Deepwater Horizon - Transocean Oil Rig Fire

Offshore
5422

[QUOTE=shahhrs;40360]

What I learnt from his testimony is following:

  1. There were four attempts at negative pressure test. All tests were inconclusive and/or failed.
    [/QUOTE]

Correct; although during the last test they had zero pressure and zero flow in the kill line which made them assume that the test had passed.

[QUOTE=]
2. That indicated problems with tests and inability to decipher the test results and possibly confusion.
[/QUOTE]

The confusion was that the DP pressure was not zero. Someone seems to have convinced everyone that this was due some bladder effect. The hearings seem to have confirmed that even with a leaking annular, the RAMS should have been able to withold the higher pressure of the fluid in the riser to be able to give zero DP pressure.

[QUOTE=]
3. The reason for confusion were primariiy a)“non standard” configuration for the test and b)not be able to evaluate the results of the negative tests correctly due to nonstandard nature of test and possibly questionable competency of the relatively new company man on board that day
[/QUOTE]

The reason of the confusion was that the DP pressure was not zero. So they looked at the annulus (thru the kill line). There was no pressure and flow there so they (Transocean and BP) assumed all was OK - see previous comment. John Smith did not talk about the competency of the new Comany Man. The Company Man in question was new to the rig and supposedly competent. Furthermore his boss’ boss was on the rig. Key issue is that someone with good convincing skills was able to convince everyone that the bladder effect caused the confusion and made everyone feel safe. My issue is that the Company Man should have called his boss in town and discussed the discrepancy.

John Smith did say that he also assumed that the LCM spacer had entered the kill line and caused the zero pressure and zero flow. Had a normal spacer been used then they proably would have seen pressure and flow in the kill line. So the set up did not cause the problem; it was most likely the LCM spacer.

[QUOTE=]
4. Unwillingness or inability to decipher the results of tests properly, compounded by the apparent rush to finish the job led to the catastrophe.
[/QUOTE]

The rush to finish the job was not a factor - this was not stated by John Smith. He stated what is normal worldwide: if you assume that a negative inflow test is successful then a sight of relief goes off and folks take less precautions. It is like driving on a highway with no cars; you take less precautions but you can still hit a telephone pole or bridge of there is a machical failure in your car.

[QUOTE=]
5. Attempt to transfer the expensive mud to another ship made it difficult to monitor the well flow as level in the various pits could not be used to determine accurately the return flow. That made it difficult to detect the well flowing
[/QUOTE]

You got this all wrong. John Smith explained at length that you need a closed mud system at all times. Especially in the nondrilling mode (when no new hole is made) and when all is cased off, the level of fluid in the tanks should always be static. When you then circulate you have 2 key sensors to monitor: Pit level and Flow out. Mud loggers and the driller also know the volume that is being pumped into the DP. When there is a kick then usually it is first detected by an increase in pit level. Flow-out meters should also detect an increase but only if closely monitored (by Transocean and the mud loggers).

The problem was that they did not use a closed system since they pumped the spacer overboard and the mud was going to the boat - not because it was expensive but since it was a mud you probably can not dump due to its toxicity (so it is recycled on other wells). There was probably also a volume issue in that they could not keep all the seawater on board in monitored tanks to do it that way.

The most reliable method of detecting a kick was therefore not available and some flow out meters were also bypassed and most likely not closely monitored since everyone assumed the well was safe.

[QUOTE=]
6. While TransOcean should or could have objected these procedures and should have intervened, major responsiblilty for the catastrophe lies with BP and BP culture
[/QUOTE]

John Smith did not talk about this. Look the responsiblity lies with Transocean since they have drillers, toolpushers, etc. who are also trained in well control. They are the ones who are responsible to line up tanks, and close the well ASAP after a kick to limit the kick volume to the minimum. They should have done a better job monitoring flow out (as should have done the mud loggers). It is like with a football team: Transocean is like the players, BP is like the owner of the team. The owner is ultimately accountable, but the players on the field are the ones that make it happen (or not).

