macondo history

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There is a saying that no single incident can cause a worst-case blowout scenario because proper drillingprocedures require multiple blowout prevention measures, further backed by spill-containment and disaster-

recovery plans in case a blowout nonetheless occurs. Accordingly, there are many potential failure points to

consider with the Macondo well as the damage continues to unfold.

Much new information has come out over the last several weeks, including documents from BP, Transocean

and Halliburton, along with sworn testimony from management and workers involved with various aspects of

the well. This write-up is intended to summarize that information for non-technical readers and to highlight the

critical issues that may have contributed to the blowout.

The causes of the blowout are not yet certain. Most of the downhole evidence has been destroyed by the blow

out or will be dstroyed by the relief wells so the exact causes may never be known. Moreover, a lot of informa

tion that might be useful has not yet been released, and some of the testimony and information that has been

provided is sketchy, self-serving or contradictory. Accordingly, the story is still evolving and may evolve for years

because the extreme stakes in any shifting liability, along with criminal prosecution threats, have understand-

ably put lawyers at the head of the company information flow.

Nonetheless, the information available so far is important and insightful. Most of the technical information avail

able has been extracted and released by the US House Committee on Energy and Commerce and by a joint task

force formed by the US Coast Guard and the US Bureau of Ocean Energy Management, Regulation, and Enforce

ment, or the BOEMRE. The BOEMRE was formerly part of the Minerals Management Service, which has been

restructured as a result of their perceived failure in the oversight of of fshore drilling.

The blowout will certainly have far-reaching consequences. Apart from the current US drilling moratorium, pre-

liminary results from the investigations are already shaping new legislation and regulations that will have a

major impact on future US of fshore operations, and will likely lead to changes around the globe.

The Lease

The Macondo prospect was on Mississippi Canyon Block 252, which is a 5,760-acre block that sits 50 miles

offshore Louisiana in about 5,000 feet of water. The block had been leased to BP in the US Minerals Manage

ment Service (MMS) lease sale #206 in March 2008. The bonus bid that BP paid for the block was $34 million

Six bids had been submitted for the block and BPs bid won by a narrow margin.

2401 Fountain View Dr., Suite 20

Houston, Texas 77057

713.780.213

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The Macondo WellPart 3 in a Series about the Macondo Well (Deepwater Horizon) Blowout

by Paul ParsonsJuly 15, 2010

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BP submitted an Initial Exploration Plan to the US Minerals Management Service in February 2009. The plan

called for drilling two exploration wells to search for oil objectives, with estimated spud dates of April 2009 and

April 2010. Both wells were to be drilled by Transoceans Marianas rig.

Macondo Prospect

In September 2009, BP prepared an internal well plan for the first well, called the Macondo Prospect. The plan

indicated that the well would be drilled in 4,992 feet of water and would penetrate 14,569 feet below the ocean

floor. The well would be testing two target intervals a primary objective at 13,319 feet deep and a second

ary objective nearer the well bottom. These objectives were in deep sandstone formations, possibly underlying

the thick salt layer that blankets much of the deepwater Gulf of Mexico, although little information has beenreleased about the well geology and there has been no mention of the presence of salt.

While all deepwater drilling is complex, the Macondo Prospect was not unusually challenging for the Gulf of

Mexico from either a water-depth or well-depth standpoint. In about 5,000 feet of water, it was just entering

ultra-deepwater territory and was in much shallower water than the 10,000 foot record depth set by Chevron

in 2003 using Transoceans Discoverer Deep Seas drillship. Also, the 14,569 foot targeted depth was not par

ticularly deep for the area and was far less than the 31,000 foot drilled-depth record set by BP in 2009 using

Transoceanss Deepwater Horizon the same rig ultimately used for the Macondo well. Moreover, the Macondo

Prospect was to be a straight vertical well whereas many wells have deviated and/or horizontal sections, which

are more difficult.

The well plan included an estimate that the well would cost $96.1 million based on a drilling time of 77 days

This was described as the AFE estimate, which means it was presumably the estimate used for BP to obtain

internal approvals and approvals from partners. However, a target drilling schedule was also presented that

was only 52 days. The target had a tighter schedule for drilling each section of the well and consolidated the two

casing sections at the bottom of the hole into one long section to save casing-setting time.

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The Participants

The well plan stated that BP did not yet have a partner for the well but that one was expected. Subsequent to

that document date, Anadarko Petroleum Corporation acquired a 25% interest in the block and a 10% interest

was acquired by MOEX USA Corp, which is owned by a consortium of Japanese companies with Mitsui holding a

majority share. Terms of the acquisitions have not been disclosed. Anadarko had bid on the block at the lease

sale and had been the last-place bidder with a $2.1 million bid. Anadarko is a capable deepwater operator itself

while Mitsui is a passive, non-operating investor.

The Contractors

In preparation for drilling, BP lined up some of the largest and most-reputable contractors in the industry. As

mentioned, Transocean was hired as the drilling contractor. Weatherford International was hired for casing in

stallation. Halliburton was hired for cementing services and directional drilling support. Schlumberger was hired

for wireline logging. M-I SWACO, a division of Smith International, which was recently acquired by Schlumberger

was hired for mud services. The wellhead and installation support were provided by Dril-Quip.

Drilling Begins

BP reports that the Marianas rig began drilling the Macondo prospect on October 6, 2009. The rig set two con

ductor pipe sections to protect the top part of the well and then drilled the first hole section and set 22 casing

After drilling the next hole section, while installing 18 casing, significant problems with the blowout preventer

(BOP) were noted. On November 1st, after the 18 casing was set, the BOP was unlatched and brought to the

rig for repairs.

Hurricane Ida passed through the area on November 8-9 before BOP repairs were complete. The rig subsequent

ly experienced electrical problems, which led to the discovery of electrical wiring damage. Marianas had to leave

the site on November 26th to undergo repairs. At that point, 3,900 feet had been drilled out of the planned tota

drilled depth of 14,569 feet.

BP did some rig-schedule shuffling and brought Transoceans Deepwater Horizon rig on site to finish the well

The well was re-entered on February 9, 2010.

The Deepwater Horizon is one of the most-capable ultra-deepwater rigs in the industry and had been under

contract with BP since its launch in 2001. It is likely that the Deepwater Horizon was a good bit more expensive

than the Marianas, so both the aborted start by the Marianas and the change to the Deepwater Horizon may

have put some early pressure on the well budget.

Additionally, the 18casing section drilled by the Marianas was only about half of its 2,000 foot planned length

described in the well plan, leaving the well 1,000 feet shallower than planned at the 18 casing point. No explanation has been given for this unfavorable development.

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Well Layout

Figure 1 shows the layout of the Macondo well as actually drilled. There were two conductor strings plus seven

casing strings, of which, three were long strings that ran the full length of the well (at the time they were set

and four were shorter liners. The horizontal and vertical scales in the diagram are not matched in order to

show more detail. However, within each scale, the hole section widths and lengths are somewhat correct rela

tive to each other. The size of the wellhead is greatly

exaggerated in order to afford a view of the casing

hanger and seal, which are important to discussions

of potential causes of the blowout.

Out of sight above the blowout preventer connecto

shown at the top of the diagram are the BOP stack

and a riser leading from the top of the BOP to the

rig.

The drilling process for each well section will be

briefly described in subsequent sections to provide

a background before potential causes of the blow

out are covered. Some of the information used in

the descriptions has been disclosed, some is based

on common practice or industry standards, and

some has been surmised from related data (i.e., if

it was disclosed that BP used a certain type of too

in one hole section then it may have been assumed

they used the same or a similar tool in other sec

tions). Accordingly, the following descriptions should

be viewed as an attempt to arrive at the facts rathe

than hard factual knowledge.

Readers should keep in mind that subsea drilling

is much more sophisticated than land or shallow

water drilling because the wellhead is far below the

rig and is in water much deeper than human diving

capability. Accordingly, deepwater well equipment is

designed for remote installation and operation, and

the installation tools are designed to accomplish

the maximum amount of work possible in one drill

string trip because a round trip can cost $200,000

or more of rig time in the deeper sections of the well

Many of the tools are driven by a sequence of drill

string actions such as applying weight, lifting, rotat

ing, adjusting pump pressure, or pumping wiping o

triggering devices down the pipe. Remotely operated

vehicles (ROVs) are also used to assist operations.


