BP's Deepwater Oil Spill - Still Important things to discuss - Open Thread 3
Posted by Gail the Actuary on October 10, 2010 - 10:50am
This thread is being closed. Please comment on http://www.theoildrum.com/node/7032.
Since folks still want to discuss the oil spill related issues, this is another open thread. Note that there are a few oil spill related articles in Drumbeat.
BP's Deepwater Oil Spill - Still Important things to discuss - Open Thread 3
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407 comments
BP's Deepwater Oil Spill - Still Important things to discuss - Open Thread 3
PDF version
407 comments
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Carried over:
Jinn whined at DeepwaterEngineer:
But DE had posted the entire relevant text above, so no link was needed (although we need one now 'cause the thread closed).
Jinn then added:
But DE had already been kind enough to address that in his prior comment, it's the part in bold in the "relevant" link.
OB, but what I love is on the previous thread, where JINN asserts that PE's are part of some society guild and ignores the fact that it had been stated several times, including DE's post, about state registration. Then Jinn turns around and states it was the Job of Louisiana not MMS to enforce the rules of Professional Engineering.
I think JINN simply asserts, claims, says whatever suits the circumstances and therefore is not a trustworthy poster and should be totally ignored. Distortion of facts, statements etc is the same as telling lies, isn't it? It's time to stop feeding Jinn as he obviously gains something from the feeding. And wastes everyone's energy and time.
Thanks for the link. That says the laws are enforced by the appropriate authority which would be the LA licensing board.
No, Jinn, it does not.
It says:
"All of such applicable laws shall be administered and enforced by the appropriate officers and courts of the United States."
edit to add: This is just common sense, the State of Louisiana has no legal authority beyond the three mile limit, so Louisiana cannot enforce its law on a deepwater platform.
No it is not common sense. Nor does it have anything to do with the State of Louisiana enforcing law.
The law of Louisiana provides that only a particular appointed group of engineers drawn from Louisiana Engineering Society can decide if a person is legally practicing engineering or not as defined by Louisiana law.
The MMS never had the legal authority or qualifications under any state or federal law to make a determination that some engineer working for BP is practicing engineering without a license in violation of Louisiana law. The Louisiana law is pretty clear - either the Louisiana Professional Engineering and Land Surveying Board makes this determination or no one does.
Hey Jinn, if you are going to keep banging on about Reg. Engineers how 'bout getting a couple of facts straight.
You said: "The law of Louisiana provides that only a particular appointed group of engineers drawn from Louisiana Engineering Society can decide if a person is legally practicing engineering or not as defined by Louisiana law." This "society" is just that! It is not an entity that licenses Reg. Engineers in the state of LA!!!
The group that licenses Reg. Engrs. in LA is the "Louisiana State Board of Registration for Professional Engineers".
One is a private society that helps with on going education and a bunch of other activities the second one does and enforces the registration.
Later on you refer to the Board but you interchange the two entities in your posts and it will continually confuse and mislead the readers. Not doing anyone a favor with your looseness of facts.
What quoted me as saying was factually correct.
Jinn, it is common sense. The LAPEL board cannot, on its own, enforce the law offshore, because it has no jurisdiction. The US government may well ask LAPEL to rule on this, or may turn over enforcement to them. But only the Federal government has the right to initiate enforcement in this case.
Remember that it is Federal law (adopted from Louisiana law) that requires licensing by LAPEL. There are two separate codes of law here, even though they refer to the same text. One code is enforced inside the three mile limit by Louisiana, the other is enforced offshore by the Feds.
Note: I am assuming that there are no pre-existing enforcement agreements between the US and Louisiana in this area. If anyone has other info, please correct me.
It's almost always a mistake to try to use common sense to understand how the various provisions of a law fit together and affect one another. The logic of the law is different from any other logic with which I'm familiar.
We should leave legal interpretation to professionals. I'd love to read an opinion from a lawyer whether Federal law requires engineers working on offshore drilling platforms to be certified by a particular state.
