Thread: Deepwater Horizon Blowout

Replies should be interesting!

To Tony 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 ofthe 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: (I) 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. Tony Hayward
June 14,20 10
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 fu ll 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 annul ar space surrounding
these steel tubes. A BP plan review prepared in mid-April reconunended 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 thi s and other
warnings, BP chose the more risky casing option, apparently because the liner option would have
cost $7 to $10 million more and taken longer.
Centralizers. When the fina l string of casing was installed, one key chall enge was
making sure the casing ran down the center of the well bore. As the American Petroleum
Institute's recommended practices explain, if the casing is not centered, "it is difficu lt, ifnot
impossible, to displace mud effectively from the narrow side of the annulus," resulting in a faiku
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 BP lowered the final string of casing with onl y six
centrali zers instead of the 21 recommended by Halliburton. 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 insuffi cient centralizers but commented: "who
cares, it's done, end of story, will probably be fi ne."
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 Halliburton's prediction of severe gas flow problems, BP
did not run a 9- to 12-hour procedure called a cement bond log to assess the integrity of the
cement sea l. BP had a crew from Schlumberger on the rig on the morning of April 20 for the
purpose of rUlUling a cement bond log, but they departed after BP told them their services were
not needed. An independent expel1 consulted by the Committee called this decision "horrib ly
neg I i gent. "
Mud Circulation. In exploratory operations like the Macondo well, wells are generally
filled with weighted mud during the drilling process. The American Petroleum Insti tute (API)
recommends that oil companies full y 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 befo re 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 insuffi cient centralizers created a significant ri sk that the cement job would channel and fail ,
while the deci sion not to run a cement bond log denied BP 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 lockdown 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 BP's
actions.
Background
BP stmt ed drilling the Macondo well on October 7, 2009, using the Marianas ri g. This
rig was damaged in Hurricane Ida on November 9, 2009. As a result, BP and the rig operator,
Transocean, replaced the Marianas ri g with the Deepwater Horizon. Drilling with the Deepwater
Hori zon started on February 6, 20 I O.
The Deepwater Hori zon rig was expensive. Transocean charged BP approximately
$500,000 per day to lease the ri g, 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
8,20 103 In fact, the Macondo well took considerably longer than plarmed to complete. By
April 20, 20 10, 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 deci sions 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 $5 17,000 in September 20 I O. See Transocean, Transocean Fleet Update, fn. II
(Apr. 13, 20 I 0) (online at http ://www.deepwater.com/fw/mainiFleet-Update-Report-58.html).
2 BP, GOM Exploration Wells Me 252 #i - Macondo Prospect Well in/ormation (Sept.
2009) (BP-HZN-CEC0087 14).
J Testimony of Steve Tink, BP, Health, Safety and Environmental Manager, before the
U.S. Coast Guard/MMS Marine Board of Investigation (May 26, 20 10).
Mr. Tony Hayward
June 14, 2010
Page 4
Well Design
Deepwater well s are drilled in sections. The bas ic process involves drilling through rock,
installing and cementing casing to secure the well bore, and then drilling deeper and repeating the
process. On April 9, 2010, BP fini shed drilling the last section of the well. The final section of
the well bore extended to a depth of 18,360 feet below sea level, which was 1,192 feet below the
casing that had previously been inserted into the we1l 4
At this point, BP had to make an important well design deci sion: 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 rurming 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 annul ar flow."s In the case of a
single string of casing, there are just two barriers to the flo w of gas up the arullliar 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 barri ers to annular
flow.,,6 They are (I ) the cement at the bottom of the well, (2) the hanger seal that attaches the
liner to the ex isting 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 more time to install,
requiring several addit ional days to complete.
Internal BP documents indicate that BP was aware of the ri sks 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 ri sks. According to this document, "Long string
of casing . .. was the primary option" but a "Liner ... is now the recommended option.")
4 BP, PowerPoint Presentation, Washington Briefing, Deepwater Horizon Interim
Incident In vestigation at 4 (May 24, 20 I 0).
S Briefing by Tonuny Roth, Vice President of Cementing, Halliburton, to House
Committee on Energy and Commerce Staff (June 3, 2010); Halliburton, PowerPoi nt
Presentation, Energy and Commerce Commillee Staff Briefing at 12 (J une 3, 20 10).
6 Id. at 6.
) BP, MC 252#1 Macondo, TD Forward Plan Review - Production Casing & TA
Options, at 9. (Apr. 20 I 0) (BP-HZN-CEC-221 09). The documents provided to the Committee
from BP contain three versions of this document. This one and a second nearly identical version
(BP, MC 252#1 Macondo, TD Forward Plan Review - Production Casing & TA Options (Apr.
2010)) (BP-HZN-CEC-22025) recommend against a single string casing and in favor ofa liner
Mr, Tony Hayward
June 14,2010
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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 cementjob(s),,,g
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 arlllulus,"
• "Primary cement job has slightly higher chance for successfiil cement lift,"
• "Remedial cement job, if required, easier to justify to be left for later." 9
Communications between employees ofBP 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 [aJ nightmare well which has
everyone all over the place, ,, lo
Despite the risks, BP chose to install the singl e 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,13
approach, The third version recommends in favor of the single string of casing and is di scussed
below,
g ]d, "HC" stands for hyd rocarbon,
9 Id, at 10,
10 E-mail from Brian Morel, Drilling Engineer, BP, to Ri chard Miller, BP (Apr. 15, 20 I 0)
(BP-HZN-CEC-2 1857),
II BP, Form MMS 123A1123S - Electronic Vers ion, Applicationfor Revised Bypass (Apr.
15,20 I 0) (BP-HZN-CECO I8357),
12 Id,
IJ E-mail from Frank Patton, MMS, to Heather Powell, JC Connor Consulting
("Modifi cation of Permit to Bypass as Location Surface Lease: 032306 Surface ATea: MC
Surface Block: 252 Bottom Lease: 032306 Bottom ATea: MC Bottom Block: 252 Well Name:
001 Assigned API Number: 608174116901 has been approved, as of2010-04-15 14:39:39,0")
(Apr. 14,20 10), Ms, Powell then forwarded the approval to BP, E-mail from Heather Powell,
Mr. Tony Hayward
June 14, 2010
Page 6
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 e-mailed Alli son 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. ,,14 On March 30, he e-mailed Sarah Dobbs, the BP
Completions Engineer, and Mark Hafl e, another BP Drilling Engineer, that "[ n Jot running the
tieback ... saves a good deal of time/money.,,15 On April IS, BP estimated that using a liner
instead of the single string of casing "will add an additional $7 - $10 MM to the completion
cost.,,16 The same document calls the single string of casing the "[b Jest economic case and well
integrity case for future completion operations.,,17
Around this time, BP prepared another undated version of its "Forward Plan Review."
Notably, this version of the document reaches a di ffe rent conclusion than the other version,
calling the long string of casing "the primary option" and the liner "the contingency option. ,,18
Like the other version of the plan review, this version acknowledges the risks of a single string of
casing, but it now descri bes the option as the "Best economic case and well integrity case for
future completion operations. ,,19
Centralizers
Centralizers are attaclm1ents that go around the casing as it being lowered into the well to
keep the casing in the center of the borehol e. If the well is not properly centered prior to the
cementing process, there is increased ri sk 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 centrali zed, it may lay near or against the borehole wall. ... It is difficult, if not
JC COImor Consulting, to Mark Hafle, Senior Drilling Engineer, BP (Apr. 15,201 0) (BP-HZNCEC021033).
14 E-mail from Brian Morel, Drilling Engineer, BP, to Alli son Crane, Materi als
Management Coordinato r, BP Gulf of Mexico Deepwater Exploration (Mar. 25, 2010). (BPHZN-
CEC02 1880).
15 E-mail from Brian Morel, Drilling Engineer, BP, to Sarah Dobbs, Completions
Engineer, BP, and Mark Hafl e, Senior Drilling Engineer, BP (Mar. 30,20 I 0) (BP-HPCEC02
1948).
16 BP, Drilling & Compielions MOC In iliale (Apr. 15,20 I 0) (BP-HZN-CEC02 1656).
17 / d.
18 BP, TD Forward Plan Review, Produclion Casing & TA Oplions at 6-7 (undated) (BPHZN-
CEC-022 145).
19 1d.
Mr. Tony Hayward
June 14, 20 10
Page 7
imposs ible, to displace mud effectively from the nan-ow side of the annulus if casing is poorly
centralized. This results in bypassed mud charll1els and inability to achieve zonal isolation.,,20
On April 15, BP informed HallibUlton'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 nUU1ing a computer analysis of a number of cement design scenarios to determine
how many centralizers would be necessary to prevent channeling21 With ten centralizers, the
modeling resulted in a "MODERATE" gas flow problem22 Mr. Gagliano's modeling showed
that it would require 21 centralizers to achieve only a "MINOR" gas flow problem23
Mr. Gagliano informed BP of these results and recommended the use of 21 centralizers24
After running a model with ten centralizers, Mr. Gagliano e-mailed Brian Morel, BP's drilling
engineer, and other BP officials, stating that the model "now shows the cement charll1eling" and
that ''I'm going to run a few scenarios to see if adding more centralizers will help us or not.,,25
Twenty-five minutes later, Mr. Morel e-mailed back:
We have 6 centrali zers, we can run them in a row, spread out, or any combination of the
1\\10. 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 centralizers26
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 , 20 10).
22 Halliburton, 9 7/8 " X 7" Production Casing Design Report (Apr. 15,2010)
