Deepwater Horizon - Transocean Oil Rig Fire

Offshore
1761

Pretty warm in the sub-sea wellbore, Brad. Plus, isn’t some of the reason why the hyrdates freeze with the seawater a function of the drop in pressure as it expands into the ocean?

[QUOTE=Brad Wehde;34613]G-Captain

TO ALL THE ENGINEERS AND SCIENTIST AT BP.

I have designed another device that will bring a hydraulic hose down into the well bore. My idea with this is to create gas hydrate in the well bore to plug it up.
Since BP likes a “Simple” approach to things, they might like this one. This is so simple and in front of their eyes. The problems with the domes was the “ice crystals”. You say (BP)… “we’ve learned a lot with our experiments” (you should have already known). Here is a simple solution and I will explain it in a simple way. When water mixes with the gas at that depth, the water molecules bond with the methane, forming “ice crystals”. Now you have just learned this in the last few weeks. This is why it plugged up your Simpson dome. Use what is against you to your advantage. Run water deep in the well bore. As the water mixes with the methane, this forms ice and plugs the well bore. You know this works because it plugged your Simpson dome before. This gives you enough time to make repairs to the (BOP) either by removing the LMRP down to the collet connector and install a valve with a flange and then you can have a solid connection if you like to a tanker or drill ship if you still want some of that oil.
G-Captain I was the one that designed the retrofit bop device at http://www.wehdeinteractive.com/RetroFitBOP.html
I did not make a animation for this one yet.
I think this is a very simple solution, easy to build, cheap and will work.
Brad Wehde brad@wehdeinteractive.com[/QUOTE]

1762

[QUOTE=OldHondoHand;34616]Pretty warm in the sub-sea wellbore, Brad. Plus, isn’t some of the reason why the hyrdates freeze with the seawater a function of the drop in pressure as it expands into the ocean?[/QUOTE]

They must have felt they were downstream of the biggest pressure drop because they put glycol in the mud from what I can gather. This would seem counter productive if they were taking the pressure drop above where they were pumping, since it would seem like it would have helped them get more mud down hole?

1763

The quote below is from The Oil Drum | The BP Deepwater Oil Spill - Why Top Kill May Have Failed and Tonight's Open Thread

I thought this was interesting. This was posted by ‘Heading Out’ as part of the main article. Prior to this, he discussed the possible flow paths of the oil and gas.

UPDATE: Thinking about this a little more, I had two more thoughts. The first is that once the LMRP preparation cuts off the riser and the bent drill pipe, then the full weight of the pipe below the shears may come onto the section in the shear jaws at the moment, pulling them further out of alignment and increasing the flows. It could also cause the pipe to drop out of the jaws, pulled out by the underlying weight, and hopefully not distorting them too much so that in the best of worlds they could then be cranked shut.

One could also, once the bent riser and pipe had been cut, go in down the pipe bit that extends up, go down past the annular seals with an abrasive jet lance (most of the flow is around the DP as we have established above) and cut it off, right above the shears. Then partially open the shears, drop the pipe out, and close them again. If they move all the way closed, without the obstruction, then the well may be sealed.

1764

I’m not in the industry, but I’ve been interested in the field for years now. But I am still learning all the names for things.

I was watching recordings of CSPAN yesterday and some guy on the panel was asking a bunch of questions about pulling a wet string. I think the driller said a couple of sections of wet string is normal. I did not understand either the question or the answer. What is wet string? (Google was NOT helpful for this!) And why is it bad? Also:

[QUOTE=bnhpr;34604]Unfortunately, we run many unshearables through the stack. For example, drill pipe connections are unshearable, as well as other pieces of the assembly, and they make up 10% of your string length. So, from that point of view, you only ever have 90% shearables in a typical drillstring. [/QUOTE] Do those familiar with sub-sea drilling think the 10% estimate is reasonable? Because as an outsider I’m a little shocked by that. You guys have been talking about two barriers in the well, so the BOP is the third and last line of defense? I’d kinda expect that the last line of defense would be a bit more reliable.

When the BOP is closed during the emergency disconnect, what seals the well? From what I have heard, the shear rams are expected to cut whatever is in the way (at least 90% of the time). Do they then lock together and seal the bore? Or is it a combination of the annular blocking flow around the pipe, [I]and[/I] the pipe rams closing around the pipe to block more of the flow [I]and[/I] then other rams smashing pipe to completely block it? Or does just one of them do it? Are we expecting 3 systems together to block it or just one? Also :

[QUOTE=bnhpr;34604] There is no indicator in the stack that tells the driller where his tooljoint is. We usually will close the annular or something and strip back to it, to locate the joint, exactly in the bop…or close pipe rams, and hang the tooljoint off in it. [/QUOTE] What does “strip back” to it mean? It sort of sounds like you close the seal around the pipe, and then withdraw the pipe to the point where the larger joint catches below the seal.

