Oil Industry Experts on the Planned Top Kill:

[amborin]

Here are about 20 blog posts from The Oil Drum.

They give one an idea of the challenges associated with the 'top kill' operation:



**************************************************
The big thing I am wondering about is the DP joint obstructions inside the casing. My interpretation is that BP believes the mud will be pumped at such a high rate as to force it downhole overcoming the ~8000 psi below the wellhead and overcoming the mud's ability to escape from the small opening in the BOP towards the ~2500 psi above.

However if what I have read is correct, then there may be as many as 90 tool joints inside the casing before getting to the bottom of the DP. These tool joints are 8-1/4" OD, leaving just a 3/8" annulus between the casing ID (9-7/8") for the kill mud to flow down. Won't these obstructions impede flow just like the small size of the opening in the BOP, leading to a buildup of pressure in the wellhead?

As I understand there are basically 4 things that could happen:

(i) mud flows in and overcomes the ~8000 psi of pressure below the wellhead, then flows down the rather small 90 separate csg ID/dp joint annuli to the bottom of the well filling casing filling it up and killing well. SUCCESS***

(ii) mud flows in, but cannot overcome the ~8000 psi of pressure (plus hammer effect) and the joint/csg restrictions, mud then flows out the small opening in the BOP towards the ~2500 psi above the wellhead and into the riser making the opening in the BOP larger as it erodes the rams/annulars - FAIL.

(iii) mud flows in, overcomes the ~8000 psi of pressure below wellhead and makes it past csg ID/DP joints, but not enough flow past last DP joint and so mud follows the oil when it reaches bottom of DP produces up DP and into riser - FAIL.

(iv) mud flows in, tries to flow both through small opening in BOP and small csgID/DP joint annulus, but bridges in csg ID/joint annulus cutting off flow of oil to seafloor, small opening of BOP prevents it from escaping that way, pressure builds up causing damaged wellhead/BOP to fail or more likely causing shallower casing or liners to fail (subsurface blowout). - FAIL

*** It would seem that success only occurs if the 16.4 ppg mud column from water surface to bottom of DP (~8300') exerts enough pressure to stop flow of O&G up the outside of the production casing past the seal assembly and down the wellbore to end of the drill pipe.

Am I missing anything or does BP know something that we do not which would suggest that there is a 60-70% chance that result (i) will occur and that the mud column will be sufficient to kill the well stopping the annular flow of O&G???? 60-70% chance of success seems like BP is overestimating to the same extent they are underestimating the 5,000 bbd flowrate.

If my thoughts are erroneous, will someone please clear it up for me?

******************************************

Just a couple comments, someone else can answer the hard stuff.

The annulus between the 8.25 inch tool joints and the 9.875 inch casing would be about 23.2 sqin. The 3 inch pipe into the BOP is about 7 sqin. So there is about 21 times the area, although 90 joints is a lot of constriction. Remember they were circulating mud pass those joints before.

I think BP said they believe the flow is up the annular spaces, not the drill pipe.


***********************************************************

I didn't double check the ID, just took the post as gospel. The increase area in an annulus would definitely increase the friction loss. But I'd still go back to the fact that they circulated mud through it before.

Now if the casing has happened to collapse in that area --------

*****************************************


Wouldn't a production casing collapse actually be a good thing if the flow is up the annulus? Then mud could flow through the hole in the production casing into the annulus and exert pressure on the formation from which the O&G is leaking and hopefully kill the well?


**********************************************************
I'm not sure what the collapse mode would look like under those conditions but we removed some imploded members from one of the first really deep platforms and the cross sections in the buckled area looked like an I-beam, but no breaks or leaks.

That's what happens when an aircraft company with no offshore experience designs their first, and as far as I know, only, platform using 1/8" wall EXTERNAL stiffeners. But they were cheap, and oil companies like cheap.

There are two 3" inlets - my bad - so that doubles the cross section area. It looks like when the you add the extra friction (viscosity might play an important part here) the tool joint will add as much or more resistance as the choke and kill lines. Won't it be picking up about 1 psi of relative pressure during the vertical flow to the bottom? Or maybe that would be a half psi/ft as it displaces the oil?

Also I don't know the distance that the mud is restricted by the 3" pipes but it might actually be more total friction than the total length of the tool joints.

But - wouldn't there be even more energy loss at each tool joint due to the constriction and expansion of the flow (accelerating and decelerating the mud) than from the friction loss? Kind of like the head loss through a fitting.

Nothing easy here folks.

*****************************************************

Exactly. I am not a flow expert, but it seems there would be significant loss of energy from constriction and expansion of flow in addition to loss of energy from increased friction (though I do not know the distance of the 3" lines, I would expect more friction in the 90 tool joints).

