BP's Deepwater Oil Spill - Capping Stack Installed - and Open Thread

This thread is being closed. Please comment on http://www.theoildrum.com/node/6722.

BP's new cap has been installed, and the company will start pressure tests tomorrow that will test the tightness of the seal and the integrity of the well. According to BP's press release:

The three ram capping stack was installed on the Deep Water Horizon LMRP at 7 p.m. CDT. The stack completes the installation of the new sealing cap.

Following installation of the capping stack and in line with the procedure approved by the National Incident Commander and Unified Area Command, the well integrity test will begin July 13 on the MC252 well.

For the duration of the test, which will be a minimum of 6 hours and could extend up to 48 hours, the three ram capping stack will be closed and all sub-sea containment systems (namely, the Q4000 and Helix Producer) will be temporarily suspended, effectively shutting in the well. It is expected, although cannot be assured, that no oil will be released to the ocean for the duration of the test. This will not however be an indication that flow from the wellbore has been permanently stopped.

Information gathered during the test will be reviewed with the relevant government agencies including the federal science team to determine the way forward. Options include reinstatement of containment as well as extending the test duration beyond 48 hours.

The sealing cap system never before has been deployed at these depths or under these conditions, and its efficiency and ability to contain the oil and gas cannot be assured.

According to the same press release,

The Helix Producer containment system started operations on July 12. The Q4000 containment system continues to capture oil and gas from the MC252 well and flare the hydrocarbons safely at the surface.

Relief well operations continue throughout this period and remain the sole means to permanently seal and isolate the well.

The New York Times has an article about the pressure tests. It says:

If the tests on the well show the pressure rising and holding — an indication that the well is intact, with no significant damage to the casing pipe that runs the length of the well bore to 13,000 feet below the seafloor — BP, working with government scientists, could decide to leave the valves closed, effectively shutting off the well like a cap on a soda bottle.

“The best-case scenario is that pressures rise to the point we anticipate they would,” Mr. Suttles said at a briefing. “We’d likely be able to keep the well shut in.”

On the other hand, the tests could show pressures that are lower than expected, Mr. Suttles said, an indication that the well is damaged. That could mean that oil and gas are leaking into the surrounding rock.

In that case, keeping the cap closed could damage the well further. The valves would have to be reopened, he said, and oil would start escaping from the well again, although much of it, and perhaps eventually all, would be funneled through pipes to surface ships.

The same article said that a technician involved with the operation offered the opinion that it was unlikely that the cap would be left on beyond the test period, since there is a chance the pressure could damage the well over time, and since facilities will soon be available to capture the oil and gas that escapes.

Prof. Goose's comment:

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Perhaps the first genuinely good news since 20 April. However, noting the many unknowns, I will contain my enthusiasm for the moment.

I left the cams just after they showed oil flowing from the long white pipe with vents above the cap. I just returned and looked at the cams to see a short grey pipe now billowing oil and no long white pipe.

What happened to the long white pipe with multiple vents?

Did they take the cap off for some reason?

Did they take the long white pipe off to replace it with some type of pressure fitting?



The perforated pipe was just the lower part of the drill pipe that lowered the new cap and was never intended to remain attached. The vents were there to allow a path for O&G to escape while they put the cap in place.

They did take it off quite soon after the cap was installed. They are moving quite smoothly through this schedule.

I'm not sure if they will eventually put some kind of collector or seal on the top or if they will just close down the flow internally and collect out of one of the side valves later if needed. I assume a gradual reduction in the flow will be visible tomorrow as they start shutting it in for the pressure test.

Thank you. It seems like people here are pleased with how things went today and that is encouraging.


I have one more question:

I was looking at the BOP and new cap, and I dont know the scale, but it looks like the cap rests on a rather thin tall-looking column above the BOP.

How much movement sway from currents or wave action, if not connected to ships, can the whole apparatus take or is it insignificant that deep? Thanks again

edit added: It would seem the long column would act as a lever.

The scale can easily get lost.

The Transition Spool (the "rather thin-looking" yellow thing) is about 12-feet tall and weighs 16k to 17k pounds. A heavy, beefy and thick piece of steel; should be well up to the task.

See http://bp.concerts.com/gom/sealingcapinstallationanimationwithkentwells0...

For overall scale of the whole stack:

Oh yeah, I forgot about that picture. It's shorter than I thought. Thank you. The flex joint can take it? Thanks again

Yes. Also, according to Kent Well's technical briefing, when they jacked the several degree of cant out of the flex joint, they also installed pillow blocks to keep it straight and plump with the BOP. See http://bp.concerts.com/gom/sealingcapinstallationoverviewwithkentwells07...

I don't know what the TOD consensus is on Kent Wells but I found his personal narration of this very believable. He repeated so many of the same words (noob on-camera nervousness) and I didn't see his eyes darting back and forth (as if reading a teleprompter) that I grokked his general belief of the narrative.



I noticed the same thing. Can anyone verify if the perf pipe was removed?

I am going to post three excerpts from the new 29 Page moratorium.

Basically, the new moratoriumwas written for Judge Feldamn. It answers his every criticism, including providing an explanation of all options considered and why they were rejected. One option considered and rejected was the one that seemed to get the most support here: let rigs open after meeting specific safety criteria.

The authoity for the moratorium comes from the existing off-shore regs, 30 C.F.R. section 250, et seq., at section 250.177.

Here's from the intro and one aspect of the identified risk:

Second, this temporary pause in deepwater drilling will give industry time to take concerted action toward the development of more effective blowout containment strategies and capabilities for deepwater operations. The oil industry has limited capability to stop an uncontrolled blowout of an oil well in deepwater. BP's inability, after more than 80 days, to contain the Macondo blowout and spill provides continuing evidence that BP - and the rest of the industry, which has been cooperating with BP in its efforts to contain the on-going spill - had not prepared to contain a blowout in the deepwater environment. In Congressional testimony, industry executives have admitted that the industry is unprepared to stop deepwater oil well blowouts effectively, and that many of the containment methods attempted with respect to the Macondo blowout have been improvised and were untested.

synco - granted a theoretical guestion for which there is no answer but I beg your answer:

"In Congressional testimony, industry executives have admitted that the industry is unprepared to stop deepwater oil well blowouts effectively, and that many of the containment methods attempted with respect to the Macondo blowout have been improvised and were untested."

Based upon your years involved in oil/NG exploration, when would you say the executive of any oil company will swear, under oath and full penalty, that his company is "...prepared to stop deepwater oil well blowouts effectively"?

I'll make it easy: a multiple choice - a)6 months b)2 years 3)never

I probably don't have enough years in O/G exploration to qualify me as an expert on that one, or much else, RM. Throwing chain, can do. Setting off explosives, can do. Shutting down the local dive on payday, can do. As far as what the oil companies can or can't do, it depends what universe you live in, doesn't it? All of them said before that they can handle a full-on worst case scenario clean-up operation in their permit applications.

Salazar phrased it the way he did because he is just laying the groundwork for his moratorium so judge Feldman doesn't call him an irrational or arbitrary fool again. It's funny, the report consider's Feldman's alternative, and rejects it. It's the specific-criteria alternative. I did not catch that immediately because it was popular here, too. But there are a few instances of apparent snideness bleeding through like that.

