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 - what will the relief well find?

With Labor Day weekend, and the recovery of the blowout preventer from the Deepwater Horizon well in the Gulf of Mexico, the remaining parts of the operation are going to be increasingly directed at plugging the well, so that it can be abandoned. Part of this operation will be to ensure that the bottom plugs at the reservoir end of the well have adequately sealed off the bottom of the well. To do this the relief well will be used to intersect the top of the unlined section of the original well, and determine the condition and fluid content of the annulus surrounding the production casing at that point.

There was concern that when the relief well intersected this annulus and then injected fluid into it as part of a possible additional plugging process, that this would increase the fluid pressure in the annulus. This could have raised the fluid pressure to the point that it might have been able to flow past the top seal at the well head, that was separating the annulus fluid channel from the path through the production casing. It was along that second path that the cement travelled to plug the bottom end of the well. Now that a BOP has been installed that can handle 15,000 psi fluid pressure in the well, the concern that a leak in the seal could allow oil to flow into the Gulf is of less consequence. So the relief well can proceed.

At the same time, it is likely that work will continue to prepare the top of the well for additional plugging so that the well can then be abandoned, according to regulation.

One of the remaining issues that will be resolved when the relief well intersects the annulus is over what type of fluid is actually in that channel. In the original sequence of events, before the well failed, the well was full of mud, and then a cement plug was pumped down the center of the well, to the bottom, from where it flowed up the outside of the production casing, filling the lower section of the annulus. In the process it pushed the mud that was already in the well, up the annulus ahead of the cement. As that cement started to set, and filled the annulus, there should have been no flow path up the annulus to the well head. Thus the fluid in the annulus should still be the original mud that was in the well ahead of that first cement injection.

In a large part of the early thinking of how the well failed, there was a preponderance of opinion that the fluid flow in the well developed up through the cement in the annulus, from the oil reservoir. This then flowed up the outside of the production casing, dislodged the hanger seal at the top of the well, and flowed on up into the BOP and on. But when the second set of cement was sent down the well, to seal it after it had stopped flowing the cement, apparently following the path that the oil had taken in leaving the well, only flowed down the production casing to the bottom of the well, and thence back up to the oil reservoir. This suggests that the early thinking which would leave the annulus full of oil and natural gas, was not correct, and rather than oil, the annulus still holds mud.

We won’t know which is right until the well is intersected, but once the information is available, then it will make it easier to decide what steps to take to complete the final stages of plugging the well.

At present the DD2 is preparing for these plug and abandon procedures. It is also, given past problems, testing the new BOP to ensure that it is fully functional before the process restarts. With there being sensibly no further likelihood of oil from the well escaping into the Gulf, the pressure to complete the process has diminished, and there is no urgent need for the relief well to be completed (apart that is for such matters as the amount of money that both the drilling rigs are costing BP every day).
As the Admiral instructs, it will be interesting to see when, and what the relief well finds as it completes its mission in the next week or so.

Deepwater Oil Spill - Flushing and Fishing

BP has now responded to Admiral Allen’s request for more information, and has obtained permission to replace the BOP and stack on the top of the Deepwater well, before completing the drilling of the relief well. They are also preparing to recover (fish for) the drill pipe that was left in the original well.

The permission letter from the Admiral reads, in the relevant section:


As a result, BP have flushed the subsea equipment which included the following steps:

The work began Wednesday afternoon and the flushing procedure will involve the following steps:
• The Discoverer Enterprise will attach a drill string to the top of the existing sealing cap.
• The middle blind shears of the sealing cap will be opened.
• The Q-4000 will pump an ‘anti-freeze’ mixture down through the existing manifold and into the BOP’s choke and kill lines. The liquid used in the flushing will be completely contained and carried to the surface through the Enterprise drill string.
• Following the flushing, the sealing cap’s blind shear ram will be closed.
Following successful flushing of the subsea equipment, BP will conduct an ambient pressure test to reassure that the well is secure. The test will be conducted over a 48-hour period, which mimics twice the time estimated to remove the original BOP and replace it with the Transocean Development Driller II (DDII) BOP.

At the present time it appears that the well is in the 48-hour period where the well is being held at the same pressure as that of the surrounding seawater, to see if there is any gain or loss in fluid or pressure under that condition. If there is no change, then the hardware will be removed, and the replacement BOP installed. It should be evident that there will be some care needed to deal with the 3,000 ft of drill pipe that may be still attached to the lower end of the initial BOP.