5423

ExCompanyMan…You know what you are talking about!! I d work for you any day!!!

5424

Thanks ExCompanyMan for your feedback. I will appreciate if you can address the following:

  1. If the negative tests were not conclusive or failed, does it mean that there was a leak?
  2. If there was a leak, then how would it show up now in the current “sealed” condition?
  3. Is there a leak close to the bottom of the well and thus pressure is slightly low and/or the area near the leak is now holding and not leaking much and therefore close to 7500 psi as they expected?
  4. Or did BP knew about the pressure during the previous “top kill” attempt and did not share those readings with us.
  5. If there is a leak, how would it impact the new “top kill” and/or “bottom kill” ?
  6. In short, if there was a leak at the time of negative tests, then how do you explain the current pressure readings and risks in future attempts?
    Thanks
5425

No disrespect ExCompanyMan, but I’ve been looking at the chart for a long time in an attempt to decipher it.

The strip chart (from here http://www.deepwaterinvestigation.com/go/doc/3043/820883/) is from the MudLoggers.

A couple of points of note:
The details/values on this chart may be different to the TransOcean computerised “FloShow” screens that they may have been using in the driller’s shack that day!
Also, there is no indication as to which pits the MudLoggers were actually monitoring vs what were actually being used for the test and for sending mud to the boat vs what they were looking at/using in the drillers shack.

  1. 13:45 after running dp/tubing to 8367 they did not circulate a bottoms up.
  2. 15:00 to 16:00 displaced choke/kill and booster lines to seawater. Every time they circulated one of those lines, there was a gas level shown. The trend of those gas levels over this one hour period was increasing.
  3. 13:45 to 16:55 they were transferring mud to somewhere else. (Boat)
  4. 17:18 Indications of flow at flowline
  5. 17:25 to 18:14 Indications of flow at flowline. Also gas units are evident and PVT is increasing.

I don’t see evidence of 4x tests. (I haven’t yet found and heard all the testimony from Prof Smith, so I can’t comment on why he states there were 4 of them)

I see the following…(times are approx, from the chart)
16:46 finish pumping LCM spacer and seawater down drillpipe. Stop pump(s).
16:46 to 17:05 get organised and close annular (everything so far says an annular was used).
17:05 to 17:25 Neg test #1? approx 1200psi on DP, and fluid then bled back to trip tank from somewhere. Also PVT shows a decrease (a leaking annular was reported)?
17:25 to 17:47 Neg test #2? DP pressure bled to zero. Monitor on trip tank.
17:47 to 20:00 Neg test #3? Monitoring Trip tank. Very slight increase seen on TT.

17:47 to 18:30 Not clear what they were doing during this time. (possible ano Neg test?)

Bladder Effect.
I’m always willing to learn something new everyday, because I haven’t seen it all by any means.
Annulars weep a bit sometimes, that I know.
Is anyone willing to teach me something new here? What is “Bladder Effect” as you understand it? (I think I’m beginning to sound like one of those lawyers…!)

5426

[QUOTE=Alf;40381] * * * Is anyone willing to teach me something new here? What is “Bladder Effect” as you understand it? (I think I’m beginning to sound like one of those lawyers…!)[/QUOTE]

Glad to Alf. To actually sound like a lawyer, particularly on cross-examination, you should ask the question in this form: “Isn’t it true that a ‘bladder effect’ is…” The way you phrased it is frighteningly open-ended; I’m not sure I would trust most of my own witnesses, let alone an adverse one with so great an opportunity to filibuster, philosophize, go where I may not want them to etc.

:wink: (Hey, you asked…)

5427

alf you are my hero!

5428

[QUOTE=dell;40383]Glad to Alf. To actually sound like a lawyer, particularly on cross-examination, you should ask the question in this form: “Isn’t it true that a ‘bladder effect’ is…” The way you phrased it is frighteningly open-ended; I’m not sure I would trust most of my own witnesses, let alone an adverse one with so great an opportunity to filibuster, philosophize, go where I may not want them to etc.