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Fig. 1 - Macondo Well Layout


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36 Conductor Pipe

Whether on land or in the ocean, the topmost layer of soil tends to be loose and can easily fall into the hole.

This is particularly true in the deepwater Gulf of Mexico where the ocean floor is covered by a thick layer of oozy

mud. Accordingly, a thick-walled conductor pipe is used to line the top part of the hole before drilling begins. A

wellhead housing is installed on top of the pipe to serve as a protective positioning base for the wellhead when

it is installed later.

In some parts of the world, the conductor pipe is driven into the soil, but in thedeepwater Gulf of Mexico, the conductor pipe can be jetted into the thick mud

The conductor assembly is hung on drillpipe with a bit at the end such that the

bit slightly protrudes from the bottom of the pipe. Seawater is pumped through

ports in the bit under high pressure to sweep away the mud so that the pipe can

sink. The bit is positioned to begin drilling the next hole section after the pipe is

set. (See Figure 2).

After the pipe reaches its targeted depth in this case 254 feet jetting is

stopped and the mud will settle back around the outside of the pipe within a few

hours, holding it firmly in place.

Sometimes a funnel-topped guide base is installed before the conductor pipeto help guide it in. Sometimes the guide base has guide wires running back

to the rig to make it easier to lower tools to the hole. With the Macondo well

it appears that no guide base was used. The pipe would therefore have been

positioned at the starting location using signals from guide buoys placed on the

ocean floor plus camera suppor t from a remotely operated vehicle.

The 36 conductor pipe was the thickest pipe used on the Macondo well. The

pipe walls were 2 thick near the top of the string and 1-1/2 thick joints were

used for the bottom portion. Conductor pipe joints are about 40 feet long.

28 Second ConductorAfter setting the 36 conductor, drilling began. This first drilled section was used

to install a second conductor pipe string down to 1,150 feet. It was 28 wide and

had walls thick.

Protection is important in this section because shallow aquifers can interfere

with the wellbore. The second conductor also strengthens the top part of the well

to add more support to the wellhead in the soft mud on the ocean floor.

During drilling, seawater was jetted through the bit to wash away cuttings, which

fell to the ocean floor. (See figure 3). The bit shown in the diagram is a simplifica-

tion. The actual drilling tools used included a combination of two cutters a 26

bit and a 32-1/2 widener above (following) the bit.

The hole was drilled wider than the 28 conductor pipe because the conductor

pipe installed in this hole was cemented in place and there had to be room for

the cement between the outside of the conductor pipe and the wellbore walls. In

this case, BP allowed 4-1/2 for cement.

Next, is a review of how the pipe was installed and cemented.

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Fig. 2 - Jetting in 36 Conductor Pipe

Fig. 3 - Drilling 28 Conductor Hole


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Installing the 28 Conductor Pipe

The 28 conductor pipe was lowered into the hole on drill-

string. (See Figure 4) On the bottom was a guide shoe with

rounded edges that kept the pipe edges from catching on the

sides of the hole as it was lowered. The guide shoe also had

one or more ports to allow wellbore fluid (seawater) to flow

through the pipe as it was lowered. The same ports would

later be used to pump cement through during the cementing

process.

Centralizers were probably used on at least a portion of

the pipe to keep it centered in the hole. Centralizers are bow-

spring devices that are secured around the outside of the

pipe to force the pipe away from the wellbore walls in all di-

rections. This is necessary to ensure an even flow of cement

around the pipe.

On the cut-away view in Figure 5, the inside of the float col-

lar is visible. The float collar has a hole in the center which is covered by a one-way flap valve. The flap is locked

open while the pipe is lowered into the hole so that fluid can flow through as the pipe sinks. Later, the flap wilbe unlocked so that outflow can pass but backflow cannot. This ensures that heavy cement pumped out the pipe

and up the annular space between the outside of the pipe and the wellbore walls would not backflow into the

pipe after the pumping pressure stops.

A cement plug tool is installed at the top of the conductor string. As illustrated in the next few graphics, these

plugs are used to separate the cement from the seawater to prevent contamination of the cement.

After the pipe is on the bottom, the locking mechanism

in the float collar is converted to allow the flap to close

There are a variety of designs to accomplish this, and

one method is to place a ball in the drillstring and pump

it through the float collar, which shears a pin that holdsthe flap open. (See Figure 6) The float collars for the

Macondo well were reportedly similar to this design ex-

cept that they had double flap valves and the ball was

caged into the float collar rather than dropped through

the drillstring. Readers should remember the conversion

procedure because it will be referred to later when dis-

cussing the final casing string (BP had difficulty with the

conversion).

After the conversion is successful, the well is circulated

to remove all cuttings and debris. (See Figure 7). As a

general rule, at least one casing/conductor pipe volumeis circulated before cementing to verify that there is no

debris in the casing that could block the float collar (such

as a glove unknowingly dropped in the hole by a rig hand). Discovering a blockage during cementing would be a

costly mistake. It is also desirable to have at least one bottoms-up circulation (fluid at the bottom of the hole

circulated out) to thoroughly remove gas, cuttings and other debris that may have entered the wellbore. If the

circulation of the casing volume does not also accomplish a bottoms up, the pumping usually continues until

both are achieved. Readers should remember this process also because it will be referred to later. (An abbrevi

ated circulation of the final hole section may have had a role in the blowout.)

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Fig. 4 - Lowering in 28 Conductor Pipe Fig. 5 - Cut-Away View of Conductor Pipe

Fig. 7 - Circulating to Clean out the HoleFig. 6 - Coverting the Float Collar Valve


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Cementing

An understanding of the cementing process is important because the possibility of a poor cementing outcome

on the final section of casing is one of the key considerations as the initial cause of the blowout. Subsea ce

menting tools and procedures are complex and a highly-simplified overview is shown in Figures 8-11. The pro-

cess for cementing each section is similar so these graphics will be shown only once.

On the rig, a high-pressure control device called a cementing head (not shown) is attached to the top of the

drillstring. A seawater line and a cement line are attached to the cementing head so that flows can be alternated.

After circulating seawater to clean out the hole, a device called a bottom plug dart is released from the ce-

menting head ahead of the cement as cement pumping begins. When the dart reaches the cement plug tool

it is caught by a receptacle that triggers the release of the bottom plug. (Figure 8) The bottom plug has elas-

tomer wiper blades that press against the inside of the casing and it push all seawater out of the way as it is

pushed downward by the pressure of the cement, thus preventing contamination of the cement.

After all of the cement is pumped a top plug dart is released from the cementing head. Then seawater pump

ing begins. When the dart reaches the cement plug tool, it triggers the release of the top plug. (Figure 9) The

top plug prevents seawater from contaminating the uphole end of the cement slurry.

Seawater pumping continues. When the bottom plug reaches the float collar, a rubber membrane in the plug

ruptures so that cement can flow onward while the plug is retained in the collar. (Figure 10) The cement flows

out the shoe and up the annular space between the outside of the casing and the wellbore walls.

Eventually, the top plug will land in the float collar and will block off any further flow. This is called bumping the

plug. (Figure 11) The cementing contractor on the rig looks for a spike in drillpipe pressure to indicate when

the plug has bumped. Pumping is then stopped and a small amount of backflow is allowed to cause the f lappe

valve to close. Then, the cement plug tool is disconnected and returned to the rig and the cement is allowed to

harden for an interval called waiting on cement, or WOC. This is clean-up time on the rig.

For this section of the well, a

volume of cement was pumpedto cause the top of the cement

to reach all the way up to the

mudline by the time that the

plug bumped. Further downhole

most sections will be cemented

only partway up the open hole.

The space between the shoe

and the float collar is called the

shoe track and will be filled

with cement after the cement

job. Normally, the shoe andfloat collar are separated by 1-4

joints of casing/conductor pipe

which are about 45 feet long, so

a shoe track would be roughly

50-200 feet long.


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Fig. 10 - Port Opensin Bottom Plug Fig. 11 -Top Plug Lands(Bumps)Fig. 9 -

Release Top PlugBehind Cement

Fig. 8 - Release Bottom PlugAhead of Cement


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22 Casing

After the cement was set on the 28 conductor, drilling began on the section for the 22 casing. The bit first had

to drill through the prior shoe track.