Perhaps DE should have also bolded the section that says,
(3) The provisions of this section for adoption of State law as the law of the United States shall never be interpreted as a basis for claiming any interest in or jurisdiction on behalf of any State for any purpose over the seabed and subsoil of the outer Continental Shelf, or the property and natural resources thereof or the revenues therefrom.
This would seem to be an ironclad restriction from the state laws having ANY jurisdiction over drilling on the OCS.
The BP engineers were clearly working in Texas, and their work product was being used on the OCS. Where is the violation of Louisiana law?
Saltwater, the Para 3 you copied was in a section on taxation not on general jurisdiction. The salient paragraph is:
(A) To the extent that they are applicable and not inconsistent with this subchapter or with other Federal laws and regulations of the Secretary now in effect or hereafter adopted, the civil and criminal laws of each adjacent State, now in effect or hereafter adopted, amended, or repealed are declared to be the law of the United States for that portion of the subsoil and seabed of the outer Continental Shelf, and artificial islands and fixed structures erected
thereon, which would be within the area of the State if its boundaries were extended seaward to the outer margin of the outer Continental Shelf, and the President shall determine and publish in the Federal Register such projected lines extending seaward and defining each such area. All of such applicable laws shall be administered and enforced by the appropriate officers and courts of the United States.
This basically says that other than taxation, the feds are adopting the laws of the states within the projection of the states boundaries seaward to the outer margin of the OCS.
This is important to understand, especially now that the new regs require sign-off and stamping of well design by a Registered Engineer. In the case of DWH, and in the present time, that would have been an engineer registered in the State of Louisiana, I believe.
Actually it is not in a section about taxation. The tax restriction is mentioned in the previous section.
There is probably case law dealing with the details of this OCS law. Until someone with real legal knowledge steps up this is just cherry picking the best supporting claims.
Saltwater, let's see if I can clear this up for you, and no, IANAL. There is a difference between the State of Louisiana and the laws of Louisiana. I agree that the State of Louisiana does not have jurisdiction on the OCS and cannot enforce its laws there. But the Federal government has adopted Louisiana law as part of Federal law in this area. It is a Federal decision to enforce state law offshore, and to use Federal officers and US courts to do so. To be clear, the Federal law we are discussing here explicitly says that relevant Louisiana law is adopted as Federal law. Since the MMS was the US enforcement agency for offshore drilling, it seems it was MMS's responsibility to enforce, IMO.
The BP engineers may have been located in Texas, but their work product was in waters subject to provisions of Louisiana law. If they were not licensed or permitted to work in Louisiana, then that appears to be a violation of the Federal law adopted from Louisiana. Similarly, if a Texas engineer designs a bridge in Louisiana without a La. license or work permit, they cannot legally sign off on the plans. The only difference between an offshore platform and a bridge would be which government enforces the law.
I think this is similar to a state adopting a standard Building Code rather than writing their own. The state enforces the building code, not the folks who wrote it. So even though the US Government didn't write the adopted Louisiana law, it has the full force of Federal law.
If you can find me a bridge 50 miles off shore I will agree with you.
Salty, remember that the particular chunk of Federal law we are discussing describes how, and how much, State law is adopted into Federal law. If the intent was for none of these state laws to apply offshore, then this part of US law wouldn't exist.
Salt, don't you ever wonder why you see the written words one way, prismed glasses or something, and most of the others are seeing it another?
Here one more time is the critical wording for you.
"the civil and criminal laws of each adjacent State, now in effect or hereafter adopted, amended, or repealed are declared to be the law of the United States for that portion of the subsoil and seabed of the outer Continental Shelf, and artificial islands and fixed structures erected."
"the civil.......of each adjacent State,........are declared to be the law of the United States.........the outer Continental Shelf, and artificial islands........erected."