(HAL_DO 1 0592).
23 HallibUlton, 9 7/8 " X 7" Production Casing Design Report (Apr. 15,20 10)
(HAL_DO 1 0699).
24 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 8 (June 11 , 20 10).
25 E-mail from Jesse Gagliano, Account Representative, Halliburton, to Mark Hafle,
Senior Drilling Engineer, BP, Brian Morel, Drilling Engineer, BP, Brett Cocales, Operations
Drilling Engineer, BP, and Gregory Walz, Drilling Team Leader, BP (Apr. 15,20 10)
(HAL_DO 1 0650).
26 E-mail from Brian Morel, Drilling Engineer, BP, to Jesse Gagliano, Account
Representative, Hallib1ll10n, Mark Hafle, Senior Drilling Engineer, BP, Brett Cocales,
Operations Drilling Engineer, BP, and Gregory Walz, Drilling Team Leader, BP (Apr. 15, 20 10)
(HAL_DO 1 0648).
Mr. Tony Hayward
June 14,2010
Page 8
The following day, April 16, the issue was elevated to John Guide, BP's Well Team
Leader, by Gregory Walz, BP's Drilling Engineering Team Leader. Mr. Walz informed Mr.
Guide: "We have located 15 Weatherford centrali zers 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.,,27 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. ,,28 Mr. Walz
added: "I do not like or want to di srupt your operations . . .. I know the planning has been
lagging behind the operations and I have to turn that around. ,,29
In his response, Mr. Guide raised objections to the use of the additional centrali zers,
writing: " it will take 10 hrs to install them . .. . I do not like thi s and ... I [am] very concerned
about using them. ,,30
An e-mail from 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 perfectl y 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 we' ll get a good cement
job. I would rather have to squeeze than get stuck .... So Guide is right on the
rI.S kJ rewar d equatI.o n. 31
On April 17, Mr. Gagliano, the Halliblllton account representative, was informed that BP
had decided to use only six centrali zers32 He then ran a model using seven centralizers and
27 E-mail from Gregory Walz, Drilling Team Leader, BP, to Jolm Guide, Well Team
Leader, BP (Apr. 16,201 0) (BP-HZN-CEC0022433).
28 Id.
29 Id.
30 Id.
31 E-mail from Brett Cocales, Operat ions Drilling Engineer, BP, to Brian Morel, Drilling
Engineer, BP (Apr. 16, 20 10) (BP-HZN-CEC022670).
32 House Committee on Energy and Commerce, Transcri bed Interview of Jesse Marc
Gagliano, at 40-41 (J une 11 ,201 0).
Mr. Tony Hayward
June 14,20 10
Page 9
found this would likely produce channeling and a failure of the cement job33 His April 18
cementing design report states: "well is considered to have a SEVERE gas flow problem.,,34
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 problem35
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 cementjob.,,36 Nonetheless, BP
ran the last casing with only six centralizers37
Cement Bond Log
A cement bond log is an acoustic test that is conducted by rurming a tool inside the casing
after the cementing is completed. The cement bond log determines whether the cement has
bonded to the casing and surrounding formations. If a channel that would allow gas flow is
found , the casing can be perforated and additional cement injected into the armular 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
I · .. ,,38 a compre lenSlve systems II1tegnty test.
J3 Id. at 8. Mr. Gagliano told the Conullittee that at the time he ran a model with seven
centralizers, he knew of BP's decision to use only six. He told the Conunittee 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.
34 HallibUl10n, 9 7/8" X 7" Production Casing Design Report (Apr. 18,20 10)
(HAL_00I0955).
35 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 43-45 (June 11 ,20 I 0).
36 BP, MC 252#1 Macondo, TD Forward Plan Review - Production Casing & TA
Options, at 9. (Apr. 20 I 0) (BP-HZN-CEC-22I 09).
37 BP, Daily Operations Report - Partners (Completion) (Apr. 18 , 2010)
(HAL_00282 10).
38 Briefing by Tommy Roth, Vice President of Cementing, Halliburton, to House
Committee on Energy and Commerce Staff (June 3, 2010); Halliburton, PowerPoint
Presentation, Energy and Commerce Commillee Staff Briefing at 12 (June 3, 20 10).
Mr. Tony Hayward
June 14,2010
Page 10
Minerals Management Service (MMS) 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."J9
In the case of the Macondo well, the HallibUlton 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 test41 As a result, the Schlumberger crew departed the Deepwater Horizon at approximately
II: 15 a.m. on a regularly scheduled BP helicopter flight 42 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
4' conducting a cement bond log. >
BP's decision not to conduct the cement bond log test may have been driven by concerns
about expense and time. The cement bond log would have cost the company over $ 128,000 to
complete44 [n comparison, the cost of canceling the service was just $10,000.45 Moreover, Mr.
Roth of Halliburton estimated that conducting the test would have taken an additional 9 to 12
hours46 Remediating any problems found with the cementing job would have taken still more
. 47 lime.
39 30 CFR § 250.428.
40 Schlumberger, Mississippi Canyon Block 252 Timeline (undated) (SLB-EC-000002).
41 ld.
42 ld
43 Briefing by Mark Bly, Group Vice President for Safety & Operations, BP, to House
Committee on Energy and Commerce Staff (May 25, 20 10).
44 Schlumberger, Estimated Costs of Equipment/Labor to Pelform the Contingent
Services Identified by BP and the AClual COS/S Upon Cancellalion (SLB-EC-000909).
45 ld.
46 Briefing by Tommy Roth, Vice President of Cementing, Halliblllton, to House
Committee on Energy and Commerce Staff (June 3, 2010).
47 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, GOM Exploralion
Wells MC 252 #lSTOOBPOl- Macondo Prospecl 7" x 9- 7/S" lnlerval at 3 (Apr. 15,2010) (BPMr.
Tony Hayward
June 14,2010
Page II
The Committee staff asked an independent engineer with expel1ise in the analysis of well
fai lure about BP's decision not to conduct a cement bond log. The engineer, Gordon Aaker, Jr.,
P.E. , a Failure Anal ysis 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 BP's decision not to conduct a cement bond log as "horribly negligent. ,,48 Another
independent expert consulted by the Committee, Jolm Martinez, P.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 fu lly
the drilling mud in the well before cementing. This procedure, known as "bottoms up," involves
circulating dri lling mud from the bottom of the well all the way to the sur face. 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 rUlming the casing
and beginning a cementing job. The reconmlended practice states that "when the casing is on
bottom and before cementing, circulating the drilling fluid will break its gel strength, decrease its
viscosi ty and increase its mobility. The dri lling fluid should be conditioned until equilibrium is
achieved .... At a minimum, the hole should be conditioned for cementing by circulating 1.5
annular volumes or one casing volume, whichever is greater. ,,50
HZN-CECO I7621). Mr. Gagliano of Halliburton told the Committee that lost returns are not a
reliab le indicator of channeling: "the amount of returns would not tell you if there's charll1eling
or not. Full returns just indicates the amount of fluid you' re pumping into the well bore, 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 format ion or losing any fluid s. It 's not really an indication of
channeling." House Committee on Energy and Conunerce, Transcribed Interview of Jesse Marc
Gagliano, at 86 (June 11 , 20 10).
48 Briefing by Gordon Aaker, Jr., P.E., Failure Anal ys is Consultant with Engineering
Services, L.P. (Houston), to House Committee on Energy and Conullerce Staff (June 10, 20 10).
49 E-mail from John Martinez, P.E.,an independent production specialist on well bore
construction, to House Committee on Energy and Commerce Staff (June 10,2010).
50 API, Recommended Practice 65-Part 2, Isola/ing Po/en/ial Flow Zones During Well
Cons/rile/ion, 4.8.4., at 36-37.
Mr, Tony Hayward
June 14, 20 10
Page 12
BP's April 15 operations plan called for a full bottoms up procedure to "circulate at least
one ( I) casing and drill pipe capacity, if hole conditions allow. ,,'1 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,,,52 According to Mr.
Gagliano, a Halliburton engineer on the rig raised the bottoms up issue with BPS}
Despite the BP operations plan and the Hallib1ll10n 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 26 1 barrels of mud, just a small
fraction of the mud in the Macondo well. 55 Mr. Roth of Hallibul10n 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 operation56 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 BP's deci sion 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, 20 I 0, Transocean briefed Committee staff on its investigation into the
potential causes of the explosion on board the Deepwater Horizon, In the presentation,
Transocean li sted the lack of a lockdown sleeve as one of its "areas of investigation," Slide
51 BP, GOM Exploration Wells, Me252 #ISTOOPBPOI - Macondo Prospect 7" X 9 7/8 "
Interval, Rev, H.2 at 6 (Apr. 15, 20 10) (BP-HZN-CEC-O 1762 1),
52 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 57 (June 11 , 20 10),
D ld,at 6 1.
54 Id, at 57,
55 Id, at 60,
56 Briefing by Tommy Roth, Vice President of Cementing, Hallib1ll10n, to House
Committee on Energy and Commerce Staff (June 3, 20 I 0),
57 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 65-66 (June 11 , 20 10),
Mr. Tony Ha)'\vard
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.,,58 Mr.
Roth of Halliburton raised a similar concern in his June 3 briefing for Committee staff59
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 6 0 On April 16, Brian Morel, BP's drilling engineer, e-mailed BP staff
that: "We are still waiting for approval of the depatture to set our surface plug . ... Ifwe do not
get this approved, the displacemenUplug will be completed shallower after running the LDS.,,61
The LDS stands for the lockdown sleeve.
Conclusion
The Conm1ittee'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
n g.
58 Transocean, PowerPoint Presentation, Deepwater Horizon Incident - Internal
Investigation: Investigation Update - Interim Report at 7 (June 8, 2010).
59 Briefing by Tommy Roth, Vice President of Cementing, Hallibutton, to House
Committee on Energy and Commerce Staff (June 3, 2010).
60 BP, GOM Exploration Wells Me 252 #lSTOOBP01- Macondo Prospect 7" x 9- 7/8"
Interval at 8 (Apr. 15, 2010) (BP-HZN-CECOI7621).
61 E-mail from Brian Morel, Drilling Engineer, BP, to Ronald Sepulvado et al. (Apr. 16,
20 10) (BP-HZN-CEC02282 I).
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.
Henry A. Waxman
Chairman
Enclosure
cc: The Honorable Joe Barton
Ranking Member
The Honorable Michael C. Burgess
Ranking Member
Sincerely,
~~
Bart Stupak
Chairman
Subcommittee on Oversight and Investigations
Subcommittee on Oversight and Investigations

