BP's Deepwater Oil Spill - A Slight Change in Plan - and Open Thread

This thread is being closed. Please comment on http://www.theoildrum.com/node/6939.

I have not had a chance to read the BP report on the Deepwater Horizon disaster yet, and due to a couple of other activities (I returned to the USA today) have had only a limited amount of time to catch up on the current plans for abandoning the well, which were reviewed by Admiral Allen at his press conference .

One of the points that he mentioned however, that I thought might be worth discussing a little, is the plan to use the Development Driller II that is connected to the original well at the moment, to complete much of the plugging and abandonment procedures. I will go through that process again in a later post, but one of the things that the Admiral noted today was that the new process would be as follows:

If you remember, the DDII was drilling the second relief well. They came off of that wellhead and took the Blow Out Preventer, and that is the Blow Out Preventer that is now on the well. So they are hooked up to the new Blow Out Preventer over the well, just the same as the original rig would have been, had it still been there.

So they can go down through the well and perforate the casing above the cement and actually cement in the annulus from the top, because they're already there and available to do it. And then shortly thereafter, we will finish the relief well from the bottom with Development Driller III, which was always drilling the first relief well, and they'll do it on the bottom.

Now the point is that to gain access to the top of the cement that was pumped down the production casing, the DD2 is going to have to send tools down to the top of the projected cement and then perforate the casing to inject either mud or cement into that area of the annulus.

Here is where I have the current question. There was some 3,000 ft of drill pipe in the well below the original BOP, that wasn’t there when the BOP was removed. The question becomes, when did it fall into the well? Was it before the cement was injected (in which case the falling DP could have done some damage to the shoe, but all is now hidden, including the DP, in the cement injected) or did the DP fall later during the removal events that took the original BOP from the well.

In that case the DP could have fallen on top of the cement, could have damaged the casing in the process, and would, quite likely be distributed within the production casing so that it will make it difficult for the current operators to get their tool down to the required perforation and injection zone, with the DP in the way.

This could very well explain why they want to get the DP out of the hole using a fishing expedition, but it could be that they won’t find it, since it fell earlier and has been buried in the cement fill. At which point they can then proceed to do the final plug and abandon, following the path that the Admiral outlined. There is, however, no hurry at the moment, and the relief well could now not be completed until the end of the month.

For those wishing to read and comment on the report that BP have just issued on the originating events, that report can be accessed at the BP internal investigation website, and your comments are welcome.

News from #theoildrum IRC chat

The BOP is on the deck on the Q-4000 and was taken apart into its main sections. The transition spool and the flexjoint were taken off.
The LRMP (lower marine riser package) part of the BOP with the two annular preventers was taken off the RAM stack.

A video camera was lowered first into the LMRP and then into the BOP. There is a video of part of the sequence by RockyP.

This picture shows the upper annular preventer in the LMRP. In the middle a piece of drillpipe can be seen. It head has the same form than the pipe they tried to fish out of the BOP while it was still on the seabed. That pipe fell down during the fishing event and got stuck where it is now. We can see quite a bit of erosion on the iris of the annular preventer.

A view into the BOP. What is visible is the completely closed Blind Shear Ram.

On both sides of the bore where the two parts of the shear ram meet the result of heavy abrasive erosion was visible. This is were the oil came through.

Erosion on the other side.

From this document a part list of the Cameron blind shear ram. It seems the packers 4 and 5 did not prevent flow and the area around them was eroded over time.

The lower part of the BSR was then opened. This revealed a cut drillpipe and more erosion on the side of the shear rams.

The pipe and dirt below the BSR were removed with the camera off.

BSR without pipe.

Now below the BSR the closed Casing Shear Ram can be seen.

The CSR was opened and revealed another piece of (dirt filled) drillpipe standing vertical in the hole. This is likely held by the Variable Bore Ram below.

The camera then went down next to the standing pipe (dark in the upper left) and showed what we believe is another short piece of pipe above the upper VBR.

That is the status of the BOP video examination as of now. More videos of the above may follow later on.

So from a quick look at that, it's seems as though the blind shear rams did close, but the packers failed, allowing oil to flow. Is this an even more potentiality damaging finding that the earlier failure modes? I mean if the rams were closed correctly, but either by design or poor servicing, it failed, isn't that a pretty big deal? Could it mean other BOP's are in this 'ready to fail' state, and making sure to check the batteries won't be enough.
Or am I jumping to crazy conclusions, or just missing something else (which is more than possible).

The BSR was only closed a few days after the blowout by an ROV intervention that simulated an emergency riser disconnect. During those days the flow may already have eroded the packers (rubber) of the then probably partly closed BSR. When the BSR then totally closed there were channels left for the oil to pass. This then caused the erosion and a steadily growing flow path.

Ah, I think I understand.
So they tried to close the BSR, but failed. Then later tried again (a few days later), and succeeded. But in the intervening few days the oil flow through the constricted rams had eroded the packers, meaning when they did fully close it, it leaked.
Does this rather ironically mean the if they hadn't tried to close it (and failed) that the later attempt to close it would of actually shut the well in, only 3 days after it popped?

"Does this rather ironically mean the if they hadn't tried to close it (and failed) that the later attempt to close it would of actually shut the well in, only 3 days after it popped?"

That is possible but unknown and will likely stay so.

Something that rather bothered me - chasing through Cameron's web site and the BOP data, the API spec for qualification testing a BOP for high temperature work (250 F) is for only one hour. Cameron are rather proud that they test for 8 hours. This is a far cry from the real life stress endured. Clearly the elements that are of most worry are the elastometric seals. Which it would appear are the components that actually eventually failed.

I can't really imagine that a simple one, or eight, hour lifetime is intended here. But the test regime seems to be way short of a real life scenario. In particular it doesn't seem to allow for degradation effects over time. A few hours will prove that the mechanical design is sound, and that everything seats down nicely and is solid. But it doesn't prove that extremely minor leaks or flaws won't creep and expand over days or weeks.

I tend to agree that the most likely scenario with this BOP is erosion when partially closed. But the test regime mandated does seem manifestly inadequate, especially the API one.

Francis, isn't that the intent of a BOP to be a temporary barrier to shut in a well until it can be controlled. It was never meant to shut in the well indefinitely. I may be totally wrong about this, but it was my understanding.

The erosion leaves me with the feeling that the initial flow rate was quite low. That would support the initial reports of the flow. As the erosion got going the flow rate ramped up to the sort of estimates that we heard at the end. How long that took is another matter, days or weeks? I suspect that the cut would have been worse early on with more sand coming out of the formation at the beginning then reducing as the flow cleaned it out. Less cut as the nozzle got larger, don't know.


I seem to recall one of the hands - I think it was the technician on 60 minutes - indicated that he had seen "rubber" in the returns prior to the incident -- could this be related?

As I recall, the "rubber" was thought to be from the annular that was damaged when they accidentally pulled the pipe through it. Which in turn may have been a factor in the decision that the test was OK.

Yes. This was from the annular that was closed on the drill pipe when one of the hands bumped the control stick dropping the string about 15', according to Mike Williams (chief electronics technician). One of the mud men brought chunks to the drill shack and showed them to the supervisor(?) who replied "no big deal".

I have the PDF, but don't know how to link to this blog!


Many thanks for your detailed information, it's appreciated.

For reference, here's a diagram of the BOP/LMRP Stack to keep all the parts relationships straight:


Having read the BP report and having followed the progress of the well kill, I would like to point out some concerns regarding the "fish" left in the well. There is a stinger of 3-1/2" tubing below the 5-1/2" drill pipe that is in the hole. The tool joint of the 5-1/2" DP is too large to go inside of the 7" casing (the bottom of the 9-7/8" X 7" producion casing). If the DP and Tubing is shouldered up on the 9-7/8" X 7" cross-over only a thru tubing perforating gun can be run in order to perforate the casing below the DP/tubing fish. It will be interesting to see if they will try to overshot the DP and pull the fish prior to any perforating.
One comment in the BP report on page 62 under "Analysis - Displacement Efficiency" states "The investigation team could not determine whether mixing or poor displacement of the slurry occurred or contributed to the accident". With the different size tubulars, joints, tanks, pumps and fluids I would think accurate displacewment was very difficult. However, the report mentions only a less than 3 barrel difference in fluid volumnes was noted when pressure was released and flow-back was measured after the cement job. The float collar had flapper valves in it and those are know for poor performance.
Upon reviewing the cement blend (Table 1. on page 57) it is no wonder the cement job failed. Trying to mix a foaming cement and in the mix you include a defoamer makes no since at all.

Now that rov activity has diminished at the macondo well, one of the early rov vessels passed thru the site yesterday evening, ocean intervention. We irc-ers watched her rovs for months.

This is a video i made of one of her rovs, ocean intervention 2, on her last day on the deepwater horizon site, august 25. the rov dives and surfaces through stunning schools of fish. with music by paul winter, "Sea Joy," from the album "Callings." http://www.youtube.com/watch?v=F3BMaEZTTyM

Watching that video, I couldn't help but empathize with the ROV, as if it had thoughts and feelings. Apparently, I've seen too many Disney flix, or maybe it was all that sci-fi I read as a kid.

The music didn't help either. Damn you, Evergreen.

What a lovely tribute! Thank you. Beautiful.

The perfect way to end the evening ... thanks evergreen.

Evergreen you are a wonder and a talent!. Please make a Documentary.

I hope the investigators do not get too BOP centric in the investigation.

TFHG - Typically rigs have a smoke room. Normally it's outboard to the quarters and has secured venting. Most hands have switched to chew. There are a number of "hot work areas" on a rig where a spark could originate at any time. When something potntially combustable is going on they'll shut down the hot areas.

Is this 'shutdown' system possibly tied to the deactivated safety systems?

jinn's response on closed thread:

Your suppositions are not supported by any evidence. Who is it that you think was inclined to call a stop to the displacement? There is no evidence that anybody on duty that night had any misgivings about moving forward.

Where is there any evidence that a mud logger or anyone else on duty had a concern about continuing with displacement?

Go look up "hypothetical" and get back to me.

OK your hypothetical is not supported by any evidence. There is not a shred of evidence that indicates anybody on duty that night thought there was any imminent danger.

The problem is that the people on duty thought the cement job had been tested. They thought because the cement had been tested the well was safe.

The fact is the cement had never been tested. The first real test of the cement came about 40-30 minutes before the rig exploded.

I suggest that you read the BP report. Especially the section titled "Pressure Integrity Testing"

The BP report very clearly states that the positive pressure test did not test the cement. It only tested the rubber plug at the top of the float collar, the casing, and the casing top seal. It did not test the cement.

It also states that the negative pressure test was supposed to simulate the underbalanced condition that displacing mud to seawater would produce. But looking at the pressure readings during the what has been called negative tests it is obvious that the procedure they performed failed to simulate the underbalanced condition that the well was about to be subjected to.

It appears that nobody on duty that evening understood that at 2100 hours that evening the cement was being tested for the first time. We now know the cement failed it first real test.

Go look up "hypothetical" again ... and read it this time.

Hypothetical is imaginary scenario presented to illustrate a point. It needs no evidence. It's imaginary.

And yes I agree they didn't actually achieve underbalance during neg test. On the other hand they did ...and they saw abnormal pressure on drillpipe. So it's a case of semantics.

I won't argue semantics with you. If you see it as neg test not being done, fine. I see it as neg test being done but not achieving hoped-for results.

You can call it whatever you want. The fact is the rig did not test the cement like they were supposed to. The first test of the cement came about 1/2 hour before the explosion. If they had been lucky the cement would have passed that first real test. But they weren't lucky.

The problem with Hypothetical thinking clearly explained in the picture below:

Apologies to Rockman during his ice cream hiatus ;)

It also states that the negative pressure test was supposed to simulate the underbalanced condition that displacing mud to seawater would produce. But looking at the pressure readings during the what has been called negative tests it is obvious that the procedure they performed failed to simulate the underbalanced condition that the well was about to be subjected to.

It appears that nobody on duty that evening understood that at 2100 hours that evening the cement was being tested for the first time. We now know the cement failed it first real test.

Jinn's theory here is far from established. It is a theory no one else seems to adopt and BP's report contradicts. As quoted in my post last night, BP states that the first negative pressure test proved that the cement failed. And BP interprets the second pressure test as also indicating communication because of the 1400 psi on the DP. The 0 psi on the kill line could be attributed to failure to open a valve properly or the heavy spacer clogging the line.

BP rejects jinn's claim that the well was never underbalanced during the test as well, as demonstrated by the quotes from the report.

Jinn claims that the well was still very over-balanced during the negative pressure tests even though they displaced seawater to 3000' (way deeper than normal procedures for the test) below mudline and isolated the mud in the riser. When asked to defend this, the request was dodged.

jinn, if you're going to keep pushing this theory, maybe you could explain it better, including how the well was overbalanced after they displaced over 8000 feet of mud before the test, and there was no pressure from the riser. And please spare the insults. Thanks.

I did not say they never acheived an underbalanced state. During the first test the pressure readings dropped below underbalanced for just a few minutes at the beginning.

What they never did was achieve the full 2350 PSI underbalance that was called for and they certainly did not hold it underbalanced for 30 minutes as required.