The plugs, float collar, and guide shoe

are all non-metallic and are designed

to be drilled without damage to the

bit.

The bit used for this section was 26

wide. Seawater was used as a drilling

fluid, and cuttings were allowed to

fall to the ocean floor. (Figure 12)

After reaching the section bottom,

22 pipe was lowered into the hole

with a wellhead securely welded on

top. (Figure 13) The wellhead had a

locking mechanism that locked into

position in the wellhead housing

when it landed. The inner diameter of

the wellhead is 18.51 so everything passing through the well after that point can be no wider than that diam-

eter. The pipe with the wellhead attached is considered the first section of casing (versus conductor pipe) and

is called the surface casing.

BP installed two supplemental hanger adapters into the 22 casing string. (Figure 14) These were to be used

to hang off the 18 and 16 casing strings when those sections were drilled. The purpose of supplementa

adapters is to allow the use of more casing hangers than could fit into the limited space in the wellhead.

The string was lowered on drillpipe along with a cement plug tool and was cemented back to the mudline like the

28 conductor string. For simplicity, the central-izers, float collar and guide shoe will be ignored

in this and further graphics.

After the wellhead was securely cemented, the

blowout preventer (BOP) was lowered down on

the bottom of riser pipe and was latched to the

wellhead. (Figures 15 and 16). This link created

a sealed conduit from the well to the rig and al-

lowed the use of drilling mud rather than sea-

water. (Figure 17) After the riser is connected,

it is very important to have mud and the BOPemployed for well control because any blowout

would erupt on the rig floor.

Before proceeding with the well sections, the

purpose of mud, the riser, the blowout preventer

and the diverter will be briefly described.


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Fig. 12 - Drilling Hole for 22 Casing Fig 13. - Lowering Casing and Wellhead Fig. 14 - Locked & Cemented

Fig. 15Lowering

BOP

Fig. 16BOP

Latched

Fig. 17DrillingAhead


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Mud

All wells require some kind of drilling fluid to be circulated through the hole to remove cuttings. Drilling fluid is

pumped through the drill string under high pressure and it exits from nozzles in the bit that are positioned to

wash away cuttings as they occur. The drilling fluid carries the cuttings to the surface through the space be-

tween the outside of the drill pipe and the formation walls, which is called the annulus. When the mud returns

to the rig, the cuttings are removed and the mud is re-circulated.

Drilling fluid is called mud because it looks like mud, but it is a carefully-managed mix of powdered clay (primar

ily bentonite) and weighting agents (like barite), with chemical additives to control the mud characteristics. The

base fluid for drilling mud is either water, oil or synthetic oil.

The Macondo well used synthetic oil based mud (SOBM), which is an environmentally-friendly derivative of oil

based mud. Advantages of SOBM are high lubricity for the drillstring, tolerance of high temperatures, and a bet

ter (reduced) reaction to certain types of formations such as salt and shale.

Mud performs several important functions in addition to removing cuttings from the hole:

Mud cools and lubricates the drill string and bit

Muds weight counters formation pressures downhole. The bit may encounter high-pressure zones of oil,

gas or water and mud weight helps prevent gas or fluids from invading the wellbore, which would cause a

backflow that could lead to a blowout at the surface.

Mud deposits a protective coating on the wellbore walls called filter cake Filter cake is formed because

wellbore pressure pushes small amounts of mud liquid into surrounding formations while the thicker com

ponents in the mud cannot follow and are filtered out and compressed against the wellbore wall. Filter

cake pressure reduces formation crumbling into the hole and provides a seal that reduces mud loss and

mud contamination into surrounding formations.

Mud can provide hydraulic power for downhole tools. For example, a mud-powered mud motor is some

times installed above (behind) the bit to cause the bit to rotate faster than the drillpipe or to rotate when

the drillpipe is not turning at all. These capabilities speed drilling and can also assist with directional

control.

Generally, the weight of mud is increased as drilling goes deeper because formation pressures are higher in

deep zones and require more weight (hydrostatic pressure) to prevent influx. The weight of mud is commonly

expressed as pounds per gallon (ppg) and the Macondo mud weight began at 9.7 and reached 14.0 at the bot

tom of the well. As a reference point, fresh water weighs 8.3 ppg and seawater weighs about 8.6 ppg.

When weak, highly-porous or fractured formations are encountered, mud losses can occur and material maybe added to the mud to block or seal the zone. Common materials used for this purpose come in fiber, flake o

granular form and include such items as wood fiber, mica, rubber, and ground nutshells. These additives are

commonly called lost circulation material or LCM.

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Riser

The riser provides a sealed conduit for the mud and a guide for the pipe and tools used in the hole. The rise

pipe joints on the Marianas are 75 feet long so there were about 65 joints spanning the approximately 5,000

feet between the rig floor and the BOP. The Deepwater Horizon had 90 foot joints and would have used 55 joints

for the riser. The pipe is 21 wide and is coated with thick buoyant material to reduce the weight load on the rig

(Figure 18).

The bottom end of the riser is attached

to a flex joint on top of the BOP stack

and the top end is held beneath the rig

floor opening by a tensioned telescopic

joint.

The flex joint connection on the BOP al

lows slight movement in the angle of

the riser connection. This flexibility is

needed in case ocean currents sway

the riser or rough seas move the rig

slightly out of position.

The telescopic joint connection below

the rig floor can expand 50+ feet to

allow for vertical and horizontal move

ments in the rig. The most common

movement is the rig heaving up and down with ocean swells. The telescopic joint is held in tension in order to

keep the riser as straight as possible.

Riser pipe integrity is critical because a separation of joints or a rupture in the pipe could have strong environ-

mental and economic consequences. Accordingly, the pipe is high strength and the joints are connected with

strong bolted flanges versus the threaded connections used for drill pipe and casing.

Four lines run along the outside of the riser. One is a set of high-pressure hydraulic lines that powers the BOP.

One is a riser booster line that jets mud upward from the bottom of the riser to aid circulation of the mud back

toward the rig. The other two lines are choke and kill lines that connect to the BOP and allow fluids to be

circulated in and out of the well when the BOP is closed. These lines will be discussed in more detail later.

To the rig crew, the riser section behaves somewhat like the top part of the hole with the exception that it doesnt

have to be drilled. In fact, the industry usually includes the riser section when quoting a deepwater well depth

even though the riser leaves with the rig. A key distinction during drilling between a deepwater riser versus a

hole section is that the wellhead and BOP are far away at the bottom of the riser whereas they are located im-

mediately beneath the rig for a land or shallow-water well. This distinction immensely complicates deepwater

drilling.


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Fig. 18 - Riser Pipe


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Blowout Preventer

A blowout preventer, or BOP, is a stacked arrangement of closing devices that can shut in a well in the event

that formation gas or fluids begin flowing into the wellbore. Such an invasion is

called a kick and could result in a blowout if uncontrolled. BOPs are big and

powerful the BOP on the Deepwater Horizon weighs about 325 tons, is about 50

feet tall and is designed to handle pressure up to 15,000 psi. (Figure 19) It was

manufactured by Cameron.

Use of the BOP is not always the first response to a kick. If the kick is mild and

the drillpipe is in the hole, a first response might be to increase the mud weight

to raise the resistance against the flow (through increased wellbore hydrostatic

pressure). In general, drilling should be designed and conducted in such a way

that well situations can be managed without heavy reliance on the BOP. The BOP

is the last line of defense and frequent reliance on the BOP will increase the

chance of an eventual failure.

If the BOP is needed, there are three general types of devices available in the

stack: annular preventers, pipe rams, and shear rams. (Figure 20) The device

used will depend on the severity of the kick as well as whether there is anythingcurrently passing through the BOP such as drillpipe or casing.

Annular preventers are the mildest control device and the most frequently used.

Its closing element is like a steel-reinforced rubber donut that, when compressed,

squeezes outward around any pipe in the hole. It can also completely seal off the

hole without any pipe present but is not the strongest tool available for that situ-

ation. An advantage of the annual preventer is that the crew can still raise and

lower drillpipe or casing while engaged (with some difficulty), which could help solve a problem situation. Mov

ing pipe with the annular preventer closed is called stripping. Deepwater Horizons BOP stack had two annular

preventers.

