An Engineering Look at the Cause of the 2010 Macondo Blowout

8/12/2019 An Engineering Look at the Cause of the 2010 Macondo Blowout

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IADC/SPE 167970

An Engineering Look at the Cause of the 2010 Macondo BlowoutJohn A. Turley, The Brier Patch, LLC

Copyright 2014, IADC/SPE Drilling Conference and Exhibition

This paper was prepared for presentation at the 2014 IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas, USA, 46 March 2014.

This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have notbeen reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarilyreflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of anypart of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print isrestricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.

AbstractThis paper examines engineering and operating activities during post-discovery temporary abandonment of the Macondo

exploration well that led to and caused the 20 April 2010 blowout and oil spill in the Gulf of Mexico. The paper ignores

finger pointing and hearsay evidence and focuses on data generated on theDeepwater Horizondrilling rig. The forensic trail

defines events that caused and exacerbated a down-hole leak between the pay zone and the lower casing. Subsequent pressure

testing of the wellbore revealed the leak, but the well was declared secure. In further preparation for temporary abandonment,

seawater was pumped down a work string to displace heavy mud from the wellbore and riser. Such displacement caused thewell to flow from the formation, down the annulus, up the casing, above the blowout preventers (BOP), into the riser, up to

the rig, and over the derrick. Crews immediately closed two BOPs, albeit too late to stop the massive flow from within the

mile-long riser. Subsequent explosions and fire killed eleven, sank the rig, and marked the beginning of one of the most

lethal, costly, manmade, environmental disasters in US history. Had industry protocol been followed, and/or had the forensic

data that pointed to the leak or flow been acted upon, the leak would have been repaired and isolated, the wellbore would

have been retested to prove pressure security, and the temporary abandonment would have proceeded as planned.

IntroductionIn April 2010, BP commenced temporary abandonment of their Macondo discovery well aboard Transocean's Deepwater

Horizon drilling rig. During the process the well blew out. Throughout months of media madness that followed, the author

focused only on data, with a simple goal: determine the engineering, operating, and mechanical steps that allowed the well to

flow out of control, on a sophisticated rig, in the face of a technically capable operator and industry. The author gleaned keyinformation and hard data from numerous public sources, including federal, corporate, and academic investigations.

HistoryThe Macondo exploration well (Mississippi Canyon Block 252) was successfully drilled in 4,992 ft of water, and a 9-7/8-in.

liner was ultimately set and cemented at 17,168 ft, as shown in Fig. 1 (Turley 2012). Below that depth, drilling yielded a

high-pressure stringer, a number of lost-circulation zones, and approximately 200 ft of under-pressured pay, which bottomed-

out near 18,200 ft. The well was drilled to a total depth of 18,360 ft with 14.2-ppg synthetic oil-based mud (SOBM) and then

extensively logged, before a pre-casing bit trip (BP 2010a).Given the successful oil-and-gas discovery, the following actionswere taken to prepare the well for temporary abandonment.

Casing and Cement: The discovery well was completed with 7-in.-by-9-7/8-in. production casing, which was hung at18,304 ft (56 ft above bottom) in 8-1/2-in. hole (under reamed to 9-7/8 in. above 18,130 ft). A 7-in. double-valve float collar

with an auto-fill tube was installed at 18,115 ft, above 180 ft of shoe-track casing. The casing was cemented with 5 bbl of

16.7-ppg Class-H (proposed top approximately 17,300 ft), followed by 39 bbl of nitrified cement and 7 bbl of 16.7-ppg Class

H cement in the shoe track (Halliburton 2010, BOEMRE 2011a). The top cement plug was bumped with approximately

1,200 psi at 12:36 a.m. on 20 April 2010. When the 1,200 psi was released, the well gave back approximately 5 bbl, and then

remained at 0 psi without additional backflow.