VIDEO: “Oil Confirmed to Be Leaking from Cracks in Sea Floor” | The Political Carnival


VIDEO: “Oil Confirmed to Be Leaking from Cracks in Sea Floor”

Thursday, June 17, 2010 at 9:02 AM by GottaLaff 11 Comments and 0 Reactions




In the interest of clarification, the blog title is that of the original post.
I received the link to this video last night just as I was getting off line, so it is the first one I am posting this morning. The headline is one of the most disturbing ones I’ve read in some time. A worst-case scenario may, indeed, become a reality:

On the video, we see oil leaking from the oil floor. What does this mean? It means that the oil pipe in the ocean has burst and now the oil is leaking from the seafloor. Simply put, there’s probably no realistic way we can stop this.

There are simply no words left…
Here are a few details:

This video was recorded from the Viking Poseidon — ROV 1 on June 13th, 2010 at 2:58 AM EST.
Location of the sea floor crack leaking:
N:10431633.05
E: 1202852.27
My calculations indicate:
The ROV is 19.11 feet north and 55.75 feet west of the leak point.
The ROV is 58.93 feet away from the leak point.

Washington's Blog

Thursday, June 17, 2010

Did BP Start Losing Containment of the Oil Well in February?



The Deepwater Horizon blew up on April 20th, and sank a couple of days later. BP has been criticized for failing to report on the seriousness of the blow out for several weeks.
However, as a whistleblower previously told 60 Minutes, there was an accident at the rig a month or more prior to the April 20th explosion:

[Mike Williams, the chief electronics technician on the Deepwater Horizon, and one of the last workers to leave the doomed rig] said they were told it would take 21 days; according to him, it actually took six weeks.
With the schedule slipping, Williams says a BP manager ordered a faster pace.
"And he requested to the driller, 'Hey, let's bump it up. Let's bump it up.' And what he was talking about there is he's bumping up the rate of penetration. How fast the drill bit is going down," Williams said.
Williams says going faster caused the bottom of the well to split open, swallowing tools and that drilling fluid called "mud."
"We actually got stuck. And we got stuck so bad we had to send tools down into the drill pipe and sever the pipe," Williams explained.
That well was abandoned and Deepwater Horizon had to drill a new route to the oil. It cost BP more than two weeks and millions of dollars.
"We were informed of this during one of the safety meetings, that somewhere in the neighborhood of $25 million was lost in bottom hole assembly and 'mud.' And you always kind of knew that in the back of your mind when they start throwing these big numbers around that there was gonna be a push coming, you know? A push to pick up production and pick up the pace," Williams said.
Asked if there was pressure on the crew after this happened, Williams told Pelley, "There's always pressure, but yes, the pressure was increased."
But the trouble was just beginning: when drilling resumed, Williams says there was an accident on the rig that has not been reported before. He says, four weeks before the explosion, the rig's most vital piece of safety equipment was damaged.