If they are able to keep the mud from simply flowing out the BOP, then I just do not see any scenario where this operation does not result in:

(i) loss of wellhead/BOPE; OR
(ii) burst casing and undergound blowout (MOST LIKELY)

Also if there is an underground blowout, do you think there is any chance BP or the feds let us know??? Or do they stream ROV footage showng the leaks are no longer flowing and continue along with the relief wells like everything is fine and dandy?

**************************************************

An underground blow out might actually be preferable to the current situation, especially to BP. I assume they would at least hint to the RW rigs that maybe they should anticipate a problem,

*****************************************************************

I am sorry I wrote too quickly and was not paying enough attention...the csg ID is 8-5/8" (OD is 9-7/8") and the joint OD is 8-1/4" leaving a 3/8" annulus through which to flow.

So even assuming there is no build up on the pipes there will be ~19.9 sqin of flow area for the mud to pass through the csg ID/Tool joint annulus with that mud being exposed to ~4.418sqin of surface area along the way.

There are going to be multiple 3" flow lines (not sure if they are actually 3-1/16" or how many there will be, I assumed 2 like in the diagram and 3" like you did), so there will be at least 14 sqin of flow area for the mud to pass through the lines to the BOP and that flow will be exposed to 1.571 sqin of surface area.

It would seem the smaller openings of the annulus with 280%+ more friction from the surface area could be problematic.

They were circulating through this annulus as you stated, but they were not trying to bullhead mud past them at high rates.

Flow is up the annular spaces, but ends up in the drill pipe. O&G flows up the annulus (outside the production casing) towards the wellhead, then past the seal assembly, down the production casing and into the drillpipe where it travels past the crimp in the BOP caused by the partially activated rams and out to sea.


*********************************************************************

If you could pump at 10,000 barrels per minute and 15,000 psi, assume that 9,000 barrels per minute goes out the existing leaks and into the ocean. That leaves 1,000 barrels per minute going into the well and it fills up in about 50 seconds assuming an 8" hole 13,600'. Scale that back and that is the procedure as I comprehend it.

**************************************************


What worries me is the force on the bends. I know a guy that was unscrewing a 2" elbow connection off an 800 psi gas storage well and he didn't bleed it off. It whipped on him and took his arm off at the shoulder in one turn.

They are relying on what looks like a lot of bends/kinks in large diameter pipes. Tons of force and potential for straightening the kinks.

I don't think it will work, I'm really sorry to say. I hate to see political pressure influence their decision. They are delaying for a reason. The reason is probably the progress of that relief well.

***********************************************

If they don't burst the csg and if they can keep a good enough seal long enough to pump in enough mud then there's a good chance to work. But too many IFS for my comfort level.

*********************************************************************
You're scaring the straits, okay?

(Here's hoping that quote will bring someone a smile. Me, I'm fighting back tears.)

******************************************************************************
I think they tried it with Ixtoc:

Countermeasures/ Mitigation
Bahia de Campeche, Mexico
Subject Countermeasures/ Mitigation
Posting Date 1979-Jun-03

In the initial stages of the spill, an estimated 30,000 barrels of oil per day were flowing from the well.

In July 1979 the pumping of mud into the well reduced the flow to 20,000 barrels per day, and early in August the pumping of nearly 100,000 steel, iron, and lead balls into the well reduced the flow to 10,000 barrels per day.

http://www.incidentnews.gov/entry/508790

***********************************************************

As you say the path will be that of least resistance and once the BOP path creates enough back pressure the rest will go down hole, whether that is down the inside or the out side of the casing it does not matter. Unfortunately i do not believe it will go to the producing formation, as we have already been told there a loss zone in the open hole section. Depending on its characteristics it may take all the flow and we will end up with a floating mud cap and an under ground blow out. Which will solve the short problems, but will be headache for the relief wells and further control of the well.

Though at this this stage of events BP will settle for the underground blow out. If the formation is too strong and it can not be bullheaded Rockmans worst dreams could come true.

***************************************************************

Okay, I understand higher pressure. But you are introducing a flow of mud at a higher pressure into an existing flow (of oil and gas) at a relative lower pressure. I am thinking least resistance here.

Wouldn't you have to lose some mud out of the BOP begore you could completely overcome the oil and gas flow? To my thinking there has to be a critical pressure differential involved.

Log in or register to leave a comment Heading Out on May 25, 2010 - 2:27pm Yes at the very start of the flow into the well there will be some small amount of mud that continues to flow, with the oil above the injection point, through the BOP. But the flow being injected is more than can be pushed through the orifice in the BOP. This assumes that the pressures that they are going to run this at will not re-open any passages through the BOP, and one thing you can be sure of is that they will be monitoring all their instrumentation as they run this, to make sure, before anything catastrophic happens, that, if possible, it is avoided.

