What’s Been Missing from the Macondo Explanations?
On April 20, 2010, the loss of control of the Macondo well led to the loss of Deepwater Horizon (DWH) and the lives of eleven contractors and crew members. The resulting oil spill would cause the greatest ecological damage in the Gulf of Mexico since the blowout of Pemex’s well Ixtoc-1 in 1979.
In a series of technical papers, Ron Sweatman and several industry colleagues, among them Juan García, formerly director of global drilling at Exxon, and Robert Mitchell, former Halliburton Technology Fellow, came to a new understanding of the root cause of the Macondo accident—that is, the original reason why formation fluids entered the wellbore several hours after the cementing operation.
This new understanding uncovered a technology gap in drilling and completion operations. Neither in 2010 nor at present, has there been a downhole tool or software program that could have alerted the mud crew that disaster was ahead. In 2015, with similar well conditions, both drilling and completion crews are as much at risk for the loss of well control as they were in 2010 in relation to the root cause of the Macondo accident.
Long before 2010, it was known as a general fact of fluid mechanics that all fluids to some extent are compressible and can shrink or expand; that is, changes in pressure or temperature will result in changes in density. It was known that a drilling fluid called synthetic-based mud (SBM) is highly compressible with a much higher coefficient of thermal expansion compared to water-based mud.
The oil industry had been aware that during drilling operations with SBM (which was used as the drilling fluid on the Macondo well) shrinkage could occur; but there was no way to differentiate actual shrinkage from the static loss of circulation, or “top-level fallback,” that occurs when fluids have leaked into the formation that surrounds a well. In either case, the correct response would be to insert mud into the wellbore. If the mud crew fails to make this response during drilling or cementing operations, the risk of a blowout is created, as shrinkage brings with it a loss of hydrostatic pressure. During cementing, a loss of density compromises the integrity of the cement during the curing phase of 14-21 hours.
In 2010, the science that explains the need for an open fluid column during the curing phase was only partially understood. Missing then was a precise understanding of the effect that changes in wellbore temperature have on volume, hydrostatic pressure and density. In API’s standards today, an explanation of the need to maintain an open fluid column during curing is only minimally presented; readers are left with the mistaken impression that hydrostatic pressure would be unaffected by isolating the wellbore from the riser.
On Macondo, the installation of the casing seal at the wellhead shortly after the placement of the cement created a closed system, which meant that the hydrostatic pressure would now respond to changing conditions in the wellbore. These changes would be undetectable by the crew.
The higher temperature of the rock formation affected the properties of the fluid: As the SBM in the casing cooled, a thermal-induced shrinkage led to a loss of density which, in turn, led to a loss of overbalance pressure in the trapped fluid column (from the wellhead to the hydrocarbon-bearing formations).
When, during the first two hours in which the cement was still a slurry, the equivalent density, or hydrostatic pressure, became less than the pore pressures in the rock formations, creating an underbalanced condition. Formation fluids, brine, oil and gas, penetrated the wet cement, creating flow channels into the weak zone below.
Over time, the flow channels grew larger, eventually building up sufficient pressure to penetrate the shoe track and enter the casing from below.
During this process, the DWH crew received no data or warning that the cement would not serve as a barrier. Today, there still is no commercial software product that would enable the thermal modeling of the behavior of drilling fluid in cases like this where geothermal gradients could affect fluid temperatures and pressures; nevertheless, there are measures that may be taken to cancel the effect of temperature. For example, the fluid’s temperature vs. the geothermal gradient may be made more stable by a complete top-to-bottom conditioning of the mud, a precaution not taken on the DWH. In some cases, mud temperatures may be adjusted on the rig to lessen the downhole effects. In addition, the setting of the casing seal should be delayed until after the cement sets hard enough to create a pressure barrier.
Looking back, neither drillers nor operators understood the importance of knowing about the changes that the formation can induce into the drilling fluid. They did not appreciate the danger that such changes could lead to an underbalancing of the well. It was this undetected change that occurred at the Macondo well that, combined with subsequent mechanical and human failures, led to the blowout and loss of the rig.
Looking forward, commercial software is needed to allow for routine thermal modeling in which the undetectable changes in the fluid properties are calculated as the fluid temperature equalizes with the surrounding formation temperature.
With the aid of such software, profiles over time may be plotted that show the effect for formation-induced changes on the properties of the drilling fluid. Such profiles would tell you if such changes induce the heating or cooling of the fluid. At Macondo, it was the cooling effect that led to the compromise of the integrity of the cement barrier.
In the meantime, the curricula of training schools, plus API standards, need to be updated to include instruction and guidance from this poorly understood risk to drilling and cementing operations.
Just like throwing an object in to a pool of water the things we do effect those around us. Who would be effected if we were injured? Family? Coworkers? Friends? Who else? No one that cares for us wants to see us hurt. Depending on the severity of the injury, the ability to interact with our loved ones with all of our senses could be compromised. What if we could not work anymore and were unable to provide income for our families? How would their lifestyles change? How would creditors and items we borrowed money to purchase be effected? Would the lenders just feel compassion for you because you were injured and let you continue without making payments or would they start repossessing those possessions that were financed? How long could you survive before you had to start selling other possessions just to make ends meet? How well could you survive on Government assistance such as food stamps and other programs?
Every action has a reaction or consequences. Those consequences are up to us to decide upon. It is your decision to work and be safe or take to chances and jeopardize your health or life. Nothing is more selfish than taking chances that could lead to that phone call to tell your loved ones that you are not coming home. How cruel is it to consider taking a short cut that takes away the father or mother of a child that counting on them for everything.
