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8/8/2019 Marathon Macondo Study
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Worldwide DrillingNorthern Business Unit,
Conventional Gas Exploitation
The Macondo Incident
Findings and Conclusions Prior toPublished Inspection of the Subsea BOP
12 October, 2010
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CONFIDENTIAL
FOR MARATHON OIL COMPANY USE
ONLY
The material contained in this
presentation is for internal training
purposes and is not to be furtherdistributed
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The Event
On the evening of April 20, 2010, control
of the BP operated Macondo Well, located
in approximately 5,000 of water in
Mississippi Canyon Block 252, was lost.
This loss of well control resulted inexplosions and fire on board
Transoceans rig Deepwater Horizon.
Eleven people lost their lives and 17
others were injured.
The blowout fed the fire for another 36
hours until the rig sank. Hydrocarbons
continued to flow uncontrolled from the
wellbore for 87 days, resulting in a spill
of national significance.
A response effort of unprecedented size,
technical complexity, political pressure,
media coverage and cost continues
today.
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The First 36 Hours
At the time of the
incident we had two rigs
operating in the GOM, the
Noble Paul Romano at
Innsbruck (MC 993) and
the Diamond Ocean
Monarch at Flying
Dutchman (GC 511).
Our supply vessels
were directed to the scene
for SAR operations and
fire fighting.
The Ocean Monarchwas contacted for use of
their BOP ROV
intervention stab, but the
Ocean Endeavor had the
same model and was
closer.
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An Unprecedented Response Effort
As an Industry we watched as
hours turned into days, days
became weeks, and weeks
grew into months. In contrast
to the failures which led to theblowout, the response effort
was nothing short of
phenomenal.
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The Flow Path
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The Flow PathIn the early days of the incident we, along with most of the industry, identified the three potential
flow paths for the blowout: Annular flow thru a failed or off-seated casing hanger pack-off,annular flow thru parted or leaking production casing, or flow thru the float equipment.
The majority of the industry, including us in the early days, became convinced that the flow path
was thru the casing hanger pack-off. We reached this conclusion for two major reasons:
1. Reports confirmed that the lock-down sleeve had not been installed before the blow-outoccurred. Quick calculations indicated that if hydrocarbons had been allowed to migrate
during and after the cement job, forces due to probable differential pressures could have off-
seated the hanger and pack-off.
2. More importantly, the feeling was that whatever happened occurred so fast that the rig crew
had no time to react appropriately. The thought of an influx coming all the way from TD to
surface without being detected and secured was considered next to impossible and
dismissed.
As days turned into weeks, several of us began to question why the exposed formations had not
failed, collapsed and bridged over the flow path. There are several hundred feet of open
formation between the productive interval and the 9-7/8 liner shoe. Despite the implications
(well unloaded from the bottom, up the production casing, undetected), some of us reachedthe conclusion that flow through the float equipment was the only path that could explain the
sustained flow without bridging.
Unfortunately BPs investigation team, which had access to much more information than the
majority of the industry, reached the same conclusion based on multiple pieces of evidence. They
go so far as to state that well control efforts were not initiated until 49 minutes had elapsed andapproximately 1,000 bbls of influx had occurred.
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Evidence of Flow Path from BPs
Accident Investigation
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Well Design Information
The discussion regarding the flow path is important because BP was heavily criticized
for running the final production casing as a long string. The assumption was that
annular flow thru poor cement and a damaged or off-seated casing hanger pack-off
was the failure mode.
The investigation team included a diagram that suggested the original Macondo well
plan called for a long string of production casing (9-7/8). According to mutual
partners, this design is not uncommon for BP. While it eliminates at least one annular
barrier (liner-top packer), it also eliminates leak paths associated with liner hangers
and tie-back seals. In some cases this design provides mitigation for annular pressure
build-up, and this appears to play heavily in BPs decision to install long strings.
Although we have not utilized a long string in our deepwater completions for a variety
of reasons, it is not appropriate to say the use of a long string across a productive
interval is negligent. Multiple risks and hazards must be addressed on a case-by-case
basis, and there may be times that a long string provides the best solution.