As Bloomberg reports today, problems at the well actually started in February:

BP Plc was struggling to seal cracks in its Macondo well as far back as February, more than two months before an explosion killed 11 and spewed oil into the Gulf of Mexico.
It took 10 days to plug the first cracks, according to reports BP filed with the Minerals Management Service that were later delivered to congressional investigators. Cracks in the surrounding rock continued to complicate the drilling operation during the ensuing weeks. Left unsealed, they can allow explosive natural gas to rush up the shaft.
“Once they realized they had oil down there, all the decisions they made were designed to get that oil at the lowest cost,” said Peter Galvin of the Center for Biological Diversity, which has been working with congressional investigators probing the disaster. “It’s been a doomed voyage from the beginning.”
***
On Feb. 13, BP told the minerals service it was trying to seal cracks in the well about 40 miles (64 kilometers) off the Louisiana coast, drilling documents obtained by Bloomberg show. Investigators are still trying to determine whether the fissures played a role in the disaster.

***
The company attempted a “cement squeeze,” which involves pumping cement to seal the fissures, according to a well activity report. Over the following week the company made repeated attempts to plug cracks that were draining expensive drilling fluid, known as “mud,” into the surrounding rocks.
BP used three different substances to plug the holes before succeeding, the documents show.
“Most of the time you do a squeeze and then let it dry and you’re done,” said John Wang, an assistant professor of petroleum and natural gas engineering at Penn State in University Park, Pennsylvania. “It dries within a few hours.”
Repeated squeeze attempts are unusual and may indicate rig workers are using the wrong kind of cement, Wang said.

In other words, the well may have lost integrity in February, and never been properly repaired. If cracks in the well were never fully sealed, then the well may have been unstable starting in February and continuing until the April 20 explosion. (There is substantial evidence that there are cracks in the well now.)

Bloomberg continues:

In early March, BP told the minerals agency the company was having trouble maintaining control of surging natural gas, according to e-mails released May 30 by the House Energy and Commerce Committee, which is investigating the spill. ***
While gas surges are common in oil drilling, companies have abandoned wells if they determine the risk is too high.

***

On March 10, BP executive Scherie Douglas e-mailed Frank Patton, the mineral service’s drilling engineer for the New Orleans district, telling him: “We’re in the midst of a well control situation.”
The incident was a “showstopper,” said Robert Bea, an engineering professor at the University of California, Berkeley, who has consulted with the Interior Department on offshore drilling safety. “They damn near blew up the rig.”

In other words, not only is it possible that the well casing has been unstable since February, but BP may have ignored standard drilling practices by failing to abandon the well when the natural gas began surging too violently.
Sure, the rig didn't actually catch fire and sink until April, but cracks in the well and dangerous natural gas surges may mean that BP actually started losing containment of the well much earlier.

Note 1: These new facts also add to the massive evidence that BP has been criminally negligent.

Note 2: I am not saying that the well has been gushing oil since February (although oil industry expert Matthew Simmons that the amount of oil leaking from the riser and blowout preventer since April 20th does not account for the massive oil plumes observed in the Gulf).

Breaking BP Video: Oil Leaking Through Cracks in Floor of Gulf


Video in link: http://firedoglake.com/2010/06/18/breaking-bp-video-oil-leaking-through-cracks-in-floor-of-gulf/

Speechless. Does this leave anything but the nuke "option"?

The Williams fellow, who is being interviewed and quoted is a rig technician (electrical). His lack of knowledge is reflected in his terminology. Lost circulation, stuck pipe, free point, back off, pipe cutter are the terms he is looking for and the lack of real knowledge is apparent. The problems he describes are not unique to this well and in fact are fairly common when drilling into a unknown reservoir. Williams and the Congressional inquiry members have about the same level of expertise when it comes to drilling a well for oil/gas. They would probably feel qualified to give a overview of Einstein's theory's after listening to a one hour lecture.

Tony wants his life back. It's all yours, prat:

Originally Posted by robuzo

Tony wants his life back.

He said that back around the beginning of the month. He's got it back now anyway, they demoted him.

http://www.huffingtonpost.com/2010/0..._n_616400.html

Ken Abbott, a former project control supervisor on BP's Atlantis deepwater oil rig, was fired in 2009 after expressing concerns about the safety of the operation.
"I got a lot of pressure from the lead engineers and from the managers saying, 'Don't do that; don't push so much; we don't want to mess with that,'" Abbott told HuffPost in an interview Wednesday. "I feel like the real reason I was fired was because I was trying to raise a safety issue, and you know BP has a long history of getting rid of people who try to raise safety issues. I was one of those victims."
"Management sets the tone," Abbott added. "If they think that production is more important than safety, then that's the tone of the company, and that was the tone at Atlantis."
In his testimony on the Hill on Thursday, BP CEO Tony Hayward repeatedly said that he didn't make any design choices. "I wasn't involved in any of the decision-making," he told Rep. Henry Waxman (D-Calif.), adding that there were clearly discussions about rig safety among the well's engineering team.
"You're not taking responsibility," Waxman said. "You're kicking the can down the road and acting like you have nothing to do with... this company. I find that irresponsible."
Congressional investigators recently obtained internal BP documents showing that BP chose a well design for Deepwater Horizon that was riskier but $3 million cheaper.
The story sounds familiar to Abbott who had his safety recommendations for Atlantis vetoed by BP management for fiscal reasons -- the estimated cost was $2 million.
Story continues below


In September of 2008, Abbott was warned by his predecessor, Barry Duff, that "hundreds if not thousands" of Atlantis's documents had not been approved or finalized, and that it could "lead to catastrophic Operator errors."
Duff had reported these concerns to management, but nothing had happened. "They didn't want to spend the money to fix it," Abbott said. "I think [Duff] was unhappy."
For months, Abbott worked to obtain BP engineer-approved drawings with little, if any, progress. "The more I insisted that we had to develop or obtain them, the more unpopular I became," he said. Hostilities mounted until he was fired on February 5, 2009.
"I was told that it was a reduction in force due to a slowdown on the Atlantis project, but I was the only person laid off," Abbott said. "Three weeks before, the BP managers of Atlantis had told the whole rig nobody was going to be laid off, that there was plenty of work to do."
Hayward said under oath Thursday that he feels "a great deal of responsibility" for the Deepwater Horizon explosion this April that triggered the Gulf Coast catastrophe. "The fire and explosion on the Deepwater Horizon never should have happened and I'm deeply sorry that it did," Hayward said.
Rep. Michael Burgess, a Texas Republican, was underwhelmed by Hayward's claim that the CEO didn't know anything about the well in question, including safety issues that had been raised repeatedly.
"With due respect," said Hayward, "We drill hundreds of wells around the world."
"That's what scares me right now," said Burgess.
Abbott said he thinks BP's lax attitude toward safety regulations extends beyond Atlantis.
"From my experience working in the industry for over 30 years, I have never seen these kinds of problems with other companies," said Abbott. "Of course, everyone and every company will make mistakes occasionally. I have never seen another company with the kind of widespread disregard for proper engineering and safety procedures that I saw at BP... BP has a culture which simply does not follow safety regulations. From what I saw [at Atlantis], that culture has not changed."

Great photos,

There seems to be too much confidence that the 2 new wells being drilled will be the solution yet it's never been tried at that depth before. Then what?

Originally Posted by phomsanuk

Great photos,

There seems to be too much confidence that the 2 new wells being drilled will be the solution yet it's never been tried at that depth before. Then what?

Lots and lots of cement...