Had they done the test they were suppose to do it would not have required BP engineers 4 months of intense computer modeling to ferret out the signs that the cement lacked integrity. If they had done the test to plan the conclusions and results would have been obvious to anybody on April 20.

Had they done the test they were suppose to do it would not have required BP engineers 4 months of intense computer modeling to ferret out the signs that the cement lacked integrity.

jinn, your silly statements like this make it difficult to take you seriously. The conclusion was based on the returns not 4 months of computer modeling. And your story keeps changing.

BP engineers say the first test was sufficient to conclude based on the returns (as the regs base it too), and it should have been concluded, that the cement was bad. You say they are wrong. Let's be clear about that.

Read the report. There was conflicting testimony on the amount that flowed when they bled the DP pressure. Testimony from witnesses had it from 3 barrels to 15 barrels.

There are no regs on how much fluid should be returned on a bleed down for a negative pressure test. Dr John Smith testified it should have been about 5 barrels. BP report said their computer model predicted it should be 3.5 barrels. None of that info was available to the rig. The amount that is supposed to come out has to do with the compliance of the entire casing system - they had no way of calculating that on the rig.

Also the amount that flowed out during bleed down wouldn't matter if they had done a proper test.

Thanks for clarifying jinn. I understand your position better now and where you depart with BP. Thanks.

if they had done a proper test.

I think the key here is BP thought they had done a proper test. BP followed their procedure. Opened and closed the right valves, bled the system down, and in the end saw no flow on the kill line.

There was just that DP pressure that should have also been at zero.

BP rationalized (with some encouragement by TO) the DP pressure and accepted the test as successful, not realizing that the kill line was plugged (and couldn't flow) and the well had actually pressured up on the DP (IBOP), annular preventer, and plugged kill line.

At least 3 BP CoMen accepted the results.

Yes 3 BP men accepted the results.

But no one from BP opened or closed any valves.

How do you know the kill line was plugged?
Looks to me like they closed the kill line valve for the second test just like they did for the first test.

17:27-17:52 Drill pipe pressure reduced from 1205 psi to 0 psi by bleeding off 15 bbls to 23 bbls of fluid to the cement unit.

17:52-18:00 Kill line opened to the cement unit. Cementer bled off 3 bbls to 15 bbls of seawater. A witness reported continuous flow from the kill line that spurted and was still flowing when instructed to shut in the line.

18:00-18:35 Drill pipe pressure gradually increased to 1400 psi over 35 minutes.

18:35-19:55 Seawater pumped into the kill line to confirm it was full. Opened kill line and bled 0.2 bbl to the mini trip tank; flow stopped. Kill line opened and monitored for 30 minutes with no flow.

Since they had bled off the DP to zero at 17:52, it should have stayed at zero. 18:35 bled kill to zero (~9 gallons) and left open 30-minutes. No kill flow but pressure held on DP.

"After they displaced over 8000 feet of mud before the test, and there was no pressure from the riser."


It may help to plug in some mud weights. These are my estimates. I've not seen any official numbers.

At the time of the negative test the average mud weight in the well with respect to the riser (drill string annulus), was 13.12 ppg. With respect to the inside of the drill pipe, the average mud weight was 11.51 ppg. The average mud weight with respect to the kill line should have also been 11.51 ppg.

Many assumptions including:

-the production casing annulus below the wellhead was isolated by the casing hanger seal.
-the heavy spacer was spotted just above the BOP.
-the closed annular isolated the drill pipe fluid from the drill pipe annulus in the riser.

The reservoir pressure was estimated at 12.6 ppg.

The negative test was set up to test the well at a roughly 1.1 ppg underbalanced condition which mimicked the condition expected when the riser was retrieved.

I may be the only one but I'm not convinced the negative test failed to test the cement. The assumption is the well blew out, therefore, the negative results indicated communication with the reservoir. I think it's possible there was not communication at the time of the negative test but the cement failed catastrophically after the negative test was complete.

If there was communication with the reservoir at the time of the negative test(s), why would some fluid be recovered initially at the surface but the flow stopped during the monitoring period. I would expect if there was communication the flow would start and progressively increase as the hydrocarbons entering the casing decreased the average mud weight.


Thanks NU! Much appreciated. Your catastrophic failure theory has a lot of appeal. In your judgment, then, the returns they did get could be explained on some other adequate basis other than barrier failure. And the 1700 psi on the DP would just be hydrostatic pressure not pressure from flow i guess you are saying.

Thanks for making things much clearer and for digging out the mud weights.

Returns stopped because the return path (kill line) was plugged. Communication was evident by the DP pressure rising until the well pressure equalized.

Your calculations is close to correct. My understanding is the well was 1.6 ppg over balance to start and the displacement was going to cut the weight by 2.5 ppg so the underbalance would end up at around 0.9 ppg. For the sake of the argument let's take your 1.0 ppg as the amount the well is supposed to be underbalanced during the test.

In the first test they had 1260 PSI. That is equivalent to adding 1.6 ppg to the mud weight. In the second test they had 1400. That adds even more to the mud weight. In both cases the added pressure means well was overbalanced. In other words, during most of the test there was more pressure on the cement in the shoe track from above than there was from the reservoir below.
The fact that no flow was observed during those periods of overbalance is not surprising.

The correct way to do the test was described in testimony by Ron Sapalvado. Displace from 8300' to well head as they did and then open the kill line (filled with seawater). Allow the drill pipe pressure to bleed to zero and then leave the kill line open. If this is done correctly the DP pressure always will stay at zero (or very close to it) and the well stays in the underbalanced state for the duration of the test. If the cement fails you see it by the flow on the kill line. If BP is right about the condition of the cement they would have seen a 9 bpm flow from the kill line. There wouldn't have been any arguing about what was happening.

To do the test correctly you must maintain the drill pipe pressure close to zero. If you close valves so that the drill pipe pressure can build up then you are not testing the well in an underbalanced state.

So everybody wants a negative pressure test but nobody has formal requirements or pass/fail criteria (see Section 2.4, pg. 85-86 of BP report).

Fig. 3 on pg 19 of the BP report shows a well depth of 18304 ft and a bottom pressure equal to 13.9 ppg. This indicates a reservoir pressure of 13230 psi (18304 * 13.9 * .052).

After cement placement, the well contained 18304 ft of 14.17 ppg mud, producing a bottom pressure of 13487 psi (18304 * 14.17 * .052). In this state, the well is over pressure by 257 psi.

During the negative pressure test the top 8367 ft of the well contained seawater (8.6 ppg). If opened to atmospheric pressure as designed, this would lowered the bottom pressure by 2423 psi ((14.17-8.6)*8367*.052) to 11064 psi. In this state the well would be 2166 psi under pressure. (Note that this does not account for some added pressure by the 16ppg spacer and a little less by 30bbl fresh water in the column.)

This was done with the following result:

16:54 Upon shutting down pumps, drill pipe pressure was at 2325 psi. Pressure in the kill line remained at 1200 psi.

An annular preventer was closed for the negative-pressure test.

16:54-16:56 Drill pipe pressure bled from 2325 psi down to 1220 psi in order to equalize with the 1200 psi on the kill line.

16:57-16:59 Kill line opened and pressure decreased to 645 psi; drill pipe pressure increased to 1350 psi.

Attempt made to bleed system down to 0 psi. Drill pipe pressure decreased to 273 psi. Kill line pressure decreased to 0 psi. Kill line shut in.

16:59-17:08 Drill pipe pressure increased from 273 psi to 1250 psi in 6 minutes.

(This abnormal result was presumed to be due to mud leaking down the riser through the possibly damaged annular preventer, so the following were done to mitigate this:)

Annular preventer closing pressure was increased from 1500 psi to 1900 psi to create a seal.

The riser was topped up with approximately 50 bbls of mud from the trip tank to replace the volume bled off through the drill pipe.

17:08-17:27 Drill pipe pressure decreased from 1250 psi to 1205 psi.

17:27-17:52 Drill pipe pressure reduced from 1205 psi to 0 psi by bleeding off 15 bbls to 23 bbls of fluid to the cement unit.

17:52-18:00 Kill line opened to the cement unit. Cementer bled off 3 bbls to 15 bbls of seawater. A witness reported continuous flow from the kill line that spurted and was still flowing when instructed to shut in the line.

18:00-18:35 Drill pipe pressure gradually increased to 1400 psi over 35 minutes.

18:35-19:55 Seawater pumped into the kill line to confirm it was full. Opened kill line and bled 0.2 bbl to the mini trip tank; flow stopped. Kill line opened and monitored for 30 minutes with no flow.

19:55 The negative-pressure test was concluded and considered a good test.

The design of the negative test is to have the DP closed off and the kill line open to atmosphere to produce the ~2000 psi under pressure condition and observe any flow. The flow path would be through the open kill line. In this case, I think the kill line was plugged with something (faulty valve? hydrate? heavy spacer?) so it was not open to atmosphere. What really happened is that the well pressured up to 1400 psi as measured on the DP, which is about 600 psi under pressure. It is not clear if this continued to rise after 18:35.

Having convinced themselves that the negative test was OK, they proceeded to displace the riser.

When this procedure started, the riser down to the BOP contained 5022 ft of mud and below this was 3345 ft of seawater and the remaining mud below that. This condition resulted in a bottom pressure 959 psi ((14.17-8.6)*3345*.052) below the cementing pressure, or 712 psi under pressure. (Note that this does not account for some added pressure by the 16ppg spacer and a little less by 30bbl fresh water in the column.)

As the displacement continued to unload mud the riser pressure would drop. By the calculations in BP's report, the well went under pressure at 20:52 and the first noticable data signs of flow were at 20:58. By 21:01 the influx was sufficient to start raising the pumping pressure on the DP at constant flow rate. At 21:08 the pumps were stopped for the sheen test and the DP pressure continues to rise. (see pg. 92-93 of the BP report.)

It appears that the negative-pressure test had a brief period of under pressure and the well flowed enough to equalize against the DP pressure with the kill line plugged. So while BP intended to conduct and thought they had conducted a negative-pressure test, Jinn may be right that the only real sustained negative-pressure condition did not occur until after 20:52 as the riser was displaced.

Thanks for the detailed analysis.

17:52-18:00 Kill line opened to the cement unit. Cementer bled off 3 bbls to 15 bbls of seawater. A witness reported continuous flow from the kill line that spurted and was still flowing when instructed to shut in the line.

18:00-18:35 Drill pipe pressure gradually increased to 1400 psi over 35 minutes.

How could this be construed as a successful test?
Were they still thinking that the annular preventer seal was leaking a little?

Even more clarity. Many thanks for taking the time to lay it all out for those of us who need spoon feeding.

Quick question. After the cementer was instructed to shut the kill line, while it was still flowing and spurted, as noted below, and the dp increased to 1400psi over the next 35 mins while they were discussing what to do, would that DP pressure increase not also be indicative of flow into the well since it was a gradual increase and the riser was isolated at that point?

17:52-18:00 Kill line opened to the cement unit. Cementer bled off 3 bbls to 15 bbls of seawater. A witness reported continuous flow from the kill line that spurted and was still flowing when instructed to shut in the line.

18:00-18:35 Drill pipe pressure gradually increased to 1400 psi over 35 minutes.

After the cementer was instructed to shut the kill line, while it was still flowing and spurted, as noted below, and the dp increased to 1400psi over the next 35 mins while they were discussing what to do, would that DP pressure increase not also be indicative of flow into the well since it was a gradual increase and the riser was isolated at that point?

Yes. But they opened the kill again from 18:35-19:55 and saw no flow. So they thought it was OK, not realizing that the kill line was plugged.

They just had to explain the DP pressure. If they had opened the DP to bleed down again, they would have seen flow on the DP.

They just had to explain the DP pressure.

Indeed. How could they proceed until that was explained?

And is there any telemetry to substantiate that they actually tried to open the kill line valve?

They found an explanation. It was utubing up the DP. BP's recent efforts to verify accuracy of that theory came up empty. No support existed for it.

But nearly everyone bought into it eventually. Not the TP who stormed off the drill floor in a huff, though. He seemed to have grasped what appears to have been happening. Vidrine was not comfortable with it either, but was persuaded. Halfe had input. He appears to have been fine with it based on Vidrine's comments to investigators.

What are the chances that Harrell would have talked on the phone to Halfe about procedures if there was disagreement? Such as a situation where maybe faluza was on duty and being the new guy and not fully up to speed he maybe had Harrell talk directly to Halfe on something where there was a disagreement?

The U-Tube is from the top of the DP, down to the bottom of the DP, back up inside the casing to the BOP, and through the kill line back up to the surface.

When the spacer and seawater are initially pumped, there could be one side heavier than the other due to containing more of the heavy spacer. In this case, the heavier side will show less pressure.

Open both ends and bleed to zero pressure. Fill any gap if one side goes down. At this point both sides are at zero pressure but may have different elevations due to fluid weight imbalance.

Any changes in pressure or flow at this point indicate well flow. What they did was close the DP path after bleeding to zero. This meant the only path was through the kill line. This is fine. Again, any change in pressure or flow indicate well flow. They saw no flow on the kill line but pressure on the DP, which they incorrectly justified.