It is the design, installation and proper verification of barriers that is critical
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Original Well Design and Actual
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Findings From BPs Investigation Team
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Investigation Teams Representation of
the Physical or Operational BarriersBreached
Disasters of this nature and magnitude are almost always the result of multiple failures. These
failures often involve decisions made, actions taken (or not taken), and barriers. The Macondo
Incident is no exception.
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Well Integrity Was Not Established or
Failed
The cement did not isolate the
hydrocarbons from within theannular space behind the
production casing
The shoe track (cement and float
equipment) failed to provide aneffective barrier
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Cementing Operation
The Investigation Team determined the annular cement failedto isolate the hydrocarbon bearing zones for one or more of
the following reasons:
Foamed slurry was likely unstable and allowed nitrogen to
break out
No fluid loss additives were included in the slurry
Complete lab testing of the slurry was not performed
Contamination of the slurry due to the small volume
pumped
Channeling due to insufficient mud removal was briefly
discussed, with a base oil spacer and only 6 centralizers
mentioned. The main focus, however, was on foam instability
and possible contamination
This complex slurry and spacer program was apparentlydesigned to minimize ECD and maximize the chance of having
returns. Having returns at surface during a cement job on a
long string at this depth should very seldom be a primary
objective, and actions taken to achieve this performance
indicator can jeopardize the critical requirements for
complete mud removal and minimal contamination of the
slurry.
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Cementing Operation
The Investigation Report fails to state the slurry volume, the pumprate used to place it, and the results of the lab testing that was
completed. They do state that full returns were achieved during the
placement of the slurry.
In a draft report from May, BP states that a 60 bbl slurry was
pumped. Based on the wellbore details provided in the final
report, the volume required to reach their planned TOC would
have been slightly more than 50 bbls assuming a gauge hole
The slurry and spacer densities were very close to the mud
density. There would have been very little to no benefit from
density differences when displacing the mud.
Although not stated (or at least not found by me), the pump
rate while placing the slurry was probably on the low end if
fracture margins were tight yet full returns were acheived.
Rate (annular velocity) plays a very critical role in effective
mud removal, minimizing contamination and eliminating
channels.
Time to develop compressive strength was not stated in the
report. A Transocean investigation stated Test on 4/12 of
7casing slurry : 0 psi compressive strength after 24 hours .
Attempts to perform a negative test commenced
approximately 16-1/2 hours after bumping the plug.
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Cementing OperationBased on the information presented, the cement slurry design and implementation had a very low
probability of ever providing an effective barrier.
Apparently in an effort to maintain an exposed shoe (9-7/8 liner, for future annular pressure buildup
mitigation), the overall slurry volume was maintained very close to a calculated gauge hole capacity.
Therefore, a 16.74 ppg cap, followed by a nitrified 14.5 ppg lead, chased with a 16.74 ppg tailwas
crammed into an overall volume of 60 bbls, preceded by a 6.7 ppg base oil and 14.3 ppg spacertodisplace 14.2 ppg mud, all pumped at a rate slow enough to allow full returns in an environment
with little fracture gradient margin through a tapered string of casing at over 18,000 deep.
While there are many factors that must be considered in the planning of a cement job, often times rate
and volume can overcome many deficiencies. Rate can help reduce the effects of poor centralization,
inability to move the pipe, and reduced density differentials to name a few. Increased volumescompensate for enlarged hole conditions and contamination that occurs during the placement and mud
removal process.
If cement is going to be relied upon as a barrier, then achieving this becomes the primary objective in the
design and execution. Had a significantly larger volume of non-nitrified cement with proper fluid
loss additives and LCM material been pumped at a rate that ensured mud displacement and
diversion (if losses were experienced below the highest HC bearing zone), it is quite possible thisdisaster would have been avoided. At these depths and objectives, our practice has and continues to be
non-nitrified slurries with tightly controlled fluid loss with LCM additives (if warranted), well centralized
casing whenever possible, and rates that ensure proper mud displacement (despite no returns at
surface the majority of the time). Ironically, had BP followed our general practice, their concern
about maintaining an exposed shoe at the 9-7/8 liner would have been addressed automatically
no returns equals no cement above the next shoe.