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Pressure Testing: Temporary abandonment plans called for high-pressure and negative-pressure tests, a lock-down seal ring

(LDSR) on top of the casing hanger, and a 300-ft cement plug inside the casing, below the seafloor.

The well passed all internal high-pressure testsup to 10,000 psifrom the wellhead to the float collar.

Further abandonment activities were related to the next day's threshold eventspulling the BOP stack and riser and

releasing the rig, as shown in Fig. 2(Turley 2012). Because pulling the BOP would cause the loss of 5,000 ft (approximate

water depth) of heavy mud, a negative-pressure test (NPT) was designed to simulate pulling the BOP stack and riser. The

simulation called for running a minimum of 5,000 ft of drillpipe (or using 5,000 ft of kill line), and thenwith the BOP

openfilling the drillpipe (or kill line) with seawater (BOEMRE 2011b). The resulting U-tube pressure (14.2-ppg mudoutside, 8.6-ppg seawater inside) would have been approximately 1450 psi.

Alternatively, Macondo drillpipe (3.5-in. / 5.5-in. / 6.625-in work string) was run to 8,367 ft (BOEMRE 2011a) and filled

with seawater, which yielded a U-tube drillpipe pressure of approximately 2,400 psi. Crews closed the upper annular BOParound the drillpipe to trap the 2,400-psi U-tube pressure and to isolate riser mud from the wellbore. The plan called for

bleeding off the U-tube pressure, thereby reducing the pressure throughout the wellbore (below the BOP) by 2,400 psi.

RegulationsMinerals Management Service (MMS) at the time, became the Bureau of Offshore Energy Management,

Regulation and Enforcement (BOEMRE), and since then the Bureau of Safety and Environmental Enforcement (BSEE)

called for bleeding and holding the test pressure at 0 psi for 30 minutes. The test had two possible successful outcomes:

(1) prove there were no leaks into the casing from outside the casing, which would indicate pressure security, or (2) prove

with equal importancethat pressure leaked from outside the casing to inside the casing, which would require remediation.

The first negative-pressure test (NPT-1), using 8,367 ft of drillpipe, allowed the pressure to be dropped from 2,400 psi to

200 psi without incident. Yet when the pressure was dropped the final 200 psi, the well yielded 15 bbls of seawater from the

drillpipe (BP 2010a). Crews shut-in the drillpipe, at which time the reduced pressure on the drillpipe began to increase.

Records indicate these results were considered anomalous, and NPT-1 was aborted (BP 2010a).

After stopping NPT-1 at approximately 6:00 p.m., the negative-test procedure was shifted to the 5,000-ft kill line (calledNPT-2), where test results ultimately held steady at 0 psi for the mandated 30 minutes. Accordingly, the well was declared

secure at 7:55 p.m. on 20 April (BP 2010a).

Fig. 1Macondo production casing Fig. 2Simulation of abandonment


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Riser Displacement: With the well deemed secure (with

seawater to 5,000 ft), crews opened the BOP and began

displacing heavy mud from the wellbore and riser by injecting

seawater through the drillpipe at 8,367 ft.

Consequences: At approximately 9:40 p.m., the well kicked

through the rig floor, and mud, seawater, oil, and gas erupted

over the derrick. Crews closed the BOP, but the well continuedto blow oil and gas (from 5,000 ft of riser above the BOP),

which ignited and exploded at approximately 9:49 p.m.

(BP 2010a). The ensuing cataclysm killed eleven men andburned and sank the rig. The well blew for 86 days before

being controlled.

Such seemingly benign actions and lethal consequences

justify digging deeper into the above events with a simple goal:

define the steps that led to and caused the blowout.

