BP's Deepwater Oil Spill - Industry Task Forces Report - and Open Thread

This thread is being closed. Please comment on http://www.theoildrum.com/node/6948.

In response to the Deepwater Horizon oil spill, four industry task forces were formed, to look into better ways of preventing oil spills in deepwater locations, intervening when an oil spill does occur, and responding to oil that has been spilled. This week, two of the task forces made their reports; the other two task forces had made their reports in May. The American Petroleum Institute issued a briefing paper on the reports.

The Subsea Task Force made 29 recommendations, which can be found in this report. One of the major recommendations was the formation of a Marine Well Containment Company (CC). Such a company has already been started by four of the major oil companies, as discussed in previous posts. Some of the things the CC is expected to do initially, in order to provide near-term response capability are the following:

  • inventory equipment and capability that has been proven fit for purpose through use in response to the Macondo blowout and acquire all appropriate equipment into a Containment Company;
  • review the services and contractors that are advertising immediate containment capability and contract those best able to deliver near term response to the Containment Company;
  • review available equipment for containment that is available “off the shelf” from manufacturers and acquire appropriate equipment; and
  • review vessels and vessel contracts from the Macondo response and contract for those vessels necessary to provide near term containment response.

A sample of a few of the other action items of this task force include:

2. Ensure that a lower marine riser package (LMRP) can be removed from lower blowout preventer (BOP) using a surface intervention vessel and remotely operated vehicle. This will allow access to the mandrel on top of the BOP and the installation of subsea containment assembly.

3. Ensure effective methods to release LMRP without riser tension.

4. Remove damaged or non-functioning BOP stack to allow installation of a new BOP on the wellhead housing, or the subsea containment assembly (Note: this capability is available now).

5. Regain full control of BOP stack by pulling and repairing the LMRP/pods and rerunning the LMRP (Note: this can be done now). Research and develop ways to regain control over all important BOP functions in the case where the LMRP is damaged and cannot be removed and in cases where the LMRP is removed but cannot be repaired and re-run.

The other task force making a report last week was the Oil Spill Preparedness and Response Task Force. The summary of findings of this group includes the following:

Oil spill response plans for each industry sector (storage facilities, marine transfer facilities and vessels, pipelines, and offshore facilities) are intentionally as standardized as possible. This improves the ability of government, industry and responders to prepare for events and implement an effective response. However, areas for improvement were apparent. Specific suggestions are made to improve 1) the speed with which the response can be “ramped up,” including modular response strategies in areas such as Area Contingency Plans and Vessels of Opportunity 2) spill response plan content and structure, 3) the role of regulatory agencies, and 4) training and exercises for large spill events.

Oil sensing and tracking was a critical element in the DWH response. A variety of methods for the remote sensing of surface oil were successful at the DWH incident, but there are still opportunities for improvement. A methodology for subsurface remote sensing does not exist and is needed. In addition, improvements are needed in the connectivity between remote sensing data and trajectory modeling, with the goal of developing standardized protocols.

Dispersant application, both surface and subsurface, was a critical element in preventing significant oiling of sensitive shoreline habitats during the DWH response. However, misperceptions and knowledge gaps led to unanticipated restrictions on dispersant use. Industry and government both need to communicate the risks and benefits of dispersant use, as well as the safety and effectiveness of dispersant products. Furthermore, additional research should focus on the behavior and long term fate of dispersed oil in the water column when dispersants are applied near the sea floor.

In situ burning was a highly valuable component of the DWH response ththat would not have been possible without the research and regulatory changes of the past 20 years. However, in situ burn technology remains limited by the performance parameters and similar to dispersant use, misperceptions and knowledge gaps led to delays in utilizing in situ burning and resulted in missed opportunities to remove more oil from the water.

The basics of mechanical recovery systems have not changed appreciably over the years, but incremental improvements continue to be made. While containment and removal is the preferred option, when possible, the practical limitations of such equipment need to be recognized and improvements to function in high sea states and currents are needed. Large skimmer systems also performed well in general, and there was no shortage of local storage capacity. Areas for improvement include continued incremental improvement in boom and skimmer design and a revisiting of the Effective Daily Recovery Capacity (EDRC) calculation for skimmers.

Shoreline protection and cleanup prevents or reduces the environmental effects of spilled oil once it reaches the shoreline. The basics of shoreline protection and cleanup have changed little over the past 20 years, but the knowledge of how and when to effectively collect oil has greatly increased. Some individual state and local actions, which were well-intentioned but in some cases potentially damaging to the environment (such as unnecessary and ineffective booming), need to be avoided through education, strengthened command and control protocols, and local involvement in planning efforts to ensure a cooperative joint response effort. In addition, the lack of trained and experienced individuals available to lead shoreline cleanup activities during the DWH Incident also demonstrates an area that needs addressing.

While the DWH response relied on proven technologies, the potential for new, or innovative alternative response technologies was a key consideration. Early in the response, an active program solicited and field tested technologies that demonstrated promise. This was later supplemented by a federal initiative, the Interagency Technology Assessment Program (IATAP), coordinated by the USCG R&D Center. Proven technologies specific to the DWH incident included the subsea injection of dispersants, the use of dispersants to dissipate concentrations of volatile organic compounds, and high capacity skimmers. Clearly, continued support of innovation in oil spill response is in the best interest of all stakeholders, but there must be a clear process and responsible organization to manage ideas.

The report went on to provide a list of action steps related to each of these areas.

Thanks for this, Gail. Jeez, I do hope they'll soon figure out good alternatives to in-situ burning, since it's so hard on animals in the sargassum clumps and also on air quality. Shoreline protection/cleanup certainly did turn out to be the weakest, most hysterics-causing piece, so may sanity prevail there.

I skimmed the response team's report, a nightmare of bureaucratic (albeit private-sector) gobbledegook that is nearly free of information. The most prominent theme is the need to use dispersants with less interference. Also:

Areas for improvement include continued incremental improvement in boom and skimmer design and a revisiting of the Effective Daily Recovery Capacity (EDRC) calculation for skimmers.

I'm glad they sort of acknowledge the phony claims of skimming capacity in the previous spill response plans.

Some individual state and local actions, which were well-intentioned but in some cases potentially damaging to the environment (such as unnecessary and ineffective booming), need to be avoided through education, strengthened command and control protocols, and local involvement in planning efforts to ensure a cooperative joint response effort.

Yeah, the federal system (power-sharing with lower levels of government) really flopped here, with the state and local initiatives usually leading to expensive, wasteful, ineffective, and perhaps environmentally harmful boondoggles. It's because the "common sense" of local leaders tended to produce tactics along the lines of "drop lots of rocks on it" which BP was powerless to resist and the feds found it politically inexpedient to resist.

In addition, the lack of trained and experienced individuals available to lead shoreline cleanup activities during the DWH Incident also demonstrates an area that needs addressing.

The cleanup effort involved 30,000 people, none of whom knew what they were doing. I guess the system was supposed to provide expert leadership through the cleanup contractors. Apparently that didn't work out.

Good summing-up, Gobbet. It's worrying to extrapolate this experience to, say, the New Madrid fault's next major letting-loose.

FEMA in normal administrations is capable of responding pretty well to disasters. There's no pre-existing organization for dealing with oil spills.

FEMA in normal administrations is capable

Yes, but I fear more abnormal administrations in future.

Gobbet: Are you writing a book on the spill and aftermath? You should, and I'd be an avid reader!

I've been thinking the same thing, NRD, and he's got a great thonkin' chunk of his first draft all nice and tidy on the "Comments by Gobbet" page.

I think that some of the problems fthat result from the 'locals' doing the wrong thing could be resolved is DHS changed the way the provide grants for training and staffing of emergency response positions at the local level. Instead of trying to provide 'all hazards' and specalists at all locations, provide grants for 'all hazards' and a few specialists. The catch is that the 'specialists' are considered to be availible for nationwide deployment. As a result: a place like Southren Calif would have a pool of 'all hazards,' earthquate, and wildfire specialists, but also have a pool of specialists working in 'low probability - high consequence' disasters. (Or better yet - make everybody an all-hazards with an additional specialty.) This way, if there is an oil spill - the appropiate specialists could be mobilized on a national level and sent to assist local governments.

Another key issue is excercises. Unless you practice your response plan under conditions that mimic reality (with additional problems thrown in to ensure that the plan can be moditied on the fly) you will never know if you plan has anything to do with reality. For $10 million a year DHS can sponsor 5 excercises every year that test (and train) the response to low-probability events.

Next, all emergency response plans should take into account the fact that over 80% of the response is going to be performed by people undergoing OJT. nd for some low-probaility events ypou may have nobody there who has ever responded to that type of emergency before. (How many of the people who dealt with Three Mile Island are now retired?)

Finally, we should all be willing to accept an amount of wasted effort and chaos in the response to an emergency. There is an old saying iin the military: "A poor solution implemented immedeatly and with follow-up is generally better than a perfect solution implemented too late."

..... all emergency response plans should take into account the fact that over 80% of the response is going to be performed by people undergoing OJT. nd for some low-probaility events ypou may have nobody there who has ever responded to that type of emergency before. (How many of the people who dealt with Three Mile Island are now retired?)

Finally, we should all be willing to accept an amount of wasted effort and chaos in the response to an emergency. There is an old saying iin the military: "A poor solution implemented immedeatly and with follow-up is generally better than a perfect solution implemented too late."

You raise some good points. While some of the criticism of the DWH response is valid, I think a lot if it is from armchair experts who have never actually been directly involved/responsible in running a response to large emergency event. While we can always do better, a certain amount of chaos, confusion, and wasted effort is inevitable.

While I have never been involved in something on the scale of DWH, I have long been a member of a local volunteer wilderness SAR group. I have some experience with how these things go down. Most SAR events are small, and are resolved by one or two local teams. A small number of people who often work and train together. Very occasionally, there is a large real deal SAR event (large in the relative sense) that may involve hundreds of people, including multiple official agencies and volunteer groups, as well untrained members of the public. This becomes a very different deal.

To learn how to manage these rare but big events, once or twice a year we have a big joint agency excercise. This usually involves some individual skills training, and a big simulated excercise. Different groups (State Troopers, US Forest Service, organized volunteer teams, etc) get the opportunity to work together. Every group/agency has it's own protocalls, procedures, priorities etc, but these excercises give us all a chance to learn how to work together towards a common goal. While we can never make these things totally realistic, the practice does help when the real thing occurs.

One thing I've learned in the excercises, and always seen in the real events is that there is ALWAYS some chaos, mistakes, and wasted effort. The value of the practice is that you learn to expect this, allow for it in your planning, and learn to work around it in your response. In the military, this is sometimes referred to as "friction", or the "fog of war". You try to minimise it, but you also learn to expect it, and deal with it. When the event involves large numbers of previously untrained general public, it will happen even more. Expect it, and learn to deal with it.

As I said, I've personally only been involved in big things (in the local sense) involving a few hundred people. However, several friends of mine who have had spill training here in Alaska, have done tours down on the Gulf Coast working on the DWH response. From what they have told me, their experiences there mirror very closely what I've experienced in local SAR events, just on a larger scale.

Pre-planning, individual skills training and practice, and large realistic (as possible) excercises can help in a big way. We can get a lot better. Just recognize that these things will never go as smoothly as we would hope. There will always be some element of "Cluster F**K" in this sort of thing. A favorite quote of mine is attributed to Dwight Eisenhower, who commanded the Normandy Invasion. He said "Plans are worthless, but planning is essential!"

Yesterday the failed BOP and LMRP from the Macondo well made their way up the Mississippi River to the NASA Assembly Facility at Michoud. For many of us who have watched the entire sequence of events unfold, it was like watching a funeral procession. There was a mixed atmosphere of joyfulness and sadness in #theoildrum.

My brother lives in New Orleans, so I called him and asked him to go down to the ship channel and take some photographs. They were taken from roughly this spot. These are the last known publicly taken photos of the BOP and LMRP.

The USCG Cutter RAZORBILL, leading the convoy

The Emily C Cheramie towing, and the Baltic Dawn pushing the LMRP and BOP on a barge

Goodbye failBOP, you gave us a solid 3 months of non-stop cam watching, and helped to develop a once-in-a-lifetime community at #theoildrum and on theoildrum.com

RockyP (from #theoildrum) has posted a mashup here: http://www.youtube.com/watch?v=kxFNZwQ9Mis

Wonderful citizen journalism -- you guys take a bow, Smokebreak!

Thanks--nice pics-- it does have a strange ceremonial quality for all us junkies. Too bad the doughty little Top Hat didn't have a place in the procession.

Kind of sad ceremonial close ...

Also sad: Yesterday ROV UHD30 visited the grave of an old colleague of his from the Deep Water Horizon.

(DWH ROV cage with the ROV laying on its side on the seafloor.)

More pics of that scene here (by "westfield") and as video mashup (by "Glyphy").

