Macondo Well Deepwater Horizon Blowout Lessons for Improving Offshore Drilling Safety (2012) / Chapter Skim
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3 Blowout Preventer System
3 Blowout Preventer System
Pages 45-74
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From page 45... ...
. During offshore drilling, the system is deployed and attached to the wellhead to seal an open wellbore, close the annular portion of the well around the drill pipe or casing, or cut through the drill pipe with steel shearing blades and then seal the well.
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From page 46... ...
A limiting factor was the maximum allowable differential pressure across the annular preventers. Reportedly, the upper annular preventer was designed for up to 10,000-psi differential pressure for sealing against a drill pipe or 5,000 psi when sealing the entire hole.
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From page 47... ...
Even if no drill pipe was present in the BOP system, the BSR was designed to seal the well when the "scissor blades" passed by each other and into the side packers. FIGURE 3-1 Deepwater Horizon BOP port side.
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From page 48... ...
FIGURE 3-3 Upper and lower shear blades crushing the drill pipe and beginning the shearing (or breaking) operation.
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From page 49... ...
These rams had metal-reinforced elastomeric annular elements that, similar in function to the annular preventers in the LMRP, were designed to seal off the annular space between the drill pipe and the BOP system. The VBRs were more structurally robust than the annular preventers but were to close on only a narrow range of pipe diameters.
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From page 50... ...
Further complicating the ram design envelope is the fact that the drill pipe joints ("tool joints") are necessarily thicker than the drill pipe itself to accommodate geometrically the threaded portions of connecting drill pipe and to transmit the drilling torque between them.
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From page 51... ...
The design of the BOP system for the Deepwater Horizon focused on the use of the BSR under controlled conditions when tension in the drill pipe can be assured, and this appears to be the only way that BOP shear rams are tested. Tension would be lost, for example, if the drill pipe and the drill rig became disconnected because of an accident or explosion and the drill pipe moved downward into the well.
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From page 52... ...
"All subsea BOP stacks used for deepwater drilling should be equipped with two blind-shear rams" was the conclusion of SINTEF (Stiftelsen for Industriell og Teknisk Forskning) in a study for MMS in 2001 (Holand and Skalle 2001, 96)
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From page 53... ...
In addition, the shear ram is unlikely to be able to sever drill pipe tool joints or heavy wall pipe such as drill collars. This means that careful housekeeping must be maintained to ensure that the correct type of pipe is in the correct position inside the BOP stack, particularly if only one shear ram exists on the BOP stack.
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From page 54... ...
CSRs are installed in the BOP stack below the BSR so that the casing rams can be used to sever thicker pipe, and then the drill string above the casing rams can be raised out of the way so that the BSR can be closed and the well sealed. Some BOP stacks use a second BSR below the CSR to create a second opportunity to shear and seal the well, which basically ensures that at least one BSR will not have a drill pipe tool joint in front of it.
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From page 55... ...
The data received primarily included shear rams having both blades ‘V' shaped.4 The two data points from shear rams that did not have both blades ‘V' shaped [as was the case on the Deepwater Horizon] were excluded from statistical consideration" (West Engineering Services 2004, 4-2)
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From page 56... ...
EQE Control System Risk Analysis According to a risk assessment of the Deepwater Horizon BOP control system conducted by EQE International, a major contributor to the failure likelihood associated with the system was the selected stack configuration. "With only one shear ram available capable of sealing the well in, it is extremely difficult to remove all the single failure points from the system."5 Specifically, (a)
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From page 57... ...
DNV's "reliability-on-demand" estimate of 99 percent does not reflect an important consideration for any crisis or panic situation: the drill pipe joints, which are nearly impossible for conventional BSRs to sever, make up 5 to 8 percent of the total pipe length. There is obviously a significant risk that a single BSR could be confronted with a tool joint and would fail to sever the pipe and seal the well 7 Information concerning the presentation was not included in the prepublication version of this report, which was issued in December 2011.