Post-blowout Forensic AssessmentFirst, there had to have been a leak, which was not seen. Post-

blowout, there was early concern the leak might have been up

the backside of the casing, but modeling of pressures

(BP 2010a) and subsequent post-kill physical examination of

the wellhead proved that was not the case. With evidenceindicating the leak had not manifested during the positive

pressure tests down the float collar, the leak had to have been

from outside the casing, below the float collar. Second, NPT-1

and NPT-2 need further scrutiny, since they were designed to

reveal such leaks. Third, the well could not have been secure, in

spite of the 30-minute, 0-psi test during NPT-2. Fourth, though the well had to have been flowing for a long time (more than

2,000 bbl) before oil and gas breached the rig floor, the flow had

not been detected. Fifth, the closure of the BOP around the

drillpipe did not stop the flow. Associated assessments follow.F

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The Leak: The post-logging-job bit trip played a role, in that a

heavy mud pill (17-ppg, for example) had not been spotted on bottom prior to pulling the bit and running casing. Turley


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(2012) shows this in Fig. 3. To quote API RP 65 Section 7.5: If casing is not run to bottom, the "rat hole" should be filled

with a higher weight mud to prevent cement from falling into the rat hole and displacing rat hole mud into the cement column

. . ."(BOEMRE 2011c; BP 2010b).

The non-standard bit trip and resulting rat-hole contamination of annular and shoe-track cement was likely the inciting

event that contributed to the leak through which the well would flow.

Further, records show that the float collar may have been damaged (by junk?) before the cement job. To wit, rather than

taking a few-hundred psi to break circulation around the just-run casing, it took more than 3,000 psi. Additionally, the float-

collar manufacturer had tested Macondo's 14.2-ppg SOBM to determine the float collar required a throughput of 6 bbl/min toactuate (convert) the two high-pressure, flapper-type check valves, yet the mud/cement pump rate through the float collar

never exceeded approximately 4 bbl/min (BP 2010a).

On two fronts, therefore, the leak was set up through: (1) gravity segregation and contamination of the 16.7-ppg lower-annular and shoe-track cement by 14.2-ppg SOBM from the rat hole, and (2) a possibly damaged and/or non-converted float

collar that precluded its ability to act as a check valve against annular flow into the casing. Note: in spite of the (static) leak,

the well was dead (approximately 1,000-psi overbalanced), and no

formation fluids had entered the wellbore.Fig. 4Negative-pressure test (NPT-1)

Exacerbating the Leak: During NPT-1, the goal was to reduce the

work-string trapped U-tube pressure from 2,400 psi to zero. Such

reduction would reflect throughout the wellbore (under the closedBOP), down to the top of the float collar. Fig. 4shows the necessary

operating sequence for NPT-1. From 5:556:00 p.m.,an attempt was

made to bleed-off the final 200 psi, but after getting back as much as

15 bbl, the test was aborted. But: Where did the 15 bbl come from?

Answer: With the wellbore pressure reduced by more than 2,000 psi,

and without a functioniong float collar, and with contaminated

cement both inside and outside the shoe track, the pay zone had been

enticed to flow. It produced 15 bbl (BP 2010a), which, as shown in

Fig. 3, was enough to clear the annular path from the pay zone down

to the shoe, as well as the 180-foot shoe-track path to and through the

float collar.

The 15-barrel backflow was the first forensic evidence that the

wellbore was in communication with the annulus, and that the cementjob needed remediation (i.e., drill out float collar and squeeze the

shoe, and/or set and test a mechanical plug, and/or set and test several

hundred ft of cement on top of the float collar.)

The Kick: Data forNPT-1 (drillpipe) and NPT-2 (kill-line) are presented graphically in BP (2010a) Page 88, and in DHSG

(2011) Page 62, and in Fig. 5, with annotations by the author.

Sarting at 6:00 p.m., two things changed. First, NPT-1 was aborted (though the BOP was kept closed), and plans were

made to shift the negative-pressure test to the kill line (NPT-2).

