[QUOTE=bnhpr;34548]In many circles, it is believed the casing is up into the BOP already, and has already failed.
So, I guess I do not understand your comment.
You can sit back in email world and say this and that is too risky, but eventually we have to shut it in.
You could say the same risk exists with any kill operation.
It’s likely the topkill has already seen full static wellbore pressure at the well head…or close to it…with high pump in rates.
This is the best plan we’ve seen yet, I believe it will succeed.[/QUOTE]
[QUOTE=alcor;34566]Have you considered the Block and Topdrive weight?[/QUOTE]
It was suggested to add 150K, what do you think? So, 203K dead weight x ~.85 bouyancy factor = 172K + 150K = 322K. The Halliburton chart showed block steady height of 30’ in the last two hours, gradually increasing from 350K to 400K after establishing pump rate.
[QUOTE=RiverPirate;34581]Question for you all re this continuing until August. In regards to the weather… I don’t think it’s a matter of if we’ll see a hurricane in the GOM by then but a matter of how many will we see and will there be some Big Ones.
What affects will a hurricane have on the well?
What If another one goes up the Miss. River?
I recall portions of Mobile Bay emptying several times.
Pensacola Bay had 40 ft. waves during Hurricane Ivan.
I know we’re just getting started but, How bad is this gonna get?[/QUOTE]
We just need to pray & have faith we won’t get a hurricane.
[QUOTE=pumpjack hand;34589]We all hope it will succeed.
Do you know what pump pressure and rate it saw?[/QUOTE]
Guess he ejected. 9 posts & everything he’s read on here is bullshit. I would love to hear an optimistic view on why this will work. However, unchecked optimism that doesn’t stand up to good sound questions is myopic. I place the odds on this working at 3-5%. I HOPE everyone can tell me how full of crap I am this time next week.
[QUOTE=alvis;34593]On the live spillcam, the task listed is ‘Deploy mud mats’. Any idea what those are/for?
Edit: Looks like they’re currently staging something in “shallow” water at 1,500 feet.[/QUOTE]
I seem to recall mud mats being used to keep the methane hydrate from forming near a wellhead. A barrier.
The following is an excerpt of a thread at drillingclub,
"Another spin on the mud-mat.
Mats are designed to have dual functions and can be easily latched to the conductor with the mat resting on the spider beams. If more surface contact area is required bat wings that fold out before the mat enter the splash zone can be employed.
Beside supporting the conductor at the mudline a hydrate seal can be installed between the latching mechanism and the ID of the mat profile. This is one way of mitigating the possibility of hydrates freezing your stack or the wellhead connector.
Not to mention the GOM… this system is used in WA , Brazil and AP.
One other advantage is that the conductor string could be hung of in the mat at the spider beams ready to RIH while the 36" hole is drilled."
Like many others, I’ve been following this thread since shortly after the DWH explosion. This and TOD seem to be the only sources of any kind of technical information. I’m an electrical engineer so know basic engineering, but have no association with the oil business (except as a consumer of their fine products).
A few noob questions on the BOP…
are the “shutoff” functions (annulars, shear rams) used routinely during operations to temporarily “shut-off” the well while some other operation is performed, or is it strictly an “emergency” device?
is it really possible to exercise the shear ram functionality as a test? Wouldn’t cycling the shear ram damage the casing or drill string? How is this bi-weekly test performed? I can imagine exercising the annulars in a non-destructive test, but the shears seem like a one-shot deal unless the drill string is pulled.
If a malfunction is observed during one of the periodic tests (like low hydraulic pressure, dead battery, etc.), what’s involved in fixing that? If the problem was discovered shortly before it was planned to plug & abandon the well, might someone be tempted to “defer” that maintenance until after the disconnect until the rig is moved to the next job?
I understand that the shear rams can’t cut/compress hardened components in the drill string. How frequently do these hard sections occur? Is it just really bad luck that a hard part happened to be positioned in the path of the ram?