Nobody ever plans to get hurt. That is why it is so important to develop plans to ensure everyone we interact with returns home the same way they left. Their future and the quality of the future of everyone that relies on them depends on this fact.
If you want to change the safety culture of your people, don't just tell them what to do to be safer, teach them why being safe is important for them and how it effects the ones who love them. Just like a pebble thrown into a pond, the effects of that single action continue outward affecting untold numbers of people and events encompassing our lives.
Judge Barbier's 153-page report did not consider the chain of events set in motion by the placement of the casing seal assembly just 17 minutes after the placement of cement.
The cited "Field Test 2" in the 2013 SPE/IADC paper entitled "Modeling Reveals Hidden Conditions that can Impair Wellbore Stability and Integrity" is actually about the Macondo well (an important detail that is hidden from the reader).
Speaking with one of the authors this morning, he recalled,"We wrote the paper in a way so that the lawyers who were still worried about liability wouldn't understand it. Otherwise, they wouldn't have let us publish the data."
Since April, I have been collaborating with the author to get the data and a new narrative of the root cause of the accident into English. The short story is that the Macondo well began to migrate (flow) within minutes of the setting of the casing collar which took place 17 minutes after the end of the cement job.
For the past month or so I have been stuck in trying to explain to myself how the coefficient of expansion of a drilling fluid can affect wellbore stability. Any guidance would be appreciated.
The paper is copyrighted by SPE/IADC and is not available on the internet, making the story even more hidden from public view.
Attached are 22 pages that are extracted, bookmarked, highlighted (and commented) from the section of the BOEMRE report of 2011 that concerned cementing at the Macondo well. I was looking for, but did not find, a clear explanation of why formation fluids entered the wellbore.
What I did find was speculation about why the float collar conversion may have failed to take place; but this fact is unimportant to any argument about why the formation fluids entered the wellbore.
The surprise was at the end of the section, where it reads: "Since the Panel concluded that the cement in [the] annulus did not fail . . . ."
Let's see: cement is the 1st barrier (nmero uno) that is designed to isolate formation fluids from the wellbore. If reservoir fluids reach the 2nd barrier (float collar) or the 3rd barrier (BOP), it means that the 1st barrier failed.
How, why and when it failed are matters that I am reviewing with a former member of the Presidential Panel on the Macondo Accident. A report is to follow.
I have been offered a interview for a thread copping position, and I have no idea what it entails, I have searched high and low on the internet but only find bits and pieces to this puzzle,I have worked in the oilfield for ten years from service rigs, coil tubing and production well testing, can any buddy explain to me what this position entails ?and what kind of career it is, whatkind of potential does it have for a guy mid career, and how much does a guy make doing this job, what kind of lifestyle is it, I would appreciate any input you may have, I appreciate it, thanks
This photo (taken with permission at the stand of Grupo R at OTC 2014) gives a suggestion of Grupo R's ambitions in the rig market.
I was interested in the governance of its 3 DW rigs. The company (Pemex) well supervisor is located in Villahermosa, and seldom visits the rig; instead, there is a field engineer who is stationed in Veracruz and who visits the rig regularly. He is selected in relation to the depth of the well, not in relation to the depth of the water.
Grupo R's rig chief is a Scot who lives in Edinburgh and rotates on a 30-day cycle. I do not know if he is an employee of Grupo R or a contractor.
The frequency at which the well supervisor, or higher Pemex leadership, visits the well is unknown to us. At one of the OTC 2014 panels on safety a speaker (from Statoil) said that, before the Macondo accident, visits by senior management were limited to the 4 Ls (Land, Lunch, List items and Leave). She said that the current practice at Statoil is that senior management spends the night on the rig.
Good questions for visiting journalists on a rig in Mexico to ask (in addition to the one about the number of pairs of blue eyes in the lunch room): How often does senior management from Pemex or Grupo R visit a DW rig? Does any visitor spend the night on the rig?
I was interested in the governance of its 3 DW rigs. The company (Pemex) well supervisor is located in Villahermosa, and seldom visits the rig; instead, there is a field engineer who is stationed in Veracruz and who visits the rig regularly. He is selected by in relation to the depth of the field, not the depth of the water.
Grupo R's rig chief is aScot wholives in Edinburgh and rotates on a 30-day cycle. I do not know if he is an employee of Grupo R or a contractor.
Here is a title list of 4 years of reporting by Mexico Energy Intelligence (MEI) on the Deepwater Horizon/Macondo accident of 2010. Neither the government nor industry has taken ownership of the role of human error in the unfolding of that accident.
Evidence? People still talk about "Stop Work Authority," as if that notion had any credibility or relevance in matters of process safety. At the end of 2013, BSEE published a list of attributes of a "culture of safety," but simultaneously announced that compliance would not be audited.
The MMS director at the time of Macondo (and who resigned within hours before her scheduled testimony to Congress) co-authors an essay that expresses concern that not enough has been done to implement the recommendations that came out of the investigation of the Macondo blow-out.
To judge from the presentations at the DECOM WORLD conference on Well Integrity Management Systems (April 15-16), quite a lot has been done to improve the operator's understanding and dashboard of key FTPD-related metrics.
I asked a speaker from API if Pemex could join as a member the Center for Offshore Safety. The speaker, believing that Pemex had blocks in the Gulf of Mexico, replied affirmatively; when told that Pemex only operated in Mexico, I was asked "Are you sure?"
"In that case," I was informed, "Pemex's status as a prospective member of COSwould be a matter for further discussion."