I can Google a term like “barite mud” and read about it. But googling “strip back” or “hang off” or “wet string” isn’t working for me.

1765

Alvis. The flow is slowing down quite a bit out of the end of the riser. Are they cutting on it upstream from the video you can see?[QUOTE=alvis;34618]The quote below is from http://www.theoildrum.com/node/6533?destination=node/6533

I thought this was interesting. This was posted by ‘Heading Out’ as part of the main article. Prior to this, he discussed the possible flow paths of the oil and gas.[/QUOTE]

1766

[QUOTE=company man 1;34621]Alvis. The flow is slowing down quite a bit out of the end of the riser. Are they cutting on it upstream from the video you can see?[/QUOTE]

It’s hard for me to tell what’s causing that low hanging “oil cloud” we’re seeing right now. I looked at the last 2.5 hours of video and sort of fast forwarded through it and the output of the well appears to vary quite a bit. There are times where I’ll see oil not pushing out very far from the riser and times where it looks like the flow doubles and triples; from my untrained eye. What’s confusing is that the flow of oil appears to be about the same when I see the oil cloud and when I don’t. So I don’t know what’s causing it to form. It’s almost like something is causing the oil to disperse more hence forming the cloud.

I don’t think you asked about the cloud, but I answered your question as if you did… ;

Edit: maybe it’s the variability of the gas output?

1767

[QUOTE=alvis;34622]It’s hard for me to tell what’s causing that low hanging “oil cloud” we’re seeing right now. I looked at the last 2.5 hours of video and sort of fast forwarded through it and the output of the well appears to vary quite a bit. There are times where I’ll see oil not pushing out very far from the riser and times where it looks like the flow doubles and triples; from my untrained eye. What’s confusing is that the flow of oil appears to be about the same when I see the oil cloud and when I don’t. So I don’t know what’s causing the cloud to form. It’s almost like something is causing the oil to disperse more hence forming the cloud.

I don’t think you asked about the cloud, but I answered your question as if you did… ;

Edit: maybe it’s the variability of the gas output?[/QUOTE]
I got ya. I’m guessing when it gets real cloudy it looks like the velocity is slowing down & then it seems to belch up another load. It definitely looks like the flow is way down from the other day & even yesterday to me. Are you getting any other video of the bent riser or where they are supposed to be cutting?

1768

The video I have of the end of the riser from yesterday won’t let me fast forward! I have to watch it real time. I guess I’ll have to pass it through a video converter to see if it enables that. But yes, it does look like it’s less.

I’d like to know where they were setting up those mud mats at! The ROV showed it was in 1,500 feet of water and the geographic coordinates on that ROV were different than the ROVs at the well site. Tomorrow I’ll try plugging those coordinates into Google Map to see where it was… Edit: The coordinates were E: 1200580.13, N: 10433047.93 if anyone knows where that’s at!

1769

[QUOTE=pumpjack hand;34605]jc95- the crossovers are also tool joints, the had at least 6-5/8 x 5-1/2 and 5-1/2 x 3-1/2. Another way they could determine within a foot or two where they are is if they use a pipe talley.

bnhpr- what’s your assessment of why the DWH bop didn’t function?[/QUOTE]

It wasn’t told to.

1770

One of the BOPs wasn’t wired correctly in the control panel on the BOP…

http://www.house.gov/list/speech/mi01_stupak/morenews/20100512bpopening.html

Second, we learned that the blowout preventer had been modified in unexpected ways. One of these modifications was potentially significant. The blowout preventer has an underwater control panel. BP spent a day trying to use this control panel to activate a variable bore ram on the blowout preventer that is designed to seal tight around any pipe in the well. When they investigated why their attempts failed to activate the bore ram, they learned that the device had been modified. A useless test ram – not the variable bore ram – had been connected to the socket that was supposed to activate the variable bore ram. An entire day’s worth of precious time had been spent engaging rams that closed the wrong way.