I can imagine after a Harrell / Hafle discussion Hafle says wait for Vidrine to look at it and then we'll decide.

Thanks esarlls3, you make it really clear. I was indeed wrong, they did not call it utubing, they called it annular compression or bladder effect:

According to witness accounts, the toolpusher proposed that the pressure on the drill pipe was caused by a phenomenon referred to as ‘annular compression’ or ‘bladder effect.’The toolpusher and driller stated that they had previously observed this phenomenon. After discussing this concept, the rig crew and the well site leaders accepted the explanation. The investigation team could find no evidence that this pressure effect exists.

...annular compression or bladder effect...

I've been thinking that this must refer to the elasticity (compliance) of the casings. But what do I know about oilrig jargon? Don't answer that.

When the spacer and seawater are initially pumped, there could be one side heavier than the other due to containing more of the heavy spacer

Thanks, esarlls3. I have seen the term U-tube used here, but it made no sense until you wrote this. Thanks for being patient.

I'm confused about "shutting in the kill line". Are you referring to closing the valve at the BOP, or at the surface?

jinn wrote in the last thread :

"Had they actually tested the well in an underbalanced state the results would have been unmistakable and not been misinterpreted. Had they tested the well underbalanced the well would have started to flow and the problem would have been addressed.
It has never been explained what TO did exactly. We don't know what lines they had connected or what valves were opened or which valves were closed. But there is one thing that is crystal clear from looking at the data - The negative test was never run. The well was never held in an underbalanced state as it was supposed to be."

And Rockman wrote :

"But what if TO misrepresented how the test was done? What if BP suspected the test wasn't valid but accepted it to save time/money?"
I don´t understand much of the neg. test, but by searching for informations I found an internal e-mail about the NEGATIVE TEST PROCEDURE :


May be it´s able to put some light to some questions.

In the now closed thread hammegk wrote...

I've contemplated it, and conclude the best use for a lawyer would be LCM.

Dammit hammegk!!

The lawyers representing my now deceased keyboard will be contacting you in regards to your concurrent negligence and causation.

I really believe the sand to road topping project Baldwin County is doing is the best way to handle this stuff. Replace it. Build roads with what you get. I realize this is a much bigger problem in scale, but I have heard of only two methods for dealing with this. Removal and 'washing'. Personally, I prefer removal and replacement, but I know that would be impractical. What is being done with the sand wash outflow? Is there a link on this floating around?

Removing sand from Horn Island leaves essentially no island without replacement and restoration. Don't see how that could be practical.

No washing is the only choice here, IMHO. This is going to take setting up on the island. We really screwed this one. Greenpeace, we know the problem. How about some solutions? I emailed you 20 times when I was working the problem. You just sent a form letter asking for money. Screw you and the whale you rode in on.

BTW: YOU ANSWERED. For better or worse. THANK YOU TOD. Greenpeace doesn't hold a candle to you. As soon as I get back on my feet I will donate.

TFHG, I share your sentiment on Greenpeace.

I am a bit puzzled by the need to clean this up though. Tar balls are not exactly hazardous. We do build roads out of them, and they have been washing ashore along the gulf coast as well as the california coast for thousands of years.

Other than being extremely ugly, why would we clean up an unpopulated beach where there seems to be a higher chance of damaging the ecosystem trying to clean it up.

To 'assist' the natural process. From what I saw, a cleaning tractor would be the way to go. Do it off season for the animals. Just get the easy to get to chunks. All I am talking about is getting the easiest 75% and I would be happy.

Horn Island is a National Seashore and National Wildlife Refuge. It is managed as wilderness. It has been catching a lot of tar for two months or so. Manual cleanup crews have worked continuously on the island, but are way undermanned. They just recently got permission to use beach-cleaning machines there, contrary to the wilderness regulations.

It's puzzling why this particular area has so much tar and what may be organic pollution, since it didn't seem to be hit very hard by the slick.

I've been to Horn Island. Don't worry about the tarballs, the infinite swarms of giant killer mutant mosquitoes will probably just eat it. Or use it for weapons in preparation for an invasion of the mainland.

I shot a few dozen of those up in the Wisconsin Northwoods. 12 gauge #9 seems to work the best. The only other time I encountered hordes of giant ones was in the Bridger Wilderness. As soon as it rained, I got the hell out of there.

I shot a few dozen of those up in the Wisconsin Northwoods.

Have you been to Minocqua, home of the world-renown Min-aquabats (and also snowshoe baseball, played on sawdust for the summer tourists? There were two movie theaters in the Greater Minocqua-Woodruff Metropolitan Area, the Aqua and the Woods. During the off season the Aqua was closed, and the marquee read "CLOSED FOR THE SEASON USE THE WOODS", which the high school kids surely did.

My father hired a guy who worked for Nekoosa-Edwards to watch our cabin when we were gone. He began and ended every sentence with one of George Carlin's seven swear words, and he always carried a sidearm on his belt (to shoot porcupines).

As my mother used to say: "TICK CHECK!"

Lived in the area for about 6 years selling real estate. Some days I saw more bears than cars while driving to work. Totaled 3 Jeeps, all deer hits. The worst mosquitozillas are up in Presque Isle. I posted this before, but here you go. Welcome to the Wise Guys in Woodruff.

In these marshes we have big ones, but when I visited my brother in Alaska and went fishing, they big yes but they were THICK as fish schools for many square kilometers. I had to fish in netting. No, that kicks any mosquito butt I have had to deal with.

Bridger Wilderness. They're not so big, which is actually worse. Big, mind you, but there are enough smaller ones to get through netting. Impossible to take in a breath without enough mosquitoes to choke you in it. It was like being in a sci-fi horror flick except it was real. My ears rang for over a year from the noise they made. Do not go there within two months of temps amenable to mosquito hatches. Eventually I found my way to a stinky outhouse and the people inside didn't want to risk opening the door to let me in.

OK, this is really off topic, but could possibly be justified as relating to upside down U-tubing (a siphon). We began one Wind River trip at the Green River Lakes trailhead, which is way the heck out in the middle of nowhere, Wyoming. While we were getting our things together to set out, a truck arrived to pump out the outhouse. He parked his rig and dragged his hose uphill to the outhouse, then came back down to the truck and started the pump. He noticed a small leak in the hose connection at the truck, so he stopped the pump and started to fix it, but the hose came off. It wasn't a pretty sight. He kept trying to reconnect the hose, but there was a pretty good pressure "head" on that siphon.

We thought about helping him, but there are limits....

Firehose. Now!

25c mugs till someone pees!!??. Now that could cause some kinda social "pressure".
Here's a picture from a place 1 hour east of my house in Ory-gun:

And, FYI, unlike Wisconsin, which only occasionally had a doe season, it's doe season every year in Oregon. When we go into the woods in the fall my dogs wear orange vests.
And speaking of the Bridger Wilderness, I was on a backpacking trip in June in the Wind River Range where we amused ourselves by seeing who could kill the most skeeters with a single swat of the hand. The record was over a dozen.

Sub-thread seems to have run its course. However, if you're traveling to the truly gorgeous and unique Wisconsin Northwoods, just in case, bring an open choke and a barrel no longer than 20" for skeeters.

We just worry about the little ones. They carry a nasty payload.


Over a dozen. IS THAT ALL?

I was on an experimental seismic crew one summer 300 miles north of the arctic circle, camped along maybe creek. A remote camp supporting maybe 75 people, 3 helicopters, one a Huey. Umiat was the closest fixed-wing airstrip, maybe 150 miles sw, i blieve, with Prudhoe to the nw.

The sun was up 24 hours a day. Camping along the creek on a big gravel bar was great because it provided some relief from the mosquitoes. Out on the tundra, it was another story altogether. A one hand swat could yield hundreds. We all had to have netting during the swarms. It was unbearable otherwise. One enterprising idiot used raid straight out of the can for repellent. Everyone else used muskol, like it was water. That stuff melts plastic.

Edit: the mile estimates are probably way off, it was a long time ago.

NOLA.com article on the cleanup effort

Oil cleanup continues on Mississippi barrier islands.

For the "mysterious night works"-CT´s (from the upper link):

"The machines are most productive at night, when temperatures drop and the debris is less gooey, Brown said.

The Beach Techs flip sand into a screen where tarballs and debris are trapped and sand filters back onto the beach. They've also been operating in Florida for several weeks."

Fa. Kässbohrer (Germany) was tested to be the best.
But the machines are only good for collecting tar balls.
What will they do against the deeper layers ?

From NYT article "Documents Fill In Gaps in Narrative on Oil Rig Blast" :

Worried about an unexplained high-pressure reading in the drill pipe, Mr. Vidrine insisted on a second pressure [negative?} test to make sure there was not an explosive bubble of gas building up in the well, even though senior members of the drilling team for Transocean, the Swiss company that owns and operated the rig, thought another test was unnecessary, according to the testimony of managers and workers on the rig.

In the end, however, Mr. Vidrine made the call that it was safe to proceed, according to the notes and the testimony of several witnesses. He accepted the explanation provided by members of Transocean’s drill team that the high pressure reading in the drill pipe, of about 1,400 pounds per square inch, was no cause for alarm. [emphasis mine]

If this is true it hammers a rather large nail in TO's coffin ...IMO.

In addition, notes from an interview he gave to BP officials investigating the blowout, obtained by The New York Times, show Mr. Vidrine raised concerns about the possibility of a surge of gas, or a kick, with a superior in Houston before going ahead and replacing the mud in the riser pipe with seawater.

Mr. Vidrine said the superior, Mark Hafle, an engineer, responded, “If there had been a kick in the well, we would have seen it.”

... and in Mark Hafle's coffin ...IMO.

Ten minutes later, Mr. Anderson, the night-shift toolpusher, called Mr. Vidrine in a panic and said the drilling mud had begun to spew out of the well, according to the notes. This was around 9:30 p.m., according to witnesses.

This actually occurred around 21:45. At 21:30 pumps were shut off to discuss abnormal returns.

I believe this article sheds new light on what happened on the drill floor, and moves me to reconsider my earlier feeling that Vidrine was acting in a negligent manner. From this article it appears he was concerned but TO crew "talked him out of it".

If this information is true it roundly refutes jinn's assertion that no one thought there might be a problem (if I understand jinn's assertion correctly).

Yes, but.

Donald Vidrine, BP's "company man," overruled the rig's chief mechanic and driller, pushing to speed up the process by removing the drilling mud faster to save BP money on the day of the tragic explosion, according to testimony from oil rig owner Transocean's Doug Brown on Wednesday.

from http://www.donaldvidrine.com/ and

In the hours before the explosion, Vidrine argued with Transocean's installation manager, Jimmy Wayne Harrell, according to testimony from rig mechanic, Douglas Brown.
That's unusual, said Phil Tobey, an area manager for Diamond Offshore Drilling Inc. in Houston who spent 35 of his 54 years working on offshore rigs and worked his way up to installation manager.
"It astounded me that they got into an argument," he said. "If any of my guys have any issues at all, it's actually settled pretty quickly. I say, 'Please go call your boss and we're going to call ours, and we'll settle this in town.'"


BP managers in Houston approved the decision to replace drilling fluid in the well with seawater, Transocean Subsea Engineer Christopher Pleasant told Coast Guard investigators.

from http://blog.al.com/live/2010/07/explosive_allegations_oil_spill.html

So TO may have some cover. Hafle, on the other hand, could be in some real trouble.

If this is true it hammers a rather large nail in TO's coffin ...IMO.

The BP report notes that the investigators could find no proof at all to support the claim that the 1400psi could have resulted from utubing. It was just someone's wrong understanding.

I disagree that this hammers a nail in TO's coffin. It nails BP. Note that the report is always careful to include TO in considerations concerning the pressure tests, even going so far as to blame TO exclusively for not properly interpreting the first negative pressure test.

But the test is BP's call. If BP relies on bs logic from TO, that's BP's negligence, not TO's, because BP has the duty to get it right, not TO. This is important because without one decision maker fully responsible for the decision, you get the chaos we ended up with here. And that is a result of BP negligence in failing to have effective procedures in place on something so critical, especially when they are taking risky short cuts.

SYN - Exactly. This seems to be where the resolution will gets bogged down on the test issue: If Party A supplies incorrect (plausable/incorrect/intensionally misleading) info to Party B and Party B makes a bad decision: where does the primary fault lay: The supplier of incorrect info or the believer of info they should have better varified? I'll accept that this call is basicly legal determination with respect to the investigation and not what I would call "reality" for lack of a better term. Reality being what I would use to fix blame and not what the legal system would conclude.

From a pure legal view how do you see this going: primary blame for the mis-informer or the acceptor of bad poop?

The outcome probably depends on jury selection and trial presentation. Especially in a civil matter where the standard is "preponderance of evidence" rather than "beyond the shadow of a doubt" (criminal standard).

Assuming that BP has the obligation to make the call on the test, which makes sense since they are responsible for well conditions and have superior knowledge and do all the planning/design with the cementer, then the answer to your question Rockman is clear as a bell, both legally and from a testing accuracy standpoint.

BP has a duty to ensure that the test is accurate. That means if it is going to listen to TO on the matter, it has an independent duty to ensure that TO info is correct. Otherwise it is abdicating it's duty to TO.