[QUOTE=company man 1;34595]Guess he ejected. 9 posts & everything he’s read on here is bullshit. I would love to hear an optimistic view on why this will work. However, unchecked optimism that doesn’t stand up to good sound questions is myopic. I place the odds on this working at 3-5%. I HOPE everyone can tell me how full of crap I am this time next week.[/QUOTE]
He was probably hoping to see some moral support, no one likes to be part of a huge undertaking with the feeling that the effort will be futile… and since what few responses he saw were jaded, he wrote it off as b.s., and from his p.o.v., rightly so. The reason he has an optimistic view on why this will work is because he’s part of it, and he’s pumped to make it happen.
pumpjack thank you for the reference to the GE H4 hydraulic connector that i believe performs the EDS function for drive off. I have taken the liberty to annotate a screen shot to assist those of us trying to learn the deepsea technology. Please anyone feel free to comment/re-annotate any errors.
[ATTACH=CONFIG]897[/ATTACH]
I see that the H4 is rated for 15,000 psi. I am wondering if BP thinks they can release it after they get the bent riser off? If they can release the H4, then the DD II BOP with an other H4 on the bottom can mate to the stub that is sticking up out of what I think is the upper annular and you have high pressure containment capability on the stack, now only limited by the strength of the upper casings if there is a communication in that annular space.
If they can’t get the H4 to separate then they go with the modified beanie cap and seal with an LMRP perched above to provide some protection up the riser for kicks? This would have very little pressure capability.
Mudmat question. Perhaps they are like the Air Force uses for temporary runways near the line for like Harrier VTOL jets. It might be used to provide a solid landing spot for something heavy coming down. Something being staged to be ready at the seafloor. Perhaps like a BOP and perhaps a separate LMRP oh and perhaps a beanie cap… but I think that is already down?
Deep sea guy corrections appreciated from those that live this every day.
[QUOTE=alcor;34572]It sounds like you were there as you seem so familiar with the process…or is it your imagination running riot?
That’s the problem with these commentaries, people are reading and listening to your comments as if they are fact and absolute truth.[/QUOTE]
No No…The problem is with THOSE people…
[QUOTE=alcor;34572]People have to remeber you are merely speculating…constantly.[/QUOTE]
Duh!!! (I kinda hate using that word…BUT it does appear to have become part of the adult vernacular)
[QUOTE=pumpjack hand;34598]He was probably hoping to see some moral support, no one likes to be part of a huge undertaking with the feeling that the effort will be futile… and since what few responses he saw were jaded, he wrote it off as b.s., and from his p.o.v., rightly so. The reason he has an optimistic view on why this will work is because he’s part of it, and he’s pumped to make it happen.[/QUOTE]
I’m down with that. I was brutalized relenlessly for calling for a top kill attempt while they jerked around talking about the top hat when we finally got a look at the flow. If his skin is that thin he doesn’t need to come on here, because he’s gonna get his oil checked. If he is even for real & not the next coming of rlanasa, & he can dish it out then he should be prepared to take on some sound serious questions & have a little patience with other’s opinions of the risks involved. Right now, my greatest concern is for the crew on the rig. Because if they stack enough weight on this thing & it makes a good seal right away, they better be prepared for the pressure comiing immediately & the gas coming in less than an hour.
[QUOTE=jc95;34597]Like many others, I’ve been following this thread since shortly after the DWH explosion. This and TOD seem to be the only sources of any kind of technical information. I’m an electrical engineer so know basic engineering, but have no association with the oil business (except as a consumer of their fine products).
A few noob questions on the BOP…
are the “shutoff” functions (annulars, shear rams) used routinely during operations to temporarily “shut-off” the well while some other operation is performed, or is it strictly an “emergency” device?
is it really possible to exercise the shear ram functionality as a test? Wouldn’t cycling the shear ram damage the casing or drill string? How is this bi-weekly test performed? I can imagine exercising the annulars in a non-destructive test, but the shears seem like a one-shot deal unless the drill string is pulled.
If a malfunction is observed during one of the periodic tests (like low hydraulic pressure, dead battery, etc.), what’s involved in fixing that? If the problem was discovered shortly before it was planned to plug & abandon the well, might someone be tempted to “defer” that maintenance until after the disconnect until the rig is moved to the next job?