Pipe rams are essentially metal bars with half circles cut out of the ends. When the pipe ram is activated,the bars move into the wellbore and clamp around the pipe, thus sealing off the full wellbore annulus around

the pipe. The pipe cannot move with

the pipe rams closed because large

tool joints (the flared ends of the dril

pipe) couldnt pass through, and pipe

rams cannot close on a tool joint o

casing. Deepwater Horizons BOP had

two variable bore pipe rams, mean

ing that they had heavy elastomer

edges that could seal around more

than one size of drill pipe because at

least two sizes of drillpipe were used

on the Deepwater Horizon (6-5/8 and

5-1/2).

Blind shear rams are designed to sea

off the wellbore at all cost and they

should cut through any drillpipe or casing that is passing through the BOP when the rams are closed. Cutting

drillpipe or casing would be expensive to retrieve at best and could ruin the well at worst, so use of the blind

Fig. 19 - DWH BOP

Fig. 20 - Blowout Preventer Functions


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shear rams would be a last resort if pipe was in the BOP. If lucky, any drillstring that was cut would remain

gripped and suspended by the pipe rams below, which are normally closed first. Deepwater Horizons BOP had

one shear ram for drillpipe and one for casing. The drillpipe ram cannot cut through a tool joint and the driller is

supposed to keep track of the joint positions to make sure the drillstring is not stopped with a tool joint in front

of the shear ram.

The Deepwater Horizon BOP also has a test ram, which is an inverted pipe ram designed to seal off pressure

coming from above the ram rather than from the wellbore below as all the other rams are designed. This allowsthe BOP to be pressure tested easily, with pipe in the hole, whereas a test without the test ram requires a plug

to be placed in the bottom of the BOP and all the pipe must be removed from the hole. The test ram position was

previously a pipe ram and was converted into a test ram in 2004 at BPs request (and cost). In the letter agree

ment to make the conversion, Transocean advised BP that it would reduce the BOP safeguards and raise the risk

profile. However, such a conversion is not uncommon in the industry and it also has some safety advantages i

increased testing ease leads to greater testing frequency.

The BOP is connected to the rig by an electrical control line. There are two control panels on the rig to operate

the BOP one on the rig floor close to the Driller and Toolpusher and one on the bridge close to the Offshore

Installation Manger and the Master/Captain. These rig control panels link to two control pods on the BOP, called

the yellow pod and the blue pod. These pods respond to signals by activating hydraulic valves that channel hy

draulic pressure to open/close the BOP devices. The BOP gets its hydraulic flow pressure from a hydraulic lineon the riser. However, the BOP has built-in accumulator bottles that store enough pressure to close all valves

fully one time in the event that pressure is lost from the riser.

The BOP stack has two separable sections. On top is the Lower Marine Riser Package (LMRP) that connects to

the riser. On the bottom is the BOP stack that connects to the wellhead. In the event of an emergency, such as

the rig drifting uncontrollably off position, an Emergency Disconnect System, or EDS, can be activated on the

control panels to separate the LMRP from the BOP. As part of that process, the EDS system will activate the blind

shear rams in the BOP to cut any pipe passing through the BOP and seal off the well. The annular preventers in

the LMRP will also close to prevent mud in the riser from spilling in the ocean.

The BOP also has a built in, battery-powered Automatic Mode Func

tion (AMF) device, commonly called the deadman switch, that wilactivate the blind shear rams to close in the well if both hydraulic

pressure and the electrical communication with the rig are lost. The

deadman switch does not separate the LMRP from the BOP.

A BOP has a kill line and kill valves and a choke line and choke

valves that allow access to the well when all or parts of the BOP are

closed. (Figure 21) The choke line is used to release pressure from

the well and leads to special equipment on the rig, including a gas

buster vessel, that can safely handle gas-laden mud. The kill line is

used to pump in heavy mud to stop the backflow.

The BOP devices and the choke and kill lines are also often used to

conduct pressure tests on casing, set seals, activate tools, etc. The

annular preventer and kill line on Deepwater Horizons BOP were

involved in the erroneous negative tests preformed on the last cas

ing string that failed to detect early signs of the blowout. This will be

described in more detail later.


- 12 -

Fig. 21 - Choke and Kill Lines


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Diverter

Another pressure-control device, called a diverter, is installed at the top of the riser. It can be activated if gas or

dangerous fluid-flow levels are coming up the riser. The diverter will close around drillpipe (if any is in the hole)

and will direct flow through a blooey line to a boom that extends over the side of the rig. A rig generally has two

booms on opposite sides so that a downwind is always available, and each boom usually has an ignition source

to cause diverted gas to be flared.

The diverter is necessary in case hydrocarbons get into the riser before the BOP is closed. Hydrocarbons are

extremely dangerous in the riser because deepwater pressures are so high that gas is compressed into a liquid

state. If liquid gas gets in the riser, it will begin to expand as it moves upward because the static pressure de-

creases. As the gas expands, its volume will accelerate into huge multiples of its liquid state, forcing the fluid

above it to jet violently ahead, up through the drill floor and into the mud processing equipment. This will be

followed by a gas and fluid burst that will be temporary if the BOP is closed and enduring if not.

Diverters only have about a 500 pound pressure capacity and can be overwhelmed by extreme flow.

18 LinerReturning to the topic of well sections, the 18 hole was the first hole section to be drilled with mud rather thanseawater. It was drilled by an 18-1/8 bit followed by a 22 reamer.

A quick word is warranted about the bit and reamer. A bit can

be either a roller cone style or fixed cutter style. A well like

Macondo probably used a style of fixed cutter bit called a poly

crystalline diamond compact, or PDC, bit. (Figure 22) PCD

bits have no moving parts and use synthetic-diamond-capped

cutters to scrape away the formation as the bit turns.

A reamer is a tool placed in the drillstring above (following) the

bit that further widens the hole. It would also use PDC cuttersA normal 22 reamer could not have fit through the 22 casing

because the inner diameter of that casing was about 20 Ac-

cordingly, the reamer has a concentric design that allows it to

be expanded and contracted in order to pass through the 22

casing. This type of reamer is called an underreamer.

The 18 casing was a liner hung from a position downhole rather than a long string that runs the full length

of the well. (Figure 23) A casing hanger was attached to the top of the liner and the string was suspended from

the 18 supplemental hanger adapter pre-installed in the 22 casing. The liner was then cemented into place.

The cement was pumped up most of the open wellbore, but not all the way, per BPs well design.

The hanger has a seal assembly that will be set after cementing, using a special running tool. Cementing must

be done first because mud displaced by the cement flow must be able to escape upward through ports in the

casing hanger. After cementing, the seal assembly is compressed by placing high drillstring weight on the run

ning tool. (Figure 24) This compresses the seal assembly to form a strong metal-on-metal plus polymer-on-meta

seal between the hanger and adapter (above the port openings so that flow is blocked). This seal is required to

isolate the wellbore outside the 18 casing to prevent any future inflow or outflow that might affect the rest of

the well.


- 13 -

Fig. 22 - PDC Bit


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- 14 -

Not much has been disclosed about the 18 liner section but it is known that it

was drilled 1,032 feet versus 2,000 feet included in BPs well plan. BPs senior

drilling engineer for the Macondo well testified that there were substantial prob-

lems with lost-circulation near top of the hole, but he did not specify whether that

occurred in the 18 section. If so, it could account for the short length because

sometimes casing is set after passing a difficult zone to avoid additional prob-

lems.

As mentioned earlier, Marianas ob

served problems with their BOP at

the end of this section while setting

the 18 liner. They unlatched the BOP

and pulled it to the rig, suffered hur

ricane damages while undergoing re

pairs and left the site on November

26, 2009. The Deepwater Horizon re

entered the hole on February 9, 2010

after a few days of set-up.

16 Casing

According to the well plan, the 16 section would take 6-7 days and be drilled about 2,500 feet. Instead, it took

about 20 days and was drilled 2,616 feet. A Transocean document indicates the well struggled with well contro

events (kicks and/or lost-circulation) for about a week, and that likely affected progress.

This section was drilled with a 16-1/2 inch bit and a 20 underreamer. The cas-

ing was hung in the 16 supplemental adapter pre-installed in the 22 casing.

(Figure 25) This section runs almost the full length of the well because the 16

supplemental adapter is only 160 below the wellhead. Cement was pumpedabout 40% of the way up the open wellbore.