Yeah I watched that, all the while expecting it to place flowers.
It was sad.

Is there a memorial site to honor those who lost their lives?
Was there ever a ceremony at sea?

Tom - On May 25, Transocean honored the 11 missing crew members in a memorial service in Jackson, Mississippi. I can't explain why but in general the oil path doesn't tend to have formal memorials. Personally I stopped going to funeral services and memorials long ago. One of the 11 was the nephew of one of my hands. Even sadder was that he lost his adult son in an accident just two weeks before the BP explosion. I expressed my regrets once. Since then neither of us has brought either incident up. Just guessing but maybe since the thoughts of such accidents are never far from mind there's little need to verbalize.

Lost my last close oil patch buddy about 16 months agao. Didn't go to his memorial (no body recovered) in Lafayette. Hardly a week or two goes by when something doesn't remind me of Mike. But rarely ever talk to anyone about him. Maybe because just writting this short note brings tears.

Thanks, Rockman.
Dad was a submariner, lost many friends at sea.
Best wishes....

Full video of UHD30 finding the "dead" Deep Water Horizon ROV.

It's as if it was startled by it.
How do we know it's dead? Did it check its pulse?
If it wasn't on board, or if it got blown off board early on, there's still hope, isn't there? If it was on board and got blown off and its camera was on, could it tell us what happened?

Smokebreak, Thanks for your idea, and to your brother for the implementation. And to RockyP for his creative presentation. Just terrific pix!

"Goodbye failBOP, you gave us a solid 3 months of non-stop cam watching, and helped to develop a once-in-a-lifetime community at #theoildrum and on theoildrum.com."


In the closed thread, Mainerd wrote:

Can't wait until the documentaries, hope Nova does one.

When this is all over, somebody ought to put together a compendium of the best videos (although there are so many good ones, it'll be tough to choose). It really would make a valuable historical document (or at the very least, a great nostalgia trip).

Edit: And effusive thanks to Smokebreak and Brian and RockyP for the Entry of the FailBOP into NOLA video. Very, very nicely done.

All of the photos and videos have been just superb - thanks to everyone involved in making them available. As a matter of fact, I posted a small collection of them at another site (with links and attribution) just because I think they're so interesting. With luck, others will be interested, too.

One reader did send me this note:

1922 marked the birth of the blowout preventer. And the original BOP lives in a neighborhood near you. The MO BOP is not in use today, having evolved considerably over 80 plus years. The original MO BOP was displayed at the Smithsonian's energy center in the early 1980s, and it was returned to Cameron headquarters, Houston, where it is now on display in the lobby.

Who knew? The next time I'm in the area, I may stop by and see if I can visit.

Can you please link to your site?

Oh, gosh! Sure. I do most of my "real" writing here, but also maintain a page at Weather Underground, where I posted the BOP videos and links.

Thanks again for such terrific work!


Many thanks to you and your brother for getting those great shots, and letting us in on the drama of dodging the black helicopter.

Just to clarify, the Coast Guard wasn't the only escort of the FailBOP - looks as if both the Secret Service and Fibbies had craft (both air and water) in proximity. Here's a link to the District 8 report:

(I looked, but didn't see them buzz your brother!)

Smoke, many thanks to you and your brother.

It was such geeky good fun yesterday to follow the BOP's progress on Marinetraffic.com with the good folks on #theoildrum, complete with your relay of your brother's play-by-play as he vaulted over the wall to chase along the top of the levee to intercept the convoy - and then to see the photos not long after.

Great way to wind down what has been such an educational summer, thanks to so many patient, knowledgeable posters here and there.


In the just-closed thread you requested a link to the cement formulation Halliburton used for the production casing. It's in Appendix K to the BP report. Appendix K is among a group of appendices zipped together (a 49+ MB download) here:


I've extracted the formulation below, but it's best to check the document itself to ensure I didn't make an error in typing it.

Halliburton base slurry design (from BP investigative report, Appendix K, page 5):

Lafarge Class H Cement
0.07% EZ-FLO
0.25% D-Air 3000
1.88lb/sk KCl Salt
20% SSA-1 (Silica Flour)
15% SSA-2 (100 mesh)
0.2% SA-541
0.11gps ZoneSealant 2000
0.09gps SCR-100L mixed with 4.93gps Fresh Water at a density of 16.741 lb/gal


ChuckV - Okay, I'll try it per the Energy Resources document

Pumping Cement
The cement program would have started immediately after circulating. Assuming the modeled program was followed, 7 barrels of 6.7 pound per gallon (ppg) base oil would have been pumped first to sit above the cement in the annulus to lighten the hydrostatic pressure. It was followed by 72 barrels of 14.3 ppg spacer fluid that keeps the base oil and mud away from the cement and helps wash out the area to be cemented. The bottom-plug dart was released behind the spacer.
Following the spacer, 60 barrels of cement was mixed and pumped, consisting of 5 barrels of regular 16.7 ppg cement, followed by 39 more barrels foamed up to a volume of 48 barrels of 14.2 ppg foamed cement, followed by 7 more barrels of regular cement. Thus, foam in the middle behind a front and back slug of regular cement. The total amount of cement needed had been calculated by Halliburton based on the cementing height required, the casing diameter, and the hole volume as calculated from caliper log data.

On a per gallon basis we can form this mass balance equation

[39 x 16.7] + [(48 -39) x X] = [14.2 x 48]

[651.30] + [9X] = 681.60

9X = 30.30

X = 3.37 ppg

1 cu ft = 7.48 gallons

Therefore, the nitrogen has an effective density of 3.37 x 7.48 = 25.20 pounds per cubic foot.

Going to the NIST data http://webbook.nist.gov/cgi/fluid.cgi?Action=Load&ID=C7727379&Type=IsoTh...

Nitrogen at a temperature of 110 deg F would have to be at a pressure of about 7614.7 psia (call it 7600 psig) to have a density of 25.221 lbs/ cu ft.

Given that they feed the nitrogen from a 2,000 psi source through a foaming nozzle into a pressure of 1,000 psig, they cannot develop 7.600 psi at the surface. And the pressure at the shoe is at least 12,000 psig to overbalance the formation pressure of 11,900 psig, so the density downhole would be 31.842 lbs/cu ft.

I am becoming convinced that it is a fool's errand to try and make thermodynamic sense out of the calculations of guys whose education ended at graduation from high school!! I didn't get to Thermo until I was a junior in college. These guys are utterly clueless in regards to thermodynamics.

Once again, I totally agree with BP's recommendation that the API do basic research into cementing at depth, because I think the industry as a whole is just as clueless as these guys, which would go a long way toward explaining why so many cement jobs fail.


After making that rant, would you feel like a fool if I were to suggest to you that it's implicit when talking about 48 bbls of foamed cement that the meaning is 48 bbls, measured under in-place (downhole) conditions?

It appears that those clueless cementing professionals, limited as they are by a high school education and ignorance of thermodynamics, don't see the value in talking much about surface volumes of a product designed to be placed deep in a hole.


But the mathematics above, along with the NIST data, shows that they can only have 48 bbls of foamed cement, starting with 39 bbls of the base slurry, if the other 9 bbls is nitrogen; which requires a pressure of 7,600 psi, which is much less than the actual pressure at the formation.

You can't get to there (48 barrels of foamed cement) at 12,000 psi from here (39 bbls before foaming)at the surface, even with 1,000 psi in the line at the injection site.

If you think these guys are so smart, why do they seem to believe natural gas exists as a gas at 12,000 psi, rather than as a supercritical fluid? Answer, They don't know thermodynamics.


I don't suppose you'd entertain the possibility that your simple arithmetic calculation demonstrates a trend, but not a precise result; that perhaps pressure is not transmitted to tiny nitrogen bubbles in a mix of cement, sand, salt, water, flow enhancer, surfactant, retarder, defoamer, and thermal thinning control agent in exactly the same way that it is to nitrogen alone?

If your disdain for CSI Technologies is less than it is for the folks who designed and implemented Halliburton's OptiCem software, you might try carefully reading page 1 of Appendix K again.


Substitute 14.2 ppg brine, spacer or whatever, and everything is perfect. That is what BP should have done, what the spirit if not the letter of the regulation required, and what would have, should have, could have prevented this disaster. Why they didn't do this is beyond me.

Ambien dosage

[-] geo_man on September 12, 2010 - 6:06pm Permalink | Subthread | Parent | Parent subthread | Comments top

You yourself stated a while back that oil-based mud left in a hole for multiple years is a very bad idea. It solidifies, coagulates, or some such thing, and you have to drill it out when you complete the well.

Substitute 14.2 ppg brine, spacer or whatever, and everything is perfect. That is what BP should have done, what the spirit if not the letter of the regulation required, and what would have, should have, could have prevented this disaster. Why they didn't do this is beyond me.

Reply | Reply in new window | Start new thread | Flag as inappropriate (?)

Shouldn't plagiaristic commercial spam be illegal?

It's like some guy breaks into your house at night, dresses up in your wifes clothes, then greets you in the morning with breakfast and an offer for Ambien.

But if the guy looks good in your wife's clothes and the breakfast is good and gives you kiss before you go back to sleep (from the Ambien) and tucks you in, then should it be legal? ;-D

Two wives? Not legal.

Of course, new wife probably served old wife for breakfast, but still, not legal.

"which would go a long way toward explaining why so many cement jobs fail."

But then Haliburton wouldn't be so successful, would they?

Yeah and thanks snakehead for the info on last thread. Was that the final well plan? I still have doubts on the Corexit complete recipe, its secret ingredients.
And thanks CV. Hope the experts here can do something with all that.

(sure been adding a lot to my dictionary lately. and sure hope added spelling is accurate)

Rant Warning:

I never had a good experience working with Haliburton. Never.

RE: Last night's little Wagner subthread:

Not that it matters much, but correction is in order; my brain's accompaniment for the procession of the BOP was


Hence the seemingly erroneous reference to frenzy. Here's the frenzy. The music still plays well in there, but have to admit it's never been so good with names. :)

Oh, Lizzy, I spent a good portion of my childhood trading off turns with little brother "conducting" (atop the piano bench, with a flute-cleaning rod for baton) or "being orchestra" on "The Ride." Thanks for the fun.

Hence the seemingly erroneous reference to frenzy.

Well, there's some nice frenzy in the Valhalla piece too. ;-) And the Mississippi is a fine stand-in for the Rhine.

I had the fantastic good fortune as a teenager to attend a performance of Die Walkure at Bayreuth, which has incredible acoustics. When the orchestra launches into the final iteration of the Ride theme with 100 percent of its forces (at 3:35 in this video), you can't even breathe, and you think your insides are going to come right out through your ears.

Here's a concert performance with the Valkyries singing "Hojo-to-ho" (don't watch, just listen, with earphones if possible).

My freshman year in college, my dorm was across the street from the Conservatory. A French horn major reserved a practice room directly opposite my room every morning and would and play "Ride of the Valkyries" out the open window promptly at 7:00 a.m., obviating any need for an alarm clock.

obviating any need for an alarm clock

Lawd, I reckon! Thanks for the Valkyries (chair-dancing with a surprised cat ensues . . .)

ducky - Ray - syn - rf: I went to bed to early apparently. LOL

Ray - That was my point. Perhaps you missed my other post. There are different protocols while completing a well than temp abandoning one. Have you ever left a well underbalanced for 2 years? If so I assume it was done offshore. And what was the justification for doing that? Or did you and I get twisted off comparing apples to oranges?

duck/rf - rf: Sorry couldn't follow your point. Not sure why you used a 9,700’ column to calc a bottom hole pressure. BHP is a combination of all fluids in the column. A 13,000’ column of 14.2 ppg mud yields a 9,600 psi. Add the water column pressure of 2,300 psi and you get a BHP of 11,900 psi. Thus the well is balanced ( but not enough margin for my taste). If you want a 500 psi margin of safety over the reservoir pressure than you would bump the MW up to 14.9 ppg from the 14.2 ppg. Doesn’t cost hardly anything compared to the cost of the well let alone the blow out.

Syn - Sorry…you completely lost me. I can’t see the connection between the depth at which they displaced mud from the prod csg and any other activity such as csg hanger work. What am I missing. Thanks in advance.

Bottom line: if BP had left the 14.2 ppg mud in the 13,000’ of prod csg (= 11,900 psi including the water column pressue) and then removed the riser the well would have been balanced. Barely but balanced. If they only displaced the top 3,500’ (still haven’t seen positive confirmation that they didn’t displace mud deeper) of 14.2 ppg MW from the csg then that left the well underbalanced. There maybe a very good reason to displace that top 3,500’ of mud with sea water. Just haven’t heard it yet.