In the end, they get their 6 month moratorium. If they had bullet-proofed the first report the way they did this one, it would have sailed through. That's why I said way back when that anyone who regularly reads the TOD could draft an acceptable basis for a moratorium if given a short outline of what had to be covered. If you read his report, you'll see what I mean. You might need staff to fill in the references to evidence and such, but otherwise it is not rocket science.

p.s. i really expected him to go farther than he did as far as allowing drilling sooner. Feldman will be pissed about that.


Actually - they DIDN"T say that they could handle a full on worst case. Didn't Tillerson say 'we never said that we could handle that. That's why we work so hard to make sure that this never happens'....and I don't htink he was including BP in that sentence.

But to give you the straight answer, Rock, never of course. And Salazar will never make that the standard. That's the funny part.

Well i finally finished my project. Time to go home.

Isn't this an MMS matter? What do courts and the Pres have to do with it? The MMS should be able to suspend all drilling permits due to an ongoing investigation. End of story. If BP would just fess up to their non-standard drilling practices then people who follow standard practices could get on with drilling. Along with all the people wishing to sue BP, the other players in the Gulf should sue them as well, they have been hurt just as much as the Gulf residents.


The cap finished after I was done writing my almost daily post so I wrote a softball pre-election post to let the voter think without last minute noise. There ought to be a federal law forbidding any media or phone campaigning no less than 72 hours before an election. I think it would help folks decide with more thought and less emotion. Just a crazy TinFoil idea.
http://gcn01.com. Buffett breakdown pictures and Hooter's girls too.

EDIT: I almost forgot. Look at the bucket, LEAKY ROLLOFFS!

From my bucket: http://s892.photobucket.com/albums/ac126/tinfoilhatguy/GS-OB%20July%2020...

TFHG - As you may be aware, France has had such a law in place for a long time. I do not know about the rest of the EU - perhaps someone can help me on that.

The shutdown on campaigning gives the voter a well needed rest and time to compare notes about all that has been said and make decisions.

It is my belief that such a law will not be passed in the US. The powers that be love the opportunity to make last minute wild assed claims (Swift Boat anybody) about the opposition that can not be disproved, in time, before the balloting. This leaves the weak, the reactionary and the highly subjective persons with untrue impressions that can result in throwing the election based on the false information.

BTW making false claims during campaigning in France breaks Federal law with substantial penalties ensuing.

They should be selling advertising on what OI 2 is observing


screen shot


(edit glad I took the screen shot, it's moved on - was a moving digital display)

yea, saw that too.

What is:
1.09 P-
2.20 R+
1.09 P-
2.23 R+

all about?

These are some sort of inclinometer readings. I do not know why they use an LED ticker for the readout but it is nifty. Most have speculated that R = roll and P = pitch but this may not be correct.

You are correct. These are pitch and roll measurements from a digital inclinometer. The inclinometer is battery powered and uses a display to remove the necessity of connecting the inclinometer physically to the ROV.

Every time you want to connect a piece of equipment to an ROV, you need to interface the data string and the power supply, and you also need to make up custom cables. Furthermore, the sensor is now hard-wired to the ROV so the sensor cannot be solidly attached to the structure, nor can it be left there whilst the ROV goes and does something else. It can be quicker and easier in some cases to have a fully self contained sensor that can just be deployed and looked at by the camera.

Here's what gets shut down:

A. Affected Operators

For the reasons discussed above and pursuant to the provisions of OSCLA, including 43 U.S.C. § 1 334(a)(1 ), and 30 C.F.R. § 250.1 72(b)-(c), and with certain exceptions set forth below, I am directing BOEM to direct the suspension of any authorized drilling of wells using subsea BOPs or surface BOPs on a floating facility. I further direct BOEM to cease the approval of pending and future applications for permits to drill wells using subsea BOPs or surface BOPs on a floating facility. These suspensions shall apply in the Gulf of Mexico and the Pacific regions through November 30, 2010, subject to modification if] determine that the significant threats to life, property, and the environment set forth in this memorandum have been sufficiently addressed. These
suspensions do not apply to production activities; drilling operations that are necessary to conduct emergency activities, such as the drilling operations related to the ongoing BP Oil Spill; drilling operations necessary for completions or workovers (where surface BOP stacks are installed, they must be utilized during these operations); abandonment or intervention operations; or waterflood, gas injection, or disposal wells. BOEM shall order any current drilling operations covered by this decision to proceed to the next safe opportunity to secure the well and take all necessary steps to cease operations and temporarily abandon or close the well. Pursuant to 30 CFR § 250. 168(a), BOEM may
direct a suspension for all or any part of a lease or unit area. Depending on the "nature of the suspended activity" the suspension is either of operations or production. 30 C.F. R.§
250.168(b). In this case, BOEM will be suspending certain activity involving certain operations and will issue individual suspension letters to that effect.

Lastly, when operationms may resume. I am skipping the duration section.

C. Potential Lifting of Suspension

The suspension could be lifted earlier than November 30, 2010, if BOEM assures me that the safety, containment and response issues that have created the need for a suspension have been resolved, or if those three issues are addressed to a degree that can be determined upon further study to ensure an acceptable margin of safety. If the results of the various investigations reveal significant unexpected ri sks, however, my duties under OCSLA could require me to extend the duration of the suspensions. As noted above, I will continue to solicit and review information relevant to this matter, and I will remai.n open to potentially adjusting the suspension period based on additional information and analysis. In that regard, I direct you to conduct public meetings and outreach to gather additional information, on an expedited basis, on the primary issues that I have identified as raising the most significant ri sks regarding the resumption of
deepwater drilling. You will be focusing on the following:

a. Drilling and workplace safety requirements as outlined in the Safety Report and a timeJine for the implementation of such safety requirements and others that may be necessary to ensure safe drilling practices;

b. Well intervention and blowout containment techno logy and methodology designed to effectively address and expeditiously contain any blowouts that could occur;

c. A review of additional and necessary oil spill response plans for offshore drilling and production facilities, and an evaluation of industry capacity to address a worst case discharge scenario under 30 eFR part 254.

I further direct you to issue a report to me no later than October 31, 2010, that contains yo ur findings and recommendations as a result of your outreach efforts and any other in formation you have acquired in the interim. This information gathering will be critical to addressing the serious risks presented by oil and gas drilling activities in deepwater environments. This additional information potentially could provide the basis for identifying conditions for resumption of drilling activities if certain conditions are met, and/or the ident ification of any oil and gas drilling activities that might be allowed prior to the expiration of the suspensions based on the relative level of risk associated with those activities.

Here's the link to the full text version, thanks to Lotus:


My quick read is that the moratorium is unlikely to be lifted prior to November 30th., except maybe possibly for the 5 rigs or so that have already been pre-identified as being the lowest risk deepwater out there.

Salazar has retained too much discretion and rejected the criteria-based alternative, and thus the message is uncertain enough that everyone is just going to assume Nov. 30th, most likely. Otherwise, they would have adopted the specific-criteria alternative, imo. Could be wrong.