Second, immediately following the 15-bbl backflow and closure of the drillpipe, the drillpipe pressure increased (kicked)

on its own at approximately 40 psi/min. By the time the drillpipe pressure reached 1,200 psi, the rate of increase was

approximately 20 psi/min. At approximately 6:30 p.m., pump activity on the kill line (pumping into the closed wellbore

system) caused the drillpipe pressure to jump to 1,400 psi, where it stabilized by 6:35 p.m. The 6:006:35 p.m. drillpipe

pressure points are clearly a pressure-buildup curve.The well had been drawn down so hard it kicked, with 1,400-psi shut-in drillpipe pressure (SIDPP), on top of 8,367 ft of

seawater and approximately 10,000 ft of 14.2-ppg mud.

The pressure buildup curve stands out as the second piece of forensic evidence that indicated the wellbore was in

communication with the annulus, and that remediation of the leak was mandatory.

Back Story: Prior to the NPTs: (1) more than 400 bbl of unused 16-ppg lost circulation materials (LCM) had been pumped

down the NPT drillpipe and up into the lower riser (BP 2010a); and, (2) crews commenced cleaning SOBM from the mud

pits (salvaged in part to a vessel alongside), in anticipation of releasing the rig the next day to a well that would use water-

based mud (BOEMRE 2011b). These activities would later prove deleterious to the abandonment process (discussed below).Fig. 5NPT-1 and NPT-2


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NPT-2 Unveiled: At approximately 6:40 p.m. (with the BOP still closed and the drillpipe stablekickingwith 1,400-psi

SIDPP), a pump was engaged to make sure the 5,000-foot kill line was full of seawater. The kill-line pressure rose rapidly,

but spiked at approximately 500 psi and broke back to approximately 400 psi, at which time the pump was shut off (duration

of this event was three minutes). As evidenced by the simultaneous, unchanged, 1,400-psi SIDPP, pumping into the kill line

and into the otherwise closed wellbore yielded a classic injectivity profile. The kill line had pressured up and fed seawater

into the closed wellbore until balance with the reservoir was reached. Then the increased kill-line pressure broke back,

indicating formation fluid had been pushed back into the open reservoir. Injection into the reservoir would not have been

possible if the top cement plug had not been pushed up the wellbore by the 15-bbl backflow.The 6:406:43 p.m. injection profile was the thirdpiece of forensic evidence that indicated the wellbore was in pressure

communication with the pay zone.

The 1,400-psi kick on the drillpipe (8,367 ft of seawater) should have caused a 450-psi kick on the kill line (5,000 ft ofseawater), though no such evidence was found. This topic will be discussed in the section on LCM.

Further, in order for the 5,000-foot kill line to have been used for NPT-2after NPT-1 was abortedit needed to have

been filled with seawater while the BOP was open (trapping 1,450 psi of U-tube pressure). Then, after crews closed the

BOP, a manual release of the trapped 1,450-psi pressure would have properly initiated NPT-2. Nevertheless, data from the rig

indicate the kill line was "filled" with seawater whilethe annular BOP remained closed around the drillpipe (i.e., the well was

still kicking up the drillpipe, at 1,400 psi, from under the closed BOP). Therefore, the kill line was not properly rigged up for

an NPT, which means: There was no valid kill-line negative-pressure test, no valid NPT-2, for the Macondo well.

Nonetheless, in spite of the ongoing kick on the drillpipe, and with no evidence of the kick on the kill line, and without

having trapped U-tube pressure on the kill line, a residual kill-line pressure of just over 100 psi (source unknown) was bled to

zero at approximately 7:15 p.m. This event started the MMS 30-minute clock, after which the well would be deemed secure.

Bleeding the kill-line pressure (from approximately 100 psi) to 0 psi had no chance of meeting MMS requirements for

simulating the replacement of 5,000 ft of heavy mud with seawater. Further, bleeding anykill-line pressure to zero shouldhave been impossible, as the state of the well was a shut-in kick. Such action to bleed the kill line would have (shouldhave)

caused the well to flow out the kill line.

But when the kill-line wasbled from approximately 100 psi to zero, there was no flow. And we need to know why.