BP installed three burst/rupture disks in the 16 string to guard against exces-

sive build-up of pressure either inside or outside the 16 casing string. These

devices will allow gas or fluid pressure to be released inside or outside of the 16

string if they exceed set levels.

Pressure build-up is a concern in deepwater wells because of large tempera-

ture differences between the drilling phase and the production phase. During

the drilling phase, the wellbore temperature approximates the mud temperature,

which is an average of the temperatures the mud encounters as it circulatesthrough the wellbore. That temperature is relatively cool through the long riser

section and gradually increased to 262F at the bottom of the well, creating an

average much lower than the bottom-hole temperature. During the production

phase, the wellbore will move much closer to the bottom-hole temperature as hot

fluid is produced up the well. This rise in temperature can cause trapped fluid in

the casing annuli to expand, putting pressure on the casing that could potentially

cause a rupture or collapse.

Fig. 24 - 18 Casing Hanger in Supplemental Adapter

Fig. 23 - 18 Liner

Fig. 25 - 16 Casing


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- 15 -

Pressure concerns can also impact cementing practices. On some wells, the operator will pump cement until the

cement top goes past all of the exposed wellbore and up 100 feet or more into the overlap space between the

current string and the prior string. This can provide an excellent seal against any leakage to/from the formation

Many operators do not do that if they think it is not necessary because more cement costs more money. How-

ever, some deepwater operators intentionally do not cement the overlap because the open space would allow

casing pressure buildup to bleed off into the exposed formation.

There have been allegations that BP should have cemented up into the overlap and that they cemented short

to save money. However, it would be premature to accept those allegations. A limited perusal of well schemat

ics on file with the Minerals Management Service reflects that BP is not alone in stopping before the overlap.

Also, BPs e-mails express annulus pressure concerns, so that may have been the driving factor. BP has not

commented on the issue.

13-5/8 Liner

The 13-5/8 section was rough for BP. According to the well plan, the section would take 6-10 days and would be

drilled about 3,000 feet. Instead, it took 19 days and was drilled 1,560 feet. A Transocean document indicates

the well experienced well control events through much of this section, and the drillstring became stuck in thehole, requiring a time-consuming sidetrack. (Figure 26)

An unplanned sidetrack is a nuisance for operators but is not that uncommon in fact, there is a whole market

segment built around resolving various drilling problems. A sidetrack is required when an obstruction in the

hole cannot be fished out or drilled through and has to be drilled around. For the Macondo well, the drillpipe

became stuck in the hole

and could not be freed

Schlumberger was brought

out to run sonic and temper

ature logging tools down the

drillpipe to determine where

the pipe was stuck so that

a determination could be

made where the pipe should

be cut and sidetracked. Ap

parently, the logging tools

became stuck in the hole

and added to the cost of the

problem. Eventually, the dril

pipe was cut downhole and

the well was sidetrackedabove the obstruction. It is

not known how much hole

was lost/redrilled because

of this problem.

Fig. 26 - Sidetrack Procedures


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The 13-5/8 liner involves the first use in the well of a

liner hanger and packer. These tools are used when a

casing string is not run from the wellhead or from a sup

plemental adapter and is hung off the inside of a prio

casing string in this case, the bottom of the 16 casing.

(Figure 27)

A hanger has metal gripping devices that can be activatedto wedge between the outside of the hanger and the inside

of the prior casing string so that the casing is suspended

(Figure 28) The packer has an elastomer ring that can be

expanded to seal off the annular space between the two

casing strings. The packer is set after the cement has

been pumped because mud that is being displaced by ce

ment must be able to flow

past the hanger and out

the annular space during

pumping.

11-7/8 and 9-7/8 LinersAccording to the well plan, the 11-7/8 liner section would take about 8 days and

would be drilled about 2,000 feet. Instead, it took 6 days and was drilled 1,958

feet. No well control events were noted. It was perhaps the most trouble-free sec-

tion of the well.

The 9-7/8 section was planned for 10 days and 2,500 feet. Instead, it took 5

days and was 2,065 feet. However, a key distinction was that the 9-7/8 section

was originally planned to reach the bottom of the hole 14,569 feet below themudline. Instead, it ended at 12,101 feet, and another hole section was required

to reach the target. This also meant that the bottom hole section would be nar-

rower than the planned 9-7/8 width.

Final Hole Section 7 x 9-7/8 Casing

The final hole section was drilled with an 8-1/2 bit followed by a 9-7/8 reamer set 230 feet back on the drill

string. According to the well plan, the well had to go 1,218 feet to reach the primary target and 2,468 feet to pass

through the secondary objective to the intended total depth. (Figure 30) It is not known whether BP still intended

to reach the secondary objective at that point. If so, they did not make it.

The primary objective was a thick sandstone layer and there were some thinner, intermittent sand layers aboveThe characteristics of the sand layers were not consistent and the mud weight used to contain pressure in some

layers began causing mud losses in one or more other layers during early drilling in the section. The situation was

not highly problematic at this point. (Figure 31)

At 650 feet into the section, the first hydrocarbons in the well were encountered in a thin sand section. Shortlybelow that section, the mud weight was lowered to reduce mud losses. More mud losses were encountered onthe way to the primary target.


- 16 -

Fig. 28 - Liner Tools

Hanger(Grip)

Packer(Seal)

Fig. 27 - 13-5/8 Liner

Fig. 29 - 11-7/8 & 9-7/8 Liners


17/40

The primary target formation wasencountered about where expected. It was 123 feet thick and contained hydrocarbons in the uppeportion. BP would have known whenthey entered thick sands becausethey were probably using a loggingwhile drilling tool behind the bithat uses gamma rays to detect thedifference between porous sandsversus tight shales or salts. Theywould have also known that theyencountered hydrocarbons becausethe mud and cuttings would eventually circulate back up the riser andbe detected by a contractor calleda mud logger who periodicallysamples the mud characteristics asit passes through the mud processing equipment. The mud processing

equipment also has gas monitorsthat work continuously as a safetydevice.

Immediately below the primary objective, the well began experiencing

heavy mud losses. BPs senior drilling engineer testified that about 3,000 barrels of mud were lost before theoutflow was eventually stopped with lost circulation material (LCM) and further mud weight reduction. BP wasusing synthetic oil-based mud, which reportedly can cost $200 to $500 per barrel. Thus, they presumably lost$600,000-$1,500,000 of mud in that one section, plus the cost of the LCM. Fighting lost circulation also slowsdrilling so rig-time costs were also incurred.

BP stopped the well at 18,360 feet measured from the rig or 13,293 feet measured from the mudline. They ap-parently were in unstable formation all the way to the end because a Halliburton report to the Energy and Commerce Committee indicates that there were loss circulation events below the casing shoe, meaning at the bottom. It appears that they stopped at a point just deep enough to get the reamer to the bottom of the hydrocarbonzone and to allow enough space to do cementing and completion work.

Shoe PositionA lost-circulation zone is an unstable place to set a cement shoe because a cement job normally calls for rigorouspre-cementing mud circulation to clean out the hole, followed by a cement flow that exerts high force because ocements heavier weight. These flows create high pressure below the shoe because the fluid must make a pound-ing u-turn and travel back up the annulus between the outside of the casing and the wellbore walls. If the shoearea is weak, the fluids could bust into the weak formation rather than travelling up the annulus.

This issue deserves attention because the weak shoe may very well have been the first key event toward the

blowout. BPs concern that the cementing process would breach the LCM barrier at the shoe and cause cemenlosses influenced their cement design toward a gentle-pressure process that lacked many of the traditional bestpractices for getting a good cementing outcome. That cement job is suspected of having a faulty result that allowed hydrocarbons to escape up the wellbore.

Any review of this issue by investigators will likely focus on whether BP could have and should have done moreto bring the well to a better shoe position by drilling deeper or by taking other actions. The first place to start thereview would be to examine BPs internal communications on the drilling termination point to see if their geologists and engineers discussed any heightened risk factors in stopping where they did, and if so, what factors had

the most influence on their decision.