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The Shoe Track Cement and Float
Equipment Failed to Provide an EffectiveBarrier
The investigation team identified the following possible failure
modes that may have contributed to the shoe track cements
inability to prevent hydrocarbon ingress:
1. Contamination of the shoe track cement by nitrogen breakout
from the nitrified foam cement.
2. Contamination of the shoe track cement by the mud in the
wellbore.
3. Inadequate design of the shoe track cement(reference to theset time of the cement in relation to the attempted negative
test?)
4. Swapping of the shoe track cement with the mud in the rat
hole (bottom of the hole).
5. A combination of these factors.
Three possible failure modes for the float collar were identified:
1. Damage caused by the high load conditions required to
establish circulation
2. Failure of the float collar to convert due to insufficient flow
rate (reference to a low cement placement rate?)
3. Failure of the check valves to seal.
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The Shoe Track Cement and Float
Equipment Failed to Provide an EffectiveBarrierWe have experienced more than one failure of this type of float
equipment. While it is run as a double valved installation, an
effective seal cannot be taken for granted.
Typically, there is enough displacement pressure (differential pressure
due to a heavier column of cement in the annulus) following a cement
job to immediately determine if the float valves (check valves in the
adjacent schematic) are holding.
Due to the spacers, nitrified slurry, and very probable channeling andcontamination, the differential pressure following the cement job on
the 9-7/8 by 7 production casing would have been very little to none.
Like we have witnessed more than once in our operations, the check
valves may never have been holding. The difference here is there was
probably insufficient differential pressure to make this determination.
The investigation team pointed out multiple potential failure modes
for the cement inside the shoe track. Exposing the cement to a
negative differential before it was capable of providing a seal is a
possibility as well.
A more conventional, higher volume cement job may have provided the
differential necessary to determine the integrity of the check valves.
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Hydrocarbons Entered the Well
Undetected and Well Control was Lost
Negative pressure test was accepted despite obvious signs that well
integrity did not exist
Influx was not recognized until hydrocarbons were above the subsea BOP
Well control response actions failed to regain control of the well
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Positive Test
The Positive Test (2,700 psi) of the production
casing was successful.
Although from the opposite direction as the
pressure differential experienced after displacingthe riser to seawater, the casing and casing hanger
seal assembly tested.
Since the wiper plug had landed during the cement
job, the positive test pressure was unlikely to be
transmitted to the shoe track.
The positive test commenced approximately 10-1/2
hours after the plug was bumped.
At this point a sigh of relief was probably breathed.
A very difficult, significantly over-budget well had
just been cased, cemented and tested.
It was also at this point that a False Sense of
Security probably set in.
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Incorrectly Interpreted Negative Test
Attempts were being made to
accomplish more than one
objective with the negative testing
operation.
The spacer referenced in theDeepwater Horizon Investigation
was more accurately described as
unused Form-a-Set and Form-a-
Squeeze LCM pills in the
Deepwater Horizon Interim
Incident Investigation dated May24th 2010 (cant be discharged
directly from rig, but if it goes into
the well, then the returns can be
discharged, so this was pumped
ahead of the seawater with the
intention of dumping after it
returned to surface)
Introducing this additional
operation into a very safety-
critical test may have added to
the difficulty personnel
experienced interpreting theresults.
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Incorrectly Interpreted Negative Test
When conducted in this
manner, the subsea BOP
element utilized (ram or
annular preventer) must holda pressure differential from the
top, opposite from what it is
designed to accomplish.
Ironically, the only ram in the
stack designed to hold a
differential from above was
the test ram, the one heavily
criticized as a useless ram
in early media reports.
The amount of fluid that
reportedly leaked by theannular preventer during the
attempted negative test did not
help the interpretation of the
results (16.0 ppg LCM pill
likely entered into and gained
height in the kill line).
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Incorrectly Interpreted Negative Test At some point it was decided to
switch from the drill pipe to the killline for monitoring.