The bottom bottom line: had they bumped the MW up to 14.9 ppg (at an almost imperceptable cost and with a 500 psi safety margin) they could have removed the riser and the well would not have blown out if they had no cmt in the bottom of the well let alone a bad job. Technically they didn't even need to set the shallow cmt plugs other than to follow the regs and add a second safety protocol.

"Bottom line: if BP had left 14.2 ppg mud in the 13,000' of production casing (=11,900 psi including the water column) and then removed the riser the well would have been balanced."


My back of the envelope mud weight estimate after complete displacement of the riser is as follows:

8367' @ 8.54 ppg=71,454 Seawater in 3313' of casing plus riser
9123' @ 14.17 ppg=129,273
545' @ 14.30 ppg=7794
18,115' 208,521

208,521 divided by 18,115' computes to an average mud weight of 11.51 ppg (1.1 ppg underbalanced)

The mud weights are from the opicem (tm) model provided by ChuckV. Of course this assumes the mud weights prescribed by Haliburton to follow the cement into the hole were used. Probably close but who knows.......

From the last thread regarding the kill cement job:

You said something like, "the job pumped resulted in 5,000' total (3,000' in the casing and 2,000' in the annulus)."

The kill cement job was 500 barrels total. From pressure charts, it appeared the cement went down the casing with 200 barrels exiting the casing and leaving 300 barrels in the casing. Your memory is perfect but your decimal point is floating and your units are wrong:)

I don't mean to be argumentative. Just trying to be some what precise.

The Admiral mentioned 5,000' of cement when discussing the missing drill pipe that was thought to be dangling from the BOP but wasn't. As you say, there is no guarentee that BP estimates are accurate. For example, the question of whether the drill pipe is cemented could change the estimate significantly (80 barrels as/per ChuckV).

The mud weight question is a good one. You would think the MMS Panel would try to nail down the mud weight that followed the original cement job into the hole but I don't recall one question on the subject.

Could they have simply bumped up the mud weight that followed the cement job? This would not have taken any extra rig time. There may be a reason this was not done but I can't figure it out. If they wanted to keep the average mud weight behind the cement at 14.2, they could have pumped heavy mud below 8367' followed by light mud in the top of the casing.


NU - Didn’t take your statements argumentative at all. Just trying to float some numbers out for TOD review. Someone calculated that the 300 bbls of cmt in the production csg yielded a 3,000’ column. Don’t have my little red book anymore so I had to take their calc for granted. As far as the MW in the well after the cmt job it was reported to be 14.2 ppg. Again, no black and white documentation that I can offer.

I’ll go with your fluid weight profile: 3,716 psi (salt water) + 6,722 psi (14.17 ppg mud) + 405 psi (14.30 ppg mud) = 10,843 psi or about 1,000 psi less than the reservoir pressure. So had they pumped 9,123’ of 16.3 ppg mud instead of 14.17 ppg then the well would have been balanced regardless of the quality of the cmt job. As you and many others know the differece in cost of those two mud weights is completely insignificant. The mixing and pumping time would have been the same. The only extra cost was some bags of cheap barite. So again the simple question: why run a mud weight profile that would be underbalanced if it cost almost nothing to run a balanced system?

Again. I greatly appreciate any discordance with anything I throw out. That’s the real value of TOD IMHO.

I’ll go with your fluid weight profile: 3,716 psi (salt water) + 6,722 psi (14.17 ppg mud) + 405 psi (14.30 ppg mud) = 10,843 psi or about 1,000 psi less than the reservoir pressure. So had they pumped 9,123’ of 16.3 ppg mud instead of 14.17 ppg then the well would have been balanced regardless of the quality of the cmt job.

This looks real good, Rock. Assuming the numbers are correct.

This is with the TOC at ~3000' below mudline?

What if they did set the depth of the top plug per the regs instead of at 3000'? That would add roughly 2,700 feet to the length of the column, with TOC 150' below mudline. What weight would it take to balance the well then?

syn - Not sure. I was using NU's column profile. Not exactly sure what it was based upon though. I think it was based upon the TOC at the bottom of the hole and not the top plug. Either way my slight modification left the well balanced.

I think I have the scenario correct now. They displaced the top 3,500' so they could do the neg test. But now it seems we're back to chicken vs. egg. Why do a neg test at this phase unless you planned to leave the well underbalanced? As someone mentioned before they'll do a neg test during the completion phase anyway. Remember they waited about 18 hours for the cmt to cure before doing the neg test. That wait cost $600,000 of rig time. But if they planned to put the well back in balance after the neg test why not just pump replacement mud down after the neg test? Instead they kept displacing which was needed in order to get the mud out of they OBM.

So we go back to the basic question we're all waiting to hear: After they finished the neg test why didn't they spend that very little bit of money to circulate around 14.2 ppg mud in the top 3,500' of the csg? Then pull the DP into the well head and displace the riser with sea water. If they had: 11,900 psi - 2,300 psi = 9,600 psi = 13,000' of 14.2 ppg mud = a balanced well = no blow out even with a bad cmt job or no one watching returns. And the cnt would have had a couple of years to cure. And even if the cmt never reached spec the completion crew was going to do a neg test as SOP anyway. And if they found the cmt job no good they would have to sqz it.

You yourself stated a while back that oil-based mud left in a hole for multiple years is a very bad idea. It solidifies, coagulates, or some such thing, and you have to drill it out when you complete the well.

Substitute 14.2 ppg brine, spacer or whatever, and everything is perfect. That is what BP should have done, what the spirit if not the letter of the regulation required, and what would have, should have, could have prevented this disaster. Why they didn't do this is beyond me.

geo - Yep. And as far as I know I'm the only one with that philosophy. On that job with the nasty OBM I had a dozen hands with 30+ years experience each and no one had seen this problem before. Nor any operator that didn't think it was OK to leave OBM in a cased hole for a long time. But why so rare? I've seldom seen an occasion to leave OBM in a well for a long period of time. That well was abandoned deep with no intention to go back down it. We took it over to drill a sidetrack out the bottom of it. Otherwise no one would have ever learned how bad the OBM turned down there.

Despite my pontification on TOD I don't spend much time telling others how to get a job done. I'll explain my experiences and then let them choose their path. Maybe I could write a paper for the SPE and spread the word. But I doubt many would pay much attention to it. But as long as I'm running ops for my company we'll never leave OBM in any well for an extended period. And FYI: I would have probably displaced with a 16 ppg brine. The 14.2 ppg would have just barely balanced the well. As you know bumping the brine weight up some is very cheap...just more bags of salt. I always like a little fudge factor. As we both know Mother Earth will punish arrogance from time to time.

RM, this is apparently why the set it at 3000'. It was part of the efficient sequence of tasks they had laid out for the day to get everything done in as few moves as possible.


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.

Comments can no longer be added to this story.

syn - Thanks. I can see why for the sake of the neg test. But not for the other ops. But why not replace the displaced mud and have the well balanced after the neg test. They did even need to mix new mud...they had the volume they had displaced. save it in the slug pit and pump it back down. Only take a couple of hours.

See my note to NU and tell me what you think. I think you have good handle on the calculations.

Let's see, RM. I think bringing the well to balance by re-filling it with mud up to the BOC level of the top plug if set at 150-300' per regs would have complicated cementing and added numerous extra steps. I recall a Hafle e-mail or testimony discussing this.

If they did it the way they planned, it would go: displace the riser, pump the cement (the casing is already clean from the seawater to depth needed). Set the lock-down sleeve, swab the rest of the casing for corrosion, etc as pooh. I think.

If they did the test, then balanced the well before displacing, they would have to set the lock down sleeve before pumping cement because once they set the plug at the shallower depth, there's not enough room to hang the pipe needed to use the lockdown tool. So does having to set the lockdown sleeve before cementing add an extra trip to the sequence, or what? Plus we have the time it will take to get the mud to weight to balance the well.


Attached is the updated procedure based on our current plan forward. If anything changes I will update and send the next revision out.

We are still waiting for approval ofthe departure to set our surface plug 3000' BML. If we do not get this approved, the displacement/plug will be completed shallower after running the LDS (basic details of this
change are included in this procedure)
. Please let me know if you have any questions or suggestions.

A detailed cement procedure should be available from Jesse sometime tomorrow.

Thank You.
Brian Morel

An interesting comment from the Haliburton report:

•Area of Investigation

- Typically negative test to ~500 ft below well head with sea water

- ~3300 ft below –stated on MMS permit in order to prevent well head seal area contamination

- Imposed additional 1000 psi differential on float equipment/casing/cement

Again, they chose the 3000' level because they needed to hang 3000' of pipe on the lock-down sleeve tool to set the sleeve. That had to leave room for 3000' of pipe to do that in the sequence of tasks they had laid out. That is spelled out in the BP report.

Aha! Latest well plan. But did they receive approval?

Rock. As far as I understand it. They displaced the top 3500 feet of mud in the production casing because that was the design position for the bottom of the "top plug" cement. The negative test was to simulate if the mechanical barriers could hold a reduced hydrostatic head of circa 8700 feet of seawater plus 9600 feet of 14.2 ppg (???) mud. A negative differential pressure of around 1000 psi across the float collar to the formation side of the well bore cement.

The bottom cubed line: The rig crew botched the negative pressure test. Not helped by an LMRP/BOP that was not fit for purpose. The float collar (non return valve), was not successfully converted and probably damaged when they, at nine attempts, used excessive pressure to try and convert it. The shoe track cement failed either by design; manufacture; quantity pushed or contamination, IMO. The oil industry should study the safety protocols of the power industry; should implement hardware and software safety systems that remove the human operator from the decision making process at times when there is no time to think.

acorn - Yep...understand about the neg test now thanks to syn. But cmt plugs are set in OBM all the time. And I agree about equipment/protocol safety. But back to the basic fact: keep the well balanced and no amount of failed equipment or bad tests or bad protocols will allow a well to blow out.

Still looking for the logical justification for leaving this well underbalanced when they displaced the riser.

From 2003 MMS report, comment on good well control practices mean avoiding single-point failures, specifically noting that mud weight is first round of defense:

4.5 Single Point Failures:
Redundant systems are fundamental in controlling a drilling operation. For example, mudweight is the first round of defense against a kick, followed up by annulars and BOP rams and ultimately the sealing shear ram. A single point failure is an individual component failure that, if inoperable, will cause a function to become inoperable from multiple sources. Minimizing single point failures is a good oilfield practice that results in fewer well control events.

syn - good catch, thanks. Interesting that they jump from keeping a proper MW to the BOP. No mention of monitoring mud returns or shutting the well in and killing it. Maybe I'm just being picky but that's the most common step for dealing with a well kick. At this point I doubt there are many of us who think of the BOP as a good "defense".

So, it looks like the BP plan for the day involved taking away the crew's first line of defense in fighting a potential kick. They made them displace to an underbalanced well. And they gave the crew false info before they started when declaring the well had integrity and the cement was good.

Handicapped by the false well integrity info and loss of their first line of defense, the crew was at a severe disadvantage in spotting and fighting that kick.

Their failure to pay attention is obviously part of it. That was through inadvertence. Taking away their first line of defense was a deliberate move, though. And an unnecessary move.

syn - And ain't that the real shame of it if we have the story more or less correct. As we joke about it not being brain surgery it really isn't. Look how many folks on TOD who have no background in the oil patch and still seem to have a good handle on the situation. That alone might make you think these thoughts must be way off. How could the TOD collective appear to understand the situation better than even the poorest oil patch engineers?

It is a shame, Rock. It's a bit emotional. Because once they blew the pressure test and proceeded to displace, the only remaining question was: will they get to the BOP in time? And if they do, will it work. They didn't. And it didn't. (Or maybe they did, and it didn't. It's still a possibility.)

I don't think BP failed to understand anything, though.

One emerging theory is that:

1. The sequence of tasks the BP operations engineers put together and/or issued for 4/20 represented the most efficient sequence they could string together to finish what they needed to get done. The only down side: it was going to leave the well dangerously underbalanced. Putting the well in balance before displacing would mess up this great sequence they put together.

2. The sequence they figured out required setting the top plug 3000' BML. To pull off the sequence, they needed to be able to set the lockdown sleeve AFTER pouring cement, and the only way to do that was to set the plug at the 3000' depth so they could hang 3000' of DP from the lockdown tool used to install the sleeve. This is they key to unraveling how much extra time they saved this way and leaving the well underbalanced.

3. Giving up the balanced well as the first line of defense against a kick obviously increased the risk of the tasks for the day - introducing a single-point failure scenario leading to a blow-out. (And I submit that this is what Harrell and the driller were so upset about.) However, BP operations engineers felt the negative pressure test adequately addressed the increased risk (rationalized it that way), and they further rationalized that the crew would be able to detect and contain any kick when doing the pressure test...while there was still mud in the riser.

This theory might be valid if there is notable time savings over doing the same tasks as per the regs/best practices: with a balanced well and the top plug set at reg depth of 150-300' - before displacing the riser.