Lost Circulation Materials: The water-base LCM products (more than 400 bbl) were in place in the lower riser for both

negative-pressure tests. The LCM played a minimal role during NPT-1 (drillpipe), but became significant during NPT-2 (kill

line). The LCM materials, which occupied approximately 450 ft of riser, were intended as a spacer between the heavy mud to

be displaced from the riser and the seawater that would do the displacing. The LCM spacer was initially pumped down the

drillpipe and into the lower riser, to just above the BOP, leaving seawater in the drillpipe. Nevertheless, during NPT-1, when

the 2,400 psi of trapped U-tube pressure was being bled from under the annular BOP, the closing pressure of the BOP had to

be continually finessed to prevent leakage. These step-by-step manipulations allowed small batches of heavy-mud to move

down the riser (displacing seawater from the drillpipe), which allowed the LCM to move down the riser and into the maincavity of the BOP stack (BP 2010a).

Data confirm the LCM played a role during kill-line negative-pressure-test activities, with the following observations:

Clear Path: The three-minute injection break-back showed there was a clear path for positive pressure from the kill line

into the wellbore (and into the pay zone), unaffected by the wad of LCM in the BOP.

The Missing Kick: With the kill line thus known to be open to the reservoir, the same kick that generated a 1,400-psi

SIDPP should have generated a 450-psi kick on the kill line. Nevertheless, with LCM filling the BOP stack, evidence

indicates the 450-psi kick was insufficient to pump LCM up the small-diameter (3-1/16-in. 15,000-psi) kill line, which

prevented the (expected) 450-psi shut-in-kill-line-pressure kick from being seen or recorded at the surface.

Isolated Bleed: For the same reason, at the end on NPT-2, when the approximate 100-psi of residual kill-line gauge

pressure was bled to zero, it had to have been bled in isolation from the rest of the wellbore; i.e., only the kill line, blocked by

LCM, bled to zero.

Declaration of Security: There is no hard evidence that indicates there was any action on the rig in response to: (1) thevalidity of three forms of forensic data that pointed to an open leak between the wellbore and the annulus, or (2) the

invalidity of the kill-line activities referred to as NPT-2. Nevertheless, when the kill-line pressure was bled from

approximately 100 psi to zero, it stayed that way from 7:15 p.m. to 7:55 p.m., which met the 30-minute countdown, as

mandated by the MMS. At 7:55 p.m., the well was declared secure (BP 2010a).

Final Temporary Abandonment Activities: Additional procedural steps were required to allow the rig to be released the

next day. Key activities would include: (1) open the BOP, (2) set and test an approximate 300-ft cement plug near 8,300 ft,

(3) install the lockdown seal ring (LDSR), (4) displace all heavy mud from the riser and BOP with seawater, (5) pull the riser

and BOP stack, and (6) release the rig. These steps are variously described in BOEMRE (2011b). BOP: As soon as the annular BOP was opened (after the NPTs), 5,000 ft of heavy mud from the riser once again added

to the hydrostatic head in the wellbore, which overbalanced the reservoir by approximately 1,000 psi. Such surge would have


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caused any minor volume of produced fluid in the wellbore (i.e., the 15-bbl backflow) to be injected back into the reservoir.

Further, the 1,400-psi kick on the drillpipe immediately disappeared, as it should. This is the good-news logic of a negative-

pressure test being asimulationof displacing the wellbore with seawater.

Cement Plug: Though normally placed a few hundred feet below the seafloor, MMS approved setting the plug near

8,300 ft (BP 2010b). Nevertheless, data indicate there was no pre-displacement cement plug installed at any depth.

Lockdown Seal Ring: Installing the LDSR (also called the lockdown sleeve) required 100,000 lbm of hang-down weight.