Originally Posted by phomsanuk

Great photos,

There seems to be too much confidence that the 2 new wells being drilled will be the solution yet it's never been tried at that depth before. Then what?

The only "never been tried at that depth" refers to ocean depth. which will have affect on the kill procedure from the relief wells. The relief well to kill the blowout is the normal practice when you cannot get any system attached to the wellhead on the blowout to control/shut the well in. With the whole world wartching BP and associates will probably watch themselves close.

My idea has always been to hit the area with high pressure liquid nitrogen into the earth then upward. Freeze the area solid then lay cement over all of it or whatever works at that depth.

BP says relief well is on target as stock tumbles - Yahoo! News


Excerpt;


• A financial disclosure report released Friday shows that the Louisiana judge who struck down the Obama administration's six-month ban on deep-water [COLOR=#366388 ! important][COLOR=#366388 ! important]drilling [COLOR=#366388 ! important]in [/COLOR][COLOR=#366388 ! important]the [/COLOR][COLOR=#366388 ! important]Gulf[/COLOR][/COLOR][/COLOR] has sold many of his energy investments. U.S. District Judge Martin Feldman still owns eight energy-related investments, including stock in Exxon Mobil Corp. Among the assets he sold was stock in Transocean, which owned the rig that exploded. The Justice Department asked a federal appeals court Friday to delay Feldman's ruling "to preserve the status quo" during the government's appeal.


more tidbits;

Vice President Joe Biden will head to the Gulf on Tuesday to visit a command center in New Orleans and the oil-fouled Florida Panhandle.

• The IRS said payments for lost wages from BP's $20 billion victims compensation fund are taxable just like regular income. Payments for physical injuries or property loss are generally tax-free.
BP is drilling two relief wells, in case the first one misses its mark. The first one, started May 2, reached a depth of 16,275 feet Wednesday — including about 5,000 feet of water — before workers paused for the test. Although the relief well is only 200 feet laterally from the [COLOR=#366388 ! important][COLOR=#366388 ! important]original [COLOR=#366388 ! important]well[/COLOR][/COLOR][/COLOR], the crew still has to drill about 2,000 feet deeper before it can intercept the original well, according to Salvin. The second relief well, started on May 16, has reached a depth of 10,500 feet.
The biggest oil spill ever in the [COLOR=#366388 ! important][COLOR=#366388 ! important]Gulf [COLOR=#366388 ! important]of [/COLOR][COLOR=#366388 ! important]Mexico[/COLOR][/COLOR][/COLOR] — an undersea gusher in Mexico that started in the summer of 1979 and leaked 140 million gallons — was eventually stopped with two relief wells. By some estimates, the BP spill could eclipse that disaster in a week or two; the spill has been put at somewhere between 69 million and 132 million gallons.



BP would need about five days to secure or move all its equipment to safety from an approaching storm but is working to shorten that to two days, Salvin said. The equipment includes ships that are processing the oil sucked up by the [COLOR=#366388 ! important][COLOR=#366388 ! important]containment [COLOR=#366388 ! important]cap[/COLOR][/COLOR][/COLOR] on the well and the rigs drilling the two relief wells.



BP is capturing anywhere from 840,000 to 1.2 million gallons of oil a day. Worst-case government estimates say 2.5 million gallons a day are leaking from the well, though no one really knows for sure.



BP is working to develop a different containment system that would be easier to disconnect and hook back up if a storm interrupted the work.

Is it raining oil <br>in Metro New Orleans?


Is it raining oil
in Metro New Orleans?
River Ridge, LA
Just south of the airport

Powered By YouTube

This video was posted to YouTube on June 22, 2010.

The town River Ridge is up river from New Orleans and near the city's airport.

It rains nearly everyday in New Orleans during the summer months.

What the Bush-Cheney administration failed to do with the levee failures and the non-relief and non-rebuilding efforts, they accomplished by permitting BP to commence an insanely reckless drilling project

This was NOT a normal well.

It's in 5,000 feet of water and is reputed to be close to 30,000 into the earth.

In Russia, where such super deep wells were pioneered, they are only drilled on land and far from human habitations.

At least one prominent oil industry safety specialist warned in writing against the drilling of this well.

This permit was made possible by Dick Cheney's gutting of the federal Minerals Management Service and the Obama administration's very cosy relationship with the oil industry.

Not an "Act of God," not an accident, not an unlucky break.

This catastrophe, which will prove to be bigger than Chernobyl, is the natural outcome of corruption completely out of control.

One thing you can count on:

The victims - and there will be millions of them - will receive no help and no compensation for their losses.

^

Hopefully when this thing hits the Yucatan Peninsula it’ll fall apart and not reform into a hurricane.


Link: http://www.nhc.noaa.gov/refresh/graphics_at1+shtml/023312.shtml?5-daynl#contents

Updates: http://www.nhc.noaa.gov/

Originally Posted by Norton

depression formed off the Yucatan Peninsula

You'd be depressed too if you had that much oil headed towards you.

Some very interesting reading gents in relation to the lead up to this "disaster"

Some heads will certainly roll on this one.