The two conditions that might change that are the political calculus and the successful killing of the Macondo well. Salazar is willing to modify the moratorium based on new and better info, he claims. Seems sincere. Who knows.

They seem to acknowledge that some rigs are going to depart deepwater and there's nothing that can be done about that. See discussion of alternatives for that acknowledgment.

Has anyone thought about how they are going to laterally restrain that new hunk of 4 tonne metal from swaying in the currents and tweaking teh flange/prying the bolts at the existing BOP flange? Has the BOP even been designed to accomadate the lateral and vertical loads of a new "BOP"?

I'm not an engineer. But the currents are weak down there, probably less than half a knot. A wild card could be a turbidity current coming down the slope. That would muddy things up for awhile but not likely to happen. Also, the BOP served as an anchor for the deepwater horizon while it drifted and finally sank (I don't think any of the firefighting ships had a line on the DWH to hold it in position). The marine riser was the anchor "chain" and it broke while the BOP stayed put. Therefore, I don't believe we need to worry about this new hunk of steel on top of it.

I am not a petroleum engineer but I hold a degree in architecture with more semesters of structural engineering than I care to have suffered. Looking at the new configurations of the well, I am curious why Leonhard Euler's iconic formula for the buckling of thin columns does not come into play. Even if all the weight of the new BOP and extend shaft of the flange spool assembly does not run afoul of Euler, then it still would seem that the addition of some guy wires or other stays would be a prudent addition to counter-act any lateral loads from currents or a nudge from an errant ROV. That's a lot of steel to be balancing atop a two-foot diameter drill pipe.

Also, I am curious why the engineers are comfortable with closing the new BOP for a stress test when there had been so many statements about fear of increased pressure on the original BOP and well casing.

It would seem that if BP can carry off much or most of the flow through new risers to various surface vessels, that would be less risky. (But I suppose that were a hurricane to force surface vessels to leave the site, we'd still be faced with the prospect of closing, or at least restricting, the flow.)

It's a pleasure reading the informed and intelligent comments from TOD folk who know the technology. And I will appreciate anything that adds to my education on these issues.

Has anyone thought about how they are going to laterally restrain that new hunk of 4 tonne metal from swaying in the currents and tweaking the flange/prying the bolts at the existing BOP flange?

Yes, I think that the design team may have thought about this.

UPDATE: A mile of Kevlar rope plus floation bags near the surface could provide tons of vertically upward 'pull' if required. Haven't seen any sign or mention of anything like this (or any equivalent) so probably not needed.

"For the duration of the test, which will be a minimum of 6 hours and could extend up to 48 hours, the three ram capping stack will be closed and all sub-sea containment systems (namely, the Q4000 and Helix Producer) will be temporarily suspended, effectively shutting in the well."

Is this really a good idea considering all of the concern about the well's integrity below the sea floor?

I am confused why this is all of a sudden OK today, after they spent over a month telling us that high pressure in the BOP is bad and dangerous.

Didn't top-kill attempts and prep give enough hard data to support proceeding with bolted attachment?

The prevailing opinion seemed to be that the results of the top kill effort had raised concern about the integrity of the well.
It is therefore surprising to learn that a shut in is to be attempted. Would a blowout of any part of the well because of excess pressure give sufficient advance warning in time to relieve the pressure by opening the valves?
The only obvious rationale for such a test is that with the relief well nearly ready to intersect the wild well, it is a reasonable risk to take to end the pollution of the Gulf now rather than sometime in August.

I have been arguing for bolted connection since May. But bolted connection doesn't imply a high BOP pressure approach. I thought that BP explicitely rejected high pressure methods after aborted "top kill"...

I can't help but wonder what was it they learned during the top kill operation followed by the 'junk shot' that was abruptly stopped that made them worry about the integrity of the well? What data were they looking at, other than the mud flowing out the bend?

Apparently, they had no worries about the junk shot abruptly stopping the flow of the well with all the associated water hammer affects. Or maybe that is exactly what happened . . . they did the junk shot, the pressure at the BOP increased rapidly and ruptured the casing.

I don't think we were told the whole story about what happened during the top kill.

I, like others before me on this thread, am of the opinion that slowly shutting in the well now from the top, instead of collecting the oil until the bottom kill is ready, is just a needless science experiment that just adds additional thousands of bbl of oil to the GOM.

And why wait until tomorrow . . . why not start the test NOW?

This just does not make sense.

$100 wager they abort the test within a few minutes.

[QUOTE=avonaltendorf]$100 wager they abort the test within a few minutes.[/QUOTE]

You're on.

If you win the bet, email manager at cwsx dot com
"A few minutes" means less than half an hour
You have to post your email, too, or the bet is off

I seem to recall your proposal to make a tight connection above the BOP and allow leakage nearer to the surface if and when necessary. It seems like a tight connection is what they are aiming for, now that they think they have enough processing capacity at the surface. But, in addition, they contemplate making an attempt to shut the well in completely despite fears of damage downhole. It's astonishing. I'ld love to see the historical data on the pressure, assuming that such exists.

I was wondering the same thing. But nobody asked me, so I guess they are going to go ahead and try.

Perhaps limited ability to shutin is key to their relief well strategy. BP has been saying "it might help" but maybe it will help a LOT if they can hold some pressure at the surface. Note that we're all pretty positive about the relief well strategy but we need to remember that it's one of those things that has never been done in deep water (like the containment dome to take a trivial example). It's relevant particularly because of the dual mud columns (relief and wild).

If no one else is willing to say it, I will. It's gross stupidity to close the well in if even for a few moments and impose well shut in pressure on the casing with the relief well option so close. So, what they are really saying is that previous statements about suspect condition of the casing during and after the top kill was all BS.

Glad you said so. Your interpretation sorta makes sense. But then another mystery remains. Why it was to BP/USCG's advantage to allude that the casing was blown escapes me.

Maybe is was BS. It also seems to me that if they can close the well in, a top kill could be done. Just start pumping heavy mud in slowly and let it push the oil back down into the reservoir. If they got mud going down it would reduce the pressure at the BOP. I'm probably missing something here but why not? Maybe cementing would still be a problem.

I agree EJB either they should go for the top kill because the last attempt was really a spectacle with almost all of the mud escaping, now there is only one path for the mud and it would probably work since the plan was chosen earlier with less integrity to the pipe which is now much better, or they can immediately start pumping everything up to the ships and wait for the relief wells.

Perhaps they are worried about the pipe freezing up and clogging with the hydrates when they hook-up so they want to shut the flow off then hook up and then turn the flow back on?

Any way you look at it though it seems that a lot of time and energy has been wasted on expedient band aid attempts to stem the flow when the riser could of been sheared and the flange unbolted 2 months ago.

I guess nobody in charge wanted to make the important call and they only would attempt procedures that if they were to fail could not be charged with making an irresponsible decision.

But sometimes when you want to make lemonade you have to squeeze some lemons.

Why they are now going to start pressure testing when the well needs to be shut down is beyond my imagination.

You would think that even if this well was going to be put into production in the future they would cement all of the current holes and start a new hole somewhere nearby but far enough away that anything that was damaged during this disaster would be of no consequence.