The rest of the LA law basically says if you want to practice engineering in our state then you must be registered to do so. It doesn't matter that the actual work was done in Russia, but if the structure, what ever it might be, and a well is a structure, and the structure is to be built in LA including its boundary extensions into the Gulf then you must be licensed. And yes in this case since the Feds adopted LA law and made it their own, they are the enforcers. Endo!!!!!!!
And because the Feds have now issued new regs requiring PE stamp on wells, then in the extent of LA boundaries it will be a LA licensed engineer with the feds doing the enforcing. What part of this is so difficult to understand?
Duck,
Have you actually looked carefully at the relevant section of the SLA without your pre-conceived conclusion? Look at the outline structure of section 1333. The highest level of outline is a, b, c, etc. Part (a) is further subdivided into (1), (2A), (2B), and (3). You are using (2A) to back your position. I am using (3) to back my position. Neither is subordinate to the other, at least in the outline form. That is why I said that case law is probably relevant.
This law was first written some 60 years ago, long before anyone even dreamed of deep sea drilling or drilling from completely floating structures. (Extremely difficult without GPS.) The law has been updated, yes, but I suspect the updates were all about royalties and such, and not about the boilerplate in section 1333.
Look at the specific wording.
Part (2A) starts with, "To the extent that they are applicable . . "
Part (3) includes " . . shall never be interpreted as a basis for claiming any interest in or jurisdiction on behalf of any State for any purpose . . "
There is clearly a conflict in wording here. Does the requirement for engineer licensing fall under (2A) or (3)?
This entire discussion has broken into three parts, of which only one is important.
* Training, qualification, and certification for various levels of drilling-related occupations.
* Whether the law was broken by the use of non-PE personnel to design the Macondo well.
* Whether PEs are inherently superior people.
The first is an important topic, and will get a lot of review and update in the coming months and years. As I have said several times, I support appropriate actions in this area.
The second is debatable, since the wording of the SLA is ambiguous. I find it interesting that this topic has not come up at all in any of the hearings. Yes, John Matthews in the MBI hearings asked everyone about their education, licenses, employment history, etc. That was just basic fact gathering, and no one from either the board or the contingent of lawyers ever questioned the lack of licenses. The subject also did not come up in the congressional hearings. The press has apparently never mentioned it either. (I would like to hear of any exceptions to my observations.)
The third item is not worthy of further discussion.
Since discussion of the second item appears local to this board, and of no worldly concern or consequence outside of this board, I will stop now.
Salt, can only stay a short time.
DE originally was quoting from RS 37:682, LA Definitions. This Code pretty much makes clear who can and who can't practice engineering in LA. So I think that should be a closed discussion.
DE then referenced USC 43 sections 1331 thru 1356a. 1333 (a) & (1) talk about this code being applicable to the Outer Continental Shelf etc, and the fact that the feds extended US law to all of the Shelf.
Now 2A, IMHO are telling the reader that state laws that "are applicable" and I believe the inference here is to the situation. In other words state law spelling out street lamps for roads is something that is 'Not Applicable' to the Shelf area. It also says that where state law is in conflict with federal law, federal law will govern, and finally extends, projects, the state boundaries to the limits of the federal jurisdiction for the purposes of defining what laws are in force in the area. The code then adopts LA law as if it were Federal law and says that enforcement will be by "appropriate officers and courts of the United States."
Section (3) falls under the section heading "State taxation laws shall not apply to the Continental Shelf." So IMHO (3) is a taxation statement only.
As for your three points.
Your statement on 1. is on target!
Your statement on 2., for me is a don't care. That Q is up to the big guys to decide, but I do find it curious that there isn't much more focus and discussion on this topic. For land based construction it would have been one of the first areas of investigation and fact finding.
Your statement on 3 is on target.
last item: the new regulation as I read it is slightly ambiguous as to the extent of coverage of the design that requires PE sign-off. http://www.doi.gov/deepwaterhorizon/loader.cfm?csModule=security/getfile...