Edit:

Still, the blowout preventer also has a “deadman switch” which is supposed to activate the blowout preventer when all else fails. But according to Cameron, there were multiple scenarios that could have caused the deadman switch not to activate. One is human oversight: the deadman switch may not have been enabled on the control panel prior to the BOP being installed on the ocean floor.

Edit 2:

I believe this is the reason they went around asking if BOPs had been modified early on.

Edit 3:

“test ram” information. article written by Hydril and Transocean.

1771

[QUOTE=OneEyedMan;34620]I’m not in the industry, but I’ve been interested in the field for years now. But I am still learning all the names for things.

I was watching recordings of CSPAN yesterday and some guy on the panel was asking a bunch of questions about pulling a wet string. I think the driller said a couple of sections of wet string is normal. I did not understand either the question or the answer. What is wet string? (Google was NOT helpful for this!) And why is it bad? Also:

Do those familiar with sub-sea drilling think the 10% estimate is reasonable? Because as an outsider I’m a little shocked by that. You guys have been talking about two barriers in the well, so the BOP is the third and last line of defense? I’d kinda expect that the last line of defense would be a bit more reliable.

When the BOP is closed during the emergency disconnect, what seals the well? From what I have heard, the shear rams are expected to cut whatever is in the way (at least 90% of the time). Do they then lock together and seal the bore? Or is it a combination of the annular blocking flow around the pipe, [I]and[/I] the pipe rams closing around the pipe to block more of the flow [I]and[/I] then other rams smashing pipe to completely block it? Or does just one of them do it? Are we expecting 3 systems together to block it or just one? Also :
What does “strip back” to it mean? It sort of sounds like you close the seal around the pipe, and then withdraw the pipe to the point where the larger joint catches below the seal.

I can Google a term like “barite mud” and read about it. But googling “strip back” or “hang off” or “wet string” isn’t working for me.[/QUOTE]

I do not nor have I ever worked on the drill floor but I have been responsible for keeping them floating “dirty side up” for 35 years now. Maybe I can answer your questions:. I apologize to any of you real drilling hands if my answers aren’t correct.

A wet string is when the fluid inside the pipe does not equalize with the level in the annulus as you are pulling up drill pipe. This basically means that the floorhands get wet when they unscrew a joint of pipe.

A section of drill pipe is approx. 30 ft. long with a male tool joint on one end and a female joint on the other. Each of these joints is about 18 in. long which give you the 30:3 length ratio or 90% pipe 10% tool joint. FYI, all of the rigs that I have worked on make up the drill pipe one joint at a time but pull the pipe to stand it back in the derrick in three joint sections called “stands”. They have to come all of the way out of the hole periodically and this “3 joint stand” makes it easier and quicker.

I think that you are correct with your understanding of the term “strip back”.

1772

[QUOTE=alvis;34624]The video I have of the end of the riser from yesterday won’t let me fast forward! I have to watch it real time. I guess I’ll have to pass it through a video converter to see if it enables that. But yes, it does look like it’s less.

I’d like to know where they were setting up those mud mats at! The ROV showed it was in 1,500 feet of water and the geographic coordinates on that ROV were different than the ROVs at the well site. Tomorrow I’ll try plugging those coordinates into Google Map to see where it was… Edit: The coordinates were E: 1200580.13, N: 10433047.93 if anyone knows where that’s at![/QUOTE]
There have to be some shipping guys looking in that can give you the coordinates in relation to the well sight.

1773

[QUOTE=Brad Wehde;34613]G-Captain

TO ALL THE ENGINEERS AND SCIENTIST AT BP.

I have designed another device that will bring a hydraulic hose down into the well bore. My idea with this is to create gas hydrate in the well bore to plug it up.
Since BP likes a “Simple” approach to things, they might like this one. This is so simple and in front of their eyes. The problems with the domes was the “ice crystals”. You say (BP)… “we’ve learned a lot with our experiments” (you should have already known). Here is a simple solution and I will explain it in a simple way. When water mixes with the gas at that depth, the water molecules bond with the methane, forming “ice crystals”. Now you have just learned this in the last few weeks. This is why it plugged up your Simpson dome. Use what is against you to your advantage. Run water deep in the well bore.[U] As the water mixes with the methane, this forms ice and plugs the well bore[/U]. You know this works because it plugged your Simpson dome before. This gives you enough time to make repairs to the (BOP) either by removing the LMRP down to the collet connector and install a valve with a flange and then you can have a solid connection if you like to a tanker or drill ship if you still want some of that oil.
G-Captain I was the one that designed the retrofit bop device at http://www.wehdeinteractive.com/RetroFitBOP.html
I did not make a animation for this one yet.
I think this is a very simple solution, easy to build, cheap and will work.
Brad Wehde brad@wehdeinteractive.com[/QUOTE]