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From page 58... ...
However, the 99 percent estimate appeared to be consistent with industry's perception before the Deepwater Horizon incident that BOPs are safe and reliable.
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From page 59... ...
After the March 8 "well control event" on the Deepwater Horizon, OpenWells records: "Stripped drill pipe through upper annular preventer from 17,146 ft.
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From page 60... ...
60 Figure Figure 3-4: Macondo Well blowout timeline FIGURE 3-4 Macondo well blowout timeline. Source: Committee.
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From page 61... ...
. 10 Testimony of Michael Fry, April 6, 2010, Hearing Before the Deepwater Horizon Joint Investigation Team, 72.
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From page 62... ...
. The asymmetric dents in the drill pipe sheared by the rams [impressed into steel 0.350 inch thick (DNV 2011a, I, 128)
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From page 63... ...
If the BSR was still open, approximately 30 gallons of fluid would visibly discharge from the open side of the BSR and ST Locks. FIGURE 3-5 Finite element analysis model of BSR blade surfaces and off-center drill pipe.
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From page 64... ...
Incident management team (IMT) responders, who were monitoring ROV operations when the autoshear was activated, reported that movement was observed on the BOP stack.
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From page 65... ...
After the drill string contents blew out, it would no longer have significant communication with the well for a period of time in the face of 900,000 pounds of clamping pressure on the output end of the severed drill string. However, this scenario does not appear to be borne out by witness descriptions of the fire.
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From page 66... ...
. On the basis of the assumption that the entire length of drill string was filled with seawater being used to displace the drilling mud, at 0.445 psi per foot the seawater added another 7,546 0.445 = 3,358 psi of hydrostatic head to the internal drill pipe pressure measured on the rig, for a total pressure inside the end of the 5½inch section of drill string of approximately 5,600 psi + 3,358 psi = 8,958 psi.
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From page 67... ...
Transocean calculates that the drill string parted above the upper annular preventer through excessive tensile load at 21:56, approximately 6 minutes (Transocean 2011a, I, 157) after the explosions, as the powerless Deepwater Horizon drifted off station.
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From page 68... ...
, and attempts to regain control by using the BOP were unsuccessful. The BSR failed to sever the drill pipe and seal the well properly, and the EDS failed to separate the lower marine riser and the Deepwater Horizon from the well.
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From page 69... ...
However, regardless of when the BSR was activated, the well continued to flow out of control. Finding 3.9: DNV hypothesized that the drill pipe below the annular preventer was being forced upward by the pressure of the flowing well, resulting in a 115,000-pound net compressive force on the drill pipe in the BOP sufficient to buckle the drill pipe until it came in con
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From page 70... ...
Finding 3.12: Flow from the well then exited the partially severed drill pipe in the BSR and began to erode parts of the ram and BOP stack by fluid flow. Finding 3.13: After the vessel sank at 10:22 on April 22, 2010, the ma rine riser with the drill pipe inside was bent at a number of places, in cluding the connector to the BOP, and oil and gas began to flow into the ocean.
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From page 71... ...
One shuttle valve is used by both control pods.
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From page 72... ...
7. There was a lack of BOP status monitoring capabilities on the rig, including Battery condition, Condition of the solenoid valves, Flow velocity inside the BOP system, Ram position, Pipe and tool joint position inside the BOP system, and Detection of faults in the BOP system and cessation of drilling operations on that basis.
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From page 73... ...
It does mean that the BOP design should be such that for any drill string being used in a particular well, there will always be a shearable section of the drill pipe in front of some BSR in the BOP.
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From page 74... ...
If the consequence of losing communication and status monitoring of the BOP system is an automatic severing of the drill pipe and discon nection from the well, the quality and reliability of this communica tion link will improve dramatically. Recommendation 3.9: BOP systems should be designed to be testable without concern for compromising the integrity of the system for fu ture use.
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