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2
Well Design and Construction
The design and construction of a well are crucial to the safe exploration
for and extraction of oil and gas resources. The process becomes more complex
as the operating environment becomes harsher, as in deep, high-pressure, high-
temperature wells drilled into the seabed beneath deep water. Macondo was such
a well, with a total depth of more than 18,300 feet below sea level in slightly
more than 5,000 feet of seawater. This chapter discusses changes that were made
to the original Macondo well plan in response to geologic conditions encoun-
tered while drilling progressed. It then focuses attention on the approaches se-
lected for temporary abandonment1 of the well given these conditions. The chap-
ter provides findings and observations concerning a number of key decisions
related to the design, construction, and testing of the barriers critical to the tem-
porary abandonment process.2 At the end of the chapter, recommendations for
achieving a more robust approach for implementing and verifying needed barri-
ers are provided.
OVERVIEW OF THE MACONDO WELL PLAN
Macondo was an exploration well designed so that it could later be com-
pleted for production if sufficient hydrocarbons were found. The initial objective
was to evaluate Miocene age formations expected to be found between 18,000
and 19,000 feet below sea level in about 5,000 feet of water. The original well
plan was to drill to a total depth of 19,650 feet, but this was modified during
drilling and the actual total depth was 18,360 feet, as discussed below. Before
the well was drilled, design teams estimated pore pressures and strengths of geo-
1
Temporary abandonment refers to a set of normal procedures used by rig personnel
to secure a well after drilling has been completed, so that the rig, along with its blowout
preventer and marine riser, can be moved from the well site. The Deepwater Horizon was
to leave the Macondo well and another rig was to be used to prepare the well for produc-
tion at some later time.
2
Detailed descriptions of the overall sequence involved in constructing and testing the
integrity of Macondo well barriers are provided in various reports listed in Box 1-1 of
Chapter 1.
19
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20 Macondo Well Deepwater Horizon Blowout
logic formations to create a design that included elements such as drilling proce-
dures, drilling mud, drill bits, casing design, cement, and testing.
The original plan, shown in Figure 2-1, called for eight casing strings and
liners (each consisting of steel casing segments that were screwed together), but
the plan was modified to react to conditions that were encountered during drill-
ing. Drilling ceased at 18,360 feet (a shallower depth than planned) and involved
the use of a total of nine casing strings and liners, rather than the planned eight,
including the final 9 7 8 - 7-inch tapered production casing (sometimes referred
to as a “long string”) as shown in Figure 2-2. The well was to be temporarily
plugged and abandoned after the production casing was set and then completed
for production at a later date.
The Macondo well presented a number of technical challenges to the drill-
ing and completion teams, including the deep water, high formation pressures,
and the need to drill through multiple geologic zones of varying pore and frac-
ture pressures. In general, many of these problems can be anticipated, but some,
such as pore and fracture pressure, are difficult to estimate in advance of drilling
the well. This is especially true for the first well drilled in a new area, as was the
case for Macondo. Thus, adaptation of the original well plan to the changing
conditions encountered with depth when the well is drilled is not unusual. It is
critical that the design be adapted to changing conditions with sufficient margins
of safety to allow for further uncertainties that may be encountered during the
operation.
Wellbore events that necessitated changes to the Macondo well plan in-
cluded the following (BP 2010, 17-22):
1. Measurements showed that pore pressures were increasing at a faster
rate than anticipated, combined with a period of lost circulation of drilling mud
at 12,350 feet, indicating that the well could not be continued without setting
protective casing. The 16-inch liner was set at 11,585 feet to seal off this section
of the well. The setting depth of this liner was 915 feet shallower than planned.
2. In the course of drilling at 13,250 feet, a kick occurred, and the lower
annular blowout preventer (BOP) was closed in response. During well control
operations, the drill string became stuck and was severed at 12,147 feet. The
drill string and hole below 12,147 feet were abandoned, and subsequent well
drilling deviated slightly to go around the abandoned materials left in the origi-
nal hole. The 13 5 8 -inch liner was run at 13,145 feet, which was shallower than
planned, to allow the well to be drilled safely past the higher-pressure reservoir
that had been encountered. The 11 7 8 -inch liner was used at 15,103 feet to seal
the reservoir and allow for the use of higher mud weights than had been antici-
pated. Mud weight was to be kept between the curves for pore pressure and frac-
ture pressure, as shown in Figure 2-3.
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FIGURE 2-1 Original wellbore architecture planned for Macondo well. Source: BP 2010, p. 16. Reprinted with permission; copyright
2010, BP.
21
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22 Macondo Well Deepwater Horizon Blowout
FIGURE 2-2 Final wellbore architecture for Macondo well. Source: BP 2010, p. 19.
Reprinted with permission; copyright 2010, BP.
3. The 9 7 8 -inch casing (originally planned as the production casing)
was used as a liner at 17,168 feet to drill the final section of the well safely,
where the use of higher mud weights was expected in continuing the well to the
planned depth of 19,650 feet.