Maybe BP is testing because if there is no escaping oil leaking through the casings or well bore they can start full scale pumping of this well and possibly extract enough oil to pay for the disaster and break even.

Too bad the environment doesn't get to break even.

So , Ron, You really think it would need a pump?

I can't understand why they don't do that either. Either the well can be shut in for a few hours or it can't. If it can, then surely it would be better to slowly start pumping in mud to relieve pressure at the BOP rather than just leaving it sitting there as is. As you say, they wouldn't even need to pump in the mud particularly quickly, since (unlike on the last attempt) there's only one way for the mud to go: down into the well. Monitoring the resulting drop-off in pressure against the amount of mud pumped in would provide some useful data regarding the integrity of the well. This data would not have been available during the original top kill, due to a large and indeterminate amount of mud escaping at the BOP and out of the broken riser.

If they can get the pressure down to zero by this method, I guess they would have the choice of cementing from the top and/or from the bottom, via the relief well.

So where's the catch?

A cynical view, perhaps not entirely incorrect, would be that shutting in the well is a public relations ploy to boost the price of BP stock. I don't see why it is necessary to risk a subterranean blowout when it is possible to channel all or most of the oil and gas for collection by ships on the surface, while the relief well is close to completion.

I am not an oil worker so I don't know if what I am saying can be true.

My guess is BP doesn't want to close down the well. My guess is they will make of show of pressure testing knowingthe casing is damaged so they can abandon stopping the well with the new cap. I think they know the relief wells will work knowing how bad the casing is damaged, however, they will "fail" at the relief well. I think they want to lay lines to a working rig and produce the oil in the well salvaging as much oil revenue as possible.

What do they have to lose? If they stop the well they are no longer needed and must go bankrupt paying for the claims and cleanup. THe other reason is the Obama administration can't let a good crisis go to waste without furthering his agenda. The well must continue to be a problem for a while yet and perhaps at least until after the elections in November.

Of course, I'm not disillusioned with all this political stuff. Then again, I truly have only a vague understadning of all this anyway. Cheers :)

A fair amount of time has passed between top kill analysis of well and currently attempted analysis. I'll guess to say they want to determine deterioration rate of well over time. This may help to plan time deadlines for future tasks. Forgive me for the vocabulary, but yes, where I work, we call it a drop-dead date.

Ex -- to emphasize your point I'll point out to all the non-oil field trash here how pressure test works. I'm not being patronizing but these are the two categories of the results of a pressure test: Think of squeezing a ballon and breaking an egg. Pressure a balloon and it expands but contracts when the pressure is dropped. No harm. Squeeze an egg and it breaks. Drop the pressure and the egg is still broke.

I'm not being silly. That's exactly how it works with a well bore. Make a cmt shoe leak and it might well return to it's original integrety. Rupture a section of csg or a csg hanger and it stays ruptured. I can't predict what will happen. But it's easy to imagine the worse case scenario developing: a well that cannot be stopped by a bottom kill and one in which no cap containment will work.

"... Drop the pressure and the egg is still broke."

So what is the great benefit of risking breaking the egg?

In this case, what is the great benefit of risking damaging the well further?

Thank you

But it's easy to imagine the worse case scenario developing: a well that cannot be stopped by a bottom kill and one in which no cap containment will work.

Sure is chilling to see you say that, RM.

I wonder why they are so determined to take the chance. There were many questions about the risk during this afternoon's press Q&A and the answers all came down to a belief there that would be adequate warning if something started to go wrong. Eggs typically don't crack slowly.

It sounds as if many of the same people who monitored the top kill attempt and decided to end it early due to concerns about well integrity will be in the room tomorrow in Houston. What changed their minds?

Rock, do you think this is an unwarranted risk? I can see certain benefits from what has been discussed in the media but I would have assumed that this was a manageable calculated risk and would be done slowly and carefully with lots of early abort points.

I've been trying to weave together the chain of logic about the approach. However, I know nothing about this and trying to understand.

If BP successfully demonstrates that they can shut in the well with the mini-BOP, is it at all possible that BP might attempt to reopen the rams produce the well indefinitely? Admittedly, I've got no idea what regulations would allow or disallow this, but might BP be bold enough to push the limits of good practice?

They'll soon have two relief wells in striking distance of the main well. Could they argue that simply having them at the ready provides a safety factor if anything should go wrong in the future?

Also, any ideas as to why they're using three rams on the mini-BOP? -- other than just making damn sure one of them operates this time.

"Squeeze an egg and it breaks"

will it? try placing an egg in your right hand and squeezing as hard as you can (do it over the sink just in case it has a small fracture in the shell)

Is it possible that some data from the top kill attempt has been analyzed now, and they've concluded that the casing isn't damaged and they can shut the well in using a new set of rams? ISTR some discussion earlier about BP saying they had forced mud down the well to 1000' below the opening, and at that point they started losing mud and pressure. What if they now believe the mud was just venting upward; with all the data and tests they had available, is that possible that they were just wrong earlier?

Because if they were correct the first time and the casing is indeed damaged, closing the well off with this new ram assembly seems to me to be the worst thing they could do right now.

As of 10.30pm the well is still "leaking".

though it appears to the untrained eye to be less than before the new cap was installed.

I think the concern with the "junk shot" was that they had no control of it once the BOP was plugged with "junk". If there was a problem below the BOP they would be SOL.

With this new mini-BOP, they can reopen it if it's causing problems with the casing.

See the related comments at http://www.theoildrum.com/node/6718#comment-674539 for what I think is their concept (only my conjecture but it seems a reasonable interpretation).

They can test if the well's integrity is intact or compromised. If indeed compromised, they will open the rams, relieve the pressure and ultimately take the entire production topside, at least to the capacity of the topside processing/flaring. If the well can take the pressure, they can shut-in the well until the RW kills the well.

Not only might (perhaps a big "might") be able to shut-in the well, the test could provide information for the RW too.

From http://www.chron.com/disp/story.mpl/business/deepwaterhorizon/7105359.html

The information, however, would better prepare workers to execute the imminent "bottom kill" operation in which a relief well will puncture the Macondo casing near the reservoir and pump in mud and cement to plug it permanently.

"Apparently, they believe the incremental benefit in knowledge of the well's condition for the kill operation is worth the near-term elevated risk of pressuring it up for several hours," Cogdell said.

Should the team find the casing is ruptured, Suttles said, the kill procedure will have to be modified, possibly using a different mud weight.

If they do shut it in, there will never have been a period of full containment to positively determine flow amounts.

Although I suspect the current estimates are solid enough, the low side may be way below actual totals. And the low end is likely to become the final estimate for fines, is my guess.

I am not implying that is why they are shutting it in, if they do. It is at least an interesting side fact, though.

Occured to me also

Very interesting. This is when we need Lotus with a press pass asking succinct questions but they will never let her in the doors now with the double wicked eye.

PS. I actually though they were stalling for the RW in order to prevent full count on flow. I also know (along with everyone here) that fines are negotiated away.