The kill line reportedly stayed at 0 psi
for 30 minutes, while the drill pipe
reportedly built to 1,400 psi over a
period of time.
The drill pipe pressure was explained
as a bladder effect and the kill line
observations were considered
accurate. The negative test was
considered successful and
displacement of the mud and 16.0 ppgspacer with seawater continued.
If two lines are connected directly
to the same compartment, similar
pressure responses (variances may
exist due to fluid densitydifferences) should be observed. If
one reads 0 psi and one builds to
1,400 psi,you STOP and determine
why such a discrepancy exists. You
dont blame it on some mythical
bladder effect.
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Incorrectly Interpreted Negative Test
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Influx was not recognized until
hydrocarbons were above the subsea BOP
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Influx was not recognized until
hydrocarbons were above the subsea BOPUnrecognized Flow Indications
In this case the drill pipe had already
been completely displaced with
seawater. The expectation should be
that at a given flow rate, the drill pipe
pressure should decline as mud is
displaced from the annulus, then
remain constant once seawater
reaches the surface.
During this displacement, influx near
the bottom of the well displaced mud
above the bottom of the drill pipe,
causing a pressure increase. Thisunexpected response, even with the
pumps off, apparently was not
recognized.
1. Drill pipe pressure increased by
100 psi when it should have been
decreasing (~ 39 bbl gain from
20:58 to 21:082. Drill pipe pressure increased by
246 psi with the pumps off, and
flow does not immediately drop off
when shutting down the pumps
3. Drill pipe pressure increased by
556 psi with the pumps off, ~ 300
bbl gain by now.
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Influx was not recognized until
hydrocarbons were above the subsea BOPInflux continues to displace mud
above the end of the drill pipe,
causing the drill pipe pressure to
increase with the pumps off.
As hydrocarbons pass the end of
the drill pipe and the displaced
mud and mud-seawater mixture
enters the riser (less height for a
given volume), the drill pipe
pressure starts to decline, rapidly.
It wasnt until the last pressure
increase with the pumps off that
someone decided something was
not right, but the action taken
was to apparently bleed off the
drill pipe pressure.
At this point the well must have
been flowing at a very
substantial rate for over 10
minutes with the pumps off
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Influx was not recognized until
hydrocarbons were above the subsea BOP
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Influx was not recognized until
hydrocarbons were above the subsea BOP
I fl i d il
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Influx was not recognized until
hydrocarbons were above the subsea BOPThere have been several discussions regarding the factors that may have contributed to the failure to recognize the influx
until it was well above the subsea BOP. The most significant of these, in my opinion, are listed below. I list these, and
discount the others on the next slide, because of the following belief:
As long as the BOPs and Marine Riser are attached to the wellhead, a conduit directly to the rig exists. As long as a
direct conduit to the to rig exists, constant monitoring to ensure well control is maintained is required. The Driller is
ultimately responsible, regardless of the other operations going on, for ensuring well control is maintained at alltimes.
1. False sense of security prevailed since the wellbore had been tested positively, and the negative test had been
mistakenly accepted as successful.
2. When preparing to perform an operation, often times the responses can be predicted and should be expected. If the
expected responses are not observed, then the operation should be stopped and the reason for the discrepancy
should be determined and remedied. The pressure responses shown on the previous slides certainly deviated from
what should have been expected. The Driller either did not observe these responses, did not comprehend that these
responses should not be expected, or both. Since action was not taken until the last significant pressure increase
(with the pumps off , 556 psi), one might conclude that he did not observe. The action, however, (bleed off the drill
pipe pressure) indicates he had no comprehension of what should be expected and what was actually happening.
3. It was not uncommon for us to displace the riser with no accurate pit monitoring, but when those cases existed, no-
flows were obtained at scheduled intervals and someone was assigned to monitor the flow and confirm no-flowwhen the pumps were shut down. This was obviously not done on the Macondo well. Flow was not recognized for
at least 49 minutes and after 1,000 bbls of influx. New regulations will likely prohibit displacements like this in the
future. From now on, displacements will be done with a closed BOP in multiple steps.