As it turns out, the TO info was completely groundless. That speaks for itself in terms of the dangers involved in abdicating the duty of ensuring an accurate test and trusting the info on faith. As a matter of policy and procedure, that should never be permitted to happen. The law makes it clear when that does happen, the party with the duty to ensure accurate testing is responsible for relying on the bad info, not the party that provided the info, unless maybe there was fraud or some hideous conduct involved.

So here BP would be negligent both in relying on the TO info without verifying accuracy, and in having such poor procedures that permitted this to happen.

syn - Sounds quit reasonable. But on the other issue you and I have been sparring over: Monitoring the well flow. BP was "abdicating it's duty to TO" WRT monitoring the well for flow back. This is how it's done on most rigs: the coman isn't standing on the drill floor watching returns (except for my comen, of course). He normally "abdicates" that responsibility to the drill crew. Sometimes if they see the well flowing there's time to call the coman and get instructions from him. Sometimes not. This may be THE inherent flaw in how the oil patch normally works.

We've joked before about Rockman Inc consultants keeping a close eye on ops for the feds. In truth if I were drilling a DW well that cost $150 million and had a daily expense of $1+ million I think I would hire two more consultants for about $3,000/day total to sit on the drill floor and monitor ops for my benefit 24/7. They would also check for flow as well as monitor first hand any other tests. And these hands wouldn't have to be as experienced as my comen. They would just be acting as eye witnesses to the ops. Sounds stupidly simple but think if BP had such a hand who knew his job was monitor flow back and nothing else when they were displacing the riser. Would have that been worth an extra $3,000/day. I'll be drilling some wells out on the shelf next year. I'll probably make that recommendation to my owner now that I'm thinking about it. Remember: we're privately owned and the money comes out of his family's account. Cheap insurance to protect the family IMHO.

Note also that nobody had written procedures and acceptance criteria for the negative test. Not MMS. Not BP. Not TO.

What about other operators/drillers?

The new regs supposedly address this.

And RM, i'm not sure the coman would be 'abdicating' under the circumstances you describe. Whose responsibility is it to ensure flow monitoring? The crew, right? They just report to him when there's trouble, you say. He would be abdicating if it was his responsibility and he fluffed it off on someone else.

syn - The responsibility would still be the drill crew. No drilling contractor would give up control over shutting a well in. If the driller/tool pusher orders a well shut in IT WILL BE SHUT IN. The coman has never had the authority to counter such an order. And never will IMHO. Doesn't matter whether it's the coman or his "floor assistant" the operator is still responsible for the well. But the coman typically spends more time in his office than walking the rig. During critical ops he'll go to the floor or some other station. But sometimes critical situations happen when you don't expect it. When I worked as a DW well site geologist I essentially functioned as an extra set of eyes for the coman. I would monitor the mud loggers and LWD engineers. If I saw an indication of trouble coming I would alert the coman. Same responsibility when I used the LWD to calculate pore pressure as we drilled. I did not interact with the drill crew. My command line was direct to the coman.

As far as the coman not abdicating I believe you’ve been arguing that it was BP, via the coman, responsible for detecting the kick and shutting the well in. Did I misunderstand you? If the BP coman was responsible for seeing the kick coming then he most certainly abdicated that control to the drill crew because he wasn’t there checking for flow. You seem to say he wasn't responsible for catching the kick. If not the coman then who? And whoever was responsible let the well come in and blow out.

I have a headache and am too sick to do my regular work, RM, so i am glad i caught this.

I believe you’ve been arguing that it was BP, via the coman, responsible for detecting the kick and shutting the well in.

No, I never intended to convey such a position at all. I have acknowledged several times that the crew appears so far to have been negligent in failing to adequately monitor the well. I am not convinced that failing to spot or stop a kick is always 100% crew negligence, however. But so far it does indeed appear they were negligent and may have been able to prevent an explosion at least had they acted sooner. I never disputed that.

However, there are multiple other failures where BP could have prevented the blowout had they not acted negligently. We have more than one negligent actor. THe rules of concurrent causation apply to determine who is responsible. Both are. However, in my analysis, BP is more culpable because they acted recklessly by taking known risks to cut costs/time (on top of being negligent too). And their conduct made it more difficult for the crew to do its job, so they are partially responsible for the crew's negligence as well. They were negligent in exposing the crew to risks the crew had no reason to believe existed because of BP's negligent handling of the pressure test.

So, no, I never suggested it was BP's duty to detect the kick or shut in the well. If you thought that was my position, i can see why you've been hammering me.

Sorry for the brain pain syn. Know how that feels. My sinuses have behaved for decades but suddenly I back to the daily pressure build. Let's try to keep it light for while. On top of that I'm pooped. Spent most of last night on one of my wells. Had some good power naps but just not the same.

I agree. I need a break! :~D

So TO may have some cover. Hafle, on the other hand, could be in some real trouble.

As noted in the NYT article, Halfe told Vidrine to go for it, based on the same erroneous conclusions BP criticizes. Vidrine was specifically raising concern that the test showed proof of a possible kick at the time.

Whatever it shows in terms of liability, it certainly shows a confused process full of errors and confusion. That's obviously not acceptable for something this critical.

But I agree that Halfe is looking like the guy who may be the hub for so much of the bad decision making based on cost-cutting. He saved upwards of $20 million the last two weeks. What does his bonus structure look like?

syn - "a confused process full of errors and confusion". Welcome to the oil patch. LOL. I really don't like point a finger at ourselves but such conditions are not rare. Fortunately they seldom lead to disastors on the level of the BP accident. Usually just losing some money; much more rarely someone getting injure/killed and the environment harmed. We do now how to do a lot correctly in the oil patch. But we can never afford to forget that Mother Earth ultimately calls the shots and sometimes even the best efforts aren't good enough.

Hafle's 6/22/09 memo about thin casings collapsing might have contributed to the apparent USG decision to chuck out plugging the well after top kill got dicey. The memo was revealed in testimony on May 28. BP stopped top kill May 29.

Hafle's having a bad day at TOD.

The fact that Hafle testified with that spiked hair puts him in jeopardy going forward. "Smug" is the word I'm looking for.
Pass the grooming product and watch the fun, kids!

Gaze upon the tough-guy hair here: http://oilgeology.blogspot.com/2010/05/you-coppers-cant-pin-nuthin-on-me...

Ah yes..the ol " Top Gun "

Jeez, man, can you puhleeze cool it with the irrelevant hair judgments?

Would hate to think what you'd say about my hair. [Agreed, there's nothing more pathetic than an old geezer with a pony tail, but at least its not a mullet or a comb-over.]

And by the way, I was thinking that armchair psychologists were loquacious until the armchair attorneys started posting here in earnest.


Just LOOK at the guy.

Despite the appearance of his hair, Hafle wasn't on the rig when the well blew.
The TO crew, on the other hand, were, as were the clammed-up company men.
It's all on these small people and they will get tossed to the sharks.

Nubs - "loquacious". For goodnes sake. I'm oil field trash and work for a living: I don't have time to look up definitions. But now that I know what it means I'll use it the next chance I get even though, being a geologist, I'm sure I'll spell it wrong.

That's why God invented spelling checkers. They due the work for us. Even before that, other means were available besides the dictionary, which I agree is two much work. My girlfriend (now wife) proofread my thesis, except four the sentence on the front page where I acknowledged her for "profreading". Everyone thought it was a joke, but it really was a typo.

BTW, my baby brother (now 58) is also rock-licker like yourself. For a while he was a gold prospector for a Big Company. Part of his job was to try to get property owners to let the Big Company take test samples. Imagine knocking on the door of some remote trailer way out in the Nevada desert. I bet he did some of his talking to Mssrs. Smith & Weston.

Nubs - A quick funny story along those lines: a friend had mailed seismic permit requests to a bunch of rather unsophisticated home owners. Most didn't know what it meant even though there was a small check enclosed. Couldn't get enough permits to shoot the seismic. Another friend said he had a sure fire solution. He showed up along the road where all the houses were with a rental truck full of color TV's. He knocked on each door and told them that if they signed this piece of paper he would give them a color TV. And if anyone was concerned they could talk to the deputy sheriff by his side (who he had hired for the day) who would explain how it was OK. The combination of a free TV and a desire to never talk to a law officer got him all the permits signed in just two days.

Imagine knocking on the door of some remote trailer way out in the Nevada desert.

"I shot her full of rock salt."

In Bama they use 00 Buckshot. If you break down in rural Alabama at night and have no cell service, you wait in your car by the road until daylight. If you are a recognizable minority, your chances of acute lead poisoning greatly increases.

Anyplace can be dangerous, I'm not a recognizable minority but I was visiting one big city and was advised not to leave my motel after dark.

Another place I visited I went into a bar were the doorman patted me down to see if I was carrying, when he saw I was unarmed he loaned me a .38 so I could protect myself.

And my apologies for my loquaciousness. I'll back off, I'm wasting way too much time here anyway. Work avoidance on the tedium i am dealing with right now. And I do love these big complex disaster cases. I just love unraveling them. Sorry.

I was just funnin'. Now you got me feeling bad. :-(

No no! I's okay!

Hey Nubs, at least us old geezers have enough hair left to make into a ponytail!


My wife always wants to "trim the split ends". I use to let her, but now I'm saving everything I got.

I fell for that too, until "trim the split ends" became " take a little off the top". My ex used to remind me of the barber I had in military school....."Skip"....Bad nickname for a barber, probably had something to do with the palsy.

donaldvidrine dot com?

Is that a joke or spoof or a clumsy attempt at character assassination?
Not that I'm defending vidrine or anyone else, but that's skating on some thin ice.

Vidrine's not talking, remember?

Somebody gonna get sued or at least lawyered half to death...
[If a flock of dorkuses set up a Web site with my name on it, I'd definitely loose the lads on them quick as a wink.]

The domain owner info isn't obtainable. It's registered through Domains by Proxy.

Looks to me like it is for sale, probably registered in may, expired in may, extended or something in June, and didn't I see a notice on the index page that it is for sale? Could be there are more of them in others' names, too. Maybe a player over at GODADDY? I think I read that this is a big gambling business these days. I don't know much about that stuff but it sure doesn't appear to be there (the site) for another reason. NO WORK put into its development at all.


Registrar: GODADDY.COM, INC.
Whois Server: whois.godaddy.com
Referral URL: http://registrar.godaddy.com
Status: clientDeleteProhibited
Status: clientRenewProhibited
Status: clientTransferProhibited
Status: clientUpdateProhibited
Updated Date: 03-jun-2010
Creation Date: 27-may-2010
Expiration Date: 27-may-2011

People register domains through Domains by Proxy as an agent so that ownership info can't be located. It almost certainly doesn't belong to Vidrine.

Coming from a house in Scottsdale, Arizona.

$7500 for the domain name, probably some wishful soul.

A speculator. Also owns garybanks.com, also for sale, and some other junk. Good at overpricing domains, though.

That is why I choose a short near nonsense domain. Hijack me and I am back in hours with a new domain. It is just an address to me.

There are some real sewer rats in that game. I used to own pinkfud.org, but I accidentally let it expire and one of those guys snapped it up. Then had the guts to ask $1200.00 for it back. AFAIK he still has it. I registered pinkfud.net instead. (Don't bother going there, it got trashed a while back and I've been too lazy to rebuild it. Nothing to see, move along.)

They should set a flat rate for domains, say $10, and no-one is allowed to charge any more. Kill that scam off real quick.


Disagree. Homes.com is worth more than $10. ICANN authorized the .name extension to get around name hijacking but it's the .com that everybody wants.

If this information is true it roundly refutes jinn's assertion that no one thought there might be a problem (if I understand jinn's assertion correctly).


It does not refute anything I said.

I asserted that no on duty thought there was a problem. Nobody in the TransOcean crew thought there was a problem. Don Vidrine (the BP company man) expressed doubts about both negative tests, but the TransOcean crew convinced him that there wasn't a problem. So going into the displacement there was no one on duty that thought there was a problem.

And Mark Hafle was correct. If the rig had properly tested the well in an underbalanced state for 30 minutes, then they would have taken a kick and the bad cement job would have been revealed.

"It does not refute anything I said."

Semantics again, and I won't argue semantics.

"And Mark Hafle was correct. If the rig ... "

Maybe Halfe was given wrong info? Was Halfe watching live Halliburton log feed from rig?

Was Halfe watching live Halliburton log feed from rig


I don't know what Hafle was doing, but it was ten o'clock at night. I would guess Hafle was at home.

Neg test was done earlier, 4 - 6 timeframe as I recall.

Yes you are right the call would have been around 7:00. And you also right that Hafle was probably given wrong information. I believe it was Kaluza that called him and Kaluza probably told him that they did a negative test. Hafle responded that if you did a negative test and the well didn't kick then you are OK. What Hafle didn't know was they hadn't done the test - they just thought they did.

What Hafle didn't know was they hadn't done the test - they just thought they did.

Not according to BP's report.