If it was not for the time savings, why would BP go to the extreme move of setting the top plug at 3000' and go through the hassle of getting an exemption from the regs to do it, and increasing the risk with the well displaced over 2,500 feet more than normal on a neg. test? It makes no sense but for efficiency savings ... or some other unknown explanation no one has offered yet.

Syn - And maybe because I’m a geologist I don’t understand. OK…set the plug at 3,000’ BML. They could have done this by just taking a few hours to circ the 14.2 ppg mud back down over the interval displaced during the neg test. And then set the sleeve. Not sure but I get the feeling you think they couldn’t set the sleeve in OMB. The only way I’ve ever seen a sleeve set was in drill mud…water base or OBM. There was no need to displace the top 3,500’ of the csg to set the sleeve…only to do the neg pressure test AFAIK. So the only time difference I see is a few hours to replace the mud from the neg pressure test. Let’s say 5 hours = $145,000. So they risk a $150 million well to save $145,000? That makes no sense so I keep thinking I’m missing something big in the time saving category. I don’t see a time savings by setting the plug at 3,000’ vs. 150’. In fact it takes a little bit of time to GIH to 3,000’ instead of 150’. So it seems like the sleeve setting conditions that make the difference. I wish a driller would chime in. AFAIK the sleeve can be set in mud…no need to displace with sea water.

This may well not be the answer but I’ve seen folks follow a procedure when it was obvious to others to not only be wrong but also not a time saver. And in a number of cases very risky. I’ve had more than few comen tell me they were following procedures from the office that didn’t make sense to them. But they did it with a word to the office.

RM the answer to your important and legitimate question may be as simple as the pressure on the rig crew to complete the job before the VIPs left the rig.

Nobody has talked about this organisational issue before but I think it is key.

If I had been in the shoes of SIMM or O'BRYAN I would have delayed the trip until the rig was underway to the next location. The purpose of the trip was to discuss maintenance issues (or so they say...). Maintenance planning could have waited a few days.

The helicopter lands and the VIPs walk on the rig. The dog and pony show begins and the pressure to perform goes up one order of magnitude.
Who delivers the show? The company men and the OIM. These three key guys to the rig operation are now distracted from their primary duties and can no longer focus 100% on the job at hand.

They screwed up the negative test and left the well unbalanced to go faster and please the VIPs.

There is no question in my mind that the presence of the VIP's had a significant impact and may have been another one of the , "if the VIP had not been there, there never would have been a blowout." That may be true.

Why? Because the supervisors would have been running the show, and making the decisions, not Jason Anderson all by himself. As good as he was, he was not up to the task of managing the drilling operations to the extent he was. He was clearly not prepared for the dreadful task that was thrown his way by the botched pressure test and the loss of a balanced well to fight the resulting totally unanticipated kick.

The senior TP and OIM were just too busy with the VIPs, and were not on the floor when they really needed to be.

Since i don't know what i'm talking about, RM, it makes it harder to explain it.

You don't quite have what i'm trying to set out, though.

According to Haliburton investigation rpt., normal depth for neg. pressure test is 500'. During the hearings, no one had ever heard of setting a plug at 3000' or doing a pressure test at that depth, including from BP. This was a first for all of them. Why did they do it at 3000' instead of 500'?

Look at all the extra mud they would have to unload to do this. If they didn't unload any of it during displacement, the well would be balanced. I don't think it would be if they displaced 500' for the neg. test with seawater, but it's much less difficult to replace 500' of mud before displacing the riser than it is to replace 2,500' of mud.

So why 3000'? Because they needed to weigh down the lock down tool to set the sleeve. (See BP Report.) It would take 3000' feet of pipe. Sure, you are absolutely right, there is no reason why they could not set it before setting the plug, except for the extra time it would take. I agree with you. And if the request to do it at 3000' was denied, that's what they were going to do. It is in the e-mails.

But if it was not denied and they could set the plug at 3000', then they could pour the top plug first and then go set the lockdown sleeve. The order would have been, neg test, displace, pour plug, set lockdown sleeve. This sequence involved the least movement and wait time. Enough so that they applied for the exemption from the reg for plug depth and gave up the security of a balanced well while displacing to get it. (Unless BP always displaces the riser to an underbalancded well. That prospect is even more troubling though.)

Compare that to normal procedures, and I bet the savings is in the neighborhood of 1/2 - 1 day over balancing the well and setting the plug before displacing. (I am sure they avoid some wait time, or move it in a way that permits other tasks to get done while waiting on cement that they would lose under a different sequence.) But they had to leave the well underbalanced while displacing to do it. And this sequence tied in most efficiently with the other tear down tasks, like removing the riser, etc. They could do it all quicker this way is the theory.

Time will tell, I guess. But if not for time savings, then what? Makes no sense. The endless loop...until we get more info.

There must be a paper trail here somewhere.

But something that comes to mind is that they may well have simply been trying something new. Someone comes up with an idea for saving half a day. Sounds feasible. Never been tried. But if it turns out OK, it can slowly be adopted and eventually become SOP. After all, that will be how many procedures come into existence.

The problem of course is that this is getting pretty close to what I (rather than a lawyer) would call reckless. Trying something new should include greater safeguards. But the curious situation is that the "new idea" is running with fewer safeguards, and seeing how it goes. The erosion of safety and what I suspect has been an erosion in communication - with a disconnect between the desk bound and the rig - would lead to exactly the problem. The idea that a rig would implement orders from the shore without understanding the reason leaves me with a very bad feeling about the erosion of communication. Harks back to the Apollo era anecdote about the launch engineers. A culture where such lack of communication exists is seriously broken. That is the point where I would be looking for the root causes of the accident.

It could be something as chillingly simple as stupid as a desk-bound engineer performing an experimental procedure change without engaging the guys whose lives are at risk in trying it out. For him it is as simple as a few emails and go home at the end of the day. Not so out on the rig.

I think they tried it because they saw a big efficiency gain in the sequence of tasks it would permit them if they could pump the top plug before doing the lock-down sleeve and after displacing the riser.

There is no reason to go to the trouble of displacing to 3000' and applying for permission to deviate from the regs just as something new. It would actually slow them down if there was no gain downstream.

I think this is what they are talking about when they say BP has a culture problem. They do sh*t like this to save money and they reward people like Hafle handsomely for taking the risks. And it's up to the workers (the crew) to save the day or die if something goes wrong. That's my tin foil hat guess.

P.S. Francis, your thoughts in the other thread on Anderson the whiz kid and the vulnerabilities of whiz kids was spot on. I think he was posturing a bit, too, because of the vip presence and the desire to fill in for his bosses to build their confidence in him. (A purely normal thing.) Ezell admitted he turned it all over to Jason for pretty much the entire tour, save some brief time on the floor. (Not a good move in retorspect.) They needed more than one guy watching the key stuff when there was so much confusion earlier.

Jason did reach out for help from Ezell at the end, but the first explosion happened before he could get out the door of his bunkroom.

But something that comes to mind is that they may well have simply been trying something new. Someone comes up with an idea for saving half a day. Sounds feasible. Never been tried.


Everything you say may be true except "saving half a day". It looks like setting the surface plug at 8367' involved considerably more time and money than setting the surface plug near the wellhead.

This could well be true. In this case I suspect there is a sufficiently solid paper trail that we will get to a definitive answer in time.

Like I have written however - I regard the precise reasons for the choice as much less important than the process that surrounds the implementation of them. Another version of the people failing the system or the system failing the people. Complex systems must have enough safeguards that a single error of judgement does not cause a catastrophic failure. If the rig crew have ultimate responsibility for the well, they must be accorded appropriate information.

Harking back the the aphorism, "there are the plans, and there is what happens." The schedule of operations was a plan. It included contingency plans for if things didn't work out - in some cases. Implicitly the rig crew were expected to know what all the other contingency and emergency plans and mechanisms were. Yet the engineering and expectations of down hole physics was not shared with them except by this design document. That isn't going to work out.

Delete duplicate.

syn - I think I might be able to clear up that one time issue: displacement 3,000' vs. 500'. The time difference would be measured in minutes...not hours. Pumping mud at 40 bbls/minute isn't even considered fast. The volume difference is only a few hundred bbls at most. The time for the mud to reach 3,000' would be less than an hour. The mud volume involved is insignificant. Remember the mud tanks on this rig can handle thousands of bbls of mud. They could have displaced the few hundreds of bbls from the 3,000' displacement into a trip tank and then pumped it back down when the neg test was done.

I suspected this might be where we were disconnecting. Needing 3,000' of DP to set the lock down sleeve was no biggie. At this stage it would take less than 30 minutes to run DP down to 3,000'. And the LS can be set in mud. I can offer you a faster track then your offering (neg test, displace, pour plug, set lockdown sleeve): same as yours except no displacement. They could just have easily (a little quicker) set the plug and ran the LS.

As far as time savings: remind me - is the neg test required by the regs.? In the hundreds of wells I've drilled I've never done a neg test. But then none of those wells had a riser to displace. They all had a kill weight fluid left in the hole when I moved the rig off. When we moved a workover rig back on a neg test would be done as well as running a CBL. You remember my comments about all the cmt failures I've seen. Those were liner cmt jobs and not prod csg jobs. And those were all positive test failures since we had drilled out the shoe. If the neg test wasn't required by regs then that's where there would have been a big time savings (18 hour wait time and the neg test time). When I cmt a liner I'll wait 24 hours or so before testing. When I cmt prod csg I don't wait 1 minute because that cmt won't be tested for weeks and more likely a couple of months when the completion rig moves on.

I think collectively we're pretty close to having all the details tied down. And, as always, we may be missing some details. But other than some BP policies I think we have a clear picture of what was done. And though it seems ridiculous for us to judge all those smart folks at BP, it appears they just did it wrong. And perhaps with little logical reason.

No that is just stupid and silly speculation. The only reason the negative test was supposed to be done down to 8367 is that is where the surface plug is going to be set. The test that is required is to simulate the hydrostac pressure of the seawater in the GOM from surface plug to atmosphere.

If the plan was to set the LDS in mud then there is no need to do a negative test to seawater gradient down to 8367'. If the permit said set the LDS before displacing to seawater, then it also would not have said test well to seawater gradient down to 8367'. There is no reason to test if you are just going to put the mud back in the hole. That would just be silly and stupid.

Th manufacturer of the Lock Down Sleeve recommended to BP to set the LDS in seawater. BP ran the the idea past MMS and MMS concurred that was best practice.

The alternative if MMS didn't approve displacing with seawater down to 8367' before setting the LDS was to go against the manufacturers reccomendation and set the LDS in mud and then set a shallow surface plug then do a shallow negative test and then displace the riser. That would have been much shorter procedure. BP submitted a plan for a longer more expensive procedure because a 3rd party sub-contractor recommended it and MMS agreed.

The testimony so far at the joint investigation seems to support this explanation.

JINN - thanks. Didn't see the reommendation from the manufacturer to set it in sea water. That explains the 3,000' displacement. But I'm a littlle confused: your 8367' - is that MD or below mud line? First time I've noticed that number.

That may be 5,000' from rig to mudline plus 3,367' from mudline down to bottom end of drillstring.
But I'm not math person so you probably should take this with a grain of salt.

http://www.theoildrum.com/node/6946#comment-719023 -by syncro

page 8:
"3. RIH to 8367' and displace to seawater:"
"4. Set a 300' cement plug from 8367' - 8067' (if approved)"


Where are you getting this from "...the only way to do that was to set the plug at the 3000' depth so they could hang 3000' of DP from the lock-down tool used to install the sleeve". Why would it need to hang anything. The Dril-Quip hanger seal is set with a running tool that seals the well side bore of the hanger. Then they close the BOP and squeeze the seal down with 10000 psi from the pumps".

The 3000 odd feet of drill pipe and stinger was to set the top plug cement deeper than normal regs require, to reduce the risk of contaminating the bore in the hanger / lock-down seal area of the well head.

I might be misunderstanding things here, but from what I've read, there were two different Dril-Quip operations involved.

The tool to run down the hanger seal was part of the string that put the production casing into the hole and cemented it. After the cementing, there were some steps in the procedure thap applied pressure to engage the tool and then had the string rotate about a half-dozen times while observing that the string dropped an additional foot or so into the hole.

There was also a "lock-down sleeve" operation being prepared on deck as the blowout occured which I took to be something that was to be wedged into the wellhead above the casing hanger.


Your equation: pressure (psi) = 0.052 * MW (ppg) * column height (feet)

My numbers: 9,600 = 0.052 * MW * 9,700'

9,600 is formation pressure (11,900) less water pressure at 5,000' (2,300).

9,700 is mud colum height from well bottom up to bottom of drillstring where they displaced and planned to set top plug.

Solving for mud weight (MW) gives 19.0476 ppg.