READ ON




HENRY A. WAXMAN. CALIFORNIA
CHAIRMAN
JOHN O. DINGELl. MICHIGAN
CIt/URMAN EMERITUS
EDWARD J. MARKEY. MASSACHUSETrS
RICK BOUCHER. VIRGINIA FRANK PALLONE. JR. . NEW JERSEY ONE HUNDRED ELEVENTH CONGRESS
BART GORDON. TENNESSEE
BOBBY L RUSH. ILLINOIS
ANNA G ESHOO. CALIFORNIA
BART STUPAK. MICHIGAN
ELtOT L ENGEL. NEW YORK
GENE GREEN, TEXAS
DIANA DEGETrE. COLORADO
VICE CHAIRMAN
ctCongrcss of tbc Wniteb $tates
j!)OU£ie of ~epre£iel1tntibe£i
LOIS CAPPS. CAUfORNIA
",IIKE DOYLE. PENNSYLVANIA
JANE HARMAN. CALIFORNIA
JAN SCHAKOWSKY. ILUNOIS
CHARLES A GONZALEZ. TEXAS
JAY INSLEE. WASHINGTON
TAMMY BALDWIN. WISCONSIN
MIKE ROSS. ARKANSAS
ANTHONY D. WEINER, NEW YORK
JIM MATHESON. UTAH
G.K. BunERFIElD. NORTH CAROLINA
CHARLIE MELANCON. LOUISIANA
JOHN BARROW. GEORGIA
BARON P. HILL. INDIANA
DORIS O. MATSUI. CALIFORNIA
DONNA CHRISTENSEN. VIRGIN ISLANDS
KATHY CASTOR. FLORIDA
JOHN SARBANES. MARYLAND
CHRISTOPHER MURPHY. CONNECTICUT
ZACHARY T. SPACE. OHIO
JERRY McNERNEY. CALIfORNIA
BETTY sunON. OHIO
BRUCE BRALEY. IOWA
PETER WELCH. VERMONT
Mr. Tony Hayward
Chief Executive Officer
BPPLC
I St. James's Square
London SWI Y 4PD
United Kingdom
Dear Mr. Hayward:
COMMITIEE ON ENERGY AND COMMERCE
2 125 RAYBURN HOUSE OFFICE BUILDING
WASHINGTON, DC 20515-61 15
MoVOOlTY 1202) 2Z~2 927
FA(;s '.' LE (202) 22~2525
M OIORJTY (202) 22S--3641
energycommerce.house.Qov
June 14, 2010
JOE BARTON. TEXAS
RANKING MEMBER
ROY BtuNT. MISSOURI
DEPUTY RANKING MEMBER
RALPH M. HALt, TEXAS
FRED UPTON. MICHIGAN
CLIFF STEARNS. FLORIDA
ED WHITFIELD. KENTUCKY
JOHN SHIMKUS. ILLINOIS
JOHN B. SHAOEGG. ARIZONA
STEVE BUYER. INDIANA
GEORGE RADANOVICH. CALIFORNIA
JOSEPH R, Pins. PENNSYLVANIA
MARY BONO MACK. CALIFORNIA
LEE TERRY. NEBRASKA
MIKE ROGERS. MICHIGAN
SUE WILKINS MYRICK. NORTH CAROLINA
JOHN SULLIVAN. OKLAHOMA
nM MURPHY. PENNSYLVANIA
MICHAEL C. BURGESS, TEXAS
MARSHA BLACKBURN. TENNESSEE
PHIL GINGREY. GEORGIA
STEVE SCALISE. LOUISIANA
PARKER GRIFFITH. ALABAMA
ROBERT E. LATTA. OHIO
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 ofthe 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: (I) 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. Tony Hayward
June 14,20 10
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 fu ll 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 annul ar space surrounding
these steel tubes. A BP plan review prepared in mid-April reconunended 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 thi s and other
warnings, BP chose the more risky casing option, apparently because the liner option would have
cost $7 to $10 million more and taken longer.
Centralizers. When the fina l string of casing was installed, one key chall enge was
making sure the casing ran down the center of the well bore. As the American Petroleum
Institute's recommended practices explain, if the casing is not centered, "it is difficu lt, ifnot
impossible, to displace mud effectively from the narrow side of the annulus," resulting in a faiku
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 BP lowered the final string of casing with onl y six
centrali zers instead of the 21 recommended by Halliburton. 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 insuffi cient centralizers but commented: "who
cares, it's done, end of story, will probably be fi ne."
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 Halliburton's prediction of severe gas flow problems, BP
did not run a 9- to 12-hour procedure called a cement bond log to assess the integrity of the
cement sea l. BP had a crew from Schlumberger on the rig on the morning of April 20 for the
purpose of rUlUling a cement bond log, but they departed after BP told them their services were
not needed. An independent expel1 consulted by the Committee called this decision "horrib ly
neg I i gent. "
Mud Circulation. In exploratory operations like the Macondo well, wells are generally
filled with weighted mud during the drilling process. The American Petroleum Insti tute (API)
recommends that oil companies full y 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 befo re 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 insuffi cient centralizers created a significant ri sk that the cement job would channel and fail ,
while the deci sion not to run a cement bond log denied BP 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 lockdown 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 BP's
actions.
Background
BP stmt ed drilling the Macondo well on October 7, 2009, using the Marianas ri g. This
rig was damaged in Hurricane Ida on November 9, 2009. As a result, BP and the rig operator,
Transocean, replaced the Marianas ri g with the Deepwater Horizon. Drilling with the Deepwater
Hori zon started on February 6, 20 I O.
The Deepwater Hori zon rig was expensive. Transocean charged BP approximately
$500,000 per day to lease the ri g, 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
8,20 103 In fact, the Macondo well took considerably longer than plarmed to complete. By
April 20, 20 10, 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 deci sions 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 $5 17,000 in September 20 I O. See Transocean, Transocean Fleet Update, fn. II
(Apr. 13, 20 I 0) (online at http ://www.deepwater.com/fw/mainiFleet-Update-Report-58.html).
2 BP, GOM Exploration Wells Me 252 #i - Macondo Prospect Well in/ormation (Sept.
2009) (BP-HZN-CEC0087 14).
J Testimony of Steve Tink, BP, Health, Safety and Environmental Manager, before the
U.S. Coast Guard/MMS Marine Board of Investigation (May 26, 20 10).
Mr. Tony Hayward
June 14, 2010
Page 4
Well Design
Deepwater well s are drilled in sections. The bas ic process involves drilling through rock,
installing and cementing casing to secure the well bore, and then drilling deeper and repeating the
process. On April 9, 2010, BP fini shed drilling the last section of the well. The final section of
the well bore extended to a depth of 18,360 feet below sea level, which was 1,192 feet below the
casing that had previously been inserted into the we1l 4
At this point, BP had to make an important well design deci sion: 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 rurming 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 annul ar flow."s In the case of a
single string of casing, there are just two barriers to the flo w of gas up the arullliar 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 barri ers to annular
flow.,,6 They are (I ) the cement at the bottom of the well, (2) the hanger seal that attaches the
liner to the ex isting 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 more time to install,
requiring several addit ional days to complete.
Internal BP documents indicate that BP was aware of the ri sks 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 ri sks. According to this document, "Long string
of casing . .. was the primary option" but a "Liner ... is now the recommended option.")
4 BP, PowerPoint Presentation, Washington Briefing, Deepwater Horizon Interim
Incident In vestigation at 4 (May 24, 20 I 0).
S Briefing by Tonuny Roth, Vice President of Cementing, Halliburton, to House
Committee on Energy and Commerce Staff (June 3, 2010); Halliburton, PowerPoi nt
Presentation, Energy and Commerce Commillee Staff Briefing at 12 (J une 3, 20 10).
6 Id. at 6.
) BP, MC 252#1 Macondo, TD Forward Plan Review - Production Casing & TA
Options, at 9. (Apr. 20 I 0) (BP-HZN-CEC-221 09). The documents provided to the Committee
from BP contain three versions of this document. This one and a second nearly identical version
(BP, MC 252#1 Macondo, TD Forward Plan Review - Production Casing & TA Options (Apr.
2010)) (BP-HZN-CEC-22025) recommend against a single string casing and in favor ofa 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 cementjob(s),,,g
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 arlllulus,"
• "Primary cement job has slightly higher chance for successfiil cement lift,"
• "Remedial cement job, if required, easier to justify to be left for later." 9
Communications between employees ofBP 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 [aJ nightmare well which has
everyone all over the place, ,, lo
Despite the risks, BP chose to install the singl e 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,13
approach, The third version recommends in favor of the single string of casing and is di scussed
below,
g ]d, "HC" stands for hyd rocarbon,
9 Id, at 10,
10 E-mail from Brian Morel, Drilling Engineer, BP, to Ri chard Miller, BP (Apr. 15, 20 I 0)
(BP-HZN-CEC-2 1857),
II BP, Form MMS 123A1123S - Electronic Vers ion, Applicationfor Revised Bypass (Apr.
15,20 I 0) (BP-HZN-CECO I8357),
12 Id,
IJ E-mail from Frank Patton, MMS, to Heather Powell, JC Connor Consulting
("Modifi cation of Permit to Bypass as Location Surface Lease: 032306 Surface ATea: MC
Surface Block: 252 Bottom Lease: 032306 Bottom ATea: MC Bottom Block: 252 Well Name:
001 Assigned API Number: 608174116901 has been approved, as of2010-04-15 14:39:39,0")
(Apr. 14,20 10), Ms, Powell then forwarded the approval to BP, E-mail from Heather Powell,
Mr. Tony Hayward
June 14, 2010
Page 6
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 e-mailed Alli son 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. ,,14 On March 30, he e-mailed Sarah Dobbs, the BP
Completions Engineer, and Mark Hafl e, another BP Drilling Engineer, that "[ n Jot running the
tieback ... saves a good deal of time/money.,,15 On April IS, BP estimated that using a liner
instead of the single string of casing "will add an additional $7 - $10 MM to the completion
cost.,,16 The same document calls the single string of casing the "[b Jest economic case and well
integrity case for future completion operations.,,17
Around this time, BP prepared another undated version of its "Forward Plan Review."
Notably, this version of the document reaches a di ffe rent conclusion than the other version,
calling the long string of casing "the primary option" and the liner "the contingency option. ,,18
Like the other version of the plan review, this version acknowledges the risks of a single string of
casing, but it now descri bes the option as the "Best economic case and well integrity case for
future completion operations. ,,19
Centralizers
Centralizers are attaclm1ents that go around the casing as it being lowered into the well to
keep the casing in the center of the borehol e. If the well is not properly centered prior to the
cementing process, there is increased ri sk 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 centrali zed, it may lay near or against the borehole wall. ... It is difficult, if not
JC COImor Consulting, to Mark Hafle, Senior Drilling Engineer, BP (Apr. 15,201 0) (BP-HZNCEC021033).
14 E-mail from Brian Morel, Drilling Engineer, BP, to Alli son Crane, Materi als
Management Coordinato r, BP Gulf of Mexico Deepwater Exploration (Mar. 25, 2010). (BPHZN-
CEC02 1880).
15 E-mail from Brian Morel, Drilling Engineer, BP, to Sarah Dobbs, Completions
Engineer, BP, and Mark Hafl e, Senior Drilling Engineer, BP (Mar. 30,20 I 0) (BP-HPCEC02
1948).
16 BP, Drilling & Compielions MOC In iliale (Apr. 15,20 I 0) (BP-HZN-CEC02 1656).
17 / d.
18 BP, TD Forward Plan Review, Produclion Casing & TA Oplions at 6-7 (undated) (BPHZN-
CEC-022 145).
19 1d.
Mr. Tony Hayward
June 14, 20 10
Page 7
imposs ible, to displace mud effectively from the nan-ow side of the annulus if casing is poorly
centralized. This results in bypassed mud charll1els and inability to achieve zonal isolation.,,20
On April 15, BP informed HallibUlton'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 nUU1ing a computer analysis of a number of cement design scenarios to determine
how many centralizers would be necessary to prevent channeling21 With ten centralizers, the