The residual pressure of 1,260 psi in the drill pipe was bled off from the well. According to witness accounts, 15 bbls of fluid returns were taken. The investigation team's analysis indicates that approximately 3.5 bbls should have been expected. This excess flow from the drill pipe, with the well in an underbalanced condition, should have indicated to the rig crew a communication flow path with the reservoir through failed barriers.

Jinn - tells us why you are right and BP is wrong.

I think this was a temporary condition. The well flowed a little through the kill line. Then they closed off the kill line. When they opened it later it had a little flow and stopped (because it was now plugged up). The reservoir was still communicating and continued to build DP pressure.

It is tough to think the kill line was flowing and plugged up to stop flow. That is not an expected situation. You just assume it is still open and something strange is going on with the DP pressure.

I think - I know - I've missed something.

What was plugging up the kill line?

and was there some way they could have known it was plugged up?

And it must have been plugged pretty tight if that pressure didn't blow the obstruction through. I've wondered that too. Seems unlikely a simple glob of mud could do that.

We don't know what plugged the kill line or where. It could have been hydrates, a stuck valve, heavy spacer fluid, a faulty command (didn't actually open the valve), something else? After the kill line was cut off the kill circuit through the BOP was used successfully during Top Kill.

After bleeding both ends to zero psi and closing the DP, there should be no change in pressure at DP or flow at kill line. They closed both ends and DP pressure rose. Kill line was sputtering when it was closed. They later opened the kill circuit and about 9 gallons of fluid came out and it stopped. It held this condition (DP pressure and no kill flow) for 35-minutes.

The DP pressure increase after equalization with no kill flow indicated something was plugged up. Certainly not expected when you just got fluid from the kill circuit a few minutes earlier.

ISTR Cocales (sp?) saying that the feeds were recorded on-shore but were not monitored.


rf - And that sounds like the real battle WRT how TO "talked him out of it". Did TO offer a logical explantion for the results? Did they fudge the reliability of the results and thus misrepresented them to Vidrine? Was Vidrine competant to understand the results? I suspect we'll have to wait for sworn testimoney to get a good handle on those answers


It sure takes plenty of stupid moves to line up things this way, and blow a well the way they did. I don't know how these deep water drilling operations are manned, but I worked on offshore completions from floaters during my career, and we always had two completions/test engineers aboard. One of us was always awake. We also had at least one drilling foreman aboard (what they call the company man).

I don't know what's happened to the industry, but I think all the radio and remote telemetry to the beach, and having people second guess what goes on aboard, makes the guys on the spot be a little less serious about their jobs, and it also creates a career path where the real hot shots don't like to be on the rig, would rather be the ones making the powerpoint presentations in Houston.

I'm looking at this from the stratosphere, and it seems the real root cause may be more of an organizational issue, and culture, whereby the guys aboard and supervising the operations in Houston just didn't have what it takes to run that show. And this goes for both the Transocean AND the BP personnel.

The guys picking and approving those guys and setting up the organization and the procedures were likely more focused on the powerpoint shows and the office politics than getting things done right. Maybe they need to have less conference rooms and more offices with real engineers writing sensible procedures, and people who make a living on the rig who know when they're taking a kick.

It is a result of generational experience loss because of the extreme boom and bust cycles of the oil bidness. I have seen it three times in my life of being oil field trash. When times are bad usually the mid level and senior experienced folks are either led to the chipper machine or just plain quit, leaving a huge hole in experienced personel to pass things down to the next generation. After a few cycles of this crap we end up with fresh college grads being comen/cogals calling the shots for things they only have 6 months experience. The awl-field ain't all book larnen.

My son, a ME and a directional driller, has seen this many times in the last 5 or 6 years. Folks calling shots completely out of their experience slot.

One of the companies I work with has a company homily that states: “The world is composed of two types of people; those who manage what they will never understand and those who understand what they will never manage.”

Do I uderstand correctly from 21:30 on with pumps off they saw continuous mud returns and (wildly) fluctuating standpipe pressure until 21:47ish when "mud started spewing out on the drill floor"?

If thats how it actually went, it boggles my mind they didn't initiate shut-in around 21:30.

rf - That's my uinderstanding. Very early we got the real-time data transmission of the hydraulics. Didn't save the link but if you haven't seen maybe some good soul on TOD will toss it out to you. I'm not expert in interpreting this data but those that are have expressed the same shock you have. The only explanation is that no body was watching the monitor until is was too late.

Are you saying mud coming up, initiate kill immediately no questions? Anybody? Like getting off the tracks if you see a train, no real decision to be made? Just curious.

TFHG - This might sound a little snotty but if I have the pumps off and the well flows enough (sometime OBM can swell, called ballooning, and adds a little flow back) then it indicates something is pushing it out the hole. Only 3 things can push mud out of the hole: oil, NG or water. From my rather simplistic view of drilling operations, a flowing well is like being pregnant. Either you are or you aren't. If the well is kicking it isn't going to stop itself most of the time. Many times these kicks are minor and don't take much to kill them. But if you let the well continue to unload, whatever is pushing the mud to the surface will eventually come out behind it. Even if it's just salt water pushing the mud out it can turn into a very costly problem. And remember: Initiating a kill is nothing more than shutting off the mud returns. If it turns out to be much to do about nothing then it really hasn't disrupted the drilling process much. Wait too long to shut a well and have to activate the BOP: now you're talking about a huge disruption and expense, especially in DW. And who knows: that may have been a big factor in the BP blow out.

Gothca, early on quit replacing the mud with water. After that, all you can do is activate BOP. I get it now. The 'Failsafe' movie. These guys were flying with nukes to take out Moscow, but they did not know the order had been canceled. Did their best to make it and one did. Did everything perfect except 'get the recall order' (detect a kick). Sort of important to the whole endeavor. Now I understand your, ...well your anger. If it were a computer failure that launched a missile (not likely) then I would be angry too if the proper information was there all the time and I could have acted upon it. They just did not see it, interpret properly, or disregarded it. From earlier posts I read you have been in a similar situation and it wasn't even close. So tell me Rock, am I out of school to ask you if you or a job you were on had the BOP activated for an emergency shutdown? Does this rate a report to the Feds? The dollars probably are the big disincentive anyhow. How often does a BOP save the day? I am guessing one, if any for you or a job you were on.

TFHG - Never been on a rig where they activated the BOP. About 5 years ago I was on a rig about 10 miles from a well that blew out. The only hand lost was the coman. He was last seen running to the substructure presumably going to manually activate the BOP. Didn’t make it in time. I don’t think they ever recovered his body. Was close a couple of times: didn’t have time to shut the well in and the oil/NG flow was diverted to a flare line. Really dramatic one time: 100’ bright flare roaring like a jet engine. Me and the other non-essentials just stood out in the field and waited to see if the rig blew up. Long ago so I’m not sure they activated the BOP on either well.

I think every BOP activation requires a report to the feds. I don’t think kicks are required to be reported but they do go into the permanent drilling record. Did you see the report the Norwigians did? Heard they looked at 15 to 20 BOP activations and the BOP only prevented a blow out 60% of the time. Never saw the report but I think enough verified it was true.

I have a really stupid question - once the BOP is closed, can it never be opened again?

You mean to work the well or is the BOP done and cannot be reused?

Either. The thought behind my question is: why would one NOT want to activate it?

$$$$$$$$. Well time, which is $$$$$$$$$.

Thanks Rock, I have Halliburton log.

Watching monitor?

What about watching trip tanks filling up / pits filling up / mud going overboard, however they had it lined up?

Seems anyone with eyes could see well was flowing from 21:30 on, blatantly obvious, especially with wildly fluctuating SPP. It was right in front of their eyes, in their face, and NO ONE said shut 'er in till mud was flooding the drillfloor?

My god, were they all in a trance ...or on break maybe?

That was my Rocky question. Do 'small' backflows of mud or water occur as a part of the process. Could a fairly new hand glance at it and think situation normal or should have anyone that saw it for more than a second hit the shutdown button? For example, do you ever get 10 gallons back for various reasons on a 'cemented in' well? Or if you see 1 gallon, hit button?

As I understand pumps were off from 21:30 on yet mud kept on coming up, standard kick sign per Rockman, and standard response is shut 'er in, no discussion, hit the button.

So it sounds like we are talking 2 seconds of observation. Yes, now I understand why you pros have been screaming about this one.

There was only 15 minutes to move from "Everything is going great" to "we have a serious problem"

The mud wasn't going overboard at that point. According to the testimony of the Damon Bankston Capt, they last received mud at 1717. He actually contacted the rig around 2100 to ask why they hadn't restarted the flow. So any odd mud returns should have been visible to those on the rig.

See quote from the captain's testimony at http://www.theoildrum.com/node/6932#comment-716660

21:08 mud diverted overboard (see Fig. 8, 9, 10, 11 on pg. 93-96 of BP report)

The mud coming from the riser was going overboard at 2130. The mud the Bankston was expecting was mud from the pits. I believe pits were being emptied so that they could be cleaned.

oh literally overboard ... thanks.

There have been comments in some media that investigators found that the crew may have been busy/distracted with tear down tasks.

And as OTP noted yesterday, if they had done this according to normal procedures in his experience, they would have had two tested plugs in place at the time of displacing the riser. They often would not even bother monitoring the returns while displacing because there is no need to at that point with both tested plugs, and it is very difficult to do so when off-loading to a boat, whereas using any spare tank increases time and slows it down.

So at this point normally there would not be the need to do all of that, according to OTP's post, because you have already achieved P&A status before you displace the riser. But this time, they took the short cut, but for whatever reason, they handled it as if it was P&A already in terms of monitoring. Still, it would seem monitoring is in order even with two plugs while displacement is underway. They had the data right there.

Edit corrections

Wait a minute. You guys are causing my poor old brain-fault-interrupter to trip. Are you saying the well return, all of it, was being sent overboard? Nothing going into the pit? Then why does the Halliburton log show that the pit volume was increasing? And the Trip Tank surge at 21:41:40? Darn, I hate when I thought I understood something, only to realize I haven't really got a clue.

21:40 Mud overflowed the flow line and onto the rig floor.

21:41 Mud shot up through the derrick. Diverter closed and flow routed to MGS.

See BP report pg. 103.

OK, at 21:42 the standpipe pressure hits a low, so that seems to follow. It would relieve the pressure temporarily when the mud first started shooting up. Where is the trip tank in this system? Clearly something flowed into it at that time. (I'm completely out of my depth here).

Yes, here's that link.

At 2130, the pumps are off and the pit volume chg is slowly but surely rising. The SPP did start going crazy too, but that's beyond my ability to interpret.

POSTED: 10:32 am CDT September 9, 2010
UPDATED: 10:45 am CDT September 9, 2010
2nd Mariner Energy Platform Catches Fire In Gulf] Email

NEW ORLEANS -- A fire at a Mariner Energy platform in the Gulf of Mexico has been extinguished, Department of Homeland Security officials told WDSU News.

It was the second fire on a platform belonging to that company in the past eight days.

The non-producing structure is located about 75 miles south of Morgan City, La., near Vermillion Bay. The Coast Guard is on the scene investigating and report no signs of pollution.

Last Thursday, a more serious fire prompted 13 people to evacuate a Mariner Energy platform in the same general area. Those workers were rescued and no one was injured.

An investigation into that incident continues.


You have got to be kidding! Is Mariner single-handedly trying to make the "moratorium" into a full scale ban? Good grief!

Actually since this is not covered by the ban BP probably lit them. This only removes the ban sooner IMHO. Now all can claim how ineffective the ban really is. Plus this makes BP look less 'bad' and takes away from the bad Macondo press. No BP probably did not want this to happen, but they are also not going to cry about it either.

Pinkfud: Maybe Exxon will give 'em a hand there. BP is a little busy at the moment.

Oh, God, I hope not. At least they don't have a supertanker to run aground. .... Do they?

Officials said no one was on board the platform at the time and no injuries were reported.

How does an unmanned and non producing platform catch fire?

Vandals (no, really. People fish out there among the platforms all the time.)
BP-controlled cylons.

I was kidding about BP lighting it. It is interesting however. Maybe not vandals, saboteurs. Where is Greenpeace again? That Whale Wars guy? T. Boone Pickens? Windmill and solar panel companies, the list goes on. Yes it was probably 'natural' causes, but you cannot help but speculate.

Gas leak coupled to an improperly sealed telemetry device will do it. Unmanned platforms produce oil and gas, they are monitored using pressure, temperature, flow, vibration, and video sensors. The sensors are wired to a remote unit, and this unit sends the signal to a location where computers and operators monitor the information flow. I can see how a small company cutting corners may have wired the platform so that a small gas leak could catch fire by entering one of the remote telemetry units.

2nd Mariner Energy Platform Catches Fire In Gulf

Added to the story:

The fire started about 9 a.m. and was put out before response teams arrived. No one was evacuated.

That means the rig crew put it out, right?

Patrick Cassidy, a spokesman for Mariner Energy, said the platform had not been in operation since 2006. It would normally be unmanned, but he said two workers were on the platform doing a cutting operation to decommission it.

The fire was put out with a water hose and a fire extinguisher, he said.


two workers were on the platform doing a cutting operation to decommission it

Not sure what a "cutting operation" is. Could it start a fire if something went amiss?

The 6,300-degree F. flame shooting out the end of the torch is a fire hazard.