- 17 -

Fig. 30 - Final Section Fig. 31 - Mud Losses


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- 18 -

Long-String Production Casing

At the same time that BP was concerned about

its ability to effectively cement with a weak shoe

it was favoring a casing design that required a

high-quality cementing outcome. BP wanted to

use a long production casing string, meaning tha

it would be hung from the wellhead with a casing

hanger and run the full length of the well. A good

cement barrier is essential for a long string that

goes through the production zone because leak

age of hydrocarbons past the cement would allow

gas to migrate all the way up to the casing hanger

seal at the wellhead, which was not designed to

be a primary line of defense against high pres

sure. (Figure 32 and 33)

The long string that BP wanted to use would have been 7 on the bottom, crossing

over to 9-7/8 further up the well to allow more room for tools, valves and pumps that

might be used later down the wellbore during the completion/production phase.

A safer, and reportedly more-common, approach would be a two-stage process of in-

stalling a liner in the final hole section and then installing a separate tie-back casing string between the liner and

the wellhead. The advantage of this process is that a liner/tieback provides two extra barriers in addition to the ce

ment and the casing hanger seal one of the extra barriers is the liner packer at the top of the liner string and the

other is the cement used to cement the tieback string into place. (Figure 34 and 35) A 7 x 9-7/8 arrangement is

also feasible with a tieback string.

Internal BP documents and e-mails that have been released show that BP preferred the long string because a tieback

would take about 3 days more work and would cost about $7-10 million more that the long string. They also indicated

that the well design would be simpler and the long-term integrity of the production string would be better without

the potential deterioration of the tieback connection. Their comments acknowledged that a weakness of the long string was the potential gas migration to the

casing hanger seal. They also acknowledged that the tieback string had some

advantages, one being that if the cement job had faults, the presence of the

liner-packer seal would allow them to more-easily justify temporarily abandoning

the well with the faults still in place leaving the remedial work for the comple-

tions crew at a later date. (More on this comment later).

BP planned to set the casing shoe 56 feet above the bottom of the hole, leav-

ing an uncased dead area called a rathole at the bottom to allow debris to fal

harmlessly out of the way during the completion phase. In this case, the length

of the rathole may have also been designed to provide a pressure cushion be

tween the shoe and the hole bottom.

BP worked with its cementing contractor, Hal

liburton, to explore cementing options for the

long string and to run simulation models on

how various options might work. The cement

ing model utilizes data taken from wireline

logs that were run after drilling stopped.

Fig. 32 - Hydrocarbon Migration

Fig. 33 - Casing Hanger Seals

Fig. 34 - Liner/Tieback Fig. 35 - Tieback Connection


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Wireline Logs and Reservoir Characteristics

BP spent four days performing and evaluating wireline logs after drilling stopped on April 10th, 2010. Wireline

logs are taken by lowered tools into the wellbore on a steel cable with electrical wiring inside to power the tools

and send/receive data. Depending on the tools used, wireline logs can provide information about the wellbore

path, formation boundaries, rock type, porosity, estimated permeability, location of oil and gas, formation angles

and downhole pressure and temperature, Also included is a caliper log that measures the wellbore diameter

throughout the uncased hole section. This is important because some sections of

the hole experience a degree of washout meaning that mud flow or formation

crumbling causes the wellbore to be wider than the size of the bit and reamer that

were used. Caliper information is important for calculating how much cement is

needed to get the top of the cement to the desired level.

The logs indicated that the well had encountered two oil and gas bearing sandstone

formations. The first formation was a thin layer at 12,054 feet below mudline. The

second was a 123-foot sandstone layer beginning at 13,026. The top 53 feet of that

layer contained oil and gas in the rock pores (The pay zone).

Everyone has seen sandstone (Figure 36) because it is sometimes used as a building material, and it can

be seen in abundance in some natural settings like the walls of the Grand Canyon. It may look solid but it is

grainy and has micro-pores between the grains that are capable of holding gas and fluids. Some sandstone has

enough porosity (void space) and permeability (connections between the void space) to be good reservoir rock

Sandstone is a bit like a sponge that cannot be squeezed, but high downhole pressure can force oil and gas

through the pores at a high rate.

Cement Modeling

Using the well log data, Halliburton ran a cementing model on April 15th. It was assumed for modeling purposes

that a lighter-weight nitrogen foamed cement would be used to reduce the bottom hole pressure. It was furthe

assumed that it would be pumped slowly to minimize the chance of breaking the LCM barrier.

Nitrogen-foamed cement is lightened up with micro-bubbles by adding surfactant (similar to a detergent) and

injecting nitrogen gas into the cement as it is pumped. It has been likened to gray shaving foam, with the ex-

ception that it is still not light at 14.2 pounds per gallon. In simple terms a bucket of foamed cement would

weigh about 70% more than a bucket of water and would weigh slightly more than the 14 ppg mud that was in

the hole.

The mud already in the hole was at a delicate balance if it was much lighter, formation fluids would begin en

tering the wellbore, and if much heavier, the LCM plug might break and cause more mud losses near the hole

bottom. The cement flow would raise the bottom-hole pressure as it was pumped but the lighter foamed weight

and slow pumping and would minimize the pressure increase.

One of the modeling constraints was that the Minerals Management Service required that the cement extend

at least 500 feet above the highest hydrocarbon-bearing zone. The top of the primary formation was 277 feet

above the hole bottom but a thin hydrocarbon zone had been encountered 539 feet from the bottom, requiring

that the cement extend at least 1,039 feet up the annulus. The extent of the cement impacted the length of

pumping required, the pumping pressure required, and the bottom-hole pressure immediately after pumping


- 19 -

Source: Wikipedia

Fig. 36 - Sandstone


20/40


-20 -

because a 1,039 foot column of 14.2 ppg cement would be where 14 ppg mud had previously been. One of the

modeling solutions was to pump some light 6.7 ppg base oil ahead of the cement so that it would sit above

the cement and displace more 14 ppg mud out the top of the well, creating some weight compensation.

A critical modeling issue was that the lighter cement and low pumping pressure necessary to protect the LCM

barrier was causing a flow up the annulus that was too gentle to push all of the mud out of the way to get a solid

displacement with cement. This would particularly be true if the casing was not well-centered in the hole.

To address this, the Halliburton modeler had assumed that 10 centralizers (Figure 37

would be used to center the casing, spread along the bottom 500 feet of the string

which is roughly one per joint over that distance. The bottom 174 feet of the casing

were in the hole that had been drilled with the 8-1/2 bit whereas the hole around

the casing further up had been reamed to 9-7/8. Due to crumbling and washout, the

actual diameter of the hole drilled by the 8-1/2 bit averaged about 9 inches, and the

reamed section was 10-11 inches. And, like all wellbores, it was not per fectly straight

The distance from the outside of the casing to the wellbore wall, divided by the distance

that would be present if the pipe were perfectly centered, is called the standoff percentage. As a general rule, the standoff per-

centage needs to stay at 70% or more in

order to allow even cement distribution.

As the pipe gets closer to the wellbore walls, the quality of the

cement placement begins to severely worsen because cement

may channel through the side of the pipe with more room and

bypass mud on the tight side altogether rather than displacing

it. A substantial and long-running stretch of bypass can render

that portion of the cement job worthless. (Figure 38)

The basis for using 10 centralizers is not known. The choice did

not seem purely logical because they only covered a portion of

the cemented section and the centralizers in the 9-7/8 reamed

section were under-sized because they were the same the cen-

tralizers used for the 8-1/2 section. It appears that Halliburton

was just told what BP had available and made the best use of

them.

Despite the lighter foamed cement, slow pumping and 10 centralizers, the model indicated the well was likely to

have a moderate gas flow problem, which would not have been acceptable for a long string design.

Temporary Change to Liner/Tieback Option

After receiving the unfavorable results of the Halliburton model, BPs drilling engineering department put to

gether a presentation recommending that a liner/tieback be used instead of the long string. The report said

cement simulations indicate it is unlikely to be a successful cement job due to formation breakdown and un

able to fulfill MMS regulations of 500 of cement above the top hydrocarbon zone.

Fig. 25

Fig. 38 - Impact of Casing Standoff on Cement Quality

Fig. 37 - Centralizer


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- 21 -

It is not known who viewed the presentation. However, it appears that the presenters were sent back to the

drawing board because, about 2-1/2 hours later, Halliburton generated a new model showing that the long

string was an acceptable option after all if 21 centralizers were used instead of 10. The new Halliburton report

said that the likelihood of a gas flow problem with the new design was only minor. There is no sign of manipula

tion by Halliburton -- it appears that they were told to revise their assumptions to use however many centralizers

were needed rather than just centralizers that were available, and that made the difference. A new BP report

was then issued saying that the long string was again the primary option.