modeling resulted in a "MODERATE" gas flow problem22 Mr. Gagliano's modeling showed
that it would require 21 centralizers to achieve only a "MINOR" gas flow problem23
Mr. Gagliano informed BP of these results and recommended the use of 21 centralizers24
After running a model with ten centralizers, Mr. Gagliano e-mailed Brian Morel, BP's drilling
engineer, and other BP officials, stating that the model "now shows the cement charll1eling" and
that ''I'm going to run a few scenarios to see if adding more centralizers will help us or not.,,25
Twenty-five minutes later, Mr. Morel e-mailed back:
We have 6 centrali zers, we can run them in a row, spread out, or any combination of the
1\\10. 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 centralizers26
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 , 20 10).
22 Halliburton, 9 7/8 " X 7" Production Casing Design Report (Apr. 15,2010)
(HAL_DO 1 0592).
23 HallibUlton, 9 7/8 " X 7" Production Casing Design Report (Apr. 15,20 10)
(HAL_DO 1 0699).
24 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 8 (June 11 , 20 10).
25 E-mail from Jesse Gagliano, Account Representative, Halliburton, to Mark Hafle,
Senior Drilling Engineer, BP, Brian Morel, Drilling Engineer, BP, Brett Cocales, Operations
Drilling Engineer, BP, and Gregory Walz, Drilling Team Leader, BP (Apr. 15,20 10)
(HAL_DO 1 0650).
26 E-mail from Brian Morel, Drilling Engineer, BP, to Jesse Gagliano, Account
Representative, Hallib1ll10n, Mark Hafle, Senior Drilling Engineer, BP, Brett Cocales,
Operations Drilling Engineer, BP, and Gregory Walz, Drilling Team Leader, BP (Apr. 15, 20 10)
(HAL_DO 1 0648).
Mr. Tony Hayward
June 14,2010
Page 8
The following day, April 16, the issue was elevated to John Guide, BP's Well Team
Leader, by Gregory Walz, BP's Drilling Engineering Team Leader. Mr. Walz informed Mr.
Guide: "We have located 15 Weatherford centrali zers 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.,,27 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. ,,28 Mr. Walz
added: "I do not like or want to di srupt your operations . . .. I know the planning has been
lagging behind the operations and I have to turn that around. ,,29
In his response, Mr. Guide raised objections to the use of the additional centrali zers,
writing: " it will take 10 hrs to install them . .. . I do not like thi s and ... I [am] very concerned
about using them. ,,30
An e-mail from 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 perfectl y 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 we' ll get a good cement
job. I would rather have to squeeze than get stuck .... So Guide is right on the
rI.S kJ rewar d equatI.o n. 31
On April 17, Mr. Gagliano, the Halliblllton account representative, was informed that BP
had decided to use only six centrali zers32 He then ran a model using seven centralizers and
27 E-mail from Gregory Walz, Drilling Team Leader, BP, to Jolm Guide, Well Team
Leader, BP (Apr. 16,201 0) (BP-HZN-CEC0022433).
28 Id.
29 Id.
30 Id.
31 E-mail from Brett Cocales, Operat ions Drilling Engineer, BP, to Brian Morel, Drilling
Engineer, BP (Apr. 16, 20 10) (BP-HZN-CEC022670).
32 House Committee on Energy and Commerce, Transcri bed Interview of Jesse Marc
Gagliano, at 40-41 (J une 11 ,201 0).
Mr. Tony Hayward
June 14,20 10
Page 9
found this would likely produce channeling and a failure of the cement job33 His April 18
cementing design report states: "well is considered to have a SEVERE gas flow problem.,,34
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 problem35
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 cementjob.,,36 Nonetheless, BP
ran the last casing with only six centralizers37
Cement Bond Log
A cement bond log is an acoustic test that is conducted by rurming a tool inside the casing
after the cementing is completed. The cement bond log determines whether the cement has
bonded to the casing and surrounding formations. If a channel that would allow gas flow is
found , the casing can be perforated and additional cement injected into the armular 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
I · .. ,,38 a compre lenSlve systems II1tegnty test.
J3 Id. at 8. Mr. Gagliano told the Conullittee that at the time he ran a model with seven
centralizers, he knew of BP's decision to use only six. He told the Conunittee 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.
34 HallibUl10n, 9 7/8" X 7" Production Casing Design Report (Apr. 18,20 10)
(HAL_00I0955).
35 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 43-45 (June 11 ,20 I 0).
36 BP, MC 252#1 Macondo, TD Forward Plan Review - Production Casing & TA
Options, at 9. (Apr. 20 I 0) (BP-HZN-CEC-22I 09).
37 BP, Daily Operations Report - Partners (Completion) (Apr. 18 , 2010)
(HAL_00282 10).
38 Briefing by Tommy Roth, Vice President of Cementing, Halliburton, to House
Committee on Energy and Commerce Staff (June 3, 2010); Halliburton, PowerPoint
Presentation, Energy and Commerce Commillee Staff Briefing at 12 (June 3, 20 10).
Mr. Tony Hayward
June 14,2010
Page 10
Minerals Management Service (MMS) 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."J9
In the case of the Macondo well, the HallibUlton 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 test41 As a result, the Schlumberger crew departed the Deepwater Horizon at approximately
II: 15 a.m. on a regularly scheduled BP helicopter flight 42 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
4' conducting a cement bond log. >
BP's decision not to conduct the cement bond log test may have been driven by concerns
about expense and time. The cement bond log would have cost the company over $ 128,000 to
complete44 [n comparison, the cost of canceling the service was just $10,000.45 Moreover, Mr.
Roth of Halliburton estimated that conducting the test would have taken an additional 9 to 12
hours46 Remediating any problems found with the cementing job would have taken still more
. 47 lime.
39 30 CFR § 250.428.
40 Schlumberger, Mississippi Canyon Block 252 Timeline (undated) (SLB-EC-000002).
41 ld.
42 ld
43 Briefing by Mark Bly, Group Vice President for Safety & Operations, BP, to House
Committee on Energy and Commerce Staff (May 25, 20 10).
44 Schlumberger, Estimated Costs of Equipment/Labor to Pelform the Contingent
Services Identified by BP and the AClual COS/S Upon Cancellalion (SLB-EC-000909).
45 ld.
46 Briefing by Tommy Roth, Vice President of Cementing, Halliblllton, to House
Committee on Energy and Commerce Staff (June 3, 2010).
47 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, GOM Exploralion
Wells MC 252 #lSTOOBPOl- Macondo Prospecl 7" x 9- 7/S" lnlerval at 3 (Apr. 15,2010) (BPMr.
Tony Hayward
June 14,2010
Page II
The Committee staff asked an independent engineer with expel1ise in the analysis of well
fai lure about BP's decision not to conduct a cement bond log. The engineer, Gordon Aaker, Jr.,
P.E. , a Failure Anal ysis 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 BP's decision not to conduct a cement bond log as "horribly negligent. ,,48 Another
independent expert consulted by the Committee, Jolm Martinez, P.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 fu lly
the drilling mud in the well before cementing. This procedure, known as "bottoms up," involves
circulating dri lling mud from the bottom of the well all the way to the sur face. 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 rUlming the casing
and beginning a cementing job. The reconmlended practice states that "when the casing is on
bottom and before cementing, circulating the drilling fluid will break its gel strength, decrease its
viscosi ty and increase its mobility. The dri lling fluid should be conditioned until equilibrium is
achieved .... At a minimum, the hole should be conditioned for cementing by circulating 1.5
annular volumes or one casing volume, whichever is greater. ,,50
HZN-CECO I7621). Mr. Gagliano of Halliburton told the Committee that lost returns are not a
reliab le indicator of channeling: "the amount of returns would not tell you if there's charll1eling
or not. Full returns just indicates the amount of fluid you' re pumping into the well bore, 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 format ion or losing any fluid s. It 's not really an indication of
channeling." House Committee on Energy and Conunerce, Transcribed Interview of Jesse Marc
Gagliano, at 86 (June 11 , 20 10).
48 Briefing by Gordon Aaker, Jr., P.E., Failure Anal ys is Consultant with Engineering
Services, L.P. (Houston), to House Committee on Energy and Conullerce Staff (June 10, 20 10).
49 E-mail from John Martinez, P.E.,an independent production specialist on well bore
construction, to House Committee on Energy and Commerce Staff (June 10,2010).
50 API, Recommended Practice 65-Part 2, Isola/ing Po/en/ial Flow Zones During Well
Cons/rile/ion, 4.8.4., at 36-37.
Mr, Tony Hayward
June 14, 20 10
Page 12
BP's April 15 operations plan called for a full bottoms up procedure to "circulate at least
one ( I) casing and drill pipe capacity, if hole conditions allow. ,,'1 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,,,52 According to Mr.
Gagliano, a Halliburton engineer on the rig raised the bottoms up issue with BPS}
Despite the BP operations plan and the Hallib1ll10n 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 26 1 barrels of mud, just a small
fraction of the mud in the Macondo well. 55 Mr. Roth of Hallibul10n 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 operation56 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 BP's deci sion 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, 20 I 0, Transocean briefed Committee staff on its investigation into the
potential causes of the explosion on board the Deepwater Horizon, In the presentation,
Transocean li sted the lack of a lockdown sleeve as one of its "areas of investigation," Slide
51 BP, GOM Exploration Wells, Me252 #ISTOOPBPOI - Macondo Prospect 7" X 9 7/8 "
Interval, Rev, H.2 at 6 (Apr. 15, 20 10) (BP-HZN-CEC-O 1762 1),
52 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 57 (June 11 , 20 10),
D ld,at 6 1.
54 Id, at 57,
55 Id, at 60,
56 Briefing by Tommy Roth, Vice President of Cementing, Hallib1ll10n, to House
Committee on Energy and Commerce Staff (June 3, 20 I 0),
57 House Committee on Energy and Commerce, Transcribed Interview of Jesse Marc
Gagliano, at 65-66 (June 11 , 20 10),
Mr. Tony Ha)'\vard
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.,,58 Mr.
Roth of Halliburton raised a similar concern in his June 3 briefing for Committee staff59
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 6 0 On April 16, Brian Morel, BP's drilling engineer, e-mailed BP staff
that: "We are still waiting for approval of the depatture to set our surface plug . ... Ifwe do not
get this approved, the displacemenUplug will be completed shallower after running the LDS.,,61
The LDS stands for the lockdown sleeve.
Conclusion
The Conm1ittee'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
n g.
58 Transocean, PowerPoint Presentation, Deepwater Horizon Incident - Internal
Investigation: Investigation Update - Interim Report at 7 (June 8, 2010).
59 Briefing by Tommy Roth, Vice President of Cementing, Hallibutton, to House
Committee on Energy and Commerce Staff (June 3, 2010).
60 BP, GOM Exploration Wells Me 252 #lSTOOBP01- Macondo Prospect 7" x 9- 7/8"
Interval at 8 (Apr. 15, 2010) (BP-HZN-CECOI7621).
61 E-mail from Brian Morel, Drilling Engineer, BP, to Ronald Sepulvado et al. (Apr. 16,
20 10) (BP-HZN-CEC02282 I).
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.
Henry A. Waxman
Chairman
Enclosure
cc: The Honorable Joe Barton
Ranking Member
The Honorable Michael C. Burgess
Ranking Member
Sincerely,
~~
Bart Stupak
Chairman
Subcommittee on Oversight and Investigations
Subcommittee on Oversight and Investigations