This is why, even though everything is just about ready to go, they haven't actually done it yet. They are going through stages to check that the things they have control over are all going to do what they are supposed to.

**************************************************************************

For anyone who has done plumbing work, this whole drama has a familiar ring. Say I've discovered a leak in an underground water main for the community (wet spot in ground + large discrepancy in metered water = bad leak). First I assemble supplied I think I'll need. Then hire some labor to dig a hole at the probable location of leak. Miss leak by a few feet. Dig more hole. Find leak. Discover that dimensions of pipe not what I thought. Discover also that close by house connection complicates things. Go back to hardware store for more fittings. Return to leak site (labor has by this time consumed all the beer I've been paying them with). Discover that hole must be dug much bigger in order to get enough flex in pipe to install new fitting. And so on. Of course the big advantage is that the water can be shut off further up the line at the well head, maybe... unless the 15 year old valve is corroded so it can't be moved, or if using a bigger wrench on it breaks it off. Then it's cut the power to the well pump. More trips to hardware store.

Murphy's law seems to reign supreme in these situations. Sure glad I'm not down there trying to deal with this leak.

***********************************************

They are doing some PFM with cast in place polymer pipe. For fixing water mains that is.

***********************************************************

You raise some valid questions. The booming response question is a tough one because all we get to see are the failures via the MSM (main stream media). Is the booming 80%, 90%, 99% effective, we just don't know. Might have to wait for one of the dozen or so books about this tragedy to come out before we know for sure. I can't quote a source but I believe spotter planes are in use.

Number of relief wells? AlanfromBigEasy and others also feel three or four would be appropriate. This is one of those hindsight deals where someone will be proven right and someone proven wrong.

Thanks for bringing up the Costner device. I did a Google search the other day and found no reference on the results of its testing. Maybe someone else has info.


*******************************************************************

As a relief well is getting close to the blown out well there needs to be some spectial instrumentation sent down to pick up indications about where the blown out hole is in relation to the relief hole.

Who makes such instrumentation? Who sub-contracts using it? I think I have heard that it uses magnetic field measurements. True / not true? What is this special instrument called (a name that I can google)?

Is there a theory of opeation for it somewhere on the web? Wikipedia? Other?

My understanding of magnetic field leads me to fear that a second relief well in the vacinity of the blowout could result in misleading magnetic signals that would make finding the blowout hole very difficult, but I know only theory, not

************************************

Let's see if I have this right. Assuming a sufficient pumping pressure and volumn of mud, and assuing that the top of the BOP stays intact, then, at the end of the pumping we will have the well bore and voids filled with the fluid known as mud, which I understand is twice the weight of water.

At that point we will have the BOP, the top of the well bore, at static pressure, about 2250 psi. The bottom of the well bore, 18,000 below sea level, will then be at a pressure of approximately 13,800 psi.

If I got it right then we need for the oil and gas deposit to he at a static pressure lower than that.

**********************************************************

If it works, this will be a dynamic kill situation so you'll have something like the hydrostatic pressure exerted by the whole heavy weight fluid column all the way back to surface plus pump pressure. I'm thinking that it won't be exactly that because you will have some losses going up through the leaking BOP and the riser. If the mud actually goes south then at some point they will switch over to cement and just keep pumping until they get some kind of "squeeze" on the cement. I believe they would adjust the anticipated pumping time on the cement to conform with the rate that they are able to pump mud into the formation. Ideally you want to get the cement into place then have the pumping pressure begin to increase fairly rapidly as the cement begins to set. It could be that the cement blend will be thixotropic which means that as soon as you stop pumping the gel strength will increase very rapidly and it should be difficult if not impossible for it to move.


***************************************************
Big day tomorrow. If the top kill fails things will turn real ugly soon. Hopefully Mr. Murphy is on holiday...

************************************************************

The following speculation is completely my own, no one else helped me screw it up.

I’m going to skip over the normal risks associated with high pressure pumps, valve, hoses, working at sea, etc and go directly problems that might result if things go really, really wrong.

From the stand point of personnel safety it seem the worst case would be failure at the BOP with a resulting unconstrained release of oil and gas. This might not be the worst case for the well.

The normal dangers associated with a blow out, like high pressure mud and oil, escaping gas, fire, etc don’t really apply as the nearest person is a mile away.