But the combination of LA RS37:682 and the new rules, to me, requires that all engineering work on wells in the area of LA boundary Projection into the Shelf be done by Reg. PE's. And yes that is going to bring squawks a plenty.
That leaves open the area of rig operation, IMHO. Interior may elect to enlarge their new rules after the joint board report is finished.
duck
Saltwater, I agree there is no subordination between (2) and (3), but I think you missed the summary statement above them, 1333(a), particularly the last line which describes the intent of (3), which is "... restriction on State taxation and jurisdiction"
This is the meaning I get from the legal text:
(2A) says, "We are borrowing applicable state law for use offshore, to fix gaps in Federal law."
(3) says, "But that doesn't give the state jurisdiction offshore, or any right to the goodies out there, that is Federal turf."
This application of state law under Federal jurisdiction is common on other Federal lands, like National Parks and military bases. A recent example is the new law allowing firearm carry in Nat'l Parks, according to the laws of the particular state, but enforced by Park Rangers.
BTW, the Federal law we are having so much fun discussing was enacted in the 50's in response to the opposing claims of coastal states for the mineral rights below coastal waters. Rigs were already drilling 20 miles or so offshore, and drilling had already been done from small floating rigs. This law was a land grab by the US gov., and it worked.
OT re: DWH specifically but not in general.
Read more: http://www.adn.com/2010/10/02/1482856/oil-is-drying-up-and-we-should.htm...
Snake, that's a good post from the Anchorage Daily News. Some parts are directly relevant to the spill thread. It mentions one of the reasons for the recent boom in Gulf deepwater drilling:
and from a Seattle Times article:
BTW, Alaska is facing a sudden shutdown of the pipeline rather than a gradual reduction because below a certain daily volume the oil doesn't stay warm enough to flow.
Shell remains unsure about 2011 Arctic oil plans
See Shell Oil's proposed exploratory drilling activity in the Chukchi Sea and Beaufort Sea (Alaska)
http://royaldutchshellplc.com/2010/05/26/letter-from-shell-oil-company-m...
They'll have to come up with a solution to the minimum oil flow rate problem. One would be to produce the heavy oil in the shallower horizons - but that oil is also very viscous. The other would be to produce the heavy and introduce it into an oil upgrader to make a light grade synthetic crude. Such an upgrader would cost about $10 billion US. But if we consider the rate is 500,000 BOPD, that's 180 million barrels, worth a gross amount of about $10 billion to the parties involved - per year. Evidently a high hydrogen input upgrader yielding a 32 degree API syncrude will stretch the production period, and it's viable. So the question is whether the government of Alaska and the companies get their act together now to put this in.
fdoleza-
Regarding the heavy oil, my understanding based on a few casual conversations with some of the low level folks involved, is that they plan it to mix the heavier stuff with lighter oil from the other fields in order to get it to flow down TAPS. Of course that suggests that as light oil production declines, that also places a limit on how much heavy oil might be produced.
Regarding the TAPS rate, from what I've been hearing the lower technical flow rate on TAPS is lower than 500K BOPD, perhaps more like 300K. (See my previous comments below.) However, that may also depend on oil grade?
Full disclosure: I am not a pipeline guy nor have I worked heavy oil, so all my comments are based on what I've read or heard around town from people involved. Evaluate accordingly.
I addressed this on another thread (over at Drumbeat I think) a couple of days ago. While it is true that TAPS throughput is a looming issue, I feel strongly that Mr. Meyers is presenting an excessively worst case scenario in order to influence the oil tax debate in the Alaska legislature. In another article I believe he was quoted as suggesting TAPS could shut down as early as 2015. I think this is rather unlikely.