4. During drilling at 18,250 feet, severe lost circulation of drilling mud
occurred. This problem was solved by the use of mud containing material de-
signed to stop lost circulation and by a reduction of mud weight from 14.3 to
14.1 pounds per gallon (ppg). The lower mud weight should not have been
needed at this depth on the basis of the original plan and was an indication that
pore pressure and fracture pressure in part of this interval were considerably less
than had been anticipated.
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23
Well Design and Construction
FIGURE 2-3 The four curves (moving from right to left) represent overburden stress,
fracture gradients in the shale and sands, and pore pressure in the Macondo well. Depth
and diameter values on the y-axis correspond to the final well bore architecture shown in
Figure 2-2. The equivalent mud weight (EMW), expressed in pounds per gallon (ppg),
must be higher than the pore pressure to avoid flow from the well and lower than the
fracture gradient to prevent accidental hydraulic fracturing. Note the small separation
between the values at depths below 18,000 feet. Source: BP unpublished report, July 26,
2010.3 Reprinted with permission, BP.
5. The well was drilled to 18,360 feet, and after 5 days of logging to
make a detailed record of the geologic formations, it was determined that hydro-
carbon-bearing reservoirs of sufficient quality existed to warrant completion of
the well for production at a later time. According to the BP accident investiga-
3
BP Post-Well Subsurface Description of Macondo well (MC0252_1BP1) v3. July 26,
2010.
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24 Macondo Well Deepwater Horizon Blowout
tion report, the well analysis indicated that there were in fact several reservoirs
open in the wellbore with decreasing pore pressure with depth, as shown in Fig-
ure 2-4. The hydrocarbon reservoirs had pore pressures equivalent to a range of
12.6 to 13.1 ppg. A reservoir containing salt water that had a pore pressure
equivalent to 14.1 ppg was also exposed in the wellbore. As discussed below,
the difference between the mud weight needed to prevent flow of salt water and
the mud weight above which reservoir fracture could occur was only 0.2 ppg.
Recent reports in the press have indicated that a thin gas sand was present above
the salt water bearing zone shown in Figure 2-4 and have questioned the possi-
ble contribution of this sand to the blowout. The committee has seen no evi-
dence indicating that flow occurred upwards in the annulus between the produc-
tion casing and the reservoirs (see discussion below). Also, the presence of the
high-pressure salt water sand created the same completion problem referenced
above as would have been created by the presence of a high-pressure gas sand.
Therefore, the presence or absence of the gas sand is expected to have had no
material effect on the cause of the blowout.
FIGURE 2-4 Variation of pore pressure in the open hole section of the Macondo well
expressed in pounds per gallon. Source: BP 2010, p. 54. Reprinted with permission;
copyright 2010, BP.
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25
Well Design and Construction
To continue drilling to the planned final depth of 19,650 feet, the reser-
voirs that had been discovered with decreasing pore and fracture pressures with
depth (Figure 2-4) were to be sealed with the 9 7 8 - 7-inch combination casing
string and cement. However, because the hole diameter that could be drilled
below the 7-inch casing was considered too small to be practical, the well was
terminated at 18,360 feet.
The challenge then was to install the production casing and pump the ce-
ment into the well without causing additional lost circulation. This was achieved
on the basis of reports from the rig that no lost circulation occurred during cas-
ing and cementing operations (BP 2010, 23).
Once the casing and cementing operations were concluded, the focus
moved to the installation and testing of the integrity of the wellhead seals and
testing of the integrity of the cement, and then to completion of the temporary
abandonment process.
FINDINGS
Beginning of Hydrocarbon Flow That Led to the Blowout
As part of the temporary abandonment process, a negative pressure test
was used to indicate whether a cement barrier and other flow barriers had iso-
lated formation fluids from the wellbore. To conduct the test, rig personnel pur-
posely reduced the hydrostatic pressure inside the well. If the barriers were ef-
fective, there should be no flow into the well (or pressure buildup) from the
formation during the test. After deciding (incorrectly) that the negative pressure
test indicated that the barriers were effective, rig personnel continued with the
temporary abandonment process. The annular BOP was opened, and seawater
was circulated down the drill pipe and up the casing and marine riser to the sur-
face. Seawater displaced the mud from the marine riser and from the well to a
depth of 8,367 feet (measured from the rig). This had the effect of reducing the
hydrostatic pressure in the well below the reservoir pressure. Because the ce-
ment and mechanical barriers did not have sufficient integrity (as discussed be-
low), hydrocarbons began to flow from the formation into the well.
Summary Finding 2.1: The flow of hydrocarbons that led to the blow-
out of the Macondo well began when drilling mud was displaced by
seawater during the temporary abandonment process.