This was addressed in his press conference on Thursday by Admiral Allen, who introduced a new step in the process. After the current pressure test is completed, BP have now been tasked with seeing if they can recover the drill string from the well, before the BOP is changed out.

Bear in mind that the actual condition of the drill string is in some question. As the Admiral noted:

If you will remember when we cut through the riser pipe before we moved the stub of the pipe and unbolted the flange, we were concerned there might be pipe or even two pieces of pipe there.


 
And one of our procedures we were prepared to do was actually put a metal band around both pieces of the pipe, pull them together so that the spooling tool could fit over the top (inaudible) that connection between the blow out preventer and the capping stack.



When we actually cut the pipe and got in, we found out there was only a single pipe there. That leads us to believe that the pipe is suspended by the shears that closed but did not cut the pipe and the deep water horizon blow out preventer. 
 
And so we're working under the assumption that there is pipe suspended, held in place by the blow out preventer. We don’t know how far down it goes and we don’t know whether or not it is connected to the 5,000 feet of cement that was put in during the top kill.

So after the ambient pressure test is done, it would inform us as to whether or not the BOP could be removed without hydrocarbons being emitted. 
 
The next thing will be to see if we can remove that pipe. That doesn't preclude us from removing the blow out preventer and putting another one on. It will just make it a little more complicated and BP will have to provide us a procedure on how they will do that.

This fishing expedition (which was also addressed in Kent Wells discussion, though that has not been released yet) is expected to occur immediately after the pressure test, i.e. sometime on Saturday.

The fishing recovery (so-called because you have to “fish around” to find the bit and engage it) will involve attaching a specifically designed fishing tool to the end of a length of drill pipe and seeing if this can get sufficient hold of the drill pipe so that it can be recovered, if the shear ram holding it in place is released. The Admiral suggested that this would be a drill bit

We are going to actually put a drill bit down in the blow out preventer and attempt to extract the drill pipe. The reason we want to try and extract the drill pipe that reduces the risk that when we remove the blow out preventer and put the new one on, there won't be an (off score) or some kind of a bar to having a seal with the new blow out preventer.

I anticipate that the tool used will be quite different from the conventional bit – some options that I found to illustrate the range:

Fishing tools (Logan Oil Tools )

Bear in mind that the tool has to grip the drill pipe and hold the weight of the string under the BOP after the shear is released. The tool will have to penetrate into the deformed metal of the pipe (remember the picture of the pipe and riser other side of the shear) and get a good enough grip that it will hold up to 3,000 ft of DP. So the grip has to be a strong one. It will be interesting to see what sort of tool BP suggests using.

Screen capture of the sheared section of the drill pipe and riser.


There are also ongoing tests to see if the contents of the annulus can be established, since it is still not clear whether this is oil (which would indicate that at one time there was communication through the bottom of the annulus with the reservoir, and thus a failure of the annular cement around the casing) or it could be mud (from the well contents before the initial cement was injected). That may not be known, with confidence, however, until after the BOP is exchanged, and the relief well intersects the bottom of the borehole, which is now not expected to occur until after Labor Day.

Deepwater Oil Spill - how to deal with a dead well?

The Admiral confirmed, in his Friday press conference, that the negative pressure test on the Deepwater well held steady for 24-hours without any inflow of fluid into the well, or increase in pressure. That means that there is sufficient cement in the annulus to block a free passage from the reservoir, through the annulus, to the well head. In other words the well is killed. The problem now becomes something different.

As I mentioned yesterday the central section of the well, inside the production casing, is full of cement. The only path possibly available is up the annulus, above the bottom section where cement has filled it. The problem that is now faced is that no-one knows how much of the cement in the annulus was there from the original cementing of the production casing into place, and how much from the injection of cement during the static kill. If it is a relatively small amount, then there is a risk that this barrier may fail, with time, and oil under reservoir pressure can then flow up the annulus to the well head. And to help with the discussion, here is the picture that I have used before to illustrate the situation.



I would suspect that it is a relatively thick barrier – the original injection of cement into the well from the production casing was, if my memory serves, about half that required to fill the annulus to the previous cement lining injection. Given that this is 800 ft above the bottom of the well, then there is 400 ft of cement above the shoe in the annulus.