In the first place, I've been told that the minimum technical flow to allow operation of TAPS is somewhere around 300,000 bbl/day. Since posting that I noticed that in a 2007 DOE report
http://www.netl.doe.gov/technologies/oil-gas/publications/AEO/ANS_Potent... (see page 3-2) they refer to a minimum technical limit of about 200,000 bbl/day. The actual economic limit is no doubt higher, but is dependent on lots of other factors such as oil price. But 500,000 seems rather pessimistic.
In the second place, the other major oil companies operating on the slope have sanctioned some very expensive projects that probably won't come on line until circa 2015 or later. For example, BP is going full speed ahead with their Liberty project. The latest I've heard is that they won't start drilling their first well until 2011. This will be a cuttings disposal well that also provides as shakedown for their brand new purpose built rig. The actual production wells (5 plus one injector) will take around 180 days each to drill. Likewise, Exxon apparently is resolving its issues with the state regarding Pt Thomson, and now expects to start produceing 10,000 bbl/day of condensate (cycling gas) by about 2014 from Pt Thomson.
The point of this is that I have heard NO sense of panic from BP or Exxon that TAPS would shut down just as these multi million dollar projects came on line. Remember that both BP and Exxon, because of overlapping ownership in Prudhoe, Kuparuk, and other fields, have access to all the same data on production trends on the slope. I find it hard to believe that BP or Exxon wouldn't be raising holy hell if they were worried that they would have no pipeline in 2015 to take that oil to market. I do get a sense of serious long range concern about TAPS, but not the kind of fear mongering that Mr. Meyers is engaging in.
You need to be aware that "ACES" (Alaska Clear and Equitable Share) is VERY unpopular with the big oil co's. This was the tax scheme pushed through by Palin when she was governor. (The "Drill Baby Drill" version of Palin didn't emerge until she became a national candidiate.) With an election for governor and many legislators in a few weeks, big oil is making a concerted push to change the tax structure in Alaska. I think Mr. Meyers is pushing an absolute worst case scenario for TAPS in order to influence this debate.
So yes, there is a serious issue with TAPS, but it's highly unlikely to shut down in five years. In ten years or so,yes, it could happen. That's my take.
One further comment regarding ACES (Alaska's oil tax). One positive aspect of ACES is that it has helped to bring a number of much smaller companies into Alaska. Outfits like Brooks Range Petroleum are drilling up small features on the edge of Prudhoe and Kuparuk. Savant has taken over Badami and is trying to make it work. Renaissance has shot a 3D at Umiat (discovered by the Navy in 1947 but never developed). Likewise a number of small outfits working in Cook Inlet. This is in significant part due to the exploration tax credit feature of ACES.
Back when I first came up here, there were only 2 1/2 games in town. Either you worked for ARCO or BP on the North Slope, or Unocal in Cook Inlet. Having more players in town is definately a positive developement in my opinion.
The big co's (Exxon, BP, COP) seem more hurt by the tax features of ACES, and less helped by the exploration tax credit. I also suspect they consider the small companies as a nuisiance.
AG, I was hoping you would comment on this. I appreciate the pipeline and oilfield details as well as your political sense.
Sounds like Anchorage isn't turning into a ghost town just yet. Now we can just hope the permafrost holds.
Thoughts in reply to DE's thoughts quoted below.
From the MBI hearings it didn't sound like BP got much of anything accomplished with the BOP intervention before the rig sank. The initial attempts failed because the ROV pumps didn't have the capacity to energize the BOP. The testimony of Billy Stringfellow Aug 25 (page 396). It sounded like just before the rig sank they finally cut all the hydraulic and communication lines in an attempt to trigger the dead-man function.
I also suspect the drill pipe broke off when the failed BOP was lifted. It swung sideways and that could have sheared the pipe. There was mud coming out of the BOP so there was no visibility.
The falling drill string is an interesting idea. However, I don't see a 5-1/2 OD pipe moving very fast in a 6-1/8 ID pipe - particularly if it is moving against a flow.