Almost 20 years ago I stood on the rig floor of a semisubmersible with the Senior Offshore Supervisor I was working
nights for. He had worked his way up through the contractor ranks on semisubmersibles, and then hired on with
Marathon. He retired not long ago. Pointing at the Driller on the brake, he said Incase you dont know, that is themost important person on this rig. He can sink this thing faster than anyone else onboard
I fl i d il
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Influx was not recognized until
hydrocarbons were above the subsea BOP
Several other contributing factors have been stated or discussed. Some of these are listed below, but
while these often receive significant discussion, they are not critical and should have had no impact on
ensuring well control was maintained.
VIPs were on board to congratulate the crews for an achieved safety performance milestone. It
doesnt matter who is onboard, ensuring constant monitoring occurs and well control ismaintained should not be negatively impacted by visitors.
Multiple operations were going on simultaneously, so attention to critical tasks was divided. There
are always simultaneous operations taking place on a facility of this magnitude. Well control,
however, must always be someones top priority; and that someone better understand this very
clearly.
Transfers of mud to a supply vessel were taking place prior to the displacement, making it difficult to
monitor volumes. It was stated in the investigation report that the mudloggers were not
notified when transfers ceased and apparently did not monitor the pit volumes. While often
used for this task, mudloggers are not the ones ultimately responsible for continuously
monitoring the well during all operations.
The mudloggers flow meter was bypassed and pit monitoring was not possible once returns were
routed overboard. Same as above, and other means of verifying the well is stable should have
been employed (frequent no-flow checks, having someone dedicated to monitoring the returns
and verifying no-flow each time the pumps are shut down)
W ll C t l R A ti F il d t
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Well Control Response Actions Failed to
Regain Control of the Well
Well control response actions were not taken
until water and mud started overflowing onto
the rig floor. At this point over 1,000 bbls had
entered the well undetected and hydrocarbons
were above the subsea BOP.
Mud was expelled through the rotary table
up through the derrick towards the crown
block before the diverter was closed
Pressure responses indicate an annular
preventer was closed, but did not sealimmediately. Transoceans protocol was to
close the annular, then close a VBR.
Eventually the pressure responses indicated
a seal was obtained. The annular was only
rated to 5,000 psi, and modeling indicated
an 8,000 psi differential could be expectedat that point. The investigation team
concluded that it was very likely that a VBR
produced the seal.
W ll C t l R A ti F il d t
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Well Control Response Actions Failed to
Regain Control of the Well
Flow from the diverter was routed to the mud gas separator (MGS), not directly overboard.
This action, regardless of whether someone intentionally lined it up this way or if it was lined
up to the MGS as SOP, ultimately eliminated any further human intervention to secure the well
and perform emergency disconnect actions.
This routing of a major gas event to the MGS resulted in component failures and the rapid
dispersion of gas across large areas of the rig. Failure of the fire and gas systems to prevent
ignition was listed as another failed barrier, but this is a weak statement. An event of this
magnitude would quickly go beyond electrically classified areas, and multiple sources ofignition, including sparks generated by failed components, would have existed.
The subsequent explosion likely took out both MUX cables in the moon pool, thereby
eliminating any further actions by the crew to shear the pipe or initiate an emergency
disconnect sequence.
Well Control Response Actions Failed to
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Well Control Response Actions Failed to
Regain Control of the Well
Instantaneous gas rates reached an estimated 165 mmscfd with pressures in excess of 100 psi
Gas would have likely vented from: Slip joint packer, 12 MGS vent, 6 MGS vacuum degasser vent, 6
overboard relief line (burst disk), 10 mud line under the main deck
Well Control Response Actions Failed to
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Well Control Response Actions Failed to
Regain Control of the Well
Well Control Response Actions Failed to
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Well Control Response Actions Failed to
Regain Control of the Well
Well Control Response Actions Failed to
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Well Control Response Actions Failed to
Regain Control of the Well
It is likely the explosion took out both MUX
cables, preventing communication to thesubsea BOPs
Manual activation of either the High-
Pressure Blind Shear Rams or the EDS
would have been prevented. Testimony
indicated that the EDS was pushed and the
panel reacted like it should, but it never left
the panel
At this point, only the AMF (Automatic
Mode Function) and ROV intervention
remained
Well Control Response Actions Failed to
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Well Control Response Actions Failed to
Regain Control of the Well
Although the pressure responses indicated
the subsea BOP sealed eventually, flow
continued after the initial explosion based
on the intensity of the fire.