Yes a cutting torch is typically an acetylene fueled torch with an oxygen jet to increase the flame. Can 'cut' through inches of plate steel like it was butter.


It's aceteleyne - oxygen mix circular (more or less) pre-heat flame with center "cutting" oxygen jet activated when surface get's hot enough to "burn" when hit with pure oxygen.

And "burn" is technically accurate, steel actually burns (oxidizes) into slag in the cut, generating enormous amounts of heat easily sufficient to melt the slag all the way down in the cut which is blown out of the cut by the oxygen jet plus flowing out if vertical cut.

That's how you can cut through 6" thick steel with a cutting torch with those tiny pre-heat flames. Steel oxidation ("burning") in the path of cutting oxygen jet generates enough heat to melt slag all down through the cut. Pre-heats just get the surface hot enough to start the process.

To demonstrate it to someone I've actually turned off pre-heats after cut gets started and cutting oxygen alone keeps it going.

Didn't know that one. I am a MIG/TIG and stick guy. The gas stuff is too much like voodoo to me.

Larger example is oxygen lance at steelmaking operation. Wana trim a hot ingot? Just aim your oxygen lance where you want to cut, turn the oxygen on, and cut down through 3 foot thick ingot like butter.

Of course you have slag blowing out everywhere on far side of cut, make sure nobody is over there. :)

From my service days we used Willy Pete (white phosphorus) and thermite grenades. Nasty stuff. The thermite could melt through an engine block.

Yeah, have played with thermite. You can weld some pretty heavy steel with it. Powdered aluminum and iron oxide. The aluminum reduces the iron to metal and gives Al2O3 as a slag. Hot and pretty.

Yep, the grenades are the size of a beer can and you do not look at it. Singed my eyes one time. Luckily it was minor and temporary.

Yeah - and the thermite is able to melt the steel beams of big buildings...

I thought it was some nano-thermite or some as yet not invented substance. Now I know how the Warren Commission felt.
Great video on the 'TRUTH' about JFK. School House Rock Style, very short ;)

This is very OT, but if you're interested in JFK, see the work of Dale Myers at http://www.jfkfiles.com/

This isn't CT stuff but serious forensic work done with incredibly-detail computer modeling. Won an Emmy. See Dale's bio at http://www.dalemyersanimation.com/html/profile_index.htm Dale started this work on his own and work for years in this personal-passion project. For a while the CT crowd liked Dale's work but when it started moving in the direction of supporting the conclusions of the Warren Commission (becuase that's where the results of the work lead), the CT folks turned against him. Any science that casts doubts on the true faith must be declared apostate (Dale vs. the CT crowd).

About 30 years of interest and work went into his models. Became featured in several documentaries, include the ABC primetime special. Still some of the best work on the subject I’ve seen. Also wrote a book http://www.amazon.com/Malice-Harvey-Oswald-Murder-Officer/dp/0966270975/...

Dale used to sell tapes of his animations to raise money to support the early days of his work. I bought several about 15 years ago while the work was pretty well developed but still evolving and details were still being added to the models. Breathtaking even then and became better with time as more details were added to the underlying models. Still not seen anything better. Sample of the video on the website. Science meets history.

PLEASE COULD YOU EXPLAIN to this foreigner. Do any of these committees / commissions or whatever they are, have the power to send anyone to jail? Are they effectively Courts of Criminal Law?

If they are not, who will prosecute individuals or corporations in this matter?

What Court of Law will the accused appear in? Will that Court have a Jury that decides?

If such Court has a Jury, how will you find a Jury that has not been tainted by all the media published evidence that you are talking about above? A Jury that will know nothing about anything that has been broadcast; and, will make a judgement based solely on evidence put before that Court.

How will you find twelve good men and true, who have not already made up their minds on the guilty persons?

Could the likes of Syncro - for instance - be picked to be on that Jury?

The corporate structure will decide who gets thrown under the bus.
By the time it gets to a jury -- if it ever does -- the outcome will be already be decided.

As soon as he is asked his profession he will not be on the jury :)


Could the likes of Syncro - for instance - be picked to be on that Jury?

Acornus, i am advocating and debating theories. That requires taking sides on the issues. So of course I look biased. I am biased in favor of the position I am advocating for because i believe it to be true, unless someone shows me otherwise. I am not acting as a juror would. It is more in sport for the enjoyment of debating.

But my perception of the truth is still what guides me, not a pre-determined outcome. I agree that TO was negligent, but BP was reckless, IMO, and BP was in charge. It was BP's judgments and plans and shortcuts that were being implemented the way BP wanted them implemented.

But to answer your questions, the civil claims for damages people and businesses suffered that are not resolved through the fund can go to a jury trial. Yes, I could be on the jury, but only if the attorneys wanted me on it. The lawyers will give the jurors written questions and will spend hours in voir dire asking them questions in order to detect and weed out biased people and other traits they find undesirable in a juror. Each side can reject a set number for no cause, and any for cause (the inability to come to a impartial judgment, demonstrated bias, etc). Usually, all 12 jurors have to agree, 9 in some states. Some juries are smaller.

Violations of regulatory laws will result in administrative charges and fines, subject to court review, is my understanding. This is outside my area of normal practice. Ultimately, a judge will decide fines, but the govt. and BP can enter into plea agreements courts often follow.

Criminal charges can be regulatory in nature, or based on crimes everyone is subject to, such as manslaughter. It's too early to say how those will play out and in what forum.

The proceedings that are going on now are being conducted by the coast guard so it can prepare a report. Charges could arise out of the information discovered during the investigation. The focus here is maritime safety and the CG role is policing DW drilling vessels.

Congress is doing investigations as well to determine what legislation might be needed and to determine what happened in order to make that judgment.

I bet if I had a bag of weed on me the system would figure out how to do it. Only in the USA.


They are under oath to tell the truth to these boards of inquiry. They can be fined or imprisoned for lying. That's one of the reasons those giving testimony parse their words very carefully. The other is they don't want to give the other represented parties any advantage in future legal battles.

edit to add:
In other words, it's pretty hard to get a clear picture of what really took place once every one "lawyers up". That's why there is still so much speculation going on... no one wants to admit to their mistakes.

SYNC. "It is more in sport for the enjoyment of debating." I guessed that a while back. Should we meet, I would buy you a beer and enjoy the banter. ;-)

The biggest lawsuit that will be filed in this case has already been filed by BP I believe..

Who do you think should be on that jury?

Help! I seem to remember a comment somewhere in the last few days about a nitrogen kick.

Anybody remember where it appeared?

Here are some factors to consider. The amount of foamed cement was 48 barrels. It was designed with a quality of 18 to 19%, but BP asserts it was actually pumped at only 12.98% quality. So right off the bat the total volume of cement pumped was less than expected. Given the concerns about the foam destabilizing through "nitrogen breakout", it is possible that such a breakout would have been detectable as a "nitrogen kick". Can we find one?

The hazard is apparent. The cement design called for the tail cement (7 bbls?) to fill the shoe track. The designed nitrogen volume was 18% x 48 barrels or 8.64 barrels. If it broke out, then then could be zero cement in the shoe track, exposing the float collar to full formation backpressure during the negative test with unknown results(it is unlikely that it was designed to handle such a large backpressure).


The BP Report doesn't assert that the foamed cement was pumped at 12.98% quality. It says that Halliburton designed for a downhole quality of 18-19%, but the sample they lab tested on 12 April 2010 was of 12.98% quality; that is, it was a different animal from what was used in their design.


You'll probably find Appendix K of interest.

Page 3 of the appendix (page 1 of CSI Technolgies report) indicates they foamed at a pressure to the nitrogen injector head of 2000 psi into a slurry at 1000 psi (1000 psi differential) and that the unfoamed cement slurry was 38 bbls and the nitrogen was 60 bbls.

Final foam at a nominal 13,000 psi and 140 F was 18.5% quality with a density of 14.55 ppg. "...the amount of nitrogen at in place conditions was about 8.5 bbls". So if they lost stability of the nitrogen foam, they could have lost a volume equal to or greater than the tail cement that was supposed to be in the shoe track. The basic foam stability question is still unanswered, but there is some possibility that it was a major contributive factor to the blowout.

And there is still the question of cement lost into the rat hole.

Yes, read Appendix K yesterday. Too bad CSI couldn't have tested Halliburton's actual mix.


Harrell claimed in testimony that he was concerned about the possibility of nitrogen bubbling from this type of cement and had wanted make sure that everyone was watching for any problems this could cause. He said he was aware of a rig that had taken a nitrogen kick and unloaded the riser contents all over the deck.

So where was Harrell @ 2130 when the mud levels were rising?

In or about to get into the shower.

I can believe they could get a nitrogen kick. I'm still trying to figure out how BP can talk about over 60 barrels of cement in one place and then have this report show that the total of 38 bbls of cement slurry and 8.5 bbls of nitrogen (at depth). According to my old math 38 + 8.5 = 46.5 at depth.

Edit - I do see how 60 bbls of nitrogen at 2000 psi & 100 deg F becomes 8.5 bbls at 13,000 psi & 140 deg F.


The references to 60 barrels of cement that I've seen refer to total cement; namely, 5 bbl of 16.7 ppg cap cement in the annulus, 48 bbl of foamed cement in the annulus, and 7 bbl of 16.7 ppg tail cement in the production casing shoe track (5 + 48 +7 = 60).


Perhaps it is a bit early or too complicated to discuss here but we have in the DWH a vessel registered in the Marshall Islands and owned by a Swiss Company, TO, under charter to a British firm, BP or its US subsidary, not to mention the other parties involved. What court(s) would have civil and criminal jurisdiction, Federal and/or state? Would the court(s) have to abide by the rules of Admiralty law rather than state/Federal statutes? I imagine the question of jurisdiction will be one of the early skirmishes in the decade long legal battles.

For instance from http://en.wikipedia.org/wiki/Admiralty_law

“From a tactical standpoint it is important to consider that in federal courts in the United States, there is generally no right to trial by jury in admiralty cases, although the Jones Act grants a jury trial to seamen suing their employers"

So the question of how a jury will view some of the issues may be a moot point.

Right. The corporate and .gov lawyers will "negotiate" and decide who eats the crap sammiches and who gets the shrimp cocktails and who gets nothing. Done deal.

[Transocean will probably loose its LA privileges and Nola Saints season tickets.]

The losers get the shrimp?

BP oil spill: Weatherford's 'float collar' concerns played down
By Rowena Mason

Investors and analysts have shrugged off BP's suggestion that Weatherford International should shoulder some blame for making a key valve that failed on the Deepwater Horizon rig... analysts at FBR Capital claimed any sell-off would be an over-reaction, saying any liability would be difficult to prove.

I posted this yesterday but think it got lost in a long post. I'm interested if anybody else picked up on this in the BP report published yesterday.

Appendix O had something very, very interesting. Remember the other oil company execs saying they would never run a long string. They might want to go back and look at their well records. Appendix O shows this not to be the case. Including Anadarko.

retired - I gather the report shows a number of other companies who used a similar csg desgn. The engineers i talked to said it would not have been their choice. But that's not the same as saying they never had or ever would run that design.

See pg 75-77 of the BP report. From the Analysis on pg. 77:

Industry data in Mississippi Canyon Block 252 area also indicates that approximately 57% of the wells used long strings while approximately 36% used liners or liners with tiebacks.

So color me curious. Is the "long string" used just because it is cheaper? If so, why doesn't everybody use it? What factors suggest one design over another?

That section of the report (pg. 75-77) goes into some detail about the pros and cons, risks and costs, during drilling and production of either design.

Mucho thanks es.

EPA has written the Corps recommending against permitting any more Jindalberms. This doesn't affect those under construction.


This doesn't affect those under construction.

But sounds like Flores wants them to stop until they change their approach.

Flores also asked the Corps to allow no further work on the six berms until the plan is changed to follow the accepted protocol of restoring barrier islands.

I am having a hard time believing this is just nitrogen leaking at the wellhead for this long. Looks like there is dark drops in it too.


Saw that on the DD2 feed. I have no idea what it is, but it isn't big enough to be a concern IMO.

They were sitting down there all day.

Yes, that's why they use unmanned vehicles. Would you prefer they bring all ROVs to the surface when there's nothing for them to do?

I have found they usually watch things that bother them.

A couple of months ago they took up three sample bottles of this stuff and we never really heard for sure what it was.

Now they are back to watching it.

EPA Formally Requests Information From Companies About Chemicals Used in Natural Gas Extraction / Information on hydraulic fracturing chemicals is key to agency study of potential impacts on drinking water
Release date: 09/09/2010

WASHINGTON — The U.S. Environmental Protection Agency (EPA) today announced that it has issued voluntary information requests to nine natural gas service companies regarding the process known as hydraulic fracturing. The data requested is integral to a broad scientific study now underway by EPA, which Congress in 2009 directed the agency to conduct to determine whether hydraulic fracturing has an impact on drinking water and the public health of Americans living in the vicinity of hydraulic fracturing wells.