I looked this up months ago and can't find the link to the catalog right now, but the rating for the flex-joint was 15 K when it was straight and not loaded. When loaded and bent to the 10 degree maximum the pressure rating was 5k.
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Just a thought. I honestly believe that the drill pipe was crimped and not cut by the BOP. I thought that the flow of mud in the center plume and the lack of it in the outer plume when the marine riser was cut off demonstrated that as a fact. However, the question upon lifting the BOP was; Where was the drill pipe? Did it break off as they were lifting it? What if it had not broken off when the rig hit the ESD. But the BOP shear rams actually closed. Remember the initial report was that the BOP was holding. Then there was a leak from the end of the fallen marine riser. Then it was leaking in several places. But what if the BOP did do its job initially but BP, in not knowing where the shear rams were, because of the fluid flow that was continuing to feed the rig fire was assumed to be coming from the well and not just fluid trapped in the marine riser that was boiling off. Maybe they cycled the BOP trying to ensure they were closed, while the rig was burning. What if they then dropped the 2,700 feet of 5 1/2 and 800 feet of 3 1/2: drill pipe. Now if the fluid density was not drilling mud but was porodcution fluid is it possible that the fall of 9,500 feet could generate enough force that the the end of the drill pipe punctured the base of the production casing just above the concrete at the shoe track. Was that near the pay sands? Just a hypothesis that someone might need to confirm with some calculations.
1) How long would a marine riser full of produced fluid generate enough vapor pressure to continue to flow at the rates of oil and gas burn demonstrated during the fire fighting efforts?
2) How much force would a 5 1/2 inch drill pipe fall at in the tapered production casing full of mud? a tapered production casing full of seawater? a tapered production casing partially full of both? or a tapered production casing full of production fluid?
As our experienced drillers have noted the real issue was getting produced fluid in the marine riser. Once that happened it was Katy bar the door cause it was coming up and expanding with a vengence. The marine riser was not rated for the any real pressure.
Also I am pretty sure that was why BP was unable to use the capping stack any earlier. They had to let the wells reservoir pressure decline to get the shutin pressure below the capping stack to below the hydrostatic test pressure of the Flexjoint. It was the weak lewak in that setup. Jinn was right back on the 24th. The ideal situation would have been to just pull off the LMRP at the HC connector above the BOP stack. There still would have been the drill pipe in the riser to deal with. Until the marine riser was cut off the drill pipe folded into the riser and trapped in the shear rams kept the LMRP connector compressed so it would not have released. Don't know why they did not try to do it again after the marine riser was cut.
Maybe they did and just didn't tell. Maybe BP or Sec Chu didn't want to place any stress on the wellhead. Remember the BP reports says they miscalculated the datum and didn't fill to the correct TOC (top of cement) to fully fill the surface and intermediate casing annuli that support the wellhead. Now was that calculation done by a .... Naw don't even want to go there.
Why have we not gotten any feedback as to what was keeping the LMRP in place. Theuy said they took it off the BOP Stack on the Q4000 to ship it to the NASA facility. They should have been able to detect there if there was anything wrong with the connector hydraulics when they separated the units.
Comments can no longer be added to this story.
Not sure which Catalog you looked it up in but the Oil States FlexJoints I saw maxed at 6,000 psi rating. The 5,000 was only hydro'ed to 7500 psi. I believe that BP confirmed this and the Admiral noted it in one of his conversation. When working on Thunder Horse in the past was told the weak leak in the risers was the Flex Joint. Not sure much has changed since then although that was back when it was Crazy Horse. Be glad to rethink this part if someone can show me a datasheet on the actual flexjoint that was used. Note BP commented it had been replaced on the DWH marine riser form one of the other rigs. Don't have time right now to chase the reference.
This page says "• Withstands operating pressures up to 10,000 psi."
http://www.oilstates.com/fw/main/Subsea-Configurations-375C471.html
The catalog data sheet that I remember was a PDF file that had different configurations depending on things like depth, maximum flex angle and axial loads. There was one rated for 10000' and 10 degrees flex and the pressure rating was 15K for no load condition, but was de-rated down to 5K when maximum loading was applied. The DWH had drilled a well to 10000' just before the Macondo well.