:wink: (Hey, you asked…)[/QUOTE]

I object your honor!! Counsel is leading the witness…

5429

More on Dudley: http://online.wsj.com/article/SB10001424052748704719104575388920360618064.html

5430

[QUOTE=shahhrs;40380]

  1. If the negative tests were not conclusive or failed, does it mean that there was a leak?
    [/QUOTE]

A non-conclusive test must be repeated until it is conclusive.
If a conclusive test is deemed a failure then there is a leak and you don’t continue with the program.
In this case they seem to have thought that they had a conclusive successful test but according to John Smith’s testimony there was a leak and none of the tests was conclusive.

So instead of continuing with the displacement they should have continued with testing until they had obtained a true conclusive test. Then if it was a failed conclusive test they should have put mud back into the hole and done a leak investigation. With a packer they could have checked whether the leak was near the hanger or further downhole thru the casing shoe (or through a casing joint or the crossover - has happened). A leak could possibly have been repaired with a lock down assembly and/or a cement squeeze (after shooting holes in the casing), or just a cement plug near the shoe, if the shoe leaked. The cement squeeze is not always successful and takes time (and $'s).

[QUOTE=]
2. If there was a leak, then how would it show up now in the current “sealed” condition?
[/QUOTE]

The leak path is now probably huge. I think a lot of folks are still surprised that the wellhead is standing. Blowouts usually cause craters that swallow everything up (including rigs on land!). The hydrostatic head of the water may have helped keep everything in a reasonable state.

So no one knows where the leap path is. However, whether it is near the shoe or near the hanger a lot of erosing will have taken place and the leak will be much bigger than during the negative tests.

Key issue is that the erosion only seems to have taken place inside the well and/or wellhead and that the well is still strong enough to withstand the 7500 odd psi they now have on the cap. Furthermore the eroded leak will be a big enough hole to squeeze cement thru like BP is planning to do thru the top.

[QUOTE=]
3. Is there a leak close to the bottom of the well and thus pressure is slightly low and/or the area near the leak is now holding and not leaking much and therefore close to 7500 psi as they expected?
[/QUOTE]

From the pressure they can not tell whether the leak is close to bottom or near the wellhead. Key issue is that some folks said there should be more pressure than 7500psi on the cap but BP (Kent) indicated that the 7500psi is as per expectation.

[QUOTE=]
4. Or did BP knew about the pressure during the previous “top kill” attempt and did not share those readings with us.
[/QUOTE]

The previous top kill attempt was a joke. They pumped thru a side outlet while the well was flowing hydrocarbons freely; so they had absolutely no control on how much kill mud went downhole and how much went into the sea with the hydrocarbons. Now they can perform a static kill and have full control. The issue is that they will put more pressure on the wellhead during the kill and if the wellhead has been weakened thru erosion then the higher pressure could cause a leak in the wellhead and then we’ll get hydrocarbons to flow freely again into the sea for the next …days. It is risky since the integrity of the wellhead is unknown.

[QUOTE=]
5. If there is a leak, how would it impact the new “top kill” and/or “bottom kill” ?
[/QUOTE]

There is leak! If there was no leak we would not have had the incident!

Looks to me that they want to do a top kill since if it is successful then they don’t have to pump cement into the relief wells and then they can keep the full reservoir in tact for future development.

There is another issue with the top kill; they don’t know where the cement will go. If the leak is near the wellhead then the cement will end up in the annulus; if it is near the shoe the cement will travel thru the casing to the leak. Issue is that the cement will travel quicker downhole in the annulus than thru the inside of casing.

The bottom kill inside the casing (after milling into the casing) seems to be to me pointless since this is only required if the leak was near the shoe (which is unlikely; the leak is probably near the top at the casing hanger) but thanks to you who pointed out that it can be done quite easily these days.

A bottom kill with a relief well very close to our well is the good old fashioned way of killing uncontrollable blowouts wells. In this case cement is pumped for hours into the reservoir thru the relief well (messing up a large part of the reservoir). Cement then also reaches our well and enables BP to bleed off the wellcap pressure to zero (without further buildup). This should possibly done first before the top kill since the top kill carries risks, as described above.