"PS. I actually though they were stalling for the RW in order to prevent full count on flow. "

That flashed on my radar screen, too. It's not that I assume that is what they are doing, but the convergence of facts opens that as a factual possibility, and under the circumstances, it is worthy of some probing to see if other facts might support it.

But in the end, getting the well sealed and their future stabilized are much more pressing matters, IMO. But saving a billion is always nice.

If the fine is $1,000 a bbl and you assume 2,000,000 bbl, the fine is $2 billion. That could go up to $8, billion if they get hit with $4k a bbl. Cutting that in half would be nice.

The current generation of caps, including today's sealing cap, have all been required to include a means to measure the flow.

Asked this afternoon

I’m curious if you are successful in closing in the well, will you ever end up with a scientifically close estimate of how much oil has been flowing out this entire time?

Suttles replied, in part,

While we’re – while we’re actually flowing it through the cap assembly, we are taking measurements to help better define what the rate is. But I think absolutely everyone’s agreed that the number one priority here is to get this flow stopped and to get the spillage stopped. So we’ll gather as much data as we can but of course we want to minimize the amount of being spilled here. So we’ll close it in as quickly as we can.


Even with full containment, the secret of the leaking flow may be forever lost. Everything they do is changing the flow conditions. Suppose they back off on the full containment but still keep some back pressure with the new valve arrangement. This back pressure will reduce the total production. Production amount will not equal leak amount. Maybe the math guys can figure what it used to be?

Why the wait for commencing closing "the valve". Are "they" getting a velocity head measurement to calc the flow? It seems that it would be very important at this stage to accurately determine the velocity head and discharge rate of the open hole once it has reached equilibrium flow conditions. Once velocity head and Q are obtained, the headloss from the bottom of hole to the discharge point could be calc'd. Then the pressure at the top of the oil bearing formation could be calc'd.

This would allow calc of the expected static pressure at the top, once the valve is closed. (Subtracting out the weight of the static column of oil/gas) I would want to know this info BEFORE I started closing any valves, so if there was any significant deviation from the path to the expected static pressure readings I could put the brakes on the procedure and re-evaluate. From what I have read previously, the static pressure at the well head is expected to be around 5-7K psi, based on depth and type of overburden.

Also, what about the "water-hammer" effect? I am assuming the Q is about 1000gpm, which has a very significant momentum. Pressure waves would show up right away on the gauges as the valve is closed, if it is closed too fast, and blow out the casing. I would want to see a nice uniform convergence to the projected static pressure, and then for it to remain steady. Thoughts?

The three-valve-stack "mini BOP" should give them absolute control. They can close the rams as slowly as they like, and reopen them it looks like the casing's gonna blow.

Well, the "blow" part usually doesn't come with a warning.

They can do it fast or slow, but the fracture event is likely very fast. Faster then their ability to control, and remember this flow has a lot of momentum and viscocity, it takes time for the pressure "knowledge" to travel down to where the possible fracture is occuring. If they are unlucky, they will see a sudden drop in pressure and they are done - they can open up the rams but it will be long, long seconds before the pressure is relieved to safe levels down below - plenty of time to rip a seal or to fracture a weakened pipe. Fracture propagation velocity in metals is very fast, once the critical crack size is reached. Once they see the pressure change up above, the dammage below is likely to have been already complete.

Seems like a very high risk to take, a couple of weeks before relief wells are operational.

"Fracture propagation velocity in metals is very fast, once the critical crack size is reached."

Once an egg is cracked, it's cracked. Remember Humpty Dumpty?

Perhaps the Deepwater Horizon Gung Ho company man is back from leave and now in charge, seeing he's familiar with the well. and looking for his lost early completion bonus.

It would be a major risk if they closed the well in and then had to abandon both it and the relief wells, due to hurricanes arriving before completion.

Maybe they just want to squeeze the egg slowly and slightly while listening and watching, and will cease once they have suitable data, or the moment they suspect damage is imminent. I think I'd be walking very carefully on egg shells whilst closing the rams and lines.

Perhaps careful sensing will also locate possible flow-paths?. I assume they want to accumulate some flow versus back-pressure data, so they can apply sufficient and timely back pressure when they commence the bottom kill.

You raise reasonable points.
What is troublesome to me, (and perhaps others) is that there is no information about the state of this well, which was drilled with minimal specs and then abused by an unprecedented disaster. It may be robust still or it may be hanging by a thread. To stress it for anything other than a matter of extreme urgency seems to be tempting fate. So why do it?

Why with the cap on tonight, are they letting it flow and starting the pressure test tomorrow?

Why with the cap on tonight, are they letting it flow and starting the pressure test tomorrow?

- Maybe the team needs some sleep & food?

- Perhaps they need daylight to monitor say gas/oil reaching the surface from a breached pipe?

- Perhaps they need time to run tests on the seals, electronics, sensors, communications links of the newly installed systems?

In case it blows, and gas vents out at full blast, surface evacuation and rescue efforts will be easier in daylight, quite simply.

Though with the distance to the surface, and without a riser connected (is that correct?), the impact of venting gas on the surface should not be as serious as it was when DWH got lit up.

What type rams does the new three ram BOP have (blind, pipe, shear)? Assume it has choke & kill outlets for production, and where are they placed? Assume it gets hydraulic power from rig above, and 22" riser with HC connector will latch onto stub shooting out oil now.

Why not produce well into surface vessels before closing it in? As long as no more oil/gas get into GOM water no harm is done. Safer to not risk damaging well.

The cap change out team have done a great job. They are heroes, like the Apollo 13 Houston bunch.

The crews manning these ROVs have evolved into the most skilled crews in this field in the history of deep well salvage. It's like watching Mozart and Beethoven now ... I hope that when this is over we will get to meet these deep sea Sully Sullenbergers.

HI LostNoz
I hear your cry!. These sites, like TOD, have their own momentum. Your observation that there are real people out there remediating this f***up will simply be buried in the traffic. I know what you are saying, I worked in HiTech all my life. This is HiTech and I agree that the brilliant and dedicated engineers, scientists, and the doers should be recognised. Unfortunately this does not happen. Occasionally we have recognition, your example, Sullenberger, is very much the exception. I suspect that many lurkers and posters on this site would agree, but there is too much other action right now. Your post did not go unnoticed!!.

A good friend made a similar comment to me earlier today. He would really like to see some more information on the individuals who operate the ROVs -- who they are, how they learned their skills, what they worry about, how they interact with the rest of the engineers and decision makers, etc.

How about a TV documentary on The Discovery Channel or similar media outlet? I know that I'd watch it.

As someone directly involved with ROVs, feel free to ask any specific questions you may have.

Has your ROV ever been attacked by underwater alien fire bugs such as the ones in this video?

Thanks for the invitation, rovman. As you have time, I'd like to know . . .

1. What qualifications land someone a job as a ROV pilot-trainee? What are the must-have attributes for this work?

2. What does your training (lasting how long?) cover? How frequently refreshed?

3. Do y'all further specialize on the sub-chores or master all three and switch-off between them? What's the usual age-range of the profession (if any)?

4. Are m/any ROV pilots women? (Mrs. Lear herself once told me that their light touch on the controls makes women the best LearJet pilots. Any parallels to ROV-work there?)