This page has the 12000' depth unit with maximum no load pressure at 9000 and loaded rating at 6000. The 10000' depth unit on this page has a rating of 7500 and 5000 psi depending on load.
http://www.oilstates.com/fw/main/Subsea-Configurations-375C471.html
Of course none of this explains why they didn't just snip off the riser and unlatch the LMRP and drop a working valve stack on top of the failed BOP. The only reason I can see why they didn't do that back in May when CEO Tony Hayward said they were considering that option is because they were afraid it would reveal that the well bore lacked integrity below the mud line. They made a calculated decision that it was better not to know than to find out the worst. We now know that was a horrible miscalculation.
Then later on when the relief well was close and they were finally ready to find out if the well had integrity they could not unlatch the LMRP at that point because somebody would undoubtedly ask why they hadn't done that earlier.
No, the page you quote does not say that at all.
The maximum working pressure of any of those units, in that range, is 6,000psi. In earlier discussions the model was quoted as being a #5 which is rated to 5,000psi working pressure. If you are unable to quote correctly a page that you yourself post to support your argument then any of the rest of the 'information' that you post must be disregarded as unreliable.
NAOM
"Axial tension, internal pressure and angular rotation are interactive functions and the ability to achieve the maximum stated condition for one function is based on the magnitude of the other two."
In other words, when the flex joint doesn't have MODU tugging on it the pressure rating is higher.
The 5000 psi rating for the no. 5.0 unit is when the joint is loaded. That means it is bent 10 degrees and has an axial load of 2500 kips. When not loaded (no axial or bending load) the pressure rating for that model is 7500 psi.
You miss out, I presume deliberately:-
Which clearly shows a de-rating under load. Please note that the spec shows a MAXIMUM working pressure ie that does not increase under reduced load. The Load Case 3 is the hydrotest, under no load, to 150% working pressure.
Please do not miss-state the information to try and bend it to your desire. If this is how the oil industry treats specifications then may your deity help the rigs, they are going to need it. It also clearly displays the need for PEs in the industry. This is my last response to this rubbish, goodnight.
NAOM
EDIT: spelling
Are you having fun playing word games?
I will stop quoting the manufacturer and say it in my words:
The flex joint can hold more pressure when there is not a load on it.
Are you having fun playing word games?
No word games here, Jinn. The problem is that you don't seem to understand the manufacturer's words. From the configuration chart you cited: "Max. Working Pressure (psi)... ...5000" [for the #5 unit we are talking about]
I will stop quoting the manufacturer and say it in my words:
You never quoted the manufacturer as far as we know; your "10000 psi" quote didn't show up on the link you cited.
The flex joint can hold more pressure when there is not a load on it.
Jinn, this is not a relevant argument. The higher rating (only in Load Case 3: "Hydrotest") does not apply to the bent, stressed, possibly damaged Macondo Flexjoint, or to any Flexjoint in actual use. In use, the joint is subject to axial loads and the test case does not apply.
You wrote this awhile ago:
I completely convinced that anybody with an ounce of intelligence would have expected that something in that well would have given way given the forces involved.
So why would anybody with an ounce of intelligence think that this beat up Flexjoint would be safe at its unloaded, brand new maximum test rating? After the riser was removed, it was stuck a few degrees off of vertical, indicating internal deformation, so it would be reasonable to doubt whether it would even hold its working pressure of 5000 psi.
You never quoted the manufacturer as far as we know; your "10000 psi" quote didn't show up on the link you cited.
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OK sorry I pasted the link to the same page twice. Here is the page that says "Withstands operating pressures up to 10,000 psi."