[QUOTE=]
6. In short, if there was a leak at the time of negative tests, then how do you explain the current pressure readings and risks in future attempts?
[/QUOTE]

You can’t compare the current pressure (with the hole or annulus full of hydrocarbons) with the DP during the negative test. During the test most of the hole and annulus was still full of heavy mud. This has since all been displaced. The reservoir also produced for circa 90 days and has been depleted somewhat.

Key issue is the well integrity and how much pressure it will take to start squeezing fluids back into the formation during the top kill; it may be something like 10,000psi. Will the wellhead be able to withstrand that? If it does and if the leak is near the hanger then cement will be pumped from the boat thru the wellhead into the annulus and travel down to the reservoir in the annulus. They did have losses during drilling so it may take less than 10,000 psi to pump fluids down…; usually you need a bit more pressure at the start of a squeeze but then it settles down and will actually decrease as cement and heavy mud enters the hole.

Let me know if anyone else has other opinions or if I missed something.

Alf, thanks for looking at the mud logging data. I just wrote stuff down that John Smith mentioned. Unfortunatly they have not posted his report but did post the diagrams he presented.

5431

[B]To ExCompanyMan and other experts:
[/B] At the risk of appearing to argue (which is not my intention) with the experts like ExCompanyMan about the responsibilities, I am seeking to understand the relationship between the employees of Transocean- the supplier and employees of BP - the customer - and culture aspects. I am using my experience in other industries which I recognize are quite different. Although the dynamics between supplier and customer remain similar in which supplier wants to maintain a good working relationship while the customer may want to maintain control and authority.
It makes sense to me that TransOcean will be responsible for providing equipment and competent personnel to do all the standard jobs on the Rig. They are paid to provide that and assumed to have the know how and training. BP can not be expected to have to worry about those standard tasks. However when BP starts changing the procedures from “standard” to more away from it…towards “non standard” then the responsiblity for documenting, training and developing consensus shifts to BP. From Dr. Smith’s testimony one gets a clear sense of his frustration with Neg tests and he implied that they were far from standard. This forum has struggled with it also. I am having difficulty with black and white stand often taken on this and other places about the responsibilities and culture etc.

For me then the questions are:

  1. Does the responsibilties shift more to BP when to use non standard procedures?
  2. Were Neg Tests non standard on this Rig?
  3. was their a consensus on this issue by the two leaders (TransOcean and BP)?
  4. Is it important to have consensus on critical issues or it is not possible in this industry?
  5. Are the differences on cementing procedures (Halliburton and BP on number of cenralizers), lack of agreement on Neg tests by two leaders etc, exception or a general practice in Industry and BP.
  6. Since cutting corners does not gurantee a failure every time, how does industry protect itself from that culture?
  7. Do employees want to cut corners or is it the culture that teaches that behavior?
  8. How do you compare cultures within different companies? Is BP a norm or an excpetion

One minor point of disagreement with the ExCompanyMan re. the competency of the Company Man that unfortunate day. Here is an excerpt for Wall Street Journal about the Mr.Kaluza, the BP man on the rig that day.

“A little after 5 p.m., to check the well’s integrity and whether gas was seeping in, rig workers did what is called a “negative pressure test.” It was supervised by a BP well-site leader, Robert Kaluza. His experience was largely in land drilling, and he told investigators he was on the rig to “learn about deep water,” according to Coast Guard notes of an interview with him. BP declined to comment on his experience”

In closing, I am hoping to learn the technical and interpersonal aspects of people on the Rigs in general and this rig on particular. No offence is meant through this.

5432

Too bad there’s not the technology to inspect the inside of the well with cameras, and dye, sorta like,when when we perform left heart caths’. to diagnose blockages, in the coronary arteries.