If they had 19.1 ppg mud below drillstring well would have hydrostatic balance, neg test would go fine, zero SPP for 30 min no flow, expected results, test successful, displace riser no worries, move ahead with top plug and rest of P&A.

Agreeing with what you said earlier, it wouldn't matter if casing cement held or not, well would be balanced, no kick no blowout, finish P&A, disconnect, trip BOP out, move on to next job.

And if they set the top plug depth per regs, that would have added at least 2,700 feet to the length of the column.

9700 + 2700 - 12,400. Lets just go with 12,000' column of mud if they had set the top plug at roughly 300' per the regs instead of 3000' per Halfe with MMS approval.

By my calculations, mud weight of 15.4ppg would have balanced the well with 9609.6 psi (plus the seawater), with a mud column 12,000' long, had they set the plug to depth per the regs.

EDIT: So now that we've cleaned this up, assuming it is correct, then the reg. requiring balanced fluid between the plugs before P&A makes perfect sense and does not impose unreasonable burdens.

Fully agree.

Displacing at 8,300' with 14 ppg mud and statistically iffy cement job and statistically iffy BOP was asking to have their rig burned up ...and it was.

syn/rf - unless we all have our heads up our butts we seem to have pretty clear picture of the circumstances and options available to BP.

And that runs us right back the the big question: WHY??????

We'll just have to wait for the final investigation to hear any sort of official answer.


We should figure out the steps involved to get the well balanced and compare it to what they did and see what they gained. Maybe it will take two stabs. One with the top plug according to regs and one with it at 3000'. And maybe a third stab with the top plug set before displacing.

We know from Morel's email that they would have had to set the lock down sleeve before pumping the top plug if the 3000' exemption was not granted. So doing the lock down sleeve after pouring entailed some sort of efficiency in time that they got the exemption for and went to the extreme length of displacing to 3000' for the pressure test. What was that time savings?

In either case, the extra time it would take to balance the well is the first thing to figure out. I'd need help with that.

EDIT: Added bold

Syn - Perhaps a more pertinent question is why didn’t they keep the well balanced and not what is would take to get it back in balance? They initially unbalanced the well to do the neg test. Finish the test and pump the 14.2 ppg mud back around and you’re balanced. The DP was already at 3,500’ so no time lost there. Pumping the mud back down would have taken just a few hours.

As far as all the other activities: lock down sleeves and setting plugs are done in OBM all the time. In fact, I’ve never seen it done with anything else in a well but drill mud. Set the lock down sleeves as they wish, POOH and PU the cmt retainer and GIH and set it. Then you pump the cmt. And ..ta da: the lock down sleeve is set, the top plug is in place and the well is balanced.

Back to your point: what extra time? AFAIK the biggest time saving would have been not waiting 18 hours for the cmt to cure and the time to do the neg test. What if the cmt never cured properly? The completion crew would deal with that when they moved back on in a few years. As that completion hand pointed out on TOD yesterday they do that as SOP anyway. And they also run the CBL to check for poor zone isolation and sqz to fix it. If I remember you research correctly there was no requirement for a CBL or neg test at the time. Correct? But even if the neg test was required the well could have been quickly put back in balance afterwards.

So the possible procedure: pump cmt into the bottom of the prod csg. No neg test. POOH and set the locking sleeve, POOH and go in with the retainer and then pump the plug. Displace the riser, pull the BOP and move off location. And all this time the well has never been left unbalanced. Again, typically I was never directly involved in this phase to any significant degree and understand for the most part from we’ve discussed on TOD. But we’ve had drilling hands here watching the discussion and they seem to confirm our analysis. If any disagree it would be a good time for them to jump in and straighten us out.

This will sound perverse but consider if they weren’t required to do the neg test. That test gave them enough confidence to leave the well unbalanced after the neg test. If they didn’t do a neg test would anyone go underbalanced? Just my guess but no. So actually doing the neg test was the first step in the chain of causes in the blow out. No neg test and they don’t put the well in an unbalanced state at anytime. A balanced well and no kick to miss. No missed kick and no wild flow to the floor. No wild flow to the floor and no BOP activation. No failed BOP activation and no dead 11 hands, a destroyed rig and a crippled GOM.

Like I said: a rather perverse view, eh?

So the possible procedure: pump cmt into the bottom of the prod csg. No neg test. POOH and set the locking sleeve, POOH and go in with the retainer and then pump the plug. Displace the riser, pull the BOP and move off location. And all this time the well has never been left unbalanced.

That's normal procedures from all i've read.

But we did determine that in order to have fluid of sufficient density in the interval between the plugs to balance the well, and assuming the top plug is set at depth per the regs., it would require fluid at about 15.4ppg to balance the well, assuming an interval length of 12,000'. So if they were going to do that, it would require time to get the denser fluid in there.

But per your calculations, as you note above, they could have balanced the well for displacement purposes only with the same mud weight they already had, just barely, and then left the well underbalanced per their original intentions after they set the plug, and then displaced. It would not matter then that it was underbalanced.

What would be the steps in setting a plug at 3000'? Are we talking cement? Do they need to put in a hard plug with mud below and cement on top? Do they use the snotty spacer stuff?


NAOM - POOH and PU a cmt retainer...sort of like a tight basket. GIH to 3,000' and set the retainer. Some times can pump cmt right after setting the retainer. Might have a spacer ahead of the cmt but not sure it's needed at this point. Need some feed in from our cmt pros.

And check THIS out: With 14.2 ppg mud and cement job starting to leak, well was pushing up at 2,437 psi above seawater ambient. NO WONDER they saw 700, then 1200, then 1400 during neg test. It would have KEPT RISING and there is NO WAY kill line would not have flowed ...and it DID flow ...until someone closed the damn valve ...and LIED about it.

Edit: Looking for a "smoking gun"? There it is.

I'm not sure that's correct. The haliburton hand Christopher Haire was operating the valves during the test.

He described it this way.

"After the first attempt, we were unsatisified with it. We were still getting flow. I was instructed to shut in from the well. At that point, pressure increased to 1400 psi. About 5 minutes later i was instructed by the driller to open up from the well. I got about 15 bbls back. And was instruicted to shut in from the well again. It was about 7:00 now. After shutting in from the well for the second time, some 45 minutes had passed. At this point, i made my way up to the rig floor just to bring some equipment up.... At that point I was instructed by the driller and tool pusher (Anderson) that they had achieved a successful negative test on the rig floor."

They just applied the annular compression theory, that's all.

Haire is suing BP and TO.

Rock, I assume this was the post you were referring to:

Rock, Looking at the schematics that Moon so nicely supplied, I think there is a very logical reason for having the Annulus plug adjacent to the column plug. It looks to me like that is the only place where you can guarantee a non-by-passable annulus plug. If the annulus plug were placed higher up in the well and did not overlap the column plug then there is some, yes pretty slight as long is there is not production casing failure, possibility for the reservoir to get around both plugs. Far fetched admittedly but possible. By using the RW and applying the annulus plug at the bottom you have overlapping cement and an almost zero potential for reservoir bypass of either plug. I'm going to bet the science coaches maybe saw that possibility also, and are taking the belts and suspenders approach. Your approach absolutely plugs the annulus but without the overlap of both plugs it leaves open the very slight possibility of a bypass fault. Keeping in mind that the Gov't side of the equation probably has not let loose of the thought long held thought that somewhere there was a casing probable / potential failure. Anyway just a thought.

I was just saying that it would seem that your proposal of pierce and pump into the annular left the two plugs offset vertically with repect to each other and that would provide a potential path from reservoir around the lower plug in the annulus into the center of the production casing and around the pierce and pump plug. This only on the condition of a perfectly placed casing breach. But if the annular plug was placed as shown on the schematic provided by Moon it would place the annular plug adjacent to the core plug thus disallowing any potential for a bypass from the Reservoir. Just a belts and suspenders kind of thought.

ducky -- That's the reply I forgot from last night. Here's the simple answer if you want an over lap of the production csg and annular cmt: sqz cmt into the annulus as I described and then dump more cmt down the prod csg cmt plug. Dumping cmt on top of the exisitng cmt in the prod csg is very quick (read: cheap) and about the safest op on a rig.

Again I'm not arguing using the RW is a high risk proposition. But it isn't risk free: you're still drilling into a potential pressured annulus with a flow capability of 50,000 bopd. Of course, they'll be prepared for that possibility. Doing the annulus and csg plugs as I decribe offers zero risk IMHO.

And again, the folks on the rig know this better than me. So why do they consider taking the risk worthwhile? There must be some reason.

Rock, agree with your plan, does solve problem, and if fact that is exactly the way BP shows the annular plug except from the RW. After I said that I looked more closely at their schematic and now notice they are showing the travel path as down the DP, though the annular and back up the RW. Doesn't filling the annular from the DP thus mean they plan on perfing the prod casing at least in one location. Looks like a combination of plans. One might conclude they want to use the RW just to use the RW because it is there, and they won't get their collective helmets dinged by the public for ordering useless work.

ducky - Yep...someone tossed in the political/PR angle of the RW utilization. There's the plan. And then there's what actually happens.

ROCK ET AL. Has anyone seen any other parts of this document anywhere? This is the bit for setting and cementing the prod casing; the neg test and setting the Dril-Qiup hanger to the well head. I have googled it to death, but can't find the other bits.


Also, I have looked on the Dril-Quip site, but haven't found a video of setting the casing hanger seal yet.



Rockman, check out page 8 of that document (drill paln?). It has the procedures laid out.


I love this bit. "However, the greatest benefit of adding the judge has been in reducing the microphone time of the U.S. Coast Guard co-chairman, who previously made antagonistic remarks
and slung accusations toward drilling-related witnesses while having little knowledge of the subject matter. His abrasive style has not been conducive to extracting testimony and has not been helpful to the image of the Board.".

Only in America, as they say.


auto-generator: " But Mr. co-chairman, I tried to warn them, I truly did. But they just ignored me."

Co-Chairman: "Don't you think you should've used LARGER FONTS, BOLD, and with RED ink? Well, do YOU? We're waiting for your answer. *tap tap taps* "

auto-generator: "But Mr. co-chairman, I ran out of red ink. *whimpers* "

Co-Chairman: "Not keeping up with your stock, eh. Negligence."

auto-generator: " *sobs* "

The autogenerated status is nice example of bad software design. These issues are known and studied in safety critical systems. Constant warnings or status indications that are simply generated from very wide and mostly useless parameters are very quickly tuned out of view by users. It isn't that far from The Andromeda Strain, but affects everyone.

Maybe they should get the guy who wrote the software in the stand to explain what criteria he used to decide what to print out, and how he came to choose those criteria. I will guarantee that he just pulled some numbers out of his nether regions. (Indeed one might be surprised and dismayed as to how much of the software used is based upon parameters and algorithms that are not really scientifically defensible.)

One thing I found interesting - the negative pressure test is simply asked for by name, with no further explanation (apart from the required 30 minutes). Implying that at least the author though that it was a perfectly well established procedure that required no further effort on his part. Which contrasts to some of the other steps which are spelled out in detail and with explanatory notes as to the reason.

One also notes the bit about monitoring mud returns being the responsibility of the rig crew, and specifically requesting numbers at different stages.

Hard to know how much is boiler plate, and how much is specific to the job.

What I do find unnerving is the lack of engagement with the crew about the process. It reads just as I feared it might. The writer has a clear idea (at least thinks he does) of the required process, but nowhere does he communicate this. If the conman is supposed to be the conduit for these directions he is handed a poor position with which to work. Either he has been part of earlier discussion about the work programme, and understands the unwritten subtext, there is another document that helps him interpret it, or he is left as much in the dark as the rest of the rig crew, but has the added problem that he is supposed to direct the crew to follow this document. I suspect the latter, and that isn't good.

Implying that at least the author though that it was a perfectly well established procedure that required no further effort on his part.

Or that the author knew that one was required, but didn't have a clue how it should be done and didn't both to find out.

Francis. Good points. From my own industry, if an operator was told to do a specific task, say, "pre-start check" a boiler steam feed pump. The operator would know that that procedure is set down in a manual of "operations work instructions". A supervisor would issue the paper version of that OWI and expect to get it back completed with exceptions noted. If there was a problem, the fact would be relayed to engineers. Abnormal procedures would be detailed and approved before work started.

I have assumed the same goes for rig operations; now I am not so sure.

A few days ago, Bob Marshall of the T-P profiled a fishing-lodge owner who says,

... "Normally, October would be one of our busiest months, and then when duck season opened in November we'd have a rush of blast-and-cast," local slang for hunting in the morning followed by fishing, Lambert said. "Right now, October looks about as weak as the summer.

"And it's not like people are calling asking how things are going, wondering if it's OK to come back. They're not calling at all. That tells me they've pretty much made up their minds."

An optimist would suggest that time could heal those wounds, just as it did after Katrina, and the $20 billion mitigation fund President Barack Obama forced BP to set aside could be a financial bridge to that day. But like other guides, Lambert isn't feeling the same "can-do" spirit that permeated the industry after Katrina. There are just too many unknowns this time, he said.