That could be fine anyone that has worked in a big business environment knows that a lot of decisions are

challenged and revised. However, in this case, it appeared that the revised modeling results were accepted by

the well team leader without him actually having the resolve, or perhaps ever even an intention, of using 21

centralizers as modeled.

A little after midnight that night, the drilling engineering team leader sent an e-mail to the well team leader. The

well team leader controls the operational side of the well whereas the drilling engineering team leader was on

the planning side. The note indicates that the drilling engineering team leader had become aware that the drill

ing operations group was only planning to use six centralizers that they had on hand (which was even less thanthe ten assumed in the model that had bad results). The drilling engineering team leader reminded the wel

team leader that the modeling results should be honored and stated that he had gone to the trouble of locat-

ing the extra 15 centralizers that were needed, had arranged to get them transported for free on an already-

planned helicopter flight, and had arranged for an installer to fly out on the same helicopter to get the job done

In other words, he handed him a solution on a silver platter and even closed with some humble apologies for

overstepping his bounds.

The well team leader pushed back on the offer around noon the next day by responding that he had learned

that the centralizers were not the type the drilling engineering team leader had said they were (did not have

stop collars pre-installed to keep them from sliding). He also noted that it would take 10 hours to install them

He expressed disapproval and the drilling engineering team leader promptly backed down. The well team leadecopied BPs drilling operations manager on the e-mail chain, so the issue was known at least up to that level.

However, it is highly unlikely that an issue like this reached the upper echelons of BP management, although it

may have been known at a high level that the well was behind schedule and over budget.

The next day, an e-mail that has gotten much attention was issued by a drilling engineer in the drilling operations

group. The first sentence of the e-mail acknowledges that the casing is not likely to be well centralized without

centralizers. However, the second sentence reads But, who cares, its done, end of story, will probably be fine

and well get a good cement job. It ends by praising the well team leader for being right on the risk/reward

equation for electing not to use more centralizers. It would be useful for investigators to determine what risk/

reward equation comments had been made by the well team leaders.

Thereafter, communications among the BP staff focused on how to make the most of the six centralizers that

would be used. Halliburton issued another model report on April 18th that included a sentence warning that

the well would have a severe gas flow problem as planned. (For unknown reasons, the model included seven

centralizers instead of six.) It has not been disclosed who in BP received that report or was told of the results

apart from the fact that it was addressed to one of the drilling engineers.


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- 22 -

Foamed Cement

Foamed cement is more expensive than regular cement and it works better than regular cement in some ap-

plications. One of the advantages is that the bubbles stiffen the wet cement so that it is less prone to being lost

into a zone or being invaded by fluids in a zone. A remote analogy is that when a sink is drained after washing

dishes, the water flows out the drain while the soap bubbles remain in the sink. Foamed cement is good at seal

ing off shallow aquifers and had been used on the Macondo well for the top two cemented sections (the 28

conductor and 22 surface casing).

However, use of nitrogen foam is less common for deep high-temperature, high-pressure zones. Halliburton

has made remarks that such use is tried and true. However, it was apparently not common for BP. The Of fshore

Installation Manager for the Deepwater Horizon testified that he had never seen foam cement used for deep

applications during his 6-1/2 years on the Deepwater Horizon working for BP. He also indicated that he had only

seen such use a couple of times in his entire career. He also indicated that he was disgruntled when he first

heard about the foam use because if the high pressure downhole caused the nitrogen to be expelled from the

cement, it could migrate uphole and cause a potentially-dangerous release for the crew at the surface. However

a small non-flammable nitrogen release would have been nothing compared to what actually happened.

Clearly, the use of foamed cement will be reviewed in the investigation as a potential poor choice that contrib-

uted to the blowout. Even if investigators determine it was a poor choice, Halliburton would not likely become

liable to BP for several reasons. First, Halliburton advised in advance that the cementing program would likely

have a poor outcome. Second, it has not been disclosed whether it was Halliburton or BP that first advocated

the use of foamed cement. Third, cementing contractors work on a best efforts basis and do not guarantee the

outcome because the operator makes the final program decisions and there are too many well variables that the

cementing contractor does not know about or control. Finally, the operator and rig contractor are responsible fo

maintaining control of the well at all times in a way that would prevent an ineffective cement job from becoming

a blowout. The cement should be adequately tested and, if necessary, remediated (under the operators direc-

tion and expense).

Halliburton could, however, face issues from the government and other contractors for performing a cement job

that they predicted would have severe problems, even if they were following industry practice of doing what the

customer ordered. There may also be an issue whether Halliburton disclosed the design weaknesses to the rig

crew, and if not, whether that knowledge might have caused them to behave more-cautiously in a way that could

prevented the blowout.

Cement Bond Log

BPs internal report that had finally recommended the long string warned of problems that could result if loss

es occurred, meaning that some amount of cement flowed into the weak formation rather than traveling up

the annulus. One problem, as mentioned in the earlier report, would be that a poor cement job could allow hydrocarbons to flow to the wellhead where the casing hanger seal assembly would be the only remaining barrier

Another problem, newly mentioned, was that the top of the cement might end up too low to meet MMS 500-foot

regulations.

The report indicated that in the event of losses, an Ultrasonic Imager Tool (USIT) log might be needed. A USIT

log falls into a broader category of wireline tools that use sonic waves and temperature readings to generate


23/40


- 23 -

a report called a cement bond log (CBL). A CBL gives a 360 view around the wellbore of the thickness of the

cement and the quality of the cement bond to the casing. (Figure 39)

In the event that cement gaps or channels are found, remediation procedures are available including a process

known as squeeze cementing. With squeeze cementing, perforations are made through the casing in the

problem area and a special tool is used to force in cement. The per forated section of casing must then be lined

over.

A CBL is expensive. According to a letter issued by the Committee on Energy and Commerce, BP had made ar-

rangements for a Schlumberger wireline crew to be on the rig on standby in case a CBL was elected, and the

charge would have been around $128,000 and taken 9-12 hours, which drives an even-higher rig cost.

A problem with BPs approach was that its trigger point to

run a CBL was focused solely on the occurrence of losses

whereas Halliburtons modeling report did not suggest

that the mere absence of losses would be an indicator of

success. To the contrary, the report implied a high poten

tial for a bad outcome under any circumstance.

Thus, BPs plan was to run a CBL only if confronted with

clear evidence that the cement did not even reach its des

tination. Otherwise, its drilling team did not seem to regis

ter much concern about the shortage of centralizers, the

Halliburton model report, the use of an uncommon (fo

them) foamed cement, the planned low pumping rates o

the fact that they were using a higher-risk casing design.

Deferral of Testing and Remediation

Earlier, it was mentioned that a comment was included in a BP report saying that an advantage of the liner/

tieback approach (if it had been elected) was that it would be easier to justify deferring a remedial cement

job, if required, until later due to the liner top seal acting as a second barrier.

Within the history of the oil and gas industry, there have been occasions of company drilling personnel leaving

behind well problems because they know the completions team will later inspect the well and do any necessary

remedial work. Likewise, there have been occasions of completions teams concluding that some drillers do a

sloppy job and leave a lot of unnecessary problems. A par tial driver of these dynamics is that wells have drilling

and completion budgets and drillers skipping expensive tests, deferring or ignoring problems, and moving off

the well as soon as possible helps their performance look better at the expense of the completions team.

Deferral of testing and remediation is a poor practice for a couple of reasons. First, it holds drillers to a lower

standard whereby they may not evaluate their work adequately for problems, and they may even avoid or ignore

problem information. Second, it puts the public domain at risk because the potential for loss of control is highe

while abandoning or reentering a faulty well versus a stable well. The Macondo well blowout occurred during

abandonment of an apparently-faulty well.