5. If there's a classic "ROV-pilot personality," what is it? Beyond basic skills, can a veteran meet up with a noob and spot right away whether s/he has the right stuff (or do they just think they can)? [Why yes, this is 1(b) in sheep's clothing.]

6. Where is the ROV corps' place in the oil-patch pecking order (and is this summer raising it)?

7. What makes for a hard shift, and how long do you need to recover after one?

As I say, no rush on the answers, I'm just curious. Thanks again.

Rockman et al with experience (or vague knowledge thereof) in oil field leasing. Since the moratorium was an arbitrary govt act, who eats the cost of all of the contracts that can't be fulfilled? Is there a clause which simply abrogates the contract? Does the supplier get to keep the deposit? Does the prospective recipient still owe expenses?

If the contracts are just broken, the moratorium is in BP's interest because it will be a while before they get a permit to drill in the GoM. It would also allow other companies to exit the scene in the face of higher liability risk and insurance rates.

I am a brandnew poster but long time reader of TOD. My Wife is a Geological engineer in Canada and I have a Masters in Physics with a short stint as a drillers helper, That is my only experience with DWD. That said, I have been wondering about BP's apperant unwillingness, up until now, to attempt to kill the well with a simple valve.

I've dealt with the math and the hydrodynamics as presented by the more knowedgeble posters but still have wondered why that simple flange with it's simple bolts couldn't have been undone and capped 2 months ago. Believe me, I've read and have wholey digested the previous posts on this matter and my perceptions have changed very little. There is something wrong with this picture. The well flow has not changed very much since they cut the riser(The visual apperance of it might have, due to the placement of the cap), but, My observations gell with earlier observations of flow volume.

This is, in my understanding, a Large resevoir, if not, A Very Large resevoir with at least 15 years @ 500000 BOPD give or take.

My question is this. Why wait till now to mate the flange?

Before a response is postulated, I simply don't buy the "Technology isn't/wasn't ready" excuse, Commercially avaliable vehicles are rated to 10000 feet and beyond for much less than you'd think.

In my simpleton view of things, it's desirable to have a taller column of lower mud weight injected by the relief well. Pumping heavier mud may (probably will) fracture the main reservoir, the lost circulation zone above it, and half a dozen shallower horizons. Bolting on a tight riser recreates 18,000 ft 14 ppg balance by DWH before they displaced to seawater.

This is, in my understanding, a Large resevoir, if not, A Very Large resevoir with at least 15 years @ 500000 BOPD give or take.

Presuming that's a typo, 50000, vs. 500000. 15 years at 500k bpd = at least 2.7 billion barrels recoverable is extremely unlikely (from 60 feet of pay...)

2 months ago: May 13. You have a twisted, deformed riser hanging off the BOP, which you've had good pictures of for about 2 weeks, having spent ~1 week on search & rescue & firefighting until rig sank, and most of that time trying different diagnostics & attempts to get the BOP to actually close & have come to conclusion that BOP won't seal, for unknown reasons.

In that same time, you were going to decide you needed a 15k rated subsea BOP or valve system, figured out how to unbolt the BOP from riser with massive riser weight hanging on the flange causing stress, and at same time deliver & install this valve system.

Nevermind the lead time on a custom built 15k subsea valve system is typically ~9 months (build time only, excluding any engineering or lead time on parts), off the shelf parts won't connect to existing setup, and you haven't figured out how to even access a flange yet. (Took 3 days of testing for ROV to unbolt its first riser bolt, watched painfully on video... and that was on an unstressed flange with no oil flow)

I am reluctant to go along with what sounds like revisionist view of the actual process that unfolded.

Specific efforts were made, using declared methodology, to achieve stated goals at specific times by BP.

There was not an articulation of an overall plan, that would culminate with an high pressure shut-in attempt in mid July.

In fact, until about a week ago or less, there was not a mention of a shut-in attempt at all.

The latest capping system was consistently presented to the public as an interim measure, specifically designed to minimize the oil flow into the Gulf and maximize top side recovery. Relief wells were consistently presented as the actual "final solution" to this disaster. Previous high pressure attempts were quickly abandoned due to anomalous behavior of the well system, leading to suspicions of well integrity compromise or loss.

Therefore, it came as a considerable surprise that the new transition cap, instead of being connected in a leakproof manner to the topside producing vessels is going to be used as a "second BOP" in a new high pressure attempt to shut in the well.

Perhaps it is the right decision, but it certainly has the hallmark of something that was not planned, at least publically. One would question why would you take a serious risk of permanently damaging the well only two weeks before the planned RW execution. Why would you risk success of the RW effort at this time? Why would the government, who ostensibly pulled the plug on the "top kill" attempt over well damage concerns, allow BP to try to do it again?

The idea that the current setup allows for pressure monitoring and flow control and, therefore, can mitigate the well bore damage risk, I think is faulty. There is pressure sensing lag and pressure control lag (sensor and valve distance from potential damage point) that will make the controllability of this experiment highly uncertain. If they are unlucky and the well is fractured under full reservoir pressure, they will not get BOP pressure reading in time and will not be able to correct in time. They will be "notified" of that event having occurred after the fact.

So, the question remains, why has the BP strategy shifted from "low risk" to "very high risk" in matter of days, with essentially no explanation?

Call me crazy, but could the takeover rumors have played a part?

Good onya Dave, correct. For that valve system to be fabricated and supplied in the short time meant that a lot of people must have been working their cotton socks off to get it done.
Its not like ordering a Big Mac in the drive through lane. Or running an algorithm on the stock exchange.

But, what if the goal were simply to have a single BOP ram that was good enough for temporary deployment while the relief wells made their way to the target? Are you thinking that Cameron couldn't quickly rob one from an existing BOP that would do?

I know that they messed around with unbolting the riser section that was laying on the sea floor for quite some time. I'm not buying the idea that had to be that difficult. With the right resources applied to developing a suitable wrench, I doubt that task would be on the critical path. Besides, why didn't they work out most of the details in the test pool at Oceaneering's facility with a similar section of riser instead of one mile down on the sea floor?

Pressure ratings.

I don't think I've seen this commented on and am having a hard time digging up real data.

The DWH has a 10k connector between the old LMRP and the old BOP. That is one weak spot.

I can't find pressure data for the Flex Joint on top of the old LMRP, and have no idea what the pressure rating of the flange on the top of the flex joint that is now attached to the new custom spool leading to the capping stack.

The original riser has a very low pressure rating as it is topped by a diverter assembly at the rig floor rated at only 500 psi. Assume for a moment the requirement to hold a 12 ppg mud differential plus 500 psi of diverter backpressure and you still generate a low absolute rating required for the riser.

Anyone know what the weak link is in the new assembly regarding pressure rating?


It took years (decades?) to sort out the contract issues surrounding the Destin Dome leases - the government offered and leased the tracts, the discovery well was drilled, but then between them Feds and Florida refused to allow the discovery (gas) to be produced. Eventually the lease bonus and I think part of the drilling cost was refunded to the oil companies and the lease was cancelled. That was just ONE set of leases! To do the whole GoM might employ all our lawyers for the rest of the century.