I understand that the shear rams can’t cut/compress hardened components in the drill string. How frequently do these hard sections occur? Is it just really bad luck that a hard part happened to be positioned in the path of the ram?
Thanks for your patience.[/QUOTE]
The BOP is used frequently in testing, isolating locating, etc…during many operations of well construction.
The shears are function tested with no pipe across them, as not to drop a fish into the well. Then we pressure tested agains it for leakage. At the FAT, we shear pipe and casing as part of the original test, but your question is quite valid, they are not really tested until you need them. 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. There are different makes, and types of shear rams, casing shears, super shears etc. all with different capabilities. 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.
Of course, it depends on the problem, and is run through a risk asessment to determine if it’s safer to continue and get to a stopping point, or pull it then. The decision is based on risk and probability, never finance. If a decision is made to continue, based on cost, our management system has failed miserably.
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=bnhpr;34604]1 At the FAT, we shear pipe and casing as part of the original test, but your question is quite valid, they are not really tested until you need them. [/QUOTE]
Thanks for the explanation of BOP operations and also for your updates here…it is much appreciated.
I thought this might be a good place to paste a comment I read three weeks ago on the drilling club forum:
"There are widely known problems with BOP technology. (for many years now)"
This is a very sweeping statement, which it seems is being latched onto and exaggerated by uninformed sources. Please note that I do not put you into this bag, because although you've stated that you're an 'outsider' to the drilling industry, you're obviously intelligent enough to understand that the BOP 'failure' is not a root cause for the accident, even if it was a critical link in the chain of events which led to the final outcome.
BOP's are by and large, highly reliable pieces of equipment, with the proviso that they have to be scrupulously maintained. And that when they are tested, if there is the slightest doubt regarding the integrity (and thus the validity) of any particular test, it has to be investigated and rectified immediately. Obviously such downtime costs a lot of money to the well's Operator, but gambling on it is simply not worth it. QED.
There is a 'Catch 22' side to BOP testing, however, which should be borne in mind by everyone. It's almost a philosophical issue. The reason that BOP's are tested on a regular basis is that they contain items which can wear out, and thus affect the equipment's performance. These range from simple 'O' ring seals in the hydraulic systems which provide the power and force to close the BOP, to the actual sealing elements of the rams or the annular preventer themselves. In fact, these latter are considered 'consumable parts', spares for which it is mandatory to keep on the rig. The problem is, the rate of wear on such items is directly proportional to the number of times that they are functioned. Which leads to the paradoxical fact that every time a BOP is tested, one has reduced the remaining lifespan of its parts, and subsequently increased the likelihood of a failure the next time the equipment is operated.
So all a BOP test really tells us is that on a certain date and at a certain time, the equipment performed as it should. It is absolutely no guarantee that it won't fail the next time. These are the kind of dilemmas one has to live with if we are going to continue exploring for, and producing, oil. If that is unacceptable, we might as well go back to living in trees straight away.
AK
So after reading that it wouldn’t surprise you to learn I advocate that the drilling crews should demand having a back up surface bop on top of a high pressure riser with pressure relief ports staged at various depths. Does anyone have a reason that would be a bad idea in principle? Some guys might think the ports would be unreliable and this might be an option, but a back up surface bop would have saved the crew of the DWH.
Would it be unreasonable to have gas sensors in the riser? and on the well head?
The spillcam is showing the end of the riser. It looks like a blizzard has hit with all the lighter colored material that’s on everything. I’m assuming some component of the mud has settled?
[QUOTE=pumpjack hand;34608]So after reading that it wouldn’t surprise you to learn I advocate that the drilling crews should demand having a back up surface bop on top of a high pressure riser with pressure relief ports staged at various depths. Does anyone have a reason that would be a bad idea in principle? Some guys might think the ports would be unreliable and this might be an option, but a back up surface bop would have saved the crew of the DWH.
Would it be unreasonable to have gas sensors in the riser? and on the well head?[/QUOTE]
A surface BOP would have let them abandon and clear the area until a contingency plan was implemented.
Gas sensors in the riser? What about an internal mount under a slick enclosure? Hydrodynamic like a pod on an aircraft.
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