[ATTACH=CONFIG]898[/ATTACH]
[I]Methane hydrate phase diagram.[/I]
Notice the pressure line of [U]60,000 kilopascals[/U] because that is 8,702psi, the approximate pressure down at the root of the BOP as we are told by officials.[U] 81.5F = 27.5C[/U] and that is the “phase shift” threshold at that pressure.
methane hydrate: a large amount of [U]methane[/U] is trapped within a [U]crystal[/U] structure of water, forming a solid similar to [U]ice[/U].

[ATTACH=CONFIG]899[/ATTACH]
Geopressure/geothermal wells are those which produce extremely [U]high-pressure (7,000 psi) and high-temperature (149 °C) water[/U] which may contain hydrocarbons. The water becomes a rapidly expanding cloud of hot steam and vapours upon release to the atmosphere from a leak or rupture. [SIZE=3][FONT=Arial][SIZE=3]Extensive on-shore and offshore zones of geopressured water reservoirs are found in the Texas and [U]Louisiana Gulf Coast region[/U]. Energy in these reservoirs is present in the form of natural gas in solution, thermal energy, and hydraulic, energy. Reservoir depths generally vary from 5000 to 20,000 feet, with corresponding temperatures from below [U]200°F to above 300OF[/U]. Natural gas is presumed to exist at saturation levels in the reservoirs
[/SIZE][/FONT][/SIZE][U][SIZE=2]http://www.osti.gov/bridge/purl.cover.jsp;jsessionid=6E492A186796F63E045E0E7885CECDF0?purl=/886701-dj1WJH/[/SIZE][/U]

Once formed, hydrates can block pipeline and processing equipment. They are generally then removed by reducing the pressure, heating them, or dissolving them by chemical means (methanol is commonly used). Care must be taken to ensure that the removal of the hydrates is carefully controlled, because of the potential for the hydrate to undergo a phase transition from the solid hydrate to release water and gaseous methane at a high rate as the pressure is reduced. [U]The rapid release of methane gas in a closed system can result in a rapid increases in pressure[/U]. When drilling in oil and gas-bearing formations submerged in deep water, the reservoir gas may flow into the well bore and form gas hydrates due to the low temperatures and high pressures found during deep water drilling.
The gas hydrates may then flow upward with drilling mud or other discharged fluids. As they rise, the pressure in the [U]drill string[/U] decreases and the hydrates dissociate into gas and water. The rapid gas expansion ejects fluid from the well, reducing the pressure further, which leads to more hydrate dissociation and further fluid ejection. The resulting violent expulsion of fluid from the drill string is referred to [U]as a “kick”.[/U]

[U]I can see how the crystals form outside this pipe at 2C and 2240psi. But just injecting water into the 200-300F crude oil and gas at 8,700psi hydraulic is not gonna make ice happen in that pipe, by way of my understanding[/U]. Can you explain how this is accomplished?

The ice clog problem and resultant ‘kicks’ is why I produced this video a week ago. http://www.youtube.com/watch?v=fB2qgOAsOLo Conceptually, aside from structural design, I wish to be corrected in any number of ways, hoping somebody could tell me why this concept should not have been on standby, already designed for Horizon or others … I can think of 50 modifications of this theme of suction dredge in 10 minutes. I simply want this spill to END.

I started to make a new 10-minute YT video expressing the gravity of my concerns this evening … but it may be illegal to show the public on Youtube how bad this thing might be, IF it is not improved … I WISH THE BEST. I’m not yelling fire … yet.

1774

[QUOTE=bnhpr;34604]The other bad thing about drillpipe connections (tooljoints), is that you never know where they are, real time. There is no indicator in the stack that tells the driller where his tooljoint is. We usually will close the annular or something and strip back to it, to locate the joint, exactly in the bop…or close pipe rams, and hang the tooljoint off in it.[/QUOTE]

Are you serious? You never know where your joints are? If so, that makes offshore drilling the only drilling I have ever heard where you don’t know where each part of the string is. In fact, now that I have read a little bit more in this informative document supplied by bp to the US Congress, I have several more questions about this construction, the mechanism of failure, and therefore, an indication of how it will be fixed. One thing I want to know is, if it is clearly known that a BOP won’t shear through a tool joint, why isn’t it standard practice to make sure that when you are setting your drill string for well construction activities, that you make sure a tool joint isn’t [I]sitting where the shears are![/I]

Now, I’m not an offshore person, or a petro-person, but I do know many other kinds of drilling. Picking where you set the string is (in every other type of drilling) typically determined by where joints are in relation to all sorts of things. In fact, it is often one of the most important bits of knowledge in the process.