"After Katrina, we knew the fishermen would come back, because the fish were still here -- in fact, it was one of the best seasons we ever had," Lambert said. "Katrina didn't damage Mother Nature, only the buildings, and we could rebuild those.

"But now, no one knows what the long-term impact will be on the natural resources. What happens if, three years from now, fish turn up with problems from the oil? What if there's a test showing specks or reds are unsafe to eat?

"That's the difference between this and Katrina. We don't know what the future will be like."

I wonder how much of this is spill-related and how much is bank-account stress among his clientele.

Everyone here considers NOAA a reliable source for information iirc. Came across this publication while gathering info:



How oil affects habitats and species

Dispersed and dissolved oil (comprised of polycyclic aromatic hydrocarbons, (PAHs)) in the water can result in exposure of aquatic resources to the toxicological effects of PAHs. This contact in the water column may be exacerbated by use of surfactants, weather conditions and other dispersal methods which increase mixing.

PAHs can cause direct toxicity (mortality) to marine mammals, fish, and aquatic invertebrates through smothering and other physical and chemical mechanisms. Besides direct mortality, PAHs can also cause sublethal effects such as: DNA damage, liver disease, cancer, and reproductive, developmental, and immune system impairment in fish and other organisms. PAHs can accumulate in invertebrates, which may be unable to efficiently metabolize the compounds. PAHs can then be passed to higher trophic levels, such as fish and marine mammals, when they consume prey.

The presence of discharged oil in the environment may cause decreased habitat use in the area, altered migration patterns, altered food availability, and disrupted life cycles.

During past oil spills in the Gulf of Mexico, NOAA has documented direct toxic impacts to commercially important aquatic fauna, including blue crabs, squid, shrimp and different finfish species.

Talk about conflicting information...sheesh.

I don't see much conflict here. There is a confusing or erroneous sentence that implies that "dispersed or dissolved oil" consists of PAHs. PAHs form a small part of crude oil, whether dispersed or not. I don't think PAHs are water soluble, so the suggestion of PAH in "dissolved oil" is incorrect.

PAH is the long-term hazard, no question about that. Plenty of it will end up in the sediment, but not because of dispersants.

Gobbet: I've noticed that you've said numerous times that the residual "oil" (crude oil after microbial decompostion is finished) will contain meaningful amounts of PAHs. This is the only thing you've said over the past few months that's surprized me, not because I know you're wrong, but because your grasp of things is exceptional yet I haven't read pre-existing evidence for this expectation. Can you point me to a reference or three to help me with this? There's so much literature that it's easy to miss things. Thanks for sharing.

(Clearly, prior cases occured under conditions unlike the Macondo 252 case. Once technical reports from this mess are published, we'll know for sure.)

PS: It's unusual for me to have to look up words in the dictionary, but I had to look up "gobbet." Then I used it in a sentence. My daughter rolled her eyes! :~)

What finger of guilt (or even "conflicting information") points at NOAA here, tiny? I can't find it.

Chemical analysis of oil allows scientists to conclusively determine whether contaminants are present in fish or shellfish tissue that would be consumed, and if so at what level, and whether the contaminants are due to the spill or related clean-up activities. The current science does not suggest that dispersants bioaccumulate in seafood. NOAA, however, is conducting studies to look at that issue.


My points are in bold. Since my post refers to Dispersed and dissolved oil. My question would be is this just for the effects of the dispersant or is it taking into account the effects of dispersant and the oil mixed together? Are these 2 separate issues or are they combined when making statements like these? Maybe I'm just being blind and not seeing it, but it would appear to a layman that they are speaking about the same thing.

Feel free to correct me if I'm wrong, but please use facts that I can confirm myself, to correct me.

I'm not understanding your question, tiny. Been sick this week, so not even as with-it as usual (not such-a-much anyhow). Not sure what "statements like these" and "the same thing" stand for, and I still don't see what you think implicates NOAA. But never mind, you don't have to keep trying to get it through my thick skull. Guess I just can't help you with this one.

Dispersants are not PAHs. Two different things. The dispersants might affect the rate of uptake of PAHs, but they themselves are not expected to linger in the food chain.

There is no conflict here.

Another thing that you are missing in this is that while invertebrates do not metabolize PHAs, vertebrates do. As these rise in the food chain they become less of an issue.

I know that dispersants are not PAH's. The PAH's come from the crude itself. As for PAH's not affecting vertebrates, I found the following information. I do not know if there are more recent studies available. I just came across this website in the pursuit of information.

A comparison between the physiological effects in fish exposed to lethal and sublethal concentrations of a dispersant and dispersed oil
Biological Institute, Section Marine Zoology and Marine Chemistry, University of Oslo, PO 1064 Blindern, 0316, Oslo 3, Norway
Received 24 November 1984.
Available online 4 April 2003.

The acute and sublethal effects of a dispersant and crude oil on anisosmotic and isosmotic regulation in flounder have been tested. Flounder were exposed to different concentrations of Corexit 9527 and crude oil by use of a biotest system. Fourteen days' exposure to 20 ppm of Corexit 9527, alone or in a 1:1 mixture with crude oil, had no effect on the blood parameters. On the other hand, 96 hours' exposure to 80 ppm of the same compounds led to 50 % mortality and significant effects on the blood parameters in surviving fish. The comparability between effects obtained in fish exposed to lethal and sublethal concentrations of toxicants, respectively, is discussed.

Oil dispersant increases PAH uptake by fish exposed to crude oil
Shahunthala D. Ramachandrana, Peter V. HodsonCorresponding Author Contact Information, E-mail The Corresponding Author, a, Colin W. Khana and Ken Leeb
a School of Environmental Studies, Queen's University, Kingston, Ont., Canada K7L 3N6
b Department of Fisheries and Oceans, Bedford Institute of Oceanography, Centre for Offshore Oil and Gas Environmental Research, Halifax, NS, Canada B2Y 4A2
Received 14 May 2003;
Revised 12 August 2003;
accepted 25 August 2003.
Available online 14 October 2003.

The use of oil dispersants is a controversial countermeasure in the effort to minimize the impact of oil spills. The risk of ecological effects will depend on whether oil dispersion increases or decreases the exposure of aquatic species to the toxic components of oil. To evaluate whether fish would be exposed to more polycyclic aromatic hydrocarbon (PAH) in dispersed oil relative to equivalent amounts of the water-accommodated fraction (WAF), measurements were made of CYP1A induction in trout exposed to the dispersant (Corexit 9500), WAFs, and the chemically enhanced WAF (dispersant; CEWAF) of three crude oils. The crude oils comprised the higher viscosity Mesa and Terra Nova and the less viscous Scotian Light. Total petroleum hydrocarbon and PAH concentrations in the test media were determined to relate the observed CYP1A induction in trout to dissolved fractions of the crude oil. CYP1A induction was 6- to 1100-fold higher in CEWAF treatments than in WAF treatments, with Terra Nova having the greatest increase, followed by Mesa and Scotian Light. Mesa had the highest induction potential with the lowest EC50 values for both WAF and CEWAF. The dispersant Corexit was not an inducer and it did not appear to affect the permeability of the gill surface to known inducers such as β-napthoflavone. These experiments suggest that the use of oil dispersants will increase the exposure of fish to hydrocarbons in crude oil.

Comparison of Acute Aquatic Effects of the Oil Dispersant Corexit 9500 with Those of Other Corexit Series Dispersants
Michael M. Singer a, 1, Saji Georgea, Susan Jacobsona, Ina Leea, Lisa L. Weetmana, Ronald S. Tjeerdemaa and Michael L. Sowbyb
a Department of Chemistry and Biochemistry, Institute of Marine Sciences, University of California, Santa Cruz, California, 95064
b Office of Oil Spill Prevention and Response, California Department of Fish and Game, P.O. Box 944209, Sacramento, California, 94244-2090
Received 25 March 1996.
Available online 19 April 2002.

The acute aquatic toxicity of a new Corexit series dispersant,Corexit 9500, was evaluated and compared with that of others in the series using the early life stages of two common nearshore marine organisms: the red abalone (Haliotis rufescens) and a kelp forest mysid (Holmesimysis costata). Spiked-concentration testing was performed under closed, flowthrough conditions, with previous termdispersantnext term concentrations measured in real time using UV spectrophotometry. Median-effect concentrations ranged from 12.8 to 19.7 initial ppm forHaliotisand from 158.0 to 245.4 initial ppm forHolmesimysis. The difference in sensitivity of the two types of tests was consistent with patterns seen with other oil previous termdispersants.next term Also, these data indicate Corexit 9500 to be of similar toxicity to Corexit 9527 and 9554. Corexit 9500 represents a reformulation of a long-time industry “standard,” Corexit 9527, to allow use on higher viscosity oils and emulsions. The present data suggest that acute aquatic toxicity concerns surrounding the use of this newer previous term dispersant next term should not be significantly different from those associated with the use of Corexit 9527.

Influence of salinity and fish species on PAH uptake from dispersed crude oil
Shahunthala D. Ramachandrana, Michael J. Sweezeya, Peter V. Hodsona, Corresponding Author Contact Information, E-mail The Corresponding Author, Monica Boudreaub, Simon C. Courtenayb, Kenneth Leec, Thomas Kingc and Jennifer A. Dixonc
a School of Environmental Studies, Queens University, Kingston, ON, Canada K7L 3N6
b Fisheries and Oceans Canada (Gulf Region) at the Canadian Rivers Institute, Department of Biology, University of New Brunswick, 10 Bailey Drive, Fredericton, NB, Canada E3B 6E1
c Center for Offshore Oil and Gas Environmental Research (COOGER), Bedford Institute of Oceanography, Fisheries and Oceans Canada, 1 Challenger Drive, Dartmouth, NS, Canada B2Y 4A2
Available online 6 March 2006.

The use of chemical oil dispersants to minimize spill impacts causes a transient increase in hydrocarbon concentrations in water, which increases the risk to aquatic species if toxic components become more bioavailable. The risk of effects depends on the extent to which dispersants enhance the exposure to toxic components, such as polycyclic aromatic hydrocarbons (PAH). Increased salinities can reduce the solubility of PAH and the efficiency of oil dispersants. This study measured changes in the induction of CYP1A enzymes of fish to demonstrate the effect of salinity on PAH availability. Freshwater rainbow trout and euryhaline mummichog were exposed to water accommodated fractions (WAF), and chemically-enhanced water accommodated fractions (CEWAF) at 0‰, 15‰, and 30‰ salinity. For both species, PAH exposure decreased as salinity increased whereas dispersant effectiveness decreased only at the highest salinity. Hence, risks to fish of PAH from dispersed oil will be greatest in coastal waters where salinities are low.

All of these are abstracts from the following website. I do not have access to the full articles.


Sorry it is such a long post and please remember I am no scientist.

Tiny, please don't put words in my mouth. I said that as PAHs rise in the food chain they have LESS, not no effect. Also I didn't say anything about emulsified oil at the rather high concentrations described in these articles having no effect. These tests are under acute conditions where the exposure clearly overwhelms the metabolic processes of the fish.

This article describes what I am talking about:


I would suggest you read it carefully, there is a lot of good information that applies here in the first part of the article.

What is going on in the GOM is quite different from the experimental conditions of the articles you quoted - in most of the Gulf we have long term exposure at far lower concentrations. PPB vs PPM. That is a set of conditions where most scientists would expect the dispersant to have less impact on the rate of uptake.

For me, it is more of a case of the devil being in the details. This is especially so when those details are missing. Nevertheless, your comment does bring up a good point.

One key detail is location of oil when dispersant is applied. A study of dispersed oil on surface water is not the same as a study of dispersed oil one mile under the surface. Also, a study of dispersed oil close to shore is not the same as a study of dispersed oil 60 miles from shore.

I have also read chemical dispersants increase intake of PAHs by sealife. From memory, I think the study compared the intake of PAHs by fish with oil on surface for both dispersed and non-dispersed cases. Even though this may be true, I would still focus on what happens to all the oil. For the non-dispersed case, the oil will still disperse naturally so there will still be an intake of PAHs by fish although it will be less of an intake. Time also has a role to play. Studies have shown dispersant increases dispersion by 50%. So, if the oil slick is of a size to disperse in 6 months naturally, it will disperse in 3 months with dispersant. Is it worse for fish to absorb a smaller amount of PAHs for 6 months or a larger amount for 3 months? Also, the non-dispersed oil on surface is more likely to affect other life such as birds not to mention more likely to reach shore.

PS. I read your comment on previous thread regarding need for information for claims and spent a little time trying to find info that didn't cost a fortune. Sometimes I find downloadable pdf's for books that are for sale but I had no luck with Marine and Freshwater Products Handbook. If I find anything worthwhile, I'll let you know.