In a relatively close to surface operation, the flow of fluid across the bottom of that column might induce enough cavitation to eat back the cement by about 20-ft or more (Glen Canyon Dam, and Tarbela High Dam for eg) but with the back pressures in the well that would suppress cavitation, I don’t anticipate that there was that much erosion out of the flow path of the oil and gas to the bottom of the well. There could be enough erosion along the contact with the overlying sandstone, which would erode out the column over the height of the sandstone, (say 60 ft) but even with that there is likely at least a couple of hundred feet of cement in the annulus above the reservoir creating a seal.

But that leaves the problem of the up to 1,000 barrels of oil that may be trapped in the annulus, begging the question as to how it is supposed to have got there if the cement in the annulus retained its integrity above the reservoir.

To determine if that is oil, which would imply that the above supposition was wrong and that the well had no cement integrity in the annulus until the cement from the static kill provided some, the relief well has to intersect the original well. When it does so it raises two problems, only one of which I mentioned in the last post.

The one I mentioned is that with a cement plug in the annulus below the intersection if BP start to inject fluid into the annulus they don’t have an easy way of displacing the fluid already there. There is nowhere to push it, and no clear way to circulate it out with the relief well configuration. The logical path to push it upwards out of the well runs into a slight problem that the Admiral introduced today, which is that the part between the new stack and the old BOP (the spooling tool) is only rated to 7,500 psi. And there is no simple path for fluid to flow from the annulus up through the existing hardware on top of the rig into a pipe that could carry it to a vessel at the surface.

The one that I did not mention was that if the original cement has been removed over the full column of the annulus down at the bottom of the well, and only replaced by the cement injected during the static kill, then there is no way of knowing how thick that barrier is. Raising the pressure in the annulus to inject cement into it from the relief well could break that barrier (though it would also provide a path for oil in the well to displace downwards back into the reservoir and thus dispose of maybe 10% of the oil in the annulus., which still leaves the question as to how to displace the rest.

On the other hand if the relief well goes into the annulus and finds nothing but mud (from the pre-cement days when the production casing was installed) then the question becomes moot.
.

Deepwater Oil Spill - is the well dead already?

Much of the focus of recent efforts at the Deepwater Horizon well site have been focussed on getting the relief well down to do a bottom kill of the well. However, in recent remarks the possibility has been raised that this may already have been done, and that the well is effectively dead already.

In his press conference on Wednesday, Admiral Allen noted, relative to the understanding of the conditions at the bottom of the Deepwater Well, that there may have been some communication (in other words a passage) from inside the production casing, out to the annulus outside the casing.

Following the cementing of the casing itself in the well last week and successful pressure test, we had discussion between the government science team and BP engineers, we believe there may be a chance that the cement that was forced down through the casing of the well entering the reservoir might have actually moved over and come back into the annulus which is the area outside the casing but inside the well bore.

We want to understand the condition of the annulus before we actually drill into it so we are working with BP right now to establish procedures to do a pressure test that will tell us whether or not there’s free communication between the annulus and the reservoir itself or there’s cement that actually works its way over there from the static kill.

He also noted

Just to project out a little bit further for everybody’s information, once the well is killed it is no longer a threat of discharge at that point it will no longer be considered part of the response to the oil spill per say because there won’t be any source of the oil.

In other words if the production casing passage is sealed, and the annulus is adequately sealed then the well is no longer a threat, and no longer part of the response activity. At that time the well moves into the jurisdiction of the Department of the Interior and their regulations, which have been discussed here earlier, of the steps needed to abandon the well.

The problem that the Admiral relates to is actually in several parts. Let me try and explain them in a little detail. Firstly we will start, this time, at the bottom of the well, where the shoe sits that was meant to seal off the inside of the production casing. Very simply, at the end of the operations with the Deepwater Horizon, the bottom of the well might have looked a bit like this (which is definitely not to scale, but drawn just to illustrate some thoughts)


At the end of the drilling a plug of cement had been pushed down the production casing and out of the end so that it flowed back up the annulus several hundred feet. The well should have been plugged at the bottom.

We now know that there was a failure at the bottom, since all the cement that was injected went down the production casing. This means that there had to be a passage between the well and the oil-bearing sandstone. I show this as green and it has eroded a path through the cement down to the bottom of the casing and then up the inside of it to the BOP and thence to the Gulf.


Note there has to be a passage through the annulus to the sandstone from the central section of the production casing for the oil and gas to flow.

Now consider that in killing the well the cement was pumped down to the bottom of the casing and 200 barrels then went out into the annulus, and up into the oil-bearing sandstone. That may have been enough to totally seal the passages to the bottom of the casing but also any erosion that had taken place eating upwards along the outside of the casing through the annulus to the top of the cement.