What could be a major danger is also different from a blowout on land or at the drill floor on an offshore rig. A large bubble of gas that expands by many times before it reaches sea level can surface directly under a ship. This huge gas bubble will literally make a hole in the water that the ship will fall into and when the water crashes back into the hole the only vessel that has a chance of survival would be a submarine.

There are a lot of unknowns here as I don’t think there is any experience with huge expanding gas bubbles from 5,000 feet. It could be that rising a full mile would allow the bubble to disperse so it reached the surface over a large area in a broken up series of smaller and less dangerous bubbles.

But if I was BP I don’t think I’d assume that would happen. I would plan for a worst case, that there could be a gigantic eruption of gas on the surface fully capable of sinking a ship or drilling rig.

The saving grace here is that there is some lead time. They will have many indicators that a catastrophic event has occurred and the ROV should give them an visual that there are large amounts of gas escaping.

Even with a huge bubble traveling at a high rate of speed should take about 20 minutes to reach the surface, say at least 15 minutes warning.

With proper preparations in place and a prepared plan they should all be able to get to a safe distance.

I expect they will pull out the RITT anyway before they try the top kill as the drilling mud could mess up the RITT recovery. So the Discoverer Enterprise could pull the RITT up a couple hundred feet and move off slowly to a safe distance prior to the top kill.

Any ROV boats that are not necessary for the top kill could also move out to a safe area. The remaining one or two RSVs (ROV Support Vessels) would have the cage already about 100 feet off the bottom and as soon as the ROV is back in the cage (or even before) they can take off on a preplanned path that avoids the sunken rig and move to a staging area.

The pumping and standby boats would have a procedure for disconnecting their hoses and then follow a designated path to their staging area.

The Q4000 has more problems because it is physically connected to the manifold and BOP through the hoses. There may be a quick disconnect on the hoses or in a worst case they could pull off until the hoses break, not a very good option or drop their drill pipe and umbilical over the side, also a poor option.

All that probably works if there is a properly prepared plan. Also from what we have seen so far it seems unlikely this well will gush out that size of gas bubble.

Without a prepared plan I think it would be problematic that every vessel could get safely away in less than 15 minutes without any entanglements or collisions.

That leaves the two rigs drilling the relief wells. There was a schematic today that showed both are as close as they can get without being inside the 500 meter safety zone from the safety zone of another vessel (the Discoverer Enterprise at the wellhead). So they are each about 1,000 meters from the well head, about 3,280 feet.

I’m not aware of any regulation stating how far away from an underwater bubble a ship should be but to me a 45 degree angle from the wellhead should certainly be a safe distance, or about a mile. The drilling rigs are about 2,000 feet closer than that. I assumed someone has determined that either my scenario is not a problem or they have determined that 1,000 meters is a safe distance.

Best of luck to BP and all the rig hand with this top kill.

*****************************************


eta:

http://www.theoildrum.com/node/6505#more

[Octafish]

1. Mud seems to have played a big role before the explosion on Deepwater Horizon

Sea captain tells of rig blast in gritty detail - Witness says hints of trouble came hours before rig blast

By BRETT CLANTON
HOUSTON CHRONICLE
May 11, 2010, 8:57PM

KENNER, La. — Hours before the late-night blast on April 20 that engulfed the Deepwater Horizon in flames and killed 11, there were signs of trouble aboard the drilling rig.

SNIP...

The Damon B. Bankston, owned by Tidewater Marine, had received about 3,100 barrels of drilling mud from the Deepwater Horizon through a hose connecting the two when the process abruptly stopped, short of the 4,500 barrels scheduled to be transferred, Landry said.

When calling for an update at 9 p.m., he was told that rig crews soon would resume removing drilling mud from the pipe-like riser connecting the rig to infrastructure on the sea floor.

Soon after, Landry noticed the mud raining down on his ship and gushing from the top of the rig's derrick.

“I asked them what was going on. I'm getting mud on me,” Landry testified.

“I heard the concern in the voice of the operator when he said he was having trouble with the well,” said Landry, who said he was then told to detach his hose and move a safe distance from the rig.

Then came the sound of a high-pressure escape of gas and the explosion, noted in the vessel's log at 9:53 p.m., Landry said.

CONTINUED...

K&R

[amborin]

3. interesting, thanks for posting!

[Turbineguy]

2. It's a question of

balancing the mass flow rate of the oil against the mass flow rate of the heavier mud. Also, the velocity of the oil is lower in the down hole pipe than at the leak.

But yeah, I hope this works.

[amborin]

4. yes, and the

joint restrictions along the way sound ominous, don't you think?

as does an underground blowout will BP and the feds tell us if this occurs?

[Turbineguy]

5. I have to assume they know more

and would not take the risk of causing the leak to increase.