Thanks. My research on this crap is starting to really pile up. Don't think my fiancee is going to be a happy camper when I make him sit down and read through all of it. What is so mind boggling about all of this is the lack of scientific information done prior to this incident, and any information coming out now is surrounded by controversy in the scientific communities that I personally don't think its totally reliable. It's no different than when a disaster happens and first reports that come out are always unreliable and full of errors regarding the facts. The facts always come out at a later time, and I feel the same will happen here.

What is so mind boggling about all of this is the lack of scientific information done prior to this incident...

Through my career as a scientist, I have thought again and again, well, someone must have done that, and again and again, I have been wrong. It's a big world out there, and science hasn't covered anywhere near all of it, particularly the observational sciences, which would include inventorying all of the life in the Gulf of Mexico. As for the effects of crude oil and the dispersants, studies on the effects on humans usually come first, although little animals like brine shrimp might be used as stand-ins. We're very species-centric.

...any information coming out now is surrounded by controversy in the scientific communities that I personally don't think its totally reliable.

That's how science is done, and small effects on organisms that you might not know a lot about to start with are going to be hard to study. So different studies will seem to get different results. The surveying of where the oil has gone is over enormous areas, and there seem to be relatively few groups doing it. That's not surprising: the ships and other equipment, plus necessarily a fairly large research group, are expensive. So yes, take all results as being provisional and probably reflecting only a small part of the picture.

As you say, there will be arguments and corrections and reconciliations, and it will take time.

So different studies will seem to get different results...

I read a book recently entitled How To Lie With Statistics. It definitely opened my eyes about how statistics can be manipulated to produce the desired results. So now every time I see statistics I'm constantly asking myself what information the study, poll, etc., did not include while doing the research.

As Mark Twain,among others,said "There are three kinds of lies: lies, damned lies, and statistics".

Different studies may seem to get different results. Sometimes stuff comes out just as predicted, or just as someone else did it.

Statistics is a whole 'nother problem. I recall when the statistical programs came out for hand-held calculators - those little guys that worked off little cards. Everyone and his brother was applying the new software to stuff they shouldn't have been, and a fair bit of it got published. I can just about guess what goes on now, with the computer capabilities they've got. Although probably some of those programs have better self-checking to avoid teh dumb.

So you don't have to lie - mistakes are made.

I've always tried to do stuff that didn't require statistics. When I needed statistics, for environmental remediation, I made sure I had good people doing it for me.

I've always tried to do stuff that didn't require statistics. When I needed statistics, for environmental remediation, I made sure I had good people doing it for me.

As a technicality, many physical phenomena cannot be understood unless you invoke statistics in the form of statistical mechanics, random walk arguments, etc. The concept of spatial dispersion is impossible to do without the aid of elementary probability and statistics. Yet, the problem is that if you let other people do this for you, you lose the entire physical interpretation. I wouldn't let a pure statistician do any of this for me unless they had some grounding in physics or chemistry, as they would likely solve the wrong problem. Jaynes claimed that probability is the logic of science, and it what ties everything together.

I always think about this situation whenever I see someone bring up the Mark Twain quote.

Good point. But I haven't seen any lying with statistics yet in the DWH spill research. I have seen lack of pre-existing info as discussed by Cheryl, scientists documenting small parts of the overall dynamic and inferring too broadly (as in the WHOI study), and incautious self-promotion (two groups have done this & probably will regret it). But we can expect good outcomes, because science is self-correcting. One can play games with credulous reporters & editors (write me another Corexit story, I've gotta sell papers; I'm right & he's wrong), but eventually scientists' passionately held views have to be backed up by evidence, and errors are exposed and either admitted or simply cast out by the judgment of peers.

The prime example in my mind is the necessity to show the constituents of deepsea oil plumes and oil remains on the sea floor. WHOI inferred that most of the original crude oil remained in the plume in early June because oxygen had not depleted very much, but Hazen actually measured what was there at the same time and found the oil mostly decomposed. So indirect measurement of oxygen levels were not diagnostic. Why not? Maybe oil was so dispersed that its metabolism only used a small portion of the available oxygen. Maybe some microbes were using other metabolic pathways. WHOI initially defended their inference but later backed off. Now Joye is claiming that the unweathered crude has simply sunk to the bottom. I say "show me" because this is not consistent with other things we think we know. The raw claim is just an opinion until Joye shows analysis of the samples. Maybe what we think we know is wrong. Maybe not.

Different studies get different results, but the differences may prove to be compatible once the data are separated from inferences. Eventually all the defensible research will make a coherent whole story. I'm looking forward to learning what happened to the oil, what damage occurred, how the system recovered or changed, and how people were effected and adjusted.

Like I stated in the last closed thread, all I am looking for is information to help my fiancee figure out what his final claim will be based on. If you know of any articles, studies and so forth that deal with how the shrimp larvae fared in GOM, if these survivors are going to have reproduction issues, deformities in their offspring, and problems with lower resistances to parasites, please point me in that direction. The same goes for oysters and crabs. This is the kind of information the fishermen, oystermen, shrimpers and crabbers are going to need. We are not a group of scientists down here, so we are going to have to make the best guesstimate that we can based on information available now.

Well done, tiny, for drawing Cheryl back into the conversation. (Having her here does wonders for our -- or at least my -- clarity quotient.)

Welcome back and thanks, Cheryl.

lotus, thanks. I usually wait to see if someone else is answering a question, if I think there are older (in TOD terms) hands around. A few of them have done much better than I have on a couple of things. Or maybe, as in this case, I have a directly relevant answer, and I'll post that.

lotus - I've done the hunt/fish combo many times. The oil spill had no direct affect. Almost all those activities are up in the bayous. But I can easily imagine a lot of lost business indirectly. Most of these hunts are paid for by local hunters and local businesses. And most of them made a living in the oil patch. During the fall the dominant conversation on a rig is about the hunts hands are setting up. Real simple: lose your income because of the oil spill and drilling moratorium = no disposable income to go play in the bayous. Every hunt/fish trip I made was put together by an oil patch service company. I've spent almost $100 million with the service companies in the last year and haven't heard of one freebie let alone get invited.

Like I said a while back: the financial loss from the moratorium will trickle down to every level of life in S. La. Again, not an argument against the moratorium but an acknowledgement of the affects. Add this to the hype put out by the MSM that turned folks away who didn’t realize the spill had no affect on fresh water fishing/hunting.

Ah, thanks, Rockman. So the Patch both directly and indirectly supports much of the Coast's leisure industry too, huh? That's the part I was missing, thinking that this guy's up- and out-of-state blast-and-casters weren't necessarily Patch people.

Hell's bells. Sure do wish the middle of April had played differently on DWH.

lotus - All I can do is offer my impression and no hard support but I would guess the great majority of hunting revenue is from oil patch hands and service companies. Even a one day hunt with some fishing thrown in can cost $500 or more.

I appreciate many folks can't stomach the thought of shooting game birds. But the fact remains: hunters supply much more revenue to support wildlife habitat than all the environmental groups combined. It is a truely a shame to see all the waterfowl killed by the spill. OTOH millions of other game birds will be harvested along the Gulf Coast this season. And the species will recover nicely due to management of those hunting areas. I don't expect the anti-hunting ground to support those efforts. A fair moral call on their part. But it doesn't change the facts: hunters are the best thing gone for the wildlife IMHO.


ORANGE BEACH, Alabama -- Tired of waiting for millions in lost tax revenue and expense claims, Orange Beach officials are packing up staff and medical equipment and moving out of BP PLC contractor work sites on Monday, Mayor Tony Kennon said Saturday.

"We’re going to pull out all of our firemen and paramedics because BP won’t pay their bills,” Kennon said. “We have a multibillion-dollar, multinational corporation having a town of 5,000 people in Alabama front the money for their emergency medical response, and I’m tired of it. We’re not going to do it anymore." ...

Haywardism still alive and well at BP?

There are two sides to every story remember.

Yep. Annnnnd . . . ?

As I recall, Tony Kennon was relatively BP-friendly at first, at least grateful for their early expressions/gestures of support. Not so much as time as gone on.

Yep. Kennon is the hack the blew 5 mil on the useless steel boom project. The IT Mayor that God inspired to BUILD. Kennon is Jindal and Nunngesser put together. Means well, but ends up rabblerousing in the wrong direction.

Gulf Shores said, nah we will keep billing them and adding interest. Who is smarter. Gulf Shores WILL get paid. Eventually.

Not much for a non-local to grab onto here, TF. What gives you confidence that Gulf Shores will get paid if it's already started charging interest? Y'all must be at the end of a very long list, eh?

Greenpeace is conducting citizen inspections at these “high-risk” facilities to highlight the need for strong, permanent chemical security legislation, before it’s too late. So far, three out of five facilities have failed our inspections (two in New Jersey and one in Texas).

Our buddies at Greenpeace are at it again. Seems they want money and votes this time to secure chemical plants and water plants...

Urge your Senators to keep your community safe by co-sponsoring and voting for the "Secure Chemical and Water Facilities Act." Safer technologies exist, let's help make them a reality!

(BS Masks on please)

It is just me or does it appear Greenpeace is supporting and promoting legislation that is designed among other things to arrest folks that do 'citizen-surveys' such as Greenpeace? Surely either Greenpeace is either stupid or brilliant for providing additional means for getting exposure and arrested so that they can raise more money. It just seems a strange pairing to me.

Greenpeace is loopy.

One thing to watch out from them is that they fund 'research' by a professor of molecular biology at the University of Caen by the name of Gilles-Eric Seralini.

Basically the M.O. is to conduct a study of something that is on Greenpeace's hit list which shows some negative effect, publish the result in a non-reviewed journal and then send out press releases.

There is nothing in the article that is dishonest per se, except for the fact that the conclusions are never applicable to real systems because of crazy experimental conditions or the the results are presented are analyzed in such a way to seem alarming if quoted in the news.

STA - I suppose Greenpeace suffers from the same problem any large organization deals with. All groups (NRA, Greenpeace, Boy Scouts) have members with extreme positions. I don't recall the fellow's name but a former head of Greenpeace resigned over conflicts with members he described as radical. It's easy to take a shot at any group when you can focus on a small but vocal minority. Long ago I use to hang with the Sierra Club. Who better to advise them on matters dealing with oil field pollution, etc? I was trying to advise them dealing with a toxic injection well by Dupont. Eventually I was ignored by the attorney leading the fight because I was working for Mobil Oil at the time. And anyone working for an oil company must be evil, of course. BTW: the SC lost the battle. And I had a technical argument that might have won the case for them.

RM, sad but true. There are more than a few of us closet greenies in the oil patch. But it does get tiresome when ones' knowledge, ideas, and insights get dismissed out of hand because you work for big bad oil. If you know something about the issues in question, you are all too often dismissed as a "shill", "shrill", or whatever.

In another post you remarked about how much revenue comes from hunters to support wildlife. It is sad that there is so much mutual distrust on both sides. The hunters think all greenies want to shut down hunting, and the greenies think all hunters only want to shoot stuff. There are dumb sh*ts and bad apples on both sides of course, but in the larger sense both groups have more to gain from each other than they want to admit.

I don't know whether to laugh or cry. Laughter usually works better for me, but sometimes it's impossible not to cry.

In the UK they banned stag hunting. The hunters used to pay farmers for the right to hunt on their land. With no money coming in from hunting to offset the damage the stags did to crops the farmers just went out and shot all the stags they could bag.


NAOM - And in Texas every year millions are spent feeding wild deer including antibiotics. A record breaking whitetail stag in S. Texas can cost a hunter $25,000. A big incentive for landowners to take very good care of the wild life.

Alaska - What really PO'd me about the Sierra Club incident is thhat I started my work with them while still in grad school at Texas A&M. And I had the entire petroleum engineering dept willing to back me up in the effort. Lots of solid gold credentials and not just some mouthy recent grad. But then I went to work for Mobil Oil and the attorney stopped returning my calls. Finally on my last call his secretary told me he would never take a call because I worked for MO. I was PO'd so I told all the profs at A&M to stand down. I should have been a little more mature about it and found a way of get around that attorney. But being young and somewhat arrogant he hurt my feelings. And that was that.

But I'm much better dealing with difficult people now. LOL

his secretary told me he would never take a call because I worked for MO

Ay yi yi, Rockman, leave it to some dilbert's foolishness to cost us. Leave us not think of how much and how often, eh?

The early Greenpeace member who quit them is Patrick Moore (not the astronomer).

Jack - Thanks. Never dug into it deep enough to tell if his statement was valid or just some sour grapes.

Mining the hydrates on the wellhead skirt from the leaking around the spud pipe.


At WaPo, BP internal report leaves some things unsaid has a bit more from M-I SWACO's Leo Lindner on his mixing Form-A-Set and Form-A-Squeeze together.