I wrote about that the other day, and as a reminder, this is what it may look like.


Now the original assumption had been that the leak was up through the annulus of cement to the Gap that I show – but that turned out not to be the case. And remember that this is 800 ft above the shoe we were just talking about.

So if the relief well intersects here it has to drill a fair way down to check on conditions at the bottom of the well, if the cement lining at this point has integrity. If there is no oil found here, which means there was no passage down to through the annulus (at this level, obviously there was at the bottom of the well) then as insurance they can inject cement back through the gap and annulus, but in reality the well is already dead.

However if that is the case, and they want to fill the annulus here with cement, they have to be careful. For the outer annulus up at the BOP is protected by a seal. The Admiral described the problem and solution.

The casing in which the drill bit and the well and the well pipe sits (hang) from the top of the well head. And then they kind of telescoped down to the smaller diameters. In that mechanism where they hang off the top of the well head, there was a seal and if enough pressure is applied from the annulus, this is outside the casing, on that seal it is meant to give way so it won’t cause damage to the well bore.

In other words it’s like a relief valve, and the seal which completely circles the casing at the top of the well if enough pressure is exerted will rise up and allow oil to flow. One of the theories was that somehow sometime during the explosion or what happened that that pipe was lifted up to allow that seal to be opened. It might have allowed oil to move up into the blow out preventer, it might have been the source of the hydrocarbons coming up other than the actual casing itself.

We don’t think that’s the case right now we think it’s seated where it should be but what we wouldn’t want to have happen is to start pumping mud and cement into the annulus at the bottom is filled with cement and you have stagnate oil there. And we increase the pressure as we’re doing that so that stagnate oil is forced up and that forces that seal to rise up open itself and go into the blow out preventer.

And as you know we restricted the pressure on the injectivity tests in the top kill to be less than 8,000 psi. The cap itself is rated at 10,000 psi and what we want to understand is we go ahead with the mud and the cement for the bottom kill is there any chance at all that that would force stagnate oil up to the point where it would lift that up again, open those seals, push that up into the blow out preventer and the capping stack and at some point erode, approach pressures that might be a concern to us.

We think it’s a very low probability outcome but the discussion of those seals and whether or not that pipe has ever been lifted is something that’s been discussed for some period of time. But we think we just need to rule it out before we go forward.

By the Thursday press conference the storm had largely passed, the storm packer was being removed from the relief well, and a negative pressure test was being carried out at the top of the well, under the BOP, to ensure that the cement had no problems, and to see if with that lower pressure there was any flow out of the annulus. They are anticipating that once drilling restarts it will take 96 hours to intersect the annulus.

The science team believe that there is a “low probability” that the leaks through the annulus to the well were sealed by the cement injected during the static kill (which suggests they still believe there was a passage up to the gap at the top of the cement) but the results of the test may indicate whether they were right or wrong. However, as the Admiral noted,

I guess what I'm saying is if the cement is already there it would obviate the need to do the bottom kill because the cement from the top kill had worked its way into the annulus. That's what we're trying to find out.

The way that they are doing this is to lower the pressure above the hanger that the production casing rides on, so that the seals to the annulus open.

lowering the pressure in the stack enough where it would raise those seals on the hangar which would allow oil to flow up and if there was communication with the reservoir we would see an increase in pressure.

That would tell us there is no cement in the annulus and we should proceed with the bottom kill. If for some reason the pressure stays level that would indicate that we have some kind of a static condition in the annulus and that would present the possibility that the cement had entered the annulus and we might either a full or a partial kill from the bottom accomplished with the static kill. . . . . . . .
What we hope we'll find out is there will be an immediate rise in pressure which will tell us there is hydrocarbons being pushed up from the reservoir and we should go ahead and proceed with the bottom kill.

It will be more problematic and quizzical if there is no discernable change in the pressure readings. That would indicate that the oil is being held in place and its' static. That won't tell us how much cement and to what extent the communication between the reservoir and the annulus may have been filled with the static kill.

And at that point there will have to be a determination made on whether or not we'll go ahead and proceed to drill in with the relief well and be prepared to go ahead and put the cement in. That will be a discussion that we'll have with the BP engineers when we know the results of the test.

That may still leave up to 1,000 barrels of oil trapped in the annulus, but this could be recovered during the plugging operation later in time, and under another jurisdiction. But the well would be dead, and no further steps, including intersecting the bottom, might be needed. But they will likely do that any way, just to be sure.

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.