Rarely seen pictures of the devastating consequences of the BP disaster.


If BP can turn off the well tomorrow no one will ever know the total flow. If they process 100% of the flow at the surface the total flow will be known. They are willing to take the risk of blowing up the well in order to conceal the total daily flow in order to limit future liability.

Makes sense. Laughable the way they fobbed off responsibility to Chu.

It seems to me that that someone wants to know the information about the well integrity. Would that be DOE or BP. Seems to me a few days ago they were debating weather to do this cap or not.

Like others, I'm wondering if they think they can cap the well entirely now, then why they didn't do it earlier. Or, if they were worried about the top kill damaging the casing, why they aren't still worried about that? In scratching around for possible scenarious, I have one dumb geologist question the reservoir engineering types: Could it be that we are dealing with a somewhat different animal now?

They had been capturing about 25 K bbls per day, more or less. Assume that they were getting half of the total flow. If total flow is in the neighborhood of ~50 K bbls / day for 80 days, that means that the reservoir could have flowed ~ 4 million bbls by now. (I know, I'm not allowing for less flow before cutting the riser, but on the other hand some estimates of total flow have been well above 50 K bbls/day.)

This is only a 60 ft sand, and I seem to remember numbers like 50 million total recoverable for the field. So it seems like it's possible that something approaching ~8% of this puppy may have already been "produced" (using the term produced very loosely). If the 50 million bbls estimate was too optimistic (been known to happen on exploration projects) then the percentage produced might be even higher.

So reservoir engineers tell me, is it possible that we are now dealing with a somewhat lower pressure animal than before? Could the pressure have been bled down somewhat by now? Could that be why BP/Chu are more willing to clamp the lid down tight now?

Just a dumb rock pounder question.

Like others, I'm wondering if they think they can cap the well entirely now, then why they didn't do it earlier.

I suspect it's simply a case of the capping stack not being a part that one can buy "off the shelf". If so, designing, manufacturing, assembling, testing, shipping and deploying such a contraption within the space of a mere few weeks is IMHO very impressive.

at one of Well's latest briefings he indicated that they had been working on this from day 1....and it sounded like it's taken this long to build.

Alaska_geo: Given the decline rates seen on most ultra-deep-water wells - at lower production rates than Macondo, and the frequent need to supplement with pressure support, I would be surprised if the formation pressure had NOT dropped significantly by now. Of course I am also surprised that a reservoir subjected to such abuse hasn't collapsed or sanded up either - my reservoirs often have trouble surviving even kid-glove treatment with sand control.

I assume that
they close the rams VERY slowly
if the rams are linear rather than binary
they can monitor the below-ram pressure in real-time and VERY accurately
a non-explosive piping failure can be detected BEFORE it causes too much trouble

So unless the primary failure mode on a damaged pipe is explosive, the pressure test should be relatively safe.

They of course may have a different goal : perhaps they simply want to close the rams to reduce the flow rate by say 50% in order make collection & storage a lot easier.


I agree. Reducing the flow rate in a controlled way wouldn't be simply a PR exercise or an attempt to run up the stock price. Even if the primary motivation for what they're doing is to keep the fines down, reducing it certainly would be a benefit in important other ways.

They have absolutely nothing to lose by gradually raising the back pressure to see what happens as they are ultimately going to need a higher pressure on the wellhead to contain the mud from the relief well. The hydrostatic pressure on the casing will be less when filled with escaping oil than when it is filled with mud. So check it out and cross another worry off the government overseers' worry list. This whole process has been governed by the most timid regulator from the start. For example, instead of screwing around with Leak 3 at the end of the riser, they could have cut off the riser at Leak 2. The big kink was still there to limit the flow! But NO, the guiding principal of the day was "First do no harm", but as was said above "you've got to squeeze some lemons to make lemonade".

That's the problem with putting a Nobel Prize winning physicist in charge and expecting to get Richard Feynmann. People tend to forget that Feynmann's thoughts were only included in the Challenger Commission Report as Appendix F http://science.ksc.nasa.gov/shuttle/missions/51-l/docs/rogers-commission... after he threatened to resign from the commission and subsequent to his o-ring in ice demonstration. This whole administraion is based on using appeals to authority, men & women in fancy uniforms (and Harvard degrees), exactly the kinds of guys Richard Feynmann's father, the uniform salesman, warned him about.

Random rumination:

It seems to me from various posts here that many people have never been involved with engineering, or large project teams or even large companies.

Quite understandably, many of these posters say things like "It would be easy to ...", "We could quickly ...", "Why haven'they ...?"

Perhaps we need a TV series or major film which shows all the support people, the costs, the difficulties, the legal issues, the recruitment issues, the skills etc involved in getting ANYTHING done in the real world?

To any naysayers: why not run through the various processes etc needed which would allow a bolt to be tightened 1 mile below the surface of the GOM, 50 miles from the coast?

You need somewhat more than a: the bolt b: a wrench (UK: spanner).

Yes agree. Add to what you said the pressure of knowing the whole world is watching and you cannot risk any action which makes things worse.

It is easy to forget that what is happening today was started weeks ago in paralell with the relief wells. The relief wells appear to have gone ok so far, and maybe this effort is less relevant than if they were behind schedule, but irrespective of the pressure tests and closing the well in, we seem very close to collecting most if not all of the oil with this new set up.

If it could have been done quicker I would guess BP have more reason than us voyeurs to have done it.


Spot on.

Well, I'm a mechanical engineer with more than thirty years experience and I have many of the same questions as some of the non-engineer types here.

I've been involved in large & small projects with large & small teams -- including a brief stint with Shell Oil for an ultra-deep water dual gradient drilling project and about three years with anti-pollution safety systems. I understand about pressure on projects that get lots of attention. And, I also know that "nothing's easy".

Taking the ramifications of such endeavors into consideration, the reasoning behind many decisions over the past months still need better explanation.

Maybe we'll get those explanations when this is over. BP is under criminal investigation and is trying to survive as a company, so I'm unsurprised that we're not getting detailed explanations now.

I hope investigators ask the right questions and press for good answers.

I'm looking forward to the books, but they'll probably be well down the road. Criminal investigations won't produce the full picture.

Noob question, if there is well breakage or significant damage from the pressure test, does that eliminate any possibility of killing the well with the RW?

No, but could make things alot more complicated!

If we imagine containment failure near or above the mudline, for example casing or BOP failure, the relief well could still establish the required column of mud to counter the pressure from the reservoir.

However, if the casing were to fail further down the well profile resulting in the reservoir flowing into a rock strata incapable of resisting the shut in well pressure, the blowout might then end up finding other routes into the sea and the "oil out of cracks in the seabed" scenario could come true.

This latter scenario could possibly still be controlled by the relief well, but the problem might be having enough mud to do so - once the we're flowing into a formation that required column of mud becomes complicated to achieve and the balance of pressures is very delicate. But there are other ways of bridging the flow in such a situation - as long as the relief well is in place I consider that they would find a way to kill the blowout.