The leaking below the wellhead is going up and building up on the bottom of the BOP because there is no lip for them to catch on until the flat bottom of the BOP. They miss the actual lip of the wellhead because of the lean of the spud pipe.

Huh! How did that happen?

Simple, the lip was a lot bigger then I thought.

If this wellhead is the same size as the old wellhead I would suspect we will see hydrates on the bottom of this BOP just like the old one.

I guess the Chronicle doesn't share its cartoonists on the website (which is too bad, judging from this editorial yesterday):

... The most succinct response to the report we've seen was offered by Chronicle cartoonist Nick Anderson, who morphed the ubiquitous BP flower symbol into petals shaped like pointing fingers in Thursday's cartoon.

Yes, the BP fingers were pointing: At Transocean, which owned the rig; at Halliburton, which performed cement jobs on the well; and at Cameron, which built the blowout preventer that failed to stop the fatal explosion.

Almost immediately, fingers were pointed back at BP by the accused. And so it is likely to go as other studies of the accident are made public. The legal jousting is likely to play out over years, if not decades, experts reckon, and cost the litigants millions in fees and perhaps billions in damages.

Like most, we've spent our summer watching the spill drama play out. Along the way, we've been visited by oil and gas industry leaders and other knowledgeable insiders passing through town. Some have dropped by for meetings with the editorial board on spill-related business; others on unrelated errands.

In one way or another, the spill has always come up, and we could not help but notice an informal consensus about BP emerging among these insiders that must be addressed. It is a concern that the company's corporate culture played a role, perhaps a large one, in setting up the circumstances that led to tragedy on April 20.

For the sake of the survival of the entire offshore industry, that subject must be addressed without flinching.

I guess the Chronicle doesn't share its cartoonists on the website


Took me a few minutes to find it. For future reference, recent cartoons are on his blog; there's a link to the blog underneath the current day's cartoon, which is in the Opinion section (to which there's no link on the page the editorial is on; you have to go to the Home page to get to Opinion--sheesh).

Wooie, that's some diligence, SL. Thanky!

OCD comes in handy now and then. ;-)

Heh. Hope it doesn't run you completely ragged cuz it sure does your pals at TOD a power o' good!

Thanks, lotus, back atcha in spades. I'm so out of my depth on so many aspects of this whole business, it makes me feel slightly less dumb to be able to contribute a little something once in a while. And I actually enjoy chasing things down.

Edit: Hope you're feeling better.

Hope you're feeling better

Thanks, that I am (past the bug if not yet the wuzzy. Need somma what Mainerd's having).

Well of course lotus. Here, have a swig of granny's cure all -- corn-sqeezins, for medicinal purposes only.

As a mentor of mine once opined, anything that has to be filtered though charcoal before you drink it isn't fit for human consumption. I prefer things made from the squezin's of barley, grapes, or apples - well "its mostly apples."

Oh dear, how shall I choose the right medicinal?



Poor Bermuda indeed. Hope they don't get completely washed away, because then there'll be no more Bermuda Triangle.

Wow~been out both days this weekend on the beach and totally missed it is a cat 4 now. Bermuda looks like the target, but ever since Ivan the "I" storms worry me, Ike and last yr Ida which was more or less like straight line winds for about 7 hrs was a great reminder to me to be always be vigilant.

I did invite another TOD'er to snorkel today and for the first time this yr went all the way to Ft. Pickens (almost to the Pensacola Pass) and got in another large school of fish, I thought they would never stop whizzing past me but it was good to know that my area has active marine life and so did this area in the Nat'l Park:)

Shoreline Cleanup Operations Continue Along the Gulf Coast

UPDATED September 9, 2010 7 PM

Past 24 HOURS


"As part of continued efforts to protect wildlife and wildlife habitats from the impacts of the BP oil spill, FWS and National Parks Service cleanup crews continued shoreline cleanup operations at Gulf Islands National Seashore and at FWS refuges—removing oil debris from Cat Island (8,860 lbs), Fort Pickens (2,134 lbs), Horn Island (5,950 lbs), Ivan’s Cut (1,320 lbs), Perdido Beach (2,263 lbs), Perdue Beach (900 lbs), Petit Bois Island (2,250 lbs), Santa Rosa (5,692 lbs) and West Ship Island (1,150 lbs)."

Thanks for the link, there were alot of cleanup crews on certain parts of Ft. Pickens -more east of Langdon Beach where TFHG and I went for my swim and snorkel........I DO wonder where on Ft. Pickens this was and whether it was the sound side or Gulf side, I know on the sound side from a friend who works there they had been picking weathered oil out of the sound by NAS for months, and alot of it.

I truly expected to see tar/weathered oil but even when I swam to the bottom and dug around in the sand I didn't see anything off that area.

I also wonder if Santa Rosa is Pensacola Bay ?

"I also wonder if Santa Rosa is Pensacola Bay ?"

I think so:

"I DO wonder where on Ft. Pickens this was and whether it was the sound side or Gulf side,"
Good question, dunno, but, ^The day's Total - 30,519 lbs
That's a lot of roadbase material, TFHGUY! And that's just for one day.
Hey, wasn't there an asphalt shortage before the spill? Well, there ya go, now not so much.

I must have looked in the wrong place on the link, I couldn't find the 30,519 lbs. Although since Ft. Pickens is on the Gulf and the sound and feeds into the bay, I'd expect more than other areas, but 30,519 seems like an extreme amount unless it was picked up with the sediment in the sound/bay as IIRC they weigh it all togather from my friends who works there. I can tell you, we couldn't find any (course I wasn't digging holes), but we saw none on my area of the beach nor off Langdon Beach (Gulf side). The amount in P-Cola bay doesn;t surprise me in the least, there are seawalls almost everywhere except some shoreline so it doesn't wash up in a long line of shoreline like it did when we got hit hard on 6/23, it can only linger in the sediment or wash up on the few unprotected areas where there aren't seawalls. Don't know anything about and asphalt shortage, but if there was one-problem fixed.

This is what I see at the visitp-cola link:

September 12, 2010

Beaches on Pensacola Beach are open for swimming. There have been minimal reports of any oil over the last several weeks. Future threats from oil have been greatly reduced due to the capping of the oil well and progress toward a permanent kill, according to the Florida Department of Environmental Protection.

So, did you follow a link on that page, certainly minimal reports and 30,519 lbs don't jive.....

Sorry about the confusion. I tallied up all the collections, from all locations posted on that page.
And yes I believe those collections include sand and anything else that ends up in the shovel/or whatever they're scooping with, even those machines can't filter out everything.

The reason I threw in the remark about asphalt was because I recalled TFHGUY mentioning he got some folks to use that stuff for roadbase (kudos to TFHGUY, btw).
Can't imagine why suppliers in that biz weren't out there collecting the stuff. <--sorta kidding there ;-) but there should be a market for it.

That's about 5 scoops of sand with my D-9 with the bucket on.

Exactly, the Macondo 'mix' is combined with other mixes to reduce the level of foreign matter per cubic yard. A 2" screen is good. A 1" screen would be better. The idea is not to build miles of road here, the idea is to get rid of as much as possible with minimal impact on landfills and communities. Of course, this landfill I am bragging about just failed arsenic tests in two or three wells. At least we found it. Now, I have a new problem, not as related to oil. I see us digging the landfill up one day and processing the waste as hazardous. I see about 10,000 other communities having to do the same for one thing or another showing up in the groundwater test wells. Think of all the landfills we do not even know that are there. Really toxic ones.

Edit: The county road guys tell me they try to recycle 90% of the asphalt they dig up. Been doing it for years. Nothing new here but the politics.

And sir, what would you charge per scoop of that top quality, made in the U.S.A., Gulf Oil Enhanced/spilt sand?

Math isn't my forte so y'all may want to check my mathmatics up thar.
(if it is accurate, then I made decent contribution to this heavily maths infused site?)

"4. Remove damaged or non-functioning BOP stack to allow installation of a new BOP on the wellhead housing, or the subsea containment assembly (Note: this capability is available now)."

In "their" hindsight, they could've done this with Macondo, as I'm sure it was suggested several hundred thousand times from the very beginning. But then we wouldn't've had so much fun, eh.
Well integrity unknown, and how to determine it? Replace BOP.


Here's a video of blue crab research done by Center for Fisheries. It's called "Oil Inside Gulf Crabs May Be Shed" and has a guardedly optimistic tone.

A month or so ago I had read about orange blobs in crabs and the scientist said lab analysis would be needed to identify. Since then I've searched for clarification of this story but haven't found any. Does anyone know what was found out? Please don't take me the wrong way and assume I have any concerns. I'm just curious...

Thought I recollected reading a comment on orange blobs in crabs.
http://www.theoildrum.com/node/6791#comment-689958 -by paintdancer

But the only thing I could find on orange blobs searching the Tulane.edu site was in Darters and Minnows.

This site mentions [Caroline] Taylor expected results the next week, but that article is dated July 2.
But it also states Harriet Perry has determined they contain hydrocarbons.

RAPID Deepwater Horizon oil spill: Impacts on Blue Crab population dynamics and connectivity

Oops! on Darters and Minnows: http://www.eebio.tulane.edu/resources/paper-minnows3.php , but unrelated.

"Crustaceans (lobsters, crabs, shrimp) have a moderate risk of exposure because they have some mobility, but utilize benthic habitats in shallow nearshore and estuarine areas."
"Ingestion of contaminated food.
This exposure model assumes that organisms uptake oil by eating contaminated food, not sediments ingested while feeding. Examples are oil droplet ingestion by copepods that are then eaten by finfish, or crabs feeding on oiled bivalves. Dietary uptake of PAHs is not very efficient, and decreases with increasing molecular weight."
Also see test results on crabs from past oil spills.

Thanks for the links.
Here's my view of what I read. Ecologist Caroline Taylor found yellow-orange droplets in blue crab larvae and another team determined these droplets contain HC. Further verification is needed to determine if HC is from DWH but gut feeling is that it is.

And even if true, it is important to follow the HC thru the next stages of crab's development. The video I posted claims this has been tested with positive results. The Center for Fisheries did lab tests of exposing clams with dispersed oil and also found HC in larvae. However, after molting, the HC was released back to environment. Also, molting occurs very often and more often in young clams.

Getting my recollections straightened-out, perhaps:

"BP internal investigation report leaves some things unsaid:
One example involves BP's use of a gooey chemical mixture in the well during a pivotal pressure test that preceded the blowout.
Under environmental protection standards, if BP used the leftover material in the well, it could then dump the product directly into the gulf...

Bly, who is BP's head of safety and operations, said that using the leftover fluids in the pressure test "would have been fine" if the material had not penetrated an area where it did not belong.

The report says M-I SWACO reviewed the mixture's properties and recommended it as suitable.

In his July testimony, Lindner of M-I SWACO said, "[W]e had the product there, and BP wanted to use it."

Lindner said to assess its suitability, he mixed a gallon of Form-A-Set in equal parts with Form-A-Squeeze and left it overnight to observe the reaction.

The Bly report's most detailed discussion of the spacer is contained in Appendix Q, which was not included in the 234-page document distributed at Wednesday's briefing. (Appendices A to H are in the printed document; the rest was issued electronically.)

Appendix Q says that, according to an M-I Swaco mud engineer, use of the mixture as a spacer "was not standard.""

On the Peak Oil Debate, do you know what would be incredibly useful? Reaction quotations from people in response to Hubbert's prediction of Continental US Peak Oil in 65-70. I bet they were saying much of the same things deniers are saying now, and that would be a knock-down point in the the argument for our side.

The Feds don't even know if there's communication between the annulus and the reservoir. All they know is there are 1,000 barrels of oil in the annulus.


This well is far from dead.

Yeah well I'd feel much better about it if it would just stop gurgling.

And I'm sure it would be a good sign the well is feeling better if it wasn't gurgling.

Not a good sign.

Maybe someone should give it a seltzer.

If not then I'll take a seltzer. At least I'll feel better.

All they know is there are 1,000 barrels of oil in the annulus.

They do?

1) How do they know that for sure?

2) Has everyone in a position to know the government's views said that, or have they also said something to the effect of "It might be oil, or it might be the original mud"?

My guess is somebody (Adm. Allen) misspoke, a not infrequent occurance, and has since stepped back from "it's oil in there".


On "Dispersant application,": "the risks and benefits of dispersant use,"
The risks *to* benefits -- acceptable percentages -- is what they mean. There are safer alternatives. Anything can be improved upon. There will always be a better way.
Every corporate entity figures in acceptable percentages. Hell they have whole departments to figure acceptable percentages, and those departments are full of people with PHDs in acceptable percentages. They should be spending all those resources on finding better solutions, and not for hiding problems with cooked numbers.
We're not stupid.

I may be insane but I'm not stupid. And you can't prove I'm insane either.

God I love the smell of crude oil.

I like rainbows they have pretty colors.