That weight called for approximately 3,300 ft of heavyweight drillpipe; hence, the 3,300 ft of space between the wellhead

and the cement plug, which justified the NPT-1 drillpipe at 8,367 ft (National Commission 2011). However, data showsthere was no pre-displacement attempt to install the LDSR.

Displacement: Though the well was deemed secure after the (invalid) 5,000-ft test, data indicate the deeperdrillpipe at

8,367 ft was nonetheless used to displace the upper wellbore and riser with seawater. Such displacement commenced at8:00 p.m. During displacement, volumes (and rates) pumped into and received from the wellbore would be measured to

ensure neither gains nor losses. A second goal involved running a sheen test on the LCM spacer once it got to the surface, to

ensure full recovery of the SOBM, after which the remaining water-base returns could be dumped overboard (BOEMRE 2b).

Flow Initiated: Rig data confirm that while crews pumped more than 1,000 bbl of seawater, the drillpipe pressure (seeing

less back pressure from the riser) decreased, as expected (BP 2010a; National Commission 2011). Then, just before

9:00 p.m. (BP 2010a; and see Fig. 6) the well kicked, evidenced when the rate of returns from the riser increased to exceed

the constant rate of seawater being pumped into the drillpipe. This was thefirstpositive indicator that formation fluids were

flowing into the wellbore. During the following ten minutes, the pump pressure on the constant-rate drillpipe increased,

rather than decreased. This secondindicator of flow means heavy mud from below the drillpipe was being lifted by kicking

formation fluids to occupy the drillpipe annulus, thereby increasing the backpressure on the drillpipe.

At 9:10 p.m. the LCM spacer reached the surface, and the well was shut-in for the sheen test. During the test, with pumpsoff, the drillpipe pressure continued to increase, a thirdpositive indicator the well was flowing (and still pushing heavy mud

into the drillpipe annulus). Subsequent to the sheen test (no sheen), seawater continued to be pumped down the drillpipe, and

returns from the riser were discharged overboard without being measured.

With the seawater pumps still pumping, kicking formation fluids flowed and filled the wellbore, entered the riser, and

kept coming. When the shallowest oil and gas finally reached bubble-point depth, gas expansion became autocatalytic.

Near 9:40 p.m., with the well flowing at approximately 100,000 B/D (all estimated flow rates from BP 2010a), the well

kicked through the rig floor and over the derrick. In minutes, mud and seawater yielded to oil and gas, which enveloped the

rig. The initial explosion and fire (9:49 p.m.) may have been in the diesel-engine power-generation room, which caused the

loss of all rig power. In seconds, a more-massive, lethal, explosion and fire wracked the rig, with extensive damage

throughout the facilities. Minutes later, the blocks fell onto the rig floor and onto the otherwise-closed drillpipe. The

blowout continued as a violent inferno, further fed by flowing oil and gas. Eleven men diednine from Transocean and two

from MI-Swaco. Their bodies were not recovered. Injuries to 115 survivors were numerous, some serious.

Blowout Preventers: Post-blowout forensic data by Det Norske Veritas (DNV) at NASA's Michoud facility in New Orleans

would later reveal that rig crews had closed the upper annular BOP and the upper variable bore ram (VBR), and may have

tried to close the blind shear ram (BSR). Yet, the drillpipe that DNV found trapped inside the closed BOPs proved to be

severely fluid eroded, which precluded the BOPs from sealing against the pipe and stopping the flow. Further, DNV found a

tool joint crammed by the high flow rate under each closed BOP. Excess drillpipe trapped between the two closed BOPs was

found to be corkscrewed and elastically buckled in the body of the BOP stack, which further precluded the blind shear ram

(BSR) from fully closing, shearing the pipe, sealing the well, and stopping the flow (BOEMRE 2011c; DNV 2011).

The Emergency Disconnect System (EDS) was initiated by surviving personnel away from the burning rig floor

approximately seven minutes after the explosions. The EDS failed to release the lower marine riser package (LMRP) from

the main BOP stack, and the burning, abandoned rig remained on station, connected by the riser to the flowing well, untilmid-day on 22 April, when it sank to the seafloor. The well flowed for 86 days before being killed.