This flow may have come from severalsources, including:
Rig drifting or traveling equipment
movement moved pipe enough to
damage the VBR and allow flow again
Damage to the drill pipe allowed flow
into riser or onto rig floor area
Surface equipment failures (swivel
packing, kelly hose)
Pressure relief valves on mud pumps
allowed flow into pit area
Well Control Response Actions Failed to
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Well Control Response Actions Failed to
Regain Control of the Well
Had the 14 overboard line been utilized,
as it should have been for any significant
gas event, the outcome may have beendifferent.
The slip joint packer may still have been
at risk, but a significant portion of the gas
would have been vented safely away,
reducing the chance for ignition.
Manual activation of the high-pressure
BSR or the EDS would have been much
more likely
Emergency BOP Functions Failed to
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Emergency BOP Functions Failed to
Secure the Well
Emergency BOP Functions Failed to
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Emergency BOP Functions Failed to
Secure the Well Manual emergency functions had beenrendered inoperable by the explosionand fire
The AMF (Automatic Mode Function,
more commonly called the Deadman
System) then became the second to last
line of defense. At a minimum thisfunction would have activated the high
pressure BSR.
The Deadman System requires a loss of
communication, electrical power and
hydraulics (all three) at both pods to
activate.
Communication and electrical power
would have been lost with the MUX
cable damage
Although more protected, the hydraulicsupply conduit and surface system
would have been destroyed as well, if
not by the explosion, then by the fire.
The Deadman System failed to
function
Emergency BOP Functions Failed to
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Emergency BOP Functions Failed to
Secure the Well
On this model BOP Stack, the Deadman System relies
on lithium battery packs in the subsea control pods to
operate the solenoid valves.
When these pods were recovered to the surface
during the response effort, the Deadman Systemfunctions in both were found inoperable.
In the Blue Pod, the battery power remaining was
significantly below that required to operate the
solenoid valve.
In the Yellow Pod, there was probably sufficient
battery power, but the solenoid valve was inoperable.
How much attention is given to the lines of
defense that are considered last or next to
last, especially when there are several
barriers before these are needed?
Emergency BOP Functions Failed to
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Emergency BOP Functions Failed to
Secure the Well
ROV Intervention also failed to secure the well
The shuttle valves on the Cameron BOP Stack require a minimum flow
rate to fully shift and direct fluid to the intended function.
ROV Intervention capability is routinely tested at surface, but it istypically done with a hot line pulling fluid directly from the rigs
accumulator system. It is seldom done with or at a rate equivalent to
what the ROV pump can generate.
The rate the ROV could generate was insufficient to shift the shuttle
valves on this stack. This was due to the design of the shuttle valvesand hydraulic leaks subsequently discovered in the system.
The ROV successfully activated the autoshear function (if armed, this
function activates the high pressure BSR when the LMRP is
disconnected) by cutting the indicator rod. This was done 07:40, 21
April 2010.
The high pressure BSR failed to secure the well, and this was the last
line of defense. Additional attempts were made to actuate
components with the ROV intervention panel. It was assumed that
attempts to close the pipe rams meant the middle VBR, but it was
discovered that the bottom, inverted test ram was the one actually
plumbed to the ROV intervention panel.