1775

The formation of the hydrate is more of a molecular action than thermal. I mean it is not due to the methane going through a phase change getting colder and freezing water. here is a better description:
A gas hydrate is a crystalline solid; its building blocks consist of a gas molecule surrounded by a cage of water molecules. Thus it is similar to ice, except that the crystalline structure is stabilized by the guest gas molecule within the cage of water molecules.

Do you know what the temperature is in the well bore?

1776

So you mean to tell me that the temp of the oil coming into the BOP is 300 F?
I did not know that, are you sure?
If that is the case then that would be hot enough to use nitrogen down in the well for it to go through its
critical point at that pressure. Then you could make that oil flow pretty slow?
Am I wrong here?

1777

[QUOTE=Anchor Guy;34627]I do not nor have I ever worked on the drill floor but I have been responsible for keeping them floating “dirty side up” for 35 years now. Maybe I can answer your questions:. I apologize to any of you real drilling hands if my answers aren’t correct.

Anchor Guy, what do you make of the situation after the well kicked and the rig went into an ESD status, and as I understand it, then the aux firewater pumps and generators came on, then the gas got sucked into the intakes and the motors ran away, to the point where they over-revved and blew up? Did the Rig Mechanic state the LEL ESD of those engines was bypassed? Thoughts? I’m thinking TO might have some culpabilitiy on this…that if they had stayed in an ESD-2 status, they might have at least have been able to activate the BOP stack and abandon ship before the inevitable explosion. But I doubt the floorhands would have left–they would have stayed and fought that well to the end. Dunno. But the analysis of this might lead to better ESD/Abandonment procedures. Sounds like it was a cluster!^% on the DWH in the minutes after the explosions.

1778

[QUOTE=OneEyedMan;34620]I’m not in the industry, but I’ve been interested in the field for years now. But I am still learning all the names for things.

I was watching recordings of CSPAN yesterday and some guy on the panel was asking a bunch of questions about pulling a wet string. I think the driller said a couple of sections of wet string is normal. I did not understand either the question or the answer. What is wet string? (Google was NOT helpful for this!) And why is it bad? Also:

Do those familiar with sub-sea drilling think the 10% estimate is reasonable? Because as an outsider I’m a little shocked by that. You guys have been talking about two barriers in the well, so the BOP is the third and last line of defense? I’d kinda expect that the last line of defense would be a bit more reliable.

When the BOP is closed during the emergency disconnect, what seals the well? From what I have heard, the shear rams are expected to cut whatever is in the way (at least 90% of the time). Do they then lock together and seal the bore? Or is it a combination of the annular blocking flow around the pipe, [I]and[/I] the pipe rams closing around the pipe to block more of the flow [I]and[/I] then other rams smashing pipe to completely block it? Or does just one of them do it? Are we expecting 3 systems together to block it or just one? Also :
What does “strip back” to it mean? It sort of sounds like you close the seal around the pipe, and then withdraw the pipe to the point where the larger joint catches below the seal.

I can Google a term like “barite mud” and read about it. But googling “strip back” or “hang off” or “wet string” isn’t working for me.[/QUOTE]

Stripping is closing the annular, and pulling back until you see the weight increase, and then you know the tooljoint is contacting the annular. i.e. method of locating

Hangoff is to close pipe rams (rams with a hole in them for drillpipe) and lower the string, until you start losing weight…i.e. your hanging the drillstring on a ram. A desired place to leave your drillstring if you plan to shear, for retrieval later.

A wet string is when you do not pump a slug, which is a heavy shot of mud inserted into drill string, before coming out of the hole (tripping out). So, when you break out the connections, mud flies all over the drill floor, and makes a mess. The roughnecks get wet. A slug will chase the mud down the pipe, and when you break the connections, there will be no fluid, due to the u-tubing of the heavy mud.

clear as mud?

1779

is it possible to stop the leak using “the russian method”: by using very very high explosives to collapse and seal the hole? I have read about how the soviets used this back in the day…

1780

Some kind of fish was checking things out. Actually swam through the outside oil plume area.

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