Originally Posted by Ripley

Is it raining oil <br>in Metro New Orleans?


Is it raining oil
in Metro New Orleans?
River Ridge, LA
Just south of the airport

Powered By YouTube

This video was posted to YouTube on June 22, 2010.

The town River Ridge is up river from New Orleans and near the city's airport.

It rains nearly everyday in New Orleans during the summer months.

What the Bush-Cheney administration failed to do with the levee failures and the non-relief and non-rebuilding efforts, they accomplished by permitting BP to commence an insanely reckless drilling project

This was NOT a normal well.

It's in 5,000 feet of water and is reputed to be close to 30,000 into the earth.

In Russia, where such super deep wells were pioneered, they are only drilled on land and far from human habitations.

At least one prominent oil industry safety specialist warned in writing against the drilling of this well.

This permit was made possible by Dick Cheney's gutting of the federal Minerals Management Service and the Obama administration's very cosy relationship with the oil industry.

Not an "Act of God," not an accident, not an unlucky break.

This catastrophe, which will prove to be bigger than Chernobyl, is the natural outcome of corruption completely out of control.

One thing you can count on:

The victims - and there will be millions of them - will receive no help and no compensation for their losses.

Are you having a bad hair day, possibly hungover? 30.000 foot deep, where did this number appear? Cheney is not my hero by any means, but to blame him might be a tad prejudicial. Not knowing who was quoted as saying " will receive no help and no compensation for their losses", but that has been shown to be incorrect by monies already paid out and much much more will be paid out. The Russia comment would be disputed by MRT, who drilled a 30,000 foot plus well, some 40 years ago.

Discovery backs theory oil not 'fossil fuel'

New evidence supports premise that Earth produces endless supply

What I've been saying all along...

Discovery backs theory oil not 'fossil fuel'

Golly you are smart, Funny how deep drilling has found no hydrocarbons...at all.