Misinterpretation of Cement Integrity Test Results
The negative pressure test was attempted three times, as described in the
BP accident investigation report (BP 2010). The initial test was flawed because
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26 Macondo Well Deepwater Horizon Blowout
the annular BOP did not seal and allowed 50 barrels (bbl) of heavy 16-ppg
spacer fluid—made up of lost circulation material (LCM)—to flow back into the
well below the BOP. This was recognized by rig personnel, and the closing
pressure on the annular BOP was increased to make a seal. At the end of this
first test, the drill pipe pressure was 273 pounds per square inch (psi) and the kill
line pressure was zero with both lines shut in.
In the second test after increasing the closing pressure on the BOP, the
drill pipe pressure increased to 1,250 psi. The drill pipe was opened and the
pressure decreased to zero after flowing out more water than was necessary to
account for mud compressibility. The drill pipe pressure should not have built
up between tests, but this could have been attributed to the heavy mud leaking
past the annular BOP. The mud volume that flowed out beyond what was neces-
sary to account for mud compressibility should have made this test a failure,
despite the drill pipe pressure having bled to zero.
With the drill pipe shut in, the kill line was chosen for the third test. It was
opened, and it flowed out between 3 and 15 bbl of water and was shut in. During
this time the drill pipe pressure slowly built up to 1,400 psi and stabilized.
The kill line was confirmed to be full of water and then reopened. It
flowed out a small volume, and then flow out of the kill line ceased. The open
kill line was monitored for 30 minutes with no pressure and no flow. Possible
reasons for this are the following: the kill line may have been plugged by the
LCM spacer, the pressure might have been equalized by the flow of the dense
spacer into the kill line, or the correct valves for the kill line may not have been
opened during this final test. The drill pipe maintained 1,400 psi.
Rig personnel focused on the fact that no flow was coming out of the kill
line instead of addressing the implications of the shut in pressure having built up
on the drill pipe. After some discussion on the rig, the negative test was deemed
a success. However, the pressure buildup actually meant that the test had failed.
The explanation used on the rig was an erroneous theory referred to as the
“bladder effect” (see BOEMRE 2011, 95). The term, as used in the industry, is
unrelated to the situation faced during the negative pressure test.
At this point the annular preventer was opened. When this was done, the
marine riser was still full of 14-ppg mud and 16-ppg LCM spacer, which was
sufficient to offset the reservoir pressure. Circulation of seawater was continued,
displacing the mud from the riser and steadily decreasing the hydrostatic pres-
sure inside the well. As mentioned above, when the hydrostatic pressure from
the seawater and mud became less than the reservoir pressure, the well began to
flow. Hydrocarbon flow into the well from the reservoir was not detected by the
rig crew during this time, although there were indications that it was occurring.
Among the indications were the following: (a) the flow of fluids pumped out of
the well was larger than the flow being pumped in and (b) the drill pipe pressure
gradually increased over time after accounting for changing pump rates (see BP
2010, Figure 8, p. 93).
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27
Well Design and Construction
Summary Finding 2.2: The decision to proceed to displacement of the
drilling mud by seawater was made despite a failure to demonstrate
the integrity of the cement job even after multiple negative pressure
tests. This was but one of a series of questionable decisions in the days
preceding the blowout that had the effect of reducing the margins of
safety and that evidenced a lack of safety-driven decision making.4
Approach Chosen to Complete the Well and
Prepare for Temporary Abandonment
According to the BP accident investigation report (BP 2010), the final
open hole section of the well contained several reservoirs with decreasing pore
pressure with depth. As shown in Figure 2-4, the largest pore pressure was esti-
mated at 14.1 ppg in a salt water–bearing reservoir, and the lowest was esti-
mated at 12.6 ppg in the hydrocarbon-bearing reservoir. The largest pore pres-
sure required that the mud weight be at least this high to prevent salt water flow
from the reservoir. The fracture mud weight was just above 14.2 ppg, as evi-
denced by lost circulation at 18,260 feet (see BP 2010, 17–18, and Figure 2-3).
This caused the margin of safety between the equivalent circulating density
(ECD),5 shown in Figure 2-3 as an equivalent mud weight, and the fracture mud
weight to be very small. The operations associated with pumping cement into
the annulus without fracturing one of the lower-pressure reservoirs were there-
fore difficult.
The completion approach chosen was to cement the production casing by
using primarily foamed cement with a density low enough that the fracture pres-
sure in the well was not exceeded. The placement of cement is always a poten-
tially problematic operation, and if it is unsuccessful it can leave channels or
pathways for fluid movement outside the casing. If the fracture pressure is ex-
ceeded while the cement is pumped, all or part of the cement can be lost to the
fracture, greatly reducing the volume of cement available to isolate the well
from high-pressure reservoirs. As explained below, foamed cement is more dif-
ficult to mix and place at the bottom of a well than is un-foamed cement. The
foamed cement does not establish the strength of the base cement used to mix
the foam, which can increase the potential for cement cracking. Furthermore,
cementing hardware, such as the backflow valves used in the float collar or cen-
tralizers on the outside of the casing, is subject to failure. Hardware failure can
lead to flow pathways through the cement and into the casing.