5433

[QUOTE=New Orleans Lady;40393]Too bad there’s not the technology to inspect the inside of the well with cameras, and dye, sorta like,when when we perform left heart caths’. to diagnose blockages, in the caronary arteries.[/QUOTE]

Good point. They should somehow connect a wireline riser to the cap and then run a spinner. With a spinner they can then tell whether flow comes thru the annnulus and then into the wellbore near the wellhead or comes from deeper down. Only problem is that there seem to be 2 pipes in the BOPs, maybe held in place by the shear rams that were unable to cut them. This would restrict the cavity and would prevent a spinner from getting down and take actual measurements.

5434

Dell, being a female, gives me the following advantage. We have intuition. And , I think Dudley is a good turn for BP to make. Its like going from cereal/milk for breakfast, to the Grand Slam!!

5435

[QUOTE=shahhrs;40392]The competency of the Company Man [/QUOTE]

I am not sure about this but Donald Vildrine (who seems to be the one with more offshore experience) was out there as well. Hopefully we’ll hear in August whether he was contacted by Sepulvado and why they did not call town.

Don’t want to get too much into your culture and all your other questions but let me say the following:

  1. The offshore personel should work as a team that clicks like clockwork, where everyone is equal and knows each others’ strengths and weaknesses. Problem is if someone comes to the rig who thinks he/she is superior or is new to the ‘team’, or if there is a fear, like the independent audit seems to indicate existed on the TO Deepwater Horizon rig, and elsewhere in the GOM, as this Forum seems to indicate.
  2. If there is an offshore disagreement between leaders then each one should call their boss in town who should try to resolve it amongst themselves, or with a call in which the onshore and offshore teams participate. I have been involved in many calls like that, sometimes in the middle of the night, to get concensus.
  3. Don’t think they took intented shortcuts in this well. You could argue about the casing vs. liner decision, especially since a paper exists in which the liner is recommended, but John Guide seems to have had semi-reasonable arguments why he was in favor of the casing. His arguments are valid for the long-term but only hold true if a good cement bond is obtained. What is lacking is a paper with pros and cons for running casing and why the casing is the right option. Too often Team Leaders, like John Guide, make decisions off the cuff (like the centralizers) without looking properly at all the pros and cons.

Think you look too much at the corner cutting stuff. The issue is risk analysis and how to do it properly. It is easy to find pros and cons but then to give each probabilities to get a result is difficult since every well is different and since valid probability numbers are hard to come by.

  1. A lot of things go right offshore since a lot of factors have to go wrong for a major incident to happen. For example in this case, if 15 centralizers had been run then the cement bond may have been good and then we would not be writing anything about this well since it would have been suspended successfully. Or if the lock hanger assembly had been run, or if they had discussed the negative tests with town a bit more: any of these event may have broken the incident ‘chain’…
5436

[QUOTE=New Orleans Lady;40393]Too bad there’s not the technology to inspect the inside of the well with cameras, and dye, sorta like,when when we perform left heart caths’. to diagnose blockages, in the coronary arteries.[/QUOTE]
There is such a capability. I suppose several companies can do it, but I know Expro has a Down Hole Video system that works well. But you run it in on a tubing string, so you need clearance for the tubing. It’s good for 10KSI, IIRC.

5437

Yes Jm I saw that website, several weeks ago,and it was fascinating…I would assume, that BP and Allen are aware of it as well.

5438

The 25% partner is heard from (and praised) at some length: http://noir.bloomberg.com/apps/news?pid=20601109&sid=arxeMsafh2hk&pos=10

5439

I was at the hearings this week and a good looking blonde approached and, after a bit of chit chat, asked for my business card… then she told me she was a BP PR rep keeping tabs on journalists. Cleaver indeed.

5440

I like you better without the mustache John <wink>

5441

[QUOTE=New Orleans Lady;40393]Too bad there’s not the technology to inspect the inside of the well with cameras, and dye, sorta like,when when we perform left heart caths’. to diagnose blockages, in the coronary arteries.[/QUOTE]

Actually, similar technology of which you speak is available and in use in the oilfield …but unfortunately, the equipment can not be used in the problem well, because it is not available for entry with such diagnostic tools.
BTW, and off topic, of all the participants on this forum …i would choose you as the person I would most care to sit down and chat with over a cup of coffee or a cold one.