Notice they also can make them to higher tension loads and higher rotational angles. That other page does not list all the available configurations.
http://www.oilstates.com/fw/main/SCR-FlexJoint%C2%AE-680.html
The point I was making is we don't know what BP knew about the flex-joint. All we can do is guess what they may have known or thought they knew.
As I said before the quickest way to cap the Macondo well and also avoid the whole question of the flex-joint would have been to unlatch the LMRP and drop a new BOP on top of the old one.
OK, Jinn, I see where you got the quote, thanks. And wow! you said "sorry", I appreciate that also.
The problem is, that quote is for OilStates' newer SCR series, not the Subsea series on the Macondo LMRP, so it doesn't apply to this well.
The new SCR Flexjoints have an inverted cup housing with solid metal on the top face. The Subsea units have an upright cup shaped housing with a black flexible (rubber?) boot on top between the housing rim and the riser connector, as we saw in the ROV videos.
[edit]You wrote: The point I was making is we don't know what BP knew about the flex-joint. All we can do is guess what they may have known or thought they knew.
Well, yes, but you have seemed pretty certain in your comments up til now.
You have been suggesting that they should have just unlatched the LMRP for a couple months now, but, as several other folks have noted, until more information comes out we can't confirm your theory. As DE said above, "Don't know why they did not try to do it again after the marine riser was cut.", but I expect we will eventually know why. Until then, we are all just speculating, right?
I have very little confidence we will ever know why they did not unlatch the LMRP. Many other questions may never be answered either. I am disappointed that Wyman Wheeler is not going to testify. That probably means we will be left to only guess what actually happened during the negative test. And they still haven't told us what relief well found in the annulus. Was it the original mud or was it the mud from August? I beginning to suspect we will never know the answer to many important questions.
And yes snipping the riser off first would be necessary for unlatching the LMRP. Attempting before cutting the riser off would be like taking your socks off without removing your shoes.
You edited your reply to say:
Well, yes, but you have seemed pretty certain in your comments up til now.
Yes I'm pretty certain that saying 5k is the upper limit for the Macondom flex-joint is nothing but a guess. The pressure it can take in with no riser load could be higher. There is the No. 6.0 unit on the page that has a no load pressure capability of 9000 psi. BP said they were prepared to let the pressure increase to 9000 psi when they shut in the well on July 15. And they actually did apply 7500 psi pressure in August during the static kill.
BP said they were prepared to let the pressure increase to 9000 psi when they shut in the well on July 15. And they actually did apply 7500 psi pressure in August during the static kill.
Jinn, if you subtract 2250 psi ambient seawater pressure from those numbers you get 6750 psi and 5250 psi for the pressures the Flexjoint would have taken. These are between the working pressure and the test pressure, so it looks likely to me that BP (or Adm. Allen's engineering team) were paying attention to the specs.
They also carefully shimmed the Flexjoint to vertical before capping, which would have moved the elastomer flex ring into its strongest position. I think this another clue they were wary of over-pressuring the joint, perhaps in response to input like the letter DE has posted below.
Yes, Thank-you for spelling it out. That was exactly the point I was trying to make.
If the original reservoir pressure was 11900 psi and the oil in the well has a density of 6.7 ppg then the shut-in pressure would be less than 7300 psi and the flex joint seal would see a pressure difference of around 5000 psi which is well below the no load maximum rating.
But for all we know the maximum pressure in the no-load state for that particular flex-joint could be higher or it could be lower than 7500 psi. It is not something (as far as I know) that has been revealed.
Also, as far as I know BP or Adm. Allen never said the flex-joint was a weak link or was in any danger of bursting. Allen did say that the transition spool was the weak link. Was Allen's statement correct or did he get that wrong? That is another thing we will probably never know.
If it is field units i.e. psi you add ambient pressure to get psia. Where are they measuring the subsurface gauges read by ROVs that are open to the sea (9,250 psia pressure opposed by 2,250 psia ambient is = 7,000 psi gauge) Here in the USