Deepwater Oil Spill - locking the hanger and relief well role

A short time ago I wrote about the concerns with the casing hanger in the Deepwater Horizon well, and the risk that it might lift and allow whatever fluid is in the annulus between the production casing and the well lining to be released. In his remarks on Friday Admiral Allen discussed that situation. At some point there has to be a seal on the top of the well to prevent fluid escaping from the annulus. The solution that he, the science team, and BP have reached is that the casing hanger will be locked into place, so that it cannot lift off the seat. This was the illustration that I used back then:

Labelled section showing the parts of the casing hanger (note that there is an animation at the source site)

With the casing hanger itself looking like this:

Casing hanger.

The lack of a locking ring was a bit of a bone of contention when the initial Congressional hearings took place back in June, being one of the five issues that Congressman Waxman brought up in a letter to Tony Hayward. (The other four were the design of the well itself; the “centralizer” issue; the failure to run a bond log; and the failure to circulate possible gas-bearing mud out of the well. ) It may not have been necessary back when the well first started to flow (if the annulus is, in fact, still full of mud rather than oil) and the seal is currently working, but by putting a lock on the casing hanger so that it cannot rise out of the seat they are ensuring that it will not move, even if pressure increases in the annulus, after the relief well makes contact. Locking it can be carried out by running a string of drill pipe down to engage the top threads of the hanger, so that it can’t move. Alternatively it can be connected to the surrounding wellhead structure, perhaps by running a sleeve back up to the overlying BOP. It could have been locked with special locking screws that ran through the wellhead, but they aren't in play at this point.

Admiral Allen noted:

In essence, we're going to put a ring or what they call a sleeve around the top that'll lock that casing hanger in place, will not allow it to move. There is always concern that when we pressurize the annulus, that casing hanger would lift, allow free communication between the annulus up into the blowout preventer.

Cement in the annulus will be one way to preclude that from happening. But after some consultation and looking at various alternatives, the BP engineers and our science team agreed that if we could ascertain that the casing hanger had not been dislodged, in other words, where we need it to be, then we could actually put a sleeve around it and basically lock it down.

And the order that I issued to BP, I ordered them to take what are called lead impressions. You go down, you take an impression of the top of the casing hanger. And then that allows you to take measurements on where its location is. Based on that measurement that they took, it appears that the casing hanger has not been dislodged to the point where we'd have a problem with the seal, so we just need to lock it in place, and that would substitute for the pressure control that cementing the annulus would have provided.

Once BP tells the Admiral how long it is going to take to lock the hanger down, and it is done, then he will give permission to restart the relief well. The impressions of the seat were apparently made by lowering lead blocks onto the hanger and deforming them. This provided the required impression of the position of the top of the hanger, from which it was possible to decide that it hadn’t moved.

With that seal in place it is no longer necessary, at this time, to perforate the top of the casing to insert a cement plug, since the seal will itself provide a plug during the relief well operations. (The plug will still be needed for the abandonment part of the process).

MoonofA has illustrated the process that is now to be followed in complying with the Admiral’s instructions. I am copying the comments that go with two of the illustrations from that comment:

(This) picture shows what will happen in the next days.

1. The casing hanger lockdown sleeve will get installed (not shown).

2. Developer Driller II above the original Macondo well will put its drill pipe into the hole and will perforate the production liner long string just above the top-kill cement. (If the annular is pressurized from the reservoir it may take a kick doing this.)

Pumping cement into the annular in this state would be dangerous and difficult as whatever is in there now, mud or oil, has no place to go. To avoid any damage when pushing cement down in there we need some communication to be able to retrieve the stuff that the cement will replace.Therefore:
3. Developer Driller III doing the relief well will intersect below the outer casing into the annular between the long string and the well bore. This will then form a U-tube between the DDII down through the annular between the long string and the outer casing and up to the DDIII. Mud can then be pumped from one rig down the hole up to the other rig to test the communication through the annular.


4. Fresh cement (green) will then be pumped from the DDII down its drill pipe into the annular. As communication is established, whatever is then in the annular, mud or oil, can be pushed by the cement up to the DDIII.


With this the annular is then truly dead and The Admiral’s point 5 demand will be fulfilled.

However, to get the perforations just above the cement, the perforating tool has to reach that position, which it can only do if there is no old drill pipe in the way. We will see if any is found, and they fish for it.

Deepwater Oil Spill - hitting the well annulus

Trying to work out exactly where the relief well has reached, relative to set target depths is slightly complicated by the difference between measured depth of the well, and true vertical depth. To use just a portion of the final slide that Kent Wells used in his last technical briefing


If one uses this as a reference to the remarks made by Admiral Allen today he notes that the well is within 200 ft of the initial intersection point, which is about 50 ft below the end of the lined section of the original well, which had been cased with a 9 7/8 inch liner. Below that level the well contains the production casing that was inserted into the well, but which was only cemented into place at the lower end. (The Admiral calls this the drill pipe – which is not the right term to use and which can be a bit confusing if you don’t look at the construction of the well). So let me just try and recreate a rough sketch of the area we are talking about.


According to the Congressional testimony the bottom of the lined section of the original well ends at 17,168 ft, which is perhaps 100 ft below the level shown by Mr Wells. This is where the original well was lined with a steel casing, with concrete around and below it, as the original well was drilled. The gap between the steel of the casing and the rock is known as the annulus, and it is this that I show filled with cement in two places.


So if you look at the above sketch of a section through the hole at the end of the 9 7/8th inch segment, the lighter steel casing liner was installed first, then the cement was pushed down to the then bottom of the hole. The cement flowed out and back up the hole giving the sort of “L” shape that the top cement segment has in this section. The hole was thus lined with a cement and steel jacket, before the drill bit on the end of the drill pipe came down and drilled through the cement at the bottom of that section, and on down to the producing formation.

At this point BP could have continued a liner section for the bottom of the well, as they had just done for the segment of the well above, or they could install what is known as production casing. This latter is a long tube that will run from the bottom of the well up to the BOP. They chose to do the latter. Thus the production casing was lowered into place, and the casing section that I show runs the full length of the underground segment of the borehole.

However in installing that continuous tube, instead of filling the gap between the rock and the tube (the annulus) with cement all the way up to the cement above it, they only partially filled the gap, over the lower segment of the well. This left a gap of somewhat indeterminate length where there is no cement between the production casing (the Admiral’s drill pipe) and the rock wall.

With that situation in mind, let me return to the Admiral’s press conference today. In it he said that the relief well is still around 15 ft from the original well and with about 200 ft to go to the point of intersection. At this point the well is being drilled in 10 – 15 ft lengths and then surveyed, so that the RW can hit the original well where intended.

The intention is

they'll go through a series of spaces, starting with what they call the annulus, and that's the area in the wellbore outside the casing, and then the casing is outside the well pipe.

They will check at each point on whether or not there is any hydrocarbons there and any pressure. And if there is none, they will attempt to actually apply mud to kill that portion of it. If they can go into the annulus and fill that with mud, and if that stops the problem, then they know the flow to the surface was to the annulus only. If that doesn't stop it and there's indications that there's product going up through the pipe, they will ultimately have to drill through the pipe and apply mud twice.

In other words they will come into the well around the zone that I have shown with no cement in the annulus. If the well is flowing oil and gas into the space outside of the production casing, then it will be flowing up the outside until it reaches the bottom of the lined section of the well. The flow then moves into the gap between the production casing and the steel casing liner and works its way up to the BOP through that channel.

If that is the case, then the bottom of the production casing may be still sealed, and by just filling the channel from the point of intersection up to the BOP with mud, then the well might be killed.

On the other hand, if the bottom seal at the lower end of the production casing has failed (which might be why the initial negative pressure test showed flow) then oil and gas are flowing up the inside of the production casing, and filling the space outside the production casing with mud won’t stop the flow.

Thus the drill will then restart and drill through the production casing, to fill it, in turn with mud. Both operations will take time. As the Admiral noted

. . .if they have to pump mud up through the annulus and then go into the pipe and pump mud there, too, that's a period of seven, 10 days to accomplish both of those things. And if they have to be done in sequence because of the condition of the wellbore when they go in, it will probably take into August, . . .

And in the meantime, the seas are still not allowing the final connections to be made to the kill circuit on the BOP, to increase oil and gas collected, which in the last report was:

For the first 12 hours on July 7 (midnight to noon), approximately 8,330 barrels of oil were collected and approximately 3,925 barrels of oil and 28.8 million cubic feet of natural gas were flared.

• On July 6, total oil recovered was approx. 24,760 barrels:
• approx. 16,535 barrels of oil were collected,
• approx. 8,225 barrels of oil were flared,
• and approx. 57.5 million cubic feet of natural gas were flared.

And incidentally it appears that the debate on changing the cap is still going on.

We are still reviewing the technical specifications that were provided to us by BP on not only that cap, but several other options. The procedures on how it would be done, the amount of time at which the well would be open for discharge of some amount of oil, and the weather window that it would take to do that, and that is all under review right now inside the administration, and I wouldn't want to attach a percentage right now.