Emergency BOP Functions Failed to
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g y
Secure the Well
Failure of the autoshear function, which closes the high-pressure BSR, to secure the well
may have been due to:
1. Insufficient hydraulic power to shear the 5-1/2 21.9 ppf, S-135 which was across thestack at the time of the incident
2. Seal failure due to prevailing flow conditions in the BOP
3. Presence of non-shearable components across the BSR
Emergency BOP Functions Failed to
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g y
Secure the Well
1. Insufficient hydraulic power to shear the 5-1/2 21.9 ppf, S-135 which was across the
stack at the time of the incident
Period of approximately 30 hours existed where the subsea accumulators were
not being charged from surface (explosion to ROV autoshear activation)
During subsequent control efforts, a control system leak of no greater than 0.32
gph was determined between pod retrieval and reinstallation.
The investigation team stated that a leak of approximately 3 gph for 30 hours
would have been required to drop the subsea accumulator pressure below that
required to shear the drill pipe.
Emergency BOP Functions Failed to
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2. BSR seal failure due to prevailing flow conditions in the BOP at the time of actuation.
BSR successfully tested during the positive pressure test on the morning of theincident
The exact flowrate at the time of actuation is not known, but the effect of closing
the BSR under what may have been high flowrates is unknown. Much later in the
response a rate of 53,000 BOPD was observed, but this was under different
conditions at surface (and probably TD).
The investigation team stated that with the leak observed in the hydraulic circuit,
the shearing operation would have taken 17 seconds to complete. Without the
leak, it should have taken 14 seconds.
Emergency BOP Functions Failed to
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3. Non-shearable components were across the BSR at the time of actuation
Pictures from later in the response effort showed two distinct drill pipe stubs inthe riser section that was cut. This immediately raised questions regarding what
exactly was across the stack when the BSR were activated.
Through examination of the recovered stubs, the investigation team concluded
only one string was across the stack at the time of the BSR activation. Erosion, rig
drift and hoisting equipment movement likely resulted in pipe movement andparting of the string above the BOP.
The location of tool joints relative to the BSR at the time of actuation is not known
exactly.
Results from the physical inspection of the subsea BOP have not yet been
released, but may shed more light on this subject.
Emergency BOP Functions Failed to
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Emergency BOP Functions Failed to
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Recommendations
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BPs Investigation team published 25 recommendations, specific to 8 key findings, in the DeepwaterHorizon Incident Investigation Report. I would encourage you to read these and determine if and
how these may apply to your operations.
Since BPs recommendations are, in some cases, specific to their structure and culture (and maybe
influenced by other objectives), lets cover some broader and a few deeper recommendations
Recommendations
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In the weeks and months following the Macondo Incident, the industry focused on Prevention. Thegovernment then demanded similar focus onSpill ContainmentandSpill Response.
The immediate focus on Prevention is both understandable and warranted. We have all heard that An
ounce of prevention is worth a pound of cure. An ounce of prevention would have been worth at least
62 lbs of cure in the case of the Macondo incident.
The same philosophy holds true when focused entirely on the multiple layers ofPrevention that werely upon. The earlier in the layers of defense that an issue is recognized and aggressively addressed,
the more efficient and reliable the response will be.
Recommendations
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Barrier Philosophy
Maintaining control of fluids, both produced and injected, throughout the life-cycle of a well is of
primary concern and is a basic expectation.
The design, installation or use, and proper verification of barriers is critical to meeting this expectation.
Examples:
If cement is going to be relied upon as a barrier, then achieving this becomes the primary objective
in the design and execution. If trying to meet other needs that may jeopardize the barrier
objective, the ability of the cement to perform as an effective barrier should be rigorously verified,
or another barrier should be installed and tested.
Safety-critical tests should be as simple and straight forward as practical, not encumbered by steps
that could contribute to the misinterpretation of deviations from the expected. The reasons for
deviations from the expected should be adequately investigated, the risks assessed if needed, and
mitigation efforts implemented before proceeding.
Recommendations
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Secondary and Emergency Control systems should be understood and tested.
Deficiencies or failures in these systems should be either remedied or risk assessed. If the risk
assessment concludes it prudent to proceed, the implications should be well understood by those
potentially relying on the system.
If another use or configuration exists for a safety-critical system, but this use or configuration may
create additional hazards, the circumstances under which the alternate use can be employed must be
well defined and understood.