In making the requests of the nine leading national and regional hydraulic fracturing service providers – BJ Services, Complete Production Services, Halliburton, Key Energy Services, Patterson-UTI, PRC, Inc., Schlumberger, Superior Well Services, and Weatherford – EPA is seeking information on the chemical composition of fluids used in the hydraulic fracturing process, data on the impacts of the chemicals on human health and the environment, standard operating procedures at their hydraulic fracturing sites and the locations of sites where fracturing has been conducted. This information will be used as the basis for gathering further detailed information on a representative selection of sites.

“This scientifically rigorous study will help us understand the potential impacts of hydraulic fracturing on drinking water – a concern that has been raised by Congress and the American people. By sharing information about the chemicals and methods they are using, these companies will help us make a thorough and efficient review of hydraulic fracturing and determine the best path forward,” said EPA Administrator Lisa P. Jackson.

What took so long ? Not to rib you Oil Patch guys too much,...but what gives with E.O.R. techniques and polymers like Brightwater....?


I understand now about "brightwater", but I wasn't aware you could actually set it on fire!

Isaac - Water blockers have been around longer than me...35 years. Don't know the details of Brightwater. Might be the Holy Grail or just another slick ad for a product that typically doesn't work nearly as well as advertised.

Just a quick comment on the hype over reg agencies wanting details on frac fluids. IMHO it's something of a red herring. Frac fluids are toxic and always have been. You don't want this stuff in your freshwater aquifers...period. Does it matter much if you know the details of the type of poison? It's all bad. The real question is how do you minimize the risk of contamination? I haven't seen one MSM article that has focused on that nearly as much as the fact that Halliburton doesn't want to give up trade secrets for no good reason. And I've pointed out before that the risk of ground water contamination from the actual frac efforts is very small. The real risk is the proper disposal of the produced frac fluids. This has been the major source of pollution in Texas for decades...not the actual frac process itself. They shouldn't be focused on operators while they are frac'ing IMHO. They need to be closely watching those small independent haulers and disposal companies. Most operators would never intentionally dump this crap on the ground. But some operators don't care what these other companies do with it as long as they get the liability off the operators back.

RM, thanks for the reply.

Yes, toxicity is a concern for sure with some of these products, although it appears that not all EOR processes rely on extremely toxic products. Funny that MSDS for some of the constituents in these products explicitly say things like " do not pour down drain ", but yet, pumping them into ground near aquifers is perfectly acceptable.

On another another note, 2 topics I have not seen yet discussed here at the OD, thought they might make good cannon fodder:

1. Underground salt dome storage of hydrocarbons on the Gulf coast
2 " Gas washing "( which I understand to be NG migration to reservoirs.)


Frac fluids are another subject I know absolutely nothing about, but there's another fracking issue I've heard of. I guess there are areas around the country where NG has gotten into the aquifer to the extent that tap water can be ignited. (Must be real handy for firefighters). Seems to me that would have nothing to do with the fluids. Rather, it would be due to the frac job having used too much pressure and fractured the caprock over the NG. Then it would migrate up and disperse into an overlying aquifer. Does that sound reasonable? Or am I missing something?

Some environment links.

Video on blue crabs. Dr. Perry, who does a census in MS every year, says the population of crablets returning to shore seems to be down some, but not catastrophically; says the famous oil droplets may be shed, but long term damage may have been done. (As I understand, this could involve the mutagenic and endocrine-disrupting effects of PAHs.)


Another report on the Cape Hatteras cruise but not from Samantha Joye. There is a graph that shows the attenuated deep plume.
Green--petroleum hydrocarbons per Aquatracka flouroscopy peak at surface, at 60-100m, and at plume depth (1000-1300 m)
Magenta--dissolved oxygen--note small bump at 1000m.
Blue--colored dissolved organic matter--I wonder why this curve increases so smoothly with depth.


Jane Lubchenko explains differences between government and UGA oil budgets. The reporter oddly treats the Aug 4 estimate as though it were current.


Mutagenic? Teenage Mutant Ninja Sea Turtles? I can't wait, there are some oil executives and government officials that have some explainin' to do then :)

Thanks Gobbet. Nice to hear something about a research project that actually has multiple years of baseline data to compare against.

Incidentally, Joye is on R/V Oceanus, not R/V Hatteras. The post http://www.theoildrum.com/node/6926#comment-715360 incorrectly tied her name to the Hatteras cruise.

I did a quick search in previous posts and didn't find a link I was looking for so I may be reposting this by mistake.

This is another JAG report called Review of Preliminary Data to Examine Oxygen Levels In the Vicinity of MC252#1 (May 8 to August 9, 2010)

I don't have time to read at the moment but will look at it in the morning.

Thanks for the great links and insights you have graciously provided!

Virus Alert!

If you get an email with the words, "Just for you", kindly delete.

This trojan impacted many computers where I work and I was surprised to see it make national news. Co-workers and I LOL when we noticed first company mentioned in article was NASA. Evidently, rocket scientists don't know how to protect themselves from email trojans.

About three years ago I was at an seminar hosted by the NSA and DSS. The guy talking about hacking described a test conducted on the NSA's internal email system. The sent out a broadcast email with the title: "Warning - virus Detected! Delete this email! The attachment to the email was a 'test' virus made by the NSA labs.*

26% of the staff at the NSA opened the email. Of those - just less than half opened the attachment also. If people at the NSA are this bad - think of what it is like out in the commercial world.

*Apparently the NSA has a staff of people whose job is to create 'custom' viruses for one time use. One time use viruses are espically dangerous because they do not replicate. All they do is deliver their payload then delete themselves. As a result - their signatures do not appear in virus scanning software.

And if you think that this is scary. According to the NSA that is not really your cell phone. It actually belongs to some hacker who does not need it at the moment.

Thanks for the interesting points about the NSA and DSS.
It doesn't startle me too much, but yes, we can only hope proper oversight is done. I have a DVD video of a classified US airbase in a country west of Iraq that was built before war started and used to bomb missile launchers and other targets in Western Iraq.

The trojan today was undetected by McAfee with current patches and replicated thru the organization very quickly. The main problem was an email that normally took 1 minute to send to a neighbor now was taking 20 minutes. McAfee had already provided a patch by the time I went home, so I expect the patch and fix to get rolled out to all computers in enterprise by morning. I work for a TBTF, so it's a huge number of computers. I don't know how the Indian folks in Chennai will make out who I work with since they are on an untrusted domain that the enterprise doesn't distribute software to.

I get more upset at the developers who design software that is so easily compromised. My expertise is in that area so I see lots of examples of easily compromised software that passes QA testing without any thought of infiltration testing. One task on a long list is for me to take a course called ethical hacking for the purpose of learning safeguards.

Yeah that hacker is called Cellular South and if I do not pay him, i do not talk on it. When Guido (national origin bias?) comes knocking I will post it here and let you know, LOL. Hey activated my doctor brother, 20 year man, USA LTC, is getting honored before the Bama/Penn State Game. Saban, box seats, the works. Look for the Korean/Creole guy. Maybe he will get a shot on TV. He is the hero of our family. Surgeon too. Ortho. He is my hero too. Sorry you are in the top 20. Not bad really you would crap if you had the list. Can't let it out sorry. Thanks to you too. Us dumbass officers couldn't find the latrine without you non-coms.

Rockman, i have some new thoughts on the requirement that there be fluid of sufficient density to achieve hydrostatic balance between the plugs as part of proper P&A. That makes sense when you figure these rules are for permanent abandonment. Two plugs and hydrostatic balancing seem appropriate. Three levels of protection for the decades or longer permanent abandonment must withstand.

Did you notice how Hafle requested that the top plug be set at the precise depth that they calculated they needed to displace the existing mud with seawater in order to do the negative pressure test at the pressure they wanted? i may be heading down a confused path here, so knock me down if i am.

This allows them to displace, do the pressure test and then set the plug in one nice clean sweep without a lot of futzing with mud weights and POOH. Plus they can recover a good bit of mud.

One consequence of doing it this way at that depth and in one move, though, is that the mud they are going to leave between the plugs is not of sufficient density to balance the reservoir pressure, as that reg requires for P&A. It sure appears from the e-mailed procedures they never intended to correct that, and thus they would be displacing without that balance as well. SO, not it isn't an either/or proposition. Normally, by my reading of everything, they would not displace the riser they had both a top plug and hydrostatic balance, in addition to the bottom plug. So the move they intended was doubly risky.

I'm not sure how much mud they would have considered normal to displace to do the pressure test if 3000' was deemed much deeper than normal. But if it was way less than what they did displace, how would they achieve the necessary unbalanced state to do the test with all that extra mud, assuming they kept the same mud weight? Would they have to use a lighter mud and then go back to what they were using before to achieve balance before P&A? Would the mud they had been using have been of sufficient density to balance the well if the space between the plugs was 2850' longer (TOC was 2850 higher)?

Syn - You’re getting dangerous close to your PetEng degree. Maybe BP did have some ingenious plan that didn’t work out. Just too much theory for me to analyze. But changing MW takes time and as we all know, time is expensive in DW. I just don’t see the advantage of making the process more complex then it had to be. Maybe some of our drillers can explain it. We’ve watched folks here debate the details of the negative test. This test took time and obviously added an extra level of evaluation. But I’ve yet to see anyone offer a good reason for putting the well in an underbalanced condition. Maybe there is but I’ve never seen a well in my 35 years intentionally underbalanced until they were ready to perf and complete. But that was the expedient thing to do in an onshore well. You already had a balanced well and no riser to displace. When you moved back on to complete you displaced the mud with an equally heavy completion fluid. Keep the mud weight balanced and it didn’t matter if the cmt was holding. If they had displaced with a heavy brine they could have done a neg test when the moved back on to complete. In fact, you usually perf a well slightly underbalanced which would be a perfect negative test.

I mentioned before why I would never leave OBM in csg that I intended to reenter a couple of years later. I would displace with a heavy completion fluid. I would have to do this anyway when I came back to do the completion. Of all the questions to be asked in the official investigation, I'm really anxious to here that one answered: why did you ever put the well in an underbalanced condition?

Why hasn't that question been asked? You need educated lawyers to be able to handle that line of questioning. But surely the MMS attorney is fully up to speed.

I did not realize before that using the same mud they had it would be possible to balance just the well with the riser isolated. But from the calculations done above, it appears so.

To answer your question, though, it appears they allowed for an unbalanced condition while displacing because it would save time? I don't know. Why else? The way it was set up, in order to balance the well before displacing, they would have had to pump mud in to displace some seawater or go with a heavier mud. But the riser was isolated at that point with the heavy spacer and seawater in the DP. It would entail more than just pumping in some mud extra it appears. [I may have this wrong, i need to check what they did again after the test) But as it was, they were all set to displace the riser and then begin cementing right at that level.

It looks like they mapped it out and set the procedures on the 20th based on how they could accomplish everything they needed to with the absolute fewest number of moves in and out of the hole, etc. as possible, and that determined how they were going to proceed, not necessarily what the regs required. They may have figured that since it was only a temp. abandon and not a permanent, leaving the well unbalanced for P&A was okay...by them. (Unless MMS signed off on it in the drill plan.) And even though they should have had both a top plug and a balanced well before displacing the riser, the bottom plug(s) would be good enough with a pressure test, they figured. That made the test critical, though.

Someone will do a chart showing how much time they saved doing it this way as opposed to the safer route. "Looking for Trouble", would be my name for those exhibits.

Edit: Added caveat

And further Edit to the post above Rock's (i can't edit now that he replied): My speculating on mud weights and additional procedures needed to achieve balance and why Hafle chose the depth he did for the plug are just that, speculation.

As I understand it...

Hydrostatic balance involves mud from well bottom up to rig.

Merely closing BOP annular takes mud from there up to rig out of the picture, and well would be underbalanced at that point if there was clear flow path up to rig.

To achieve clear flowpath up to rig they pump seawater down drillpipe sufficient to clear mud from drillpipe and move mudline just above annular, then close annular. Now they have mud above annular taken out of the picture plus some amount of mud below annular taken out of the picture, in this case top 8,000 feet of mud is taken out of the picture (5,000 feet above annular plus 3,000 feet below annular), well is way underbalanced, and drillpipe is free of mud giving that clear flow path to rig.

Then they bleed off drillpipe pressure hoping it will drop to zero and stay there for 30 minutes with no flow (or valve off drillpipe to prevent flow and hope pressure stays at zero for 30 minutes).

There. They just did a negative test.

If drillpipe pressure stays at zero with no flow for 30 minutes, neg test has hoped-for results and is deemed successful.

Again, this is my understanding of it, nothing more.

I think RM is referring to why, after they did the test, didn't they proceed to balance the well before they displaced the riser, especially since the regulations appear to require sufficient density fluid between the two plugs to balance the reservoir when doing a P&A.

Had they done that, even if they skipped doing the top plug, the well would not have flowed as they displaced the riser even with bad cement. It would have been a nice safety step to take even if they were not going to set the top plug. And the regs required it, it would appear, since that is what is required for permanent abandonment. Temp. P&A regs saw follow permanent P&A procedures.

More specific question is why did they not set lock-down sleeve and top plug before displacing riser?

Answer: It would have required another drillstring round trip costing probably $300,000 or so in extra rig time.

IMO saving that $300,000 or so in rig time is why they switched things around to displace riser, then top plug, then set lockdown sleeve.

