BP sets stage for Disaster"

No oil and gas well ever drilled has gone exactly to plan, or without mistakes being made. The Upstream Industry has learned the hard way. The path to todays drilling (well construction) approach is littered with terible loss events, and awash with lessons. But the fact is that todays drilling approach allows for mistakes to be made, simply because wells do not always behave as planned, and the execution of each step of the well construction plan relies on people. Contingency measure after contingency measure is layered over the average well construction plan such that if one, two, three, or even more consecutive issues occur and stack up against the well construction team there remains the cability on hand to identify there is a problem, to secure the well, and to plan and effect an appropriate remedial plan.

Yes a number of issues were stacking up against the well contruction team on Mississippi Canyon 252 #1-01 well on the night of the tradgey. Issues such as a communication path between the reservoir (oil and gas) and the well bore, the choice of casing plan and related well barriers, etc. However up until around 21:45 there remained the cability on hand to identify there was a problem, to secure the well, and to plan and effect an appropriate remedial plan to deal with the issues that had stacked up.

Unfortunately, at around 21:47 the Annular BOP opened releasing the immense energy that had accumulated beneath it (gas), energy that on release evacuated (ejected) the drilling riser of fluids in seconds. Thousands of gallons of fluids entering the workspace (drill floor) at almost jet force would have made any subsequent action to try to regain control of the well very difficult.

Much has been made about the issues that stacked up against the well construction team on that night, the cement program, the cement quality, the casing program, the testing program, etc etc, however the point remains that until around 21:45 the team still had the ability on hand to identify there was a problem, to secure the well, and to plan and effect an appropriate remedial plan to deal with the issues that had stacked up. The BOP Annular was closed and was capable of containing pressure build up as a result of the leak path between the reservoir and the well bore. There were other BOP Ram Preventers available of high pressure rating than the BOP Annular Preventer to call upon if required. With this contingency at hand (the last layer of contingency in any well construction plan), why did it still go so wrong?

I would offer that the real question is why did the BOP annular open? Did it fail? Was it opened by mistake? Was it opened thinking there was no hazardous gas build up below it? The investigation team will undoubtedly determine the truth.

I can also offer that in the Drilling Industry the Driller (the man that operates the drilling machine integrated into the rig structure) has two Golden Rules when it comes to well control: #1, if there is any doubt whatsoever about a possible influx of formation fluid into the well bore then the well must be shut in (close the BOP), he requires approval from no-man for this action #2, if the BOP has been closed for whatever well activity the Driller must be assured that doing so will not result in a hazardous situation for him, his team and all with him at the worksite. He requires approval from the worksite supervisors for this action.

The mud logger charts (main drilling parameter record) for the period 20:00hrs through 21:50hrs as presented at the Senate hearing show clear indicators of a problem with the well. There was more flow coming back from the well than going in, there was additional pressure where there should not have been. Evaluation and interpretation of these charts is an essential part fo providing the Driller the assurance he needs that opening the BOP Annular will not result in a hazardous situation.

If the BOP Annular was opened by the well construction team the other question undoubtedly being asked by the investigation team is whether suitable and sufficient evaluation and interpretation of the drilling parameter records was undertaken prior to authorising the opening of the BOP Annular?

The time line on the mud logger chart suggests around 15 minutes (from 21:30hrs to around 21:45hrs) may have been available for the well construction team to evaluate and interpret why there was pressure under the BOP Annular when there shouldnt have been.

15 minutes is not a long time to consider this kind of situation. Given that there had been a number of issues going on with this well since the casing was run and cemented (a lot of red flags were flying) there should have been the highest degree of awareness on every subsequent step of the operation. This means the full attention of all supervisors at all times. So, assuming again that the BOP Annular was opened by the team, why was there only a few minutes spent deciding the next step when the biggest red flag of them all (pressure under the BOP Annular) was waving.

(Key paragraphs)

The BOP Annular was closed and was capable of containing pressure build up as a result of the leak path between the reservoir and the well bore. There were other BOP Ram Preventers available of high pressure rating than the BOP Annular Preventer to call upon if required. With this contingency at hand (the last layer of contingency in any well construction plan), why did it still go so wrong?

Under normal circumstances, the annular BOP is open, as are the other sets of rams. That the riser was displaced with seawater (lessening the hydrostatic pressure of the fluid in the wellbore by some 2200 lbs.) indicates that there was no awareness of a problem.

With the pumps shut down, the well should not have been flowing, either before or after that displacement.

From the data charts posted on other sites and in other posts on this site, it appears the well was flowing, and at that point, the displacement should have been stopped, and the mud pumped back into the wellbore, eventually displacing the seawater and restoring the hydrostatic pressure.