Examples:
How much attention is given to the lines of defense that are considered last or next to last,
especially when there are several barriers before these are needed (Deadman, autoshear and ROV
intervention)? At least in the GOM, this is soon to be mandated.
A diverter system is designed to divert flow safely away from personnel and the facility while
minimizing the pressure on components with low pressure ratings. With the prevalence of SBM
usage in the deepwater environment, the ability to route the diverter to a MGS became common.
The diverter should direct flow directly overboard through a large ID line to avoid over pressuring
the slip joint packer, diverter element and marine riser components. Since SBM cant be discharged,and gas has the ability to go into solution (oil phase of the mud) and then be liberated near surface,
the use of the MGS to control relatively minor solution-gas events (bottoms up after a trip, extensive
sampling operations, or controlling a kick) has been widely accepted. Routing returns to the MGS
during a major event, however, poses significant hazards. In the case of the Macondo incident,
this action may have resulted in the death of 11 people and the elimination of some critical
barriers that are typically relied upon.
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Culture
In the days following the Macondo incident, most
companies immediately searched for assurances that this
could not happen to them. I wont speculate on how many
assurances were made.
The established processes that BP had in place(documented reviews, management of change, basis of
design) are impressive. Unfortunately, these failed to
prevent 11 deaths and a spill of national significance.
Although harder to define and measure, and even more
difficult to regulate, we pointed to our culture as the
single most important differentiating attribute when
comparing us to BP.
In a recent meeting with an individual who has numerous
dealings with BP, he observed that regardless of the
purpose of the gathering (planning session to morning rig
call), it is almost impossible to determine who is ultimatelyresponsible and accountable for the operation being
discussed. Evidence of this exists in the very report this
presentation was derived from.
RecommendationsIn a White Paper presented to the BOEM we presented what Marathon considered appropriate
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In a White Paper presented to the BOEM, we presented what Marathon considered appropriate
safeguards to have in place in order to resume operations in the GOM. The language below comes
directly from that letter and was drafted by Greg Sills (VP Upstream Developments). Additionalcomments are shown in blue:
The BP incident serves as a stark reminder, however, that systems and expectations are not enough no
matter how well presented a culture that encourages the appropriate leadership and individual
behaviors is perhaps even more important. We intend to continue to reinforce the culture of a highly
reliable organization that sustains attributes such as the following:
A preoccupation with deviations, lapses, errors responding quickly and rigorously to anything
which falls outside expectations, and refusing to recalibrate expectations in order to avoid
normalization of deviance. (Opposite responses during the negative test, yet rationalized
and dismissed; continued warning signs during the displacement that well integrity did
not exist)
A listening environment where leaders listen to the front line and defer to expertise, faint signals
are heard, and the front line reports confidently - even (especially) when the report is troublesome.
(Our established culture of brutally honest reporting)
Certainty is created where possible standard procedures are followed, not circumvented -
creating excess capacity for dealing with the truly unexpected. (One of the reasons that drovethe creation of our Design and Operating Guidelines unless you have obtained proper
approval for a deviation, the established standards will be followed so attention can be
focused on other areas)
These are examples of a responsive and agile organization that detects small misjudgments early,
notices the unexpected while it is still forming, arrests it before it expands, and safely returns to normal
operation.
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.
Final Thoughts:
Responsibility and Accountability. Focus and awareness increase when you know that you are both
responsible and accountable. Take the earlier points made when discussing well monitoring:
As long as the BOPs and Marine Riser are attached to the wellhead, a conduit directly to the rig
exists. As long as a direct conduit to the to rig exists, constant monitoring to ensure well control is
maintained is required. The Driller is ultimately responsible, regardless of the other operations
going on, for ensuring well control is maintained at all times.
Would an influx of 1,000 bbls over 49 minutes occur undetected if the Driller truly understood and
believed this?
False Sense of Security. We must always guard against complacency in the absence of recent
consequences. For years the industry bragged that there had never been a deepwater blowout of any
significance. Last line of defense safety systems went years without ever being needed. Guards were
lowered. We must maintain a sense of vulnerability.