerce Staff (June 3, 2010).
HP. COW Exploration d'''ells MC 252 #ISTOOBPOI- Macondo Prospect 7"x 9-7/8" Interval at 8 (Apr. 15, 2010) (BP-HZN-CECO17521).
G1 E-mail from Brian Morel. Drilling Engineer. BP, to Ronald Scpulvado ct al. (Apr. 16. 2010) (BP-HZN-CEC022821).
Mr. Tony Hayward June 14, 2010 Page 14
During your testimony before the Committee, you will be asked about the issues raised in this letter. This will provide you an opportunity to respond to these concerns and clarify the record. We appreciate your willingness to appear and your cooperation in the Committee's investigation.
Sincerely,
Frankeh said:
jshell said:
Ross1988 said:
The relief wells are pretty certain to work. Just another few weeks at worst. But for what ever reason, if they fail, then I have no idea.
If gas migrates up the outside of the casing (as it's starting to do) causing considerable sea-bed 'cratering' before the relief well is drilled, then there could be the situation where nothing will stop it - until the reservoir is fully depleted to the sea. That's the 'nightmare' scenario.Extinction for a lot of sea life... Sure.
But I think humans will manage without cod for a bit.
I think that 75% of most hydrocarbon spillages tend to evaporate fairly quickly.
dirty boy said:
If you're interested....
Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Strange, I was just reading through the .pdf version of that and a pile of other stuff forwarded to me.Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Reading through that and other e-mails, presentations etc, BP are gonna be VBRJ'd.
jshell said:
dirty boy said:
If you're interested....
Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Strange, I was just reading through the .pdf version of that and a pile of other stuff forwarded to me.Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Reading through that and other e-mails, presentations etc, BP are gonna be VBRJ'd.
dirty boy said:
jshell said:
dirty boy said:
If you're interested....
Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Strange, I was just reading through the .pdf version of that and a pile of other stuff forwarded to me.Long read..some bits may have converted a bit weird due to scanner recognition.
Committee on Energy & Commerce
Reading through that and other e-mails, presentations etc, BP are gonna be VBRJ'd.
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