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Fig. 6Sequence of events Fig. 7The cause of the blowout

ConclusionsThe paper shows (see Fig. 7), from an engineering perspective, the events that led to and caused the blowout:

(1) A potential open, albeit static, leak was formed during casing and cementing operations by rat-hole mud contamination of

the otherwise-cemented path between the formation and the wellbore.

(2) Negative-pressure-testing activities through drillpipeNPT-1: (a) exacerbated the unseen leak by flowing 15 bbl fromthe reservoir, (b) generated forensic pressure-buildup data that confirmed the reservoir was kicking into the wellbore, and

(c) confirmed the possibly mechanically damaged, non-converted float collar did not block such flow.

(3) After NPT-1 results were declared anomalous, an invalidly executed kill-line negative-pressure test (NPT-2)which was

also isolated from the wellbore by LCM in the BOPgenerated invalid results that allowed the well to be deemed secure.

(4) Subsequent displacement of heavy mud from the riser with seawater caused the well to flow through the open leak.

(5) The flow from the well escalated, unseen, yet generated evidentiary data in the form of: (a) differential barrels, which

showed more fluid rate out of the well than the seawater being pumped in; and, (b) increasing static and dynamic drillpipe

pressures, which were the result of formation fluids pushing heavy mud up the wellbore, around the drillpipe.

(6) The resulting high-pressure, high-flow-rate kick through the rig floor further escalated in spite of closed BOPs, fueled by

additional oil and expanding gas from the riser above the closed BOPs.

(7) The BOPs were found to have been disabled by flow-related fluid erosion and elastic deformation of the drillpip.

(8) Post-blowout, the EDS failed to release the LMRP, preventing the rig from leaving the location.

SignificanceThe paper defines the sequential engineering and operating steps that caused the 2010 Macondo blowoutone of the most-

lethal, costly, manmade, environmental disasters in US history. The work is invaluable to petroleum engineering faculty and

students, and to industry personnel (operators and contractors, rig and office, offshore and onshore) who study, justify, plan,

design, fund, and are responsible for executing drilling activities. No aspect of the Macondo blowout can be blamed on the

water being too deep, or on pressures and temperatures being too high, or on required technologies being too demanding.

Every step of the disaster, of each piece of forensic data, is understandable and controllable relative to petroleum engineering

fundamentals and standard oil-&-gas industry practices. Further, such information is vital to ongoing industry-wide efforts to

use, improve, and develop educational and training programs, as well as drilling-process-safety, real-time-data, and safety-


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and-environmental-management systems. The spirit of the paper is simply: Only if we care about and understand the cause

of the 2010 Macondo blowout, will we know why it should not have happened and why it should never happen again.

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%20 for%20 BOEMRE%20Volume%20I.pdf

(5) HalliburtonFoamed Production Casing Post Job Report. http://www.boemre.gov/pdfs/maps/HalliburtonReport10.pdf. 20 April 2010

(6) National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. 11 Jan 2011. http://www.oilspillcommission.gov/

See also: http://www.gpo.gov/fdsys/pkg/GPO-OILCOMMISSION/pdf/GPO-OILCOMMISSION.pdf

(7) Turley, J.A. 2012, The Simple Truth: BP's Macondo Blowout, Littleton, Colorado, The Brier Patch, LLC

Conversion Factors

bbl ! 1.589 873 E"01 = m3

ft ! 3.048* E"01 = m

in. ! 2.54* E+00 = cm

mile ! 1.609 344* E+00 = km

lbm ! 4.535 924 E"01 = kg

psi ! 6.894 757 E+00 = kPa

An Engineering Look at the Cause of the 2010 Macondo Blowout

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Transcript of An Engineering Look at the Cause of the 2010 Macondo Blowout