Fig. 39 - Cement Bond Log (CBL)


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The fact the above comment was in a BP management report suggests that deferral of testing and remediation

was not discouraged by BP management and was possibly even encouraged. BPs senior drilling engineer made

a comment during testimony suggesting that BPs completions group routinely ran cement bond logs and the

drilling department therefore took comfort in skipping the test themselves. Specifically, the comment was: A

CBL would have been run on this well. Some day in the future when we bring another rig out to do the completion

you would run a cement bond log to find out if the cement across the productive interval had enough integrity

to warrant perforating the casing during the completion and allowing this well to flow back to a platform. If thatcement bond log in the future showed that there was poor cement you would do a remedial cement job because

you have to have a good cement job for a production. That comment does not reflect much concern about the

quality of the cement at the time the well was abandoned, awaiting arrival of the completions team.

Nightmare Well

The media and the Energy and Commerce Committee have made much of the fact that, during planning for the

final casing string, a drilling engineer wrote in an e-mail that Macondo had been a nightmare well which has

everyone running all over the place and the senior drilling engineer wrote that Macondo was a crazy well for

sure. These remarks have been interpreted as an indication that the well had long been flirting with loss of

control, and stories of kicks and lost circulation probably contributed to that interpretation. However, that interpretation doesnt recognize industry jargon.

Rig crews use a similar term very often a well from hell. Within the industry, none of these terms is taken at

face value as meaning that a well came close to a blowout. Unless more is added, it implies that the well was

a hassle that did not go as planned. Along those lines, there was plenty of oppor tunity to call Macondo a night

mare well at the time the phrase was used two different rigs, a hurricane, 18 casing set 1,000 feet short, a

sidetrack, major lost circulation, extra casing strings, cost and time overruns, and stopping short of the second

ary objective, leaving it untested.

Within the industry, kicks and lost circulation events are so routinely encountered and successfully handled

that they do not even make interesting conversation unless the frequency, duration or severity is noteworthyHowever, a near blowout would be an extreme and rare event that would garner much attention and would likely

result in an internal investigation. Accordingly, the mere presence of kicks and lost circulation should not be

confused as a near-blowout situation.

It could be said that the further one gets away from the rig floor, the less the possibility of a blowout even enters

their mind. Everyone expects that blowout preventers will reliably work if all else fails. After all, BOPs are formi

dably big, heavy and powerful and are inspected and tested regularly. Also, there are multiple types of devices

in the stack so that others will work if one fails. It almost certainly never occurred to BPs drilling team that

risks they were taking would bring them even close to a blowout situation. Of course, therein lies the biggest

problem.

Potential Blowout Preventer Problems

During the last hole section, stripping operations occurred over a length of about 1,300 feet of pipe while

pulling out of the hole. As mentioned previously, stripping is the process of moving pipe when an annular pre-

venter (rubber donut) is closed. Rig hands reported seeing a fair amount of rubber material show up in the mud

processing equipment, suggesting that the rubber element was damaged or eroded in the process. One rig hand


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reported that the rubber had come off during an operating error when the drillpipe was lifted accidentally while

a high level of annular pressure was on the pipe. The lower annular preventer had a special stripping device

so presumably it was the preventer that was used during stripping and had experienced the issue. Transocean

states that the preventer subsequently passed pressure tests.

Also, a Transocean driller testified that he had been told by a subsea drilling engineer that the BOP had a coi

fault and a minor leak. Oddly, the questioners did not ask the driller to elaborate what he meant by the vague

term coil and did not ask him to describe the type and location of the leak.

The term coil may have meant one of the two redundant control pods that receive signals and direct hydraulic

power to operate the BOP. A contractor on the rig said in a recent television interview that he had identified a

hydraulic leak on the BOP and that rig management and the BP company man had been notified. He indicated

that Transocean shut down the related control pod, switched to the other, and continued to operate with a single

pod. This has not been confirmed by Transocean or BP.

BP has reported that a remotely operated vehicle (ROV) working after the blowout found a number of hydraulic

leaks on the system. It also noted that Transocean had previously made note of a leak(s) in the rig log. Thus, the

occurrence of leaks is supported.

BP also noted that the ROV discovered undocumented modifications to the hydraulic control system and that

hydraulic system errors were identified such that the control for the lower variable pipe ram was activating the

test ram instead. Hopefully, that error was only with the emergency BOP panel on the ocean floor because an

error like that on the main controls would be stunning.

It is possible that none of the above had a direct role in the blowout. However, it raises questions about the

reliability of BOPs and about the threshold at which a BOP should be pulled for repairs rather than allowing a

problem to continue.

Was BP in a Corner-Cutting Hurry?A central narrative that has developed, correctly or incorrectly, is that BP was in a hurry to move the Deepwate

Horizon off the Macondo well because it had gone far over time and over budget and the next planned job for the

Deepwater Horizon, in the Nile Field on Viosca Knoll Block 914, was getting far behind schedule. The narrative

continues that BPs rush to complete Macondo caused them to cut corners at the end in a way that contributed

to the blowout.

That narrative is mentioned now because the final stages of the well, which will be presented in the following

sections, may make more sense with that possible narrative in mind.

It should be said that during the Coast Guard/BOE hearings, questioners repeatedly asked Transocean rig man

agement if they had been pressured by BP to speed up the pace and those employees were consistent in saying

that they had not been pressured. However, telling rig managers to speed up would be an odd and ineffective

approach for hurrying a rig that is eff iciently working through the operators own work plan. Instead, the operato

might shorten or eliminate procedures in the work plan.

The truth will become known because there is almost certainly a heavy stream of recorded or recountable com

munication between the company men on the rig and BPs Houston office during the last few days before the


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blowout. As mentioned in the Part 2 of this series, company men do not make big decisions on their own so the

Houston office would likely be making and communicating most of the decisions. Disclosure of that communica

tion stream will provide a good insight into BPs mode of operation.

Investigators attempted to tap into that sort of information by questioning BPs two company men on the rig but

one asserted 5th Amendment rights against self-incrimination and the other excused himself from testimony

citing a medical condition as the reason.

Running Casing

On April 16th and 17th, the rig crew circulated a bottoms up, meaning that the mud on the bottom was circu

lated out of the hole to clean out all gas and settled cuttings. Then a wiper trip was run, which involved going

back through the bottom hole section again with an 8-1/2 inch bit to ensure that the wellbore was still smooth

and clear before the casing was installed. A wiper trip was done because the well had been idle for about 6 days

during and after logging, and sometimes formations will swell or crumble into the hole after long exposure to

mud.

On April 18th, the rig began running casing first installing a 7 shoe track assembly with the shoe and float

collar 190 feet apart. Above that, 7 casing was installed, then a crossover to flare out to 9-7/8, then 9-7/8casing. A casing hanger and an unset seal assembly were installed on top. Like the 18 and 16 casing hang-

ers set earlier in the 22 casing, the casing hanger had ports to allow displaced mud to flow through during

pre-cementing circulation and during the cement pumping. The seal would be set only after the cement was

in place. Then a cement plug tool was installed followed by a tool that would be used to set the seal assembly

around the casing hanger after cementing was complete. The assembly was lowered down on drillpipe until the

casing hanger landed in the wellhead.

After reaching bottom, mud was pumped to create the pressure needed to unlock (convert) the float collar

flapper valves by pushing through the conversion ball. The conversion procedure should have taken one attempt

at 500-700 psi but instead took nine attempts with a final pressure of 3,142 psi. The higher pressure raised

concerns about disturbing the formation. There is no clear evidence that any problem was caused.

Cleaning Out the Hole

Thoroughly circulating mud before cementing is extremely important. Mud gels quickly after sitting idle, which

is a quality that is desired, monitored and adjusted during drilling to keep cuttings from sinking to the bottom

whenever circulation is stopped. However, that quality can be detrimental during cementing because gelled mud

will resist displacement by the cement flow.

Gelled mud is a bit like ketchup that has been sitting idle. As ketchup gel can be broken up by shaking the

bottle, mud gel can be broken up by a long period of exposure to turbulence from mud circulation. Inadequate

circulation may break paths through the gel and leave some clinging in place, particularly around the side ofany casing that is too close to the wellbore walls. Gel left behind will either additionally resist displacement by

the cement flow or will be broken up and contaminate areas of the cement. Accordingly, the cement job could

be seriously flawed.

Another reason to circulate mud is to remove excess wall cake formed by the mud that could interfere with ce-

ment bonding to the formation walls. A final reason is to flush out all mud that has been around the hydrocar

bon zone. This mud might contain gas tha

macondo history

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