This is what OIM Harrell got upset about. BP switching things around creating a risky situation to save a few hundred thousand dollars in rig time, and wanting to skip the neg test altogether to save more rig time.

Is this fact or just something you created to support the preconceived conclusion that they compromised safety for cost?

The lockdown sleeve has nothing to do with well integrity and wouldn't have done anything to prevent the blowout. The LDS isn't needed until years later when the well is put in production and thermal stability becomes an issue.

The guy from DrillQuip (at the rig to install the LDS) testified the correct way to do the LIT-LDS is after displacement to seawater. Doing it then avoids problems that can occur if done before removing the mud.

I don't have the BP report in front of me but I think it addresses this and it is actually the reverse of what you are saying. The plug depth determined the amount to negative pressure test to, not the other way around. But there was one factor before this that went into the decision. The hang off weight needed on the hangar lockdown setting tool. So the thinking sequence was:
1) Calculate the amount of drill pipe that needed to be hung off of setting tool. Approximately 3000'
2} So the plug could be set no higher than 3000' below mudline to accomodate the hanger setting tool.
3} Then calculate the underbalance condition that would be in the well with seawater down to 3000 below mudline. That was the test pressure then for the negative test.

I repeat, I don't have the report in front of me so I may not remember it exactly correct. It was after all a long report.

Bingo! Thanks ROM. After re-reading the mud calculations above, i realized i got things pretty jumbled up there, having forgotten about the pressure readings and focusing only on the mud weight. But i could not edit any longer. I'm just groping at this stage.

But you provide an explanation for the 3000' depth, and maybe it's out there already, but I never heard an explanation for that, and it was a mystery to me why that depth exactly. If you just calculated that on your own, I bow to you in respect for your insight and knowledge. The explanations I have heard given might make some sense, but they didn't seem to warrant that particular depth. Faluza thought it very odd, too. He had no idea why.

But it fits in nicely with the theory that procedures for the 20th were determined by figuring out how to do everything that needed to be done with the least amount of rig time involved possible, and waiting time.

I wish I could take credit for figuring that out but I didn't. It was in the BP report issued yesterday.

Do you have a link to the MMS regs you quote about the balanced between plugs. It hasn't been that long since I retired but it's been quite a long time since I dealt with MMS regs. The internet didn't even exist at that time. I remember you had a post way back when with the details but I can't find it now. I want to look at the context and see if I can recreate the thinking of the displacing and plug placement.

I'm sorry but if this was against MMS regs, I would have thought the MMS questioners would have been all over it at the Kenner hearings. I can't help but think you/we are missing something.

As far as "But it fits in nicely with the theory that procedures for the 20th were determined by figuring out how to do everything that needed to be done with the least amount of rig time involved possible, and waiting time." (Don't know how to put a quote from your post in a nice box), I have to say that they wouldn't be doing their business if they did it any differently. The key is to do it SAFELY in the least amount of rig time involved. It's not always straight forward but rig time ALWAYS has to be considered. Sometimes you don't have a choice but accept some extra rig time but every decision ever made involves some level of risk/benefit analysis.

ROM, I have wondered why it has not come up as well, except that they still had some steps to go and could have still balanced the well before setting the top plug. It's only of hypothetical interest in that regard. They had not yet violated the reg. And maybe it is in the drill plan.

But even if the regulations don't require it for P&A, it seems best practices would require balancing the well before displacing the riser. The new regs specifically require two barriers, one mechanical, when displacing. ANd the current regs have broad requirements to follow good well control practices. Maybe they did and everyone missed it, but it seems curious no one at the hearing discussed the well being under-balanced while they were displacing.

In any event, the pertinent regs are quoted below and the link is at the bottom.

And yes, that was a pretty stupid thing of me to say. Of course they're going to figure how to do things in the least time. Duh! I'll blame it on the headache. I should have been more precise. It seems they were possibly willing to cut some safe practices to shave more time off the procedures they still had to complete.

§ 250.442 What are the requirements for a subsea BOP stack?
e) Before removing the marine riser, you must displace the riser with seawater. You must maintain sufficient hydrostatic pressure or take other suitable precautions to compensate for the reduction in pressure and to maintain a safe and controlled well condition.


§ 250.1715 How must I permanently plug a well?

(a) You must permanently plug wells according to the table in this section. The District Manager may require additional well plugs as necessary.

Permanent Well Plugging Requirements

(8) A well with casing...

(9) Fluid left in the hole...


(8)A cement surface plug at least 150 feet long set in the smallest casing that extends to the mud line with the top of the plug no more than 150 feet below the mud line.

(9) A fluid in the intervals between the plugs that is dense enough to exert a hydrostatic pressure that is greater than the formation pressures in the intervals.


And here's on temp abandonment, where it says to follow permanent abandonment P&A procedures:

250.1721 - If I temporarily abandon a well that I plan to re - enter, what must I do?


(b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in 250.1715

SYNC. I have confusion here. Are we mixing up "cased" holes with "un-cased" holes. Why would you have to worry about hydrostatic pressure in the "interval" between plugs, in a cased hole, where the mud in that interval is not in contact with the rock formation?


Your link to the reg did displayed an unformatted jumble for the table for me.

Looking at another source of 30 CFR 250.1715 (via a Cornell page), one that correctly formats the table, it occurs to me that this might not be a "Fluid left in the hole..." well but rather a "Fluid left in the casing..." one, except for the small annular section below the bottom of the last liner.

For "Fluid left in the casing..." there are no requirements regarding hydrostatic pressure.

For that small annular section, they were not displacing it. Whether the mud ahead of the cement had sufficient weight to meet the pressure requirement after the annulus was sealed, I don't know.

Displaying the table contents as if "THEN YOU MUST USE" #9 applies to "IF YOU HAVE" #8 is incorrect, however.

Now, I might be wrong with my "Fluid left in the casing..." theory. But it seems to me that the fluid in the annulus still has to be taken into account in determining whether the requirements of #9 have been met, as well as the question of whether the MMS District Manager may have waived the requirements when BP's abandonment plan was approved.


The mud in the backside of the production casing (annulus) was on April 20 very close to balanced with the given reservoir pressure of 12.6 ppg. According to testimony at the MMS/USCG investigation there would be 27 PSI differential on the top seal when the riser was removed.

retired et al - Here's the thing I'm sure you'll appreciate and others will have to contemplate for a bit. Here's the picture: it's 2012. You've just moved the rig on to complete the BP well. After hooking up the BOP etc you GIH with DP to drill out the plug. You know the well has been sitting there unmonitored for 2 years and that the 11,900 psi reservoir has been sitting under a mud column insufficient to keep it from flowing. But you got a couple of plugs to drill out. Question: where will you be when you drill the plugs? Are any of the hands in their bunk sleeping when you drill the last plug?

If my point is to subtle: any time you drill out a plug that has a live reservoir underneath it, even when you've left a heavy fluid in the hole, it's more than a little nerve racking. Even with a balanced fluid in the hole some NG could seep into the csg and be a nasty surprise. Granted, most of the time drilling a plug is uneventful. But that's when you have a kill mud already in the hole. Imagine if BP had managed to set the top plug before the well kicked and the cmt job held just long enough. And then 2 years later the completion crew drills the plug out thinking the well is dead and it really isn't. Granted I threw a good bit of hypothetical’s into my story. But wasn't hypothetical is the concern ever hand has when drilling a plug out even when they know they HAD an overbalanced hole initially.

Again, a bit from my expertise. But what would it have taken to leave the hole balanced once they displaced the riser? You add some barite to the mud in the pit and pump a heavy "slug" around. Br isn't very expensive and it would have only taken 6 to 9 hours to raise the mud weight. Let's say that means leaving 800 bbls of OBM behind more than the salt water displacement would have. That mud would be worth around $100,000. So they take the risk to save $100,000 on a well that cost $150 million. I'm all for saving money but the risk to reward of this effort just doesn't make sense to me. Maybe I’m just too cautious but it doesn’t make sense to me.

So they take the risk to save $100,000 on a well that cost $150 million. I'm all for saving money but the risk to reward of this effort just doesn't make sense to me. Maybe I’m just too cautious but it doesn’t make sense to me.

Rockman, I wish I had more than a rumor to go on, but a persistent rumor passed to me by a rocklicker who works in deep water GOM is that BP needed to get the DH off of the Macondo hole and move it ASAP to a new lease before they lost the lease. That is an incentive to hurry in the billion dollar range, not just 100K. This would explain the push to wrap up coming from BP's onshore crew better than just penny pinching. I believe my friend, but they can't talk publicly, and I can't get any other confirmation. Heard any scuttlebutt along these lines?

Brat must confess, I thought female gender from the handle. Was picturing one of the Ewing girls, the blonde. My bad.

brat -- No cofirmation but I have seen some opeators do very wild things in an effort to get a rig to a lease as fast as possible. So the basis of the rumor is credible IMHO.

See by Hiver-- http://www.theoildrum.com/node/6756#comment-683844

"They were supposed to go drill another well for BP by March 8, according to NY Times. http://www.nytimes.com/2010/05/27/us/27rig.html "

ProPublica article on Feinberg, et al.
FOR TFHG and others interested


I am fascinated with the technology that can do what the drillers, ROV's, etc., do a mile under water & have learned so much from everyone on this website, even though a lot is still way over my head. Thank you all! marinetraffic.com is showing the Q4000 underway & appearing to head to shore. Destination still shows MC252 & it looks like C FREEDOM is following. Thanks again, this as been something a regular person, even one living on the Texas gulf coast, never would get to see. We occasionally see a platform pass through, but unless one works offshore, or in the industry, that's all we see.

Hello to everyone:
In all of the analysis of the explosive event here presented, it seems the "mixture of two chemicals" has been forgotten about. I remember reading, here at TheOilDrum, about how the usual mud was replaced with a mixture of two chemicals. This was done so that the two chemicals could be disposed of at sea as part of a drilling operation --- a ploy to save the cost of properly disposing of the two chemicals where they were warehoused. One of the platform hands tried mixing the two chemicals as a small batch: it formed a "snot". A similar "snot" was observed dripping off of the overhead structures after the event. The mixture of two chemicals did not behave the same as the mud/water that was supposed to be counterbalancing pressure conditions within the well assembly. This is my recollection. I see no mention of this in the arguments presented on this day, September 9th 2010.
Has this datum of "a Two Chemical Mixture used instead of the usual mud" been declared void? Was this mixture in play at the time of the explosive event? I have tried searching the site and find only "Stephen Bertone, Transocean's chief engineer, testified earlier Monday that he was surprised to see slippery fluid that he likened to "snot" on the deck ..."

I recall there was speculation that the snot-like mud could have blocked the kill line and gave the zero-press readings.

If what you say is true then it points blame at MI-Swaco for sinking the rig.

TransPcean introduced this theory in their in house investigation and report on the disaster.

The fact is that either the heavy spacer plugged the kill line or somebody from TransOcean closed the valve on the kill line.

MI-Swaco mud engineer testified the heavy spacer mix wouldn't plug the kill line.

I am quite surprised by the videos taken inside the BOP showing the erosion in the steel of the BSR blade and the casing around it.

The blowout sand blasted (I assume there must have been sand involved) its way out to the surface!

I'll say the same about that poor piece of drill pipe that was squeezed in the annular (ref: the picture in the Bly BP report). That drill pipe is tough steel - 135+ Kpsi yield strenth - not any bozo steel alloy!

These observations raise the question: is it reasonable to expect a DW BOP to interrupt a blowout?

Maybe we don't find out. What else you got? 60% isn't very good for a critical piece of gear.


Sorry saw an H as in DWH. No, they need to be made better. Time to put the pocket protected on it.

While we're discussing pipes and NG....


Edit: (KRON) they are saying it's a 24" gas main, which is still burning. There are reports that PG&E had been called in a while back to investigate gas smell. D'oh.

Just heard a reporter near the 20' by 30' by 15' deep crater - he says he saw a section of 24" pipe around 20' long some distance from the hole, split "like a banana when you're making a banana split."

(KRON) they are saying it's a 24" gas main, which is still burning. There are reports that PG&E had been called in a while back to investigate gas smell. D'oh.

I read in one story that several people reported hearing a plane in trouble right before the explosion, but supposedly no planes are missing in the area.

SL: I have it from a friend in SF that the sound people heard was the pipe actually starting to rupture. They say it sounded like a stuttering engine. Seems this pipe just ripped open before anything caught fire, and then the gas explosion finished the job big time.

They say it sounded like a stuttering engine.

Guess that explains it, then. What a nightmare.

SWIFTY - the radio report this says over 50 homes completely destroyed and ove 100 with some damage. Maybe 3 confirmed deaths. Injuries are uncertain as some folks were self transporting to the hospitals. Stories like this always bring to mind the most powerful non-nuke bomb in existance: fuel-air bomb. Nothing more than a giant container of NG that's quickly released to the atmosphere and then touched off.

I now hear a report that there is a 20 foot section of the pipe that blew completely out of the hole. And get this: The report says it is split lengthwise like a banana for a banana split. To me, that says seam failure. Don't they ever pig these big interstate lines? This is getting ridiculous.