Yes, throttling the new valve to keep head on the mud flow during the kill operation will provide oppotunities to fill as much of the damaged casing/fraced zones as possible. They know that the mud pressures could do more damage than good if there were no relief mechanism in place. The issue that no one has listed as a potential problem is the possibility of delayed hydrogen embrittlement of the well casing due to the high H2S content of the stream. You are right, they may need alot of mud for the best possibly kill and it should follow every path.
The thing to remember is that as soon as mud is introduced into the bottom, pressure will be from the mud pumps and this pressure will need to be throttled at the mud manifold and the new top valves to make it all work.
Being able to make critical decisions under these conditions takes the kind of experience that would cripple most of us.
It's the leading edge stuff like this situation is creating and its ultimate resolution that will permit BP to lead the pack.

Every legitimate reference to Macondo H2S that I've seen indicates there's very little of it.

It may not, but you have to assume it is in the stream if you are going to analyze all the issues.
If BP used incoloy for any of the casing you know they expected H2S, and at high pressure the effect is much worse. Did they use incoloy?
If they did not use it and H2S is not in the stream, which I doubt, I would try to produce this reservoir because of the exceptionally high quality of the crude. I just would not produce it with the existing well, maybe one of the relief wells, depends on how the kill goes.
We need one of the wells to produce.

Hence, my earlier questions about cathodic protection, eletromagnetic induction,etc. Would this create cause for pause before tapping into the WW with the relief wells if they are detecting the presence of H2S or NH3?

Hello, all.

As a geologist with no oil field experience, I've hung on your every word here and learned a lot. Now that it looks like you have a handle on the main problem - killing the WW - I wonder if we could take a moment to discuss the other problem. There is an awful lot of oil mixed with an awful lot of seawater and spread over an awfully big area. Something has to be done about that.

Some friends and I have been think-tanking this, and we have some theoretically workable ideas. But we need one piece of information none of us can provide. Hopefully it's within your experience and you will be kind enough to comment on it.

My understanding is that the oil-water mix is deteriorating. Lighter fractions are leaving, possibly some chemical reactions are occurring with sea salts that could make organometallic compounds, etc. Suppose for a minute that a machine exists that can separate the oil from the water. Not perfectly - we can't hope to undo the emulsion completely, so there will be water entrained in the oil. Our question is: Would such "oil" have any economic value at all, or would it just be a big glob of hazardous waste? If nothing else, could it be processed into petroleum coke?

Thanks for your time, and thanks also for your contributions to this site!

Assuming the flow is both up the DP and the annulus between the 9 7/8" and 16" casing as some have speculated, where are the 'weak-links' when the well is shut-in? Does the 16" casing have enough burst strength for the pressures that it will be subjected to? Do the "burst discs" in the 16" casing enter into this now?

Thanks in advance for any thoughts.

The 16" saw higher pressures during drilling than it is seeing now or will see during a controlled shut-in. I don't know what kind of dynamic pressure it saw during the blowout and associated BOP shut-in attempts, which I suppose could have damaged it.

Since I studied the burst disk problem let me take a crack at your questions.

The disks are intended to relieve thermal expansion of the mud outside the 16" casing as it is heated and expands due to the high soil temperatures around it. Without any vapor space, the mud is essentially incompresible and could create very high pressures over a large surface area. Lots of square inches times a high pounds per square inch means lots of pounds of force, which is what would cause the casing to implode.

The disks can also break due a pressure difference in the other direction (what is known in the business as the "reversal ratio"), typically at about 1.5 times the burst pressure of the disk. The problem under such a scenario is that it would be feeding into the intact annulus, which would in that case be full of mud and be incompressible, so you would not get a differential pressure (which is what it would take to either rupture the disk or burst the casing).

Several threads ago there was a mention of "Occam's Razor", the principal that the simplest explanation is also the most likely. The explosion occurred while they were working inside the production casing and reduced the hydrostatic pressure in it. The oil is flowing up the drill pipe which is inside the production casing. The most likely flow path is from the formation downward, u-turning back upward through a "wet shoe" and then up the production casing (and the drill pipe where they meet). That would mean there is no unusual pressure on the casing as it would still be intact. The only things that failed would be the cement shoe and the cement plugs in the production casing.

They have already put 10,000 psi on the wellhead during the top kill, so they have hydrostatically tested the casing that high. This is why I offered the "all the marbles" plan earlier, to demonstrate that the top kill failed because they used too fine a particle size in their mud and so got too little mud down inside the well bore to hold pressure when they stopped pumping. They chickened out too early in trying to find a better way to make it work. I would note that Rockman has indicated that there is 28 ppg Galena (lead based) mud but no one has indicated they have ever used anything higher than 22 ppg. The reason is simple enough, oilmen want to be able to circulate the mud out of the hole later on, so Galena mud would need extremely fine particles of lead. But if you are not an oil man, you are open to the idea of using even higher specific gravity materials in larger particle sizes to ensure that they can flow downward under only the force of gravity to clog the hole. One model simulation of having the well filled with 13,000 feet of 1/2" diameter glass marbles put the flow at 500 barrels a day, instead of about 50,000 barrels a day at present. That's roughly 20,000 cubic feet of marbles. Glass is derived from sand, so you could use recycled glass bottles to make glass marbles to re-introduce into the well to form a column of vitrified sand which under pressure and time would become sandstone. Completely non-toxic, organic even. Dust to dust.

Also on an earlier thread there was the supposition that the "junk" of the junk shot fell to the bottom of the well because its specific gravity was higher than the oil & gas mixture flowing up and it was a large enough "particle" to be able to sink in accordance with Stoke's Law. They never blocked the BOP because the junk went down instead of up! The answer to that question ought to be easy to find, drop a golf ball (the archetypical piece of junk) into the well and see if it spits it out. If it doesn't, you've got your answer as to why the junk shot failed.

The overarching philosophy of the people involved, especially the government, has been focused on containment not well intervention to constrict and then control the flow. The only previous attempts at constricting and controlling were the top kill and junk shot. They nearly succeeded before they got cold feet and quit. As I have said before, Sec Chu has got a lot of 'splainin' to do about those top kill and junk shot operations.

Most oil is produced along with salt water, and is often biodegraded and/or emulsified. It is routine practice to break the emulsion, separate the oil from gas, water, & sand, and sell the oil (even biodegraded oil) to the refineries. So yes, 'your' oil would have utility, though the costs of the logistics handling it in small and irregular batches may exceed the value (depending on the countercost of whatever 'deal' you can strike with the politicians about landfill disposal.)

Nalco VP Dr. David Horsup demonstrating the effects of Corexit on oil in circulating water:

Compare the mixture in Horsup's beaker to the underwater plumes documented by Philippe Cousteau:

I don’t think Euler buckling will be an issue since the transition piece is so short.

However, the BOP is swaying which I think will cause higher amplitudes on the smaller BOP. This is same as hanging a heavy steel ball by a string and then hanging a much lighter steel ball from the heavy steel ball by a string. If you set the heavy ball in oscillation, the lighter ball will have a much greater oscillation and this will cause very high stresses in the transition piece. It looks like BP could have put a little more fat in that transition piece.

I believe if I rooted around a bit, I could find some equations for this type of motion.