Whether the BOP would need to be closed would have become apparent while circulating the well, displacing the gassy, oil cut drilling mud with drilling mud at full density.

Had the BOP been closed, the well would be circulated with the returning drilling mud circulated through the choke line to have the gas separated from it to bring the mud density back up, but at some point, the rams would have to be opened to move the seawater out of the riser (a decision reserved for supervisory personnel). That would mean that even heavier drilling mud might have had to be circulated into the wellbore to kill the kick, in order to make up for the lack of hydrostatic pressure exerted by the volume of seawater in the riser, or the well might start flowing again. Keep in mind, though that once the well was being circulated, the pressure from the mud moving (known as equivalent circulating density, or ECD, higher than the static pressure) might have been sufficient to make up the difference, and once the main kick had been circulated out, the ECD may have been sufficient to keep the production of gas/oil into the mud (which is circulating) down to a manageable level long enough to dispace the riser with drilling mud without adding extra weight to the drilling fluid (a decision made by the supervisory personnel in consultation with the Drilling Fluids engineer).

It is easier if you think of the mud as a conveyor belt, down the inside of the drill pipe, up the outside) which gets a small load of gas as it is moving (when the pumps are on and the well is circulating) and cuttings when drilling, but when it stops (the pumps are shut down), gets overloaded by oil and gas seeping into the wellbore from a producing formation, creating a 'light spot' in the drilling fluid charged with gas and oil.

Without any other data, the status of the HCR valve to the choke line might indicate if an effort to kill the kick was being made, even if the BOP failed to actuate. At the same time, any control problem which might keep the BOP from actuating might have affected the valve controls as well.

From available data, it is difficult to say who, if anyone, was aware of the developing problem, or what was being done about it before the explosion.

A word about BOPs.

The annular BOP is designed to close over whatever is in the hole, or an open hole. It is possible to 'strip' drill pipe through the closed element, and to drill ahead with the BOP closed. The annular generally has a slightly lower pressure rating than the other rams in the stack. The pipe rams are designed to close and seal around a specific size of drill pipe. That does not include the tool joints at the ends of the drill pipe (where the sections of pipe screw together) which are larger in diameter. The Blind rams close over an open hole and will not seal around drill pipe. Shear rams are designed to cut the drill pipe and close over the opn hole, but may not be rated for cutting through a tool joint, which is much thicker than the wall of the pipe.

While rules vary, generally, the driller has the authority to shut the well in (close the rams) whenever they think a situation has developed making it the appropriate course of action. Drillers generally attend blowout/well control schools, as have rig managers (toolpushers, for us old hands), and Company Hands.

I'm not pointing any fingers, nor am I saying who did what or didn't do what, because I do not know what happened on the rig in the last minutes leading up to the explosion. The people who do may no longer be among the living. I can only go by the data on the charts, and the accuracy of my interpretation of events is limited to the accuracy (and completeness or lack thereof) of that data.

It is rumored ( I have no way to verify one way or the other) that the 'suits' were there to present some sort of safety award. (Ironic, that). Drilling was done, the liner in place, and they were getting ready to move the rig.

While a day or two--or even a week to keep a lid on things and remediate any problems would have been expensive, the indicators should have been that they had a good discovery on their hands, and at that point no one sane would want to risk losing the well.

One account I have read said that the explosion stove in the bulkhead to the area they were having the presentation, and that the injured were helped out of there to the lifeboats by those in better shape. That same account said that some guys may have been blown into the water, others caught in the fireball. Most, if not all of the suits were inside, not out on the rig, and would have been sheltered from most of the force of the blast, as well as the radiant heat, flash burns, and whatever got thrown around when it went.

It is understandable that almost no amount of training, no number of drills, will completely enable most people to deal with the mayhem and confusion of the moment, and while there were several lifeboats, in the confusion it is possible that someone might end up inadvertently left behind.

I would hope that despite the overwhelming instinct for self-preservation, none were knowingly left, and from the same account, some freed those who were pinned in the mess and took them to the lifeboats. I don't know who did what, or if any didn't, but I suppose anything bad will come out eventually, if that happened. A lot of 'suits' in the industry used to be guys who came up the ranks from worm's corner and earned those supervisory positions the hard way.

Without knowing more, I'm not one to cast dispersions on any of the living--especially if undeserved, giving someone such a reputation would cost someone their carreer, and I'd hate to even imply that someone who might well be innocent of any wrongdoing might have left men behind. If anyone did knowingly leave someone else, they will ultimately have to live with that, and I would not be in those shoes for a CEOs pay.

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