4
Various questionable decisions are discussed in this chapter. Also see discussions in
BOEMRE (2011), Chief Counsel (2011), DHSG (2011), and Presidential Commission
(2011).
5
ECD is a parameter that reflects the pressure that a column of fluid exerts when it is
circulating. It is a function of the density of the fluid and the friction pressure in the annu-
lus required to circulate.
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28 Macondo Well Deepwater Horizon Blowout
Summary Finding 2.3: The reservoir formation, encompassing multi-
ple zones of varying pore pressures and fracture gradients, posed sig-
nificant challenges to isolation using casing and cement. The approach
chosen for well completion failed to provide adequate margins of
safety and led to multiple potential failure mechanisms.
Pumping Sequence of Cement Slurries for the Macondo Well
The primary function of cement is to provide the first barrier to flow from
the formations into the wellbore or to flow between individual formations ex-
posed in the wellbore. In addition, the cement stabilizes the wellbore wall and
supports the steel casing. Cement slurries are often heavy, with densities around
16.4 ppg. Use of a high-density slurry is not a problem so long as the density of
the slurry, along with the density of the mud, does not create a pressure in the
well that exceeds the fracture pressure of exposed reservoirs. Cement slurries
that are dense have a high fraction of cement in the mixture and develop excel-
lent strength over fairly short intervals of time. This type of slurry can be ad-
justed by using a variety of additives to perform at the conditions found at the
bottom of a given well.
For the Macondo well, the concern was to use a combination of cements
with an average density sufficiently low that the open well would not be hydrau-
lically fractured. As indicated by the experience during drilling, the density that
would cause a fracture was about 14.3 ppg.
The pumping sequence of fluids for cementing the Macondo well was de-
signed as follows to reduce the ECD during the cementing job to prevent a hy-
draulic fracture from being created:
1. 7 bbl of 6.7-ppg oil,
2. 72 bbl of 14.3-ppg spacer,
3. 5.26 bbl of Class H cement mixed at 16.74 ppg,
4. 47.75 bbl of N2–Class H foam cement with bottom hole density of 14.5 ppg,
5. 6.93 bbl of Class H cement at 16.74 ppg,
6. 20 bbl of 14.3-ppg spacer, and
7. 857 bbl of 14.1-ppg mud displacement (calculated).
The first four fluids were to be pumped down into the casing and up into
the annulus. Fluid 5 was to be left in the shoe track. Fluids 6 and 7 were to dis-
place the leading fluids to the float collar6 (see Figure 2-5). The end of the cas-
ing was to be at 18,304 feet, measured from the rig floor.
6
The bottom section of the casing in the Macondo well, called the “shoe track,” was a
section of casing about 189 feet long with a reamer-guide shoe at the bottom and a dual-
flapper float collar on top.
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29
Well Design and Construction
6.7 ppg oil
14.3 ppg spacer
14.1 ppg drilling mud
16.74 ppg cap cement
14.5 ppg foam cement
cementing plugs
and float collar
16.74 ppg tail cement
foam cement
and dispersed
tail cement
Drawings Not To Scale As Placed
As Planned
FIGURE 2-5 Planned cement location and likely cement location after pumping. Source:
Committee.
To make a foamed cement slurry that has a density of 14.5 ppg at the bot-
tom of the well, the foam quality7 had to be 17.4 percent at bottom hole condi-
tions of 245F and 13,321 psi (see Appendix D for the calculations).8 At the
surface, where the conditions in the mixer were about 600 psi and 60F, the
foam quality had to be 66 percent, producing a foamed slurry of about 6 ppg, to
allow for the substantial compression and heating that were to occur as the foam
was pumped to the bottom of the well. (For reference, freshwater has a density
of 8.33 ppg.) Figure 2-6 shows the calculated foam density versus depth.
The purpose of the float collar is to stop wiper plugs from falling farther down the
casing string and to prevent cement slurry pumped into the annular space around the cas-
ing from flowing up the casing.
7
Foam quality is the volume fraction of gas in a given volume of foam expressed as a
percent.
8
There is some discrepancy as to what the bottom hole temperature might have been
when the cement was placed (circulating temperature). In this analysis, however, suffi-
cient time is assumed to have elapsed such that the wellbore had returned to the static
temperature.
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34 Macondo Well Deepwater Horizon Blowout
FIGURE 2-8 Float collar with flapper valves and differential fill tube. Source: BP 2010,
p. 71. Reprinted with permission; copyright 2010, BP.
Once the casing was in place in the Macondo well, initial circulation could
not be established until 3,142 psi of pump pressure was applied. This suggests
that the shoe track was plugged with foreign material when it was run into the
well. The practice of allowing mud to fill the casing by flowing up through the
differential fill tube is a time-saving step that would not be needed if the casing
were filled with mud from the top as it is run, a much slower process but one
that reduces the possibility of debris entering the casing.
Several factors pointed to the probable failure of the flapper valves in the
float collar. Once circulation was established, the pump rate never exceeded 4
barrels per minute (bpm), when at least 5 bpm was needed to shear the differen-
tial fill tube holding the flapper valves open. This indicates that the flapper
valves likely remained open. Another possibility is that sufficient debris re-
mained inside the shoe track to prevent the tube from falling out of the floats but
allowing the ball to be pumped out the end of the tube. A third possibility is that
the flappers in the valves were damaged when the higher pressure cleared the
plug in the casing.
After the cement was pumped, spacer followed by mud was pumped. The
plug bumped on the float collar after 881.5 bbl of total displacement, about what
was expected, and the plug was bumped with 1,150 psi of additional pressure
above the circulating pressure (BP 2010, 23). After bumping the plug, the pres-
sure was bled off and 5 bbl of drilling mud was flowed back out of the well. The
volume necessary to account for fluid compression is shown in the following
equation:
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35
Well Design and Construction
Vc = Vmpcm
where
Vc = volume compressed (bbl);
Vm = total volume of mud (bbl);
p = applied pressure (psi); and
cm = mud compressibility (bbl/bbl/psi), taken from the BP report,
Appendix R.
Vc = 881.5(1,150)3.3358 10–6 = 3.4 bbl
Thus, the expected flow out of the well to relieve the pressure trapped
above the plug was only 3.4 bbl, and the additional 1.6 bbl that flowed out can
only be attributed to flow through the flapper valves. Flow from the well ceased,
and the floats were considered closed. If the valves were in fact open, the differ-
ential pressure across the flapper valves would have been very small after the
trapped pressure was bled off and equalized after the small volume of flow back
through the floats. The fact that more volume flowed back before flow ceased
than was necessary to account for fluid compression should have been a sign—
although a subtle one—that the flapper valves were likely open.
Failure of the flapper valves would have provided a possible pathway for
reservoir fluids to flow inside the casing and up to the surface. Had it been sus-
pected that the flapper valves were not closed, the well probably would have
been shut in and monitored for a time sufficient for the cement to set.
Finding 2.6: Evidence available before the blowout indicated that the
flapper valves in the float collar probably failed to seal, but this evi-
dence was not acted on at the time.
Probable Path of Hydrocarbon Flow
Identification of the probable hydrocarbon flow path up the Macondo well
can provide insights for well design considerations to enhance the safety of drill-
ing operations. Pictures of the long string casing hanger that was recovered,
shown as Figure 2-9, indicate that hydrocarbon flow was up the inside of the
casing, because the inside of the hanger showed signs of fluid erosion while the
outside did not. However, under the correct circumstances, flow could have been
up the annulus. Because the lockdown sleeve was not installed, the margin of
safety against the potential for flow up the annulus was reduced.
There are alternative possibilities for the point of entry into the casing. As
discussed above, the most likely possibility appears to be the combination of
weak cement inside the casing and leaking flapper valves in the float collar. An-
other option would be for a split to have formed in the casing at some point. A
review of the casing design and the pressure to which the casing was subjected
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36 Macondo Well Deepwater Horizon Blowout
makes this possibility unlikely. In addition, the closing cementing plug was dis-
placed to the top of the float collar with the correct volume of fluid and held
pressure when the plug landed on the float collar. This would not have occurred
had a split formed in the casing above the float collar.
Finding 2.7: On the basis of photographic evidence, it appears that
flow was up the inside of the casing, because the inside of the hanger
showed signs of fluid erosion while the outside did not. However, not
installing a lockdown sleeve left a potential for flow up the annulus.
Good Cementing Practice
Industry practices that have been shown to provide the best chance for
quality cement jobs are based on numerous principles (Smith 1990):
Once casing is in the well, circulate at least one annular or one cas-
ing volume, whichever is larger. This is done to ensure (a) that no debris is in-
side the casing that might plug the float collar or shoe and (b) that the open hole
section is stable, has no hydrocarbon flow entering the borehole, and is free of
debris before cementing. The circulation also improves the likelihood of good
bonding of the cement to the surfaces of the borehole and pipe by removing
stagnant mud along with any debris.
FIGURE 2-9 View inside casing hanger. Source: Presidential Commission 2010, Slide 118.
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Well Design and Construction
This type of circulation was not done completely at the Macondo well to
reduce the possibility of exceeding the fracture pressure because of unforeseen
pressure surges. This decision by BP also cut down on the time spent circulat-
ing. Failure to perform the minimum circulation could leave debris inside the
casing or annulus that may plug it. Any hydrocarbons in the annulus may result
in a well control problem.
Centralize the casing in the hole. This helps to prevent mud-filled
channels in the cement by preventing the casing from being closer to one side of
the hole than another. Failure to achieve good centralization increases the likeli-
hood that mud-filled channels will be left in the cement, which can become flow
pathways. A high gas flow potential indicates that gas may percolate through the
cement as it sets and provide flow pathways through the cement.
Whether the casing was adequately centralized in the Macondo well is not
clear, although the final computational simulation by Halliburton suggested that
a gas flow potential existed. The simulation was run to obtain an optimal num-
ber and placement of centralizers onto the production casing. The simulation
was flawed in that it did not use the most accurate data set available from the
well. The best practice for centralizer placement is to use the results of the simu-
lation, if it has used the most accurate well data. Some confusion about the
number and placement of the centralizers and the accuracy of the final simula-
tion appears to have occurred. A final simulation on the basis of the most accu-
rate well data followed by a discussion of the results to make a decision on the
final centralizer placement would have been prudent.
Use a float collar and a guide or float shoe on the casing. The floats
are valves that prevent backflow from outside the casing.
A float collar with two float valves in it was used in the Macondo well. A
reamer shoe rather than a float shoe was used so that the differential fill tube
could be installed in the float collar. The use of a float shoe in addition to the
float collar would have increased the redundancy and thus the margins of safety.
The casing should be reciprocated or rotated during the cement
placement. Casing movement tends to help keep the mud moving ahead of the
spacer and cement and tends to force cement to flow into pathways that might
otherwise be bypassed.
This could not be done for the Macondo well because of the design choice
of using the long string of casing. The long string casing hanger must be set into
the wellhead when the casing reaches bottom to avoid its becoming stuck and
losing the ability to place the casing hanger into the wellhead. Once the hanger
is in the wellhead, the casing cannot be moved. Had a liner been used with a
rotating liner hanger, it would have been possible to rotate the casing during
cementing.
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38 Macondo Well Deepwater Horizon Blowout
Use a mud flush to remove the mud ahead of the cement. Surfactants
are necessary for oil-base mud to reverse wettability on casing and hole wall,
and they were used.
Use enough cement to fill the desired hole volume plus excess to
make up for hole washout and mud cake contamination. This was probably
achieved, at least to the standards of the Minerals Management Service (MMS).
However, it could not be verified because cement bond logging was not used.
Where possible, achieve turbulent flow in the annulus, at least for the
mud flush. Turbulent flow tends to help keep the mud moving ahead of the ce-
ment. Turbulent flow probably did not occur because of the low pump rate used.
Finding 2.8: Because of the choice of the long string of production cas-
ing, it was not possible to reciprocate or rotate the casing during the
cementing operation. Casing movement tends to help remove any mud
left in the path of the cement and force the cement into pathways that
might otherwise be bypassed. The minimum circulation of mud was
not achieved in this well, which would have been helpful in removing
stagnant mud and debris from the annulus. Thus, the possibility of
mud-filled channels or poor cement bonding existed.
Cement Bond Log
Whether to run a cement bond log was up to the discretion of the operator
because MMS rules did not require a bond log if no lost circulation occurred
during cementing operations. The decision was made not to run a cement bond
log because no lost circulation had been noted during cementing operations. The
design of the well placed the top of the float collar above the bottom of the
deepest reservoir, so even had a log been run it could not have been run deep
enough to examine the condition of the cement across all of the productive
zones. The top of the cement and the cement quality in the annulus above the
float collar could have been determined if the software necessary to evaluate the
foam cement was on board.
Finding 2.9: No cement bond log was run to investigate the condition
of the cement. The well design placed the float collar above the bottom
of the deepest reservoir and would have prevented the log from inves-
tigating the lower sections of the well in which cement had been
pumped.
Onshore Oversight
No person in authority (from BP onshore management or a regulatory
agency) was required to review critical test data such as the results of the nega-
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Well Design and Construction
tive test. Had this been a requirement before operations could continue, the
negative pressure test data might have been questioned and additional testing
conducted that would have exposed the problem of reservoir communication
with the well. The real-time data from the rig were being recorded but not moni-
tored on shore. Even with the negative test having been accepted, subsequent
data showing that the reservoir and well were in communication might have
been discovered by personnel on shore in time to take the appropriate control
action.
Finding 2.10: Although data were being transmitted to shore, it ap-
pears that no one in authority (from BP onshore management or a
regulatory agency) was required to examine test results and other
critical data and render an opinion to the personnel on the rig before
operations could continue.
OBSERVATIONS
Alternative Well Completion Techniques for Temporary Abandonment
Alternative cement types or completion styles were available for use at the
Macondo well. When personnel on the rig encountered a low margin of safety
between the ECD and the fracture pressure, the safest approach would have been
to plug the bottom open portion of the well and use the geologic data to design a
replacement well. The replacement could have been a new well entirely or a
sidetrack out of the lower portion of the existing well. Had a higher margin of
safety between the ECD and the fracture pressure been required, this is the op-
tion that most likely would have been chosen. A redesign of the completion
could also have provided sufficient depth below the producing formations so
that the cement bond log could examine the presence and quality of the cement
throughout the productive interval.
A sufficient margin of safety should be used for the ECD while fluids are
circulating so that even with unforeseen pressure surges or rate and fluid prop-
erty fluctuations, the possibility of fracturing is reduced. This is especially im-
portant during cement jobs in which only small cement volumes are used be-
cause the entire cement volume could be lost to a fracture.
ECD is a function of the density of the fluids and the friction pressure in
the annulus required to circulate. Thus, the fluid properties, pipe-to-hole dimen-
sions, and pump rate have an influence. There are no standards for this margin
of safety, but one possible standard is to use a safety (kick) margin of 0.5 ppg, as
referenced by several authors (Bourgoyne et al. 1991; Aadnoy et al. 2009). The
authors define that safety margin in the same manner as an ECD margin of
safety is defined in this report: as the difference between the mud weight that
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would create a fracture and the ECD used. The ECD margin of safety discussed
here does not obviate the need for other good drilling and completion practices
to help avoid a kick or blowout.
Summary Observation 2.1: While the geologic conditions encountered
in the Macondo well posed challenges to the drilling team, alternative
completion techniques and operational processes were available that
could have been used to prepare the well safely for temporary aban-
donment.
Missed Opportunity to Discover Hydrocarbon Flow
Data presented in the BP accident investigation report (BP 2010, 93) indi-
cate that drill pipe pressure increased to 1,400 psi during the last of the negative
pressure tests. The increase in the drill pipe pressure at that time should have
been a clear indication that hydrocarbons might be flowing into the well. The rig
personnel explained the pressure increase by using an erroneous theory termed
the “bladder effect.”
Observation 2.2: Had an attempt been made to bleed off the drill pipe
pressure at the end of the negative test, the communication with the
reservoir would likely have been discovered.
Instability of the Foamed Cement
Foam is inherently unstable, and the extent to which it is stable is sensitive
to its chemical makeup and the environment to which it is exposed. To make a
foamed cement slurry that has a density of 14.5 ppg at the bottom of the well,
the foam quality must be 17.4 percent at bottom hole conditions of 245F and
13,321 psi. At the surface, where the conditions in the mixer are about 600 psi
and 60F, the foam quality must be 66 percent, producing a foam of about 6 ppg,
to allow for the substantial compression and heating that will occur as the foam
is pumped to the bottom of the well.
As foam is pumped into the well, where pressure and temperature increase
with depth, the foam quality and slurry density change all the while (see discus-
sion earlier in the chapter). Also, the shear associated with fluid movement
down the inside of the pipe would act to break up large bubbles, which immedi-
ately reform as smaller bubbles so long as agitation is taking place. The foam
cannot be considered stable in all of these conditions.
However, a chemical blend and surfactants were used on the rig in an at-
tempt to make the foam stable at bottom hole conditions of the Macondo well—
at least long enough for the slurry to set.
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Well Design and Construction
After the blowout, static tests were performed under laboratory conditions
on a foam cement slurry similar to the one pumped into the Macondo well. Ana-
lysts observed settling of cement and breakout of nitrogen from the foamed ce-
ment exposed to atmospheric pressure. The tests were not carried out at bottom
hole conditions. Therefore, it is impossible to say whether the foam was stable at
the bottom of the well.
Observation 2.3: The results of a variety of static tests of foamed
cement mixed at 14.5 ppg and exposed to atmospheric pressure call
into question the stability of the foam, because settling of cement
and breakout of nitrogen were observed in these tests. The tests
were not performed at conditions that existed during pumping or
at the bottom of the well and therefore cannot be considered as
representative of the foam during displacement or at bottom hole
conditions.
Potential for Cement Contamination
The lead slurry pumped into the Macondo well was made up of 5.26 bbl of
un-foamed Class H cement and was in contact with the spacer and any mud that
was not successfully moved out of the annulus once it was pumped out the end
of the casing. The small volume of lead cement was designed to provide a high-
strength cap between the spacer and mud that was ahead of and above the slurry
and the foamed cement that was following and below. The small volume of lead
cement may have been contaminated by either the spacer or the drilling mud
from the annulus above the lead slurry or by mixing with the trailing foam
slurry. Any contamination of the lead slurry would reduce the compressive
strength of the cement once it set.
Observation 2.4: The pumping sequence of cement slurries and other
fluids used for cementing the Macondo well subjected the volume of
the lead cement slurry to contamination by the spacer or mud that
was placed ahead of it. If it was heavily contaminated, the slurry
would not have established a cement cap with the compressive
strength of uncontaminated cement.
Possible Path of the Blowout and Implications for Well Construction
Had the blowout occurred up the annulus rather than inside the casing, the
various liner tops and the rupture discs in the 16-inch liner would have been
exposed to high pressure. A liner top or the rupture discs could have failed and
allowed flow to exit the annulus and flow into a formation outside the well. This
would have resulted in a downhole blowout rather than the surface blowout that
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occurred. The shallowest possible escape point would have been 7,937 feet had
a rupture disc and the top of the 18-inch liner failed (see Figure 2-2). This is
about 2,937 feet below the ocean floor. Depending on the flow rate, pressure,
and formation type, flow at this point might find a pathway to the ocean floor
and cause a breach outside of the well. Therefore, a more robust design from a
downhole blowout point of view would be to lower the possible point of escape
from the wellbore to a deeper point where eventual breaching at the seafloor is
impossible or at least very unlikely. This could be done by running a deeper
casing string as a long string rather than as a liner and sealing it in the wellhead.
Observation 2.5: Had the path of the blowout been up the annulus, a
liner top or the rupture discs could have failed and allowed flow to es-
cape the well into a shallow formation. This would result in a down-
hole blowout that could breach at the seafloor under the correct con-
ditions. Future well construction could avoid this possibility by
running one of the deeper casing strings back to the wellhead where it
can be sealed. For example, in this well the 13 5 8 -inch liner could have
been run back to the wellhead. This would protect the shallower liner
tops and rupture discs from potential exposure to high pressure from
flow up the annulus from a deeper reservoir.
Use of the Long String Production Casing
The use of the long string of production casing has already been cited as a
reason the casing could not be reciprocated or rotated during cementing opera-
tions. One alternative to using the long string is to run a production liner on the
drill pipe. The liner is suspended or hung several hundred feet up inside the pre-
vious casing, in this case the 9 7 8 -inch drilling liner that had been set at 17,168
feet. Cement is then pumped though the drill pipe and liner to fill up the desired
annular volume. Often cement can be circulated to the top of the liner, which
may create a seal at the top of the liner. If cement cannot be or is not circulated
to the top of the liner, a cement squeeze is performed at the liner top where ce-
ment is forced into the annular space between the liner and the previous casing
to form a seal at the top of the liner. A liner top packer that forms a mechanical
seal at the top of the liner can also be deployed to replace or supplement the
cement seal. The liner top is tested with a positive and a negative test in a man-
ner similar to the testing of the long string to demonstrate wellbore isolation
from the formations outside the liner. Because of the short length of the liner, it
is also possible that the differential fill tube used in the float collar could have
been omitted, removing one possible failure mechanism for the float equipment.
A major difference between testing of the liner top and testing of the long
string is the reduced likelihood of other operations that can confuse the interpre-
tation of the test being carried out at the same time. In addition, should the liner
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Well Design and Construction
top show signs of a leak, the well is still substantially full of drilling mud near
the bottom of the well, and the drill pipe is in a better position, near the bottom
of the well, to control the leak and begin repair operations.
Observation 2.6: The use of a production liner rather than the long
string could have allowed for the use of a rotating liner hanger to im-
prove the chances of good cement bonding; allowed for the use of a
liner top packer to add a barrier to annular flow near the bottom of
the well; allowed for the omission of the differential fill tube, which
would remove a potential failure mechanism for the float collar; po-
tentially made the negative test simpler to conduct and interpret; and
configured the well to better control and repair a leak in the liner by
leaving the well filled with drilling mud to a greater depth and by
placing the drill pipe at a greater depth in the well during the test.
RECOMMENDATIONS
Margins of Safety
Summary Recommendation 2.1: Given the critical role that margins of
safety play in maintaining well control, guidelines should be estab-
lished to ensure that the design approach incorporates protection
against the various credible risks associated with the drilling and
completion processes.
Recommendation 2.2: During drilling, rig personnel should maintain a
reasonable margin of safety between the ECD and the density that
will cause wellbore fracturing.
There is no standard for this margin of safety. As a guide until a reason-
able standard is established, industry should design the ECD so that the differ-
ence between the ECD and the fracture mud weight is a minimum of 0.5 ppg. In
the event that a sufficient margin of safety cannot be maintained, the open sec-
tion of the well should be plugged and alternative drilling or completion meth-
ods used in which the required safety margin can be maintained. Additional
evaluations and analyses should be performed to establish an appropriate stan-
dard for this margin of safety.
Verifying Barrier Integrity
Summary Recommendation 2.3: All primary cemented barriers to flow
should be tested to verify quality, quantity, and location of cement.
The integrity of primary mechanical barriers (such as the float
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equipment, liner tops, and wellhead seals) should be verified by using
the best available test procedures. All tests should have established
procedures and predefined criteria for acceptable performance and
should be subject to independent, near-real-time review by a compe-
tent authority.
This includes the timing of the start and the magnitude of the pressure
tests compared with the amount of time needed for strength development of the
cement, the results of the pressure tests, verification that the flapper valves have
closed and the other mechanical seals are holding, and evaluation of cement
bond logs.
Well Design Review
Recommendation 2.4: The general well design should include the re-
view of fitness of components for the intended use and be made a part
of the well approval process.
For example, the review should consider alternatives to the use of a series
of two cement slurries that will be gravitationally unstable during placement in
the well and potentially result in a slurry that does not achieve the desired com-
pressive strength. The review should also consider the use of a differential fill
device because the use of this device in the Macondo well appears to have con-
tributed to the failure of the flapper valves to perform their intended function.
Well Construction Practice
Recommendation 2.5: Generally accepted good operational or best
practices should be used in the construction of the well. Such practices
would ensure that the most accurate well data are passed from the op-
erator to the various contractors for use in simulations and design and
that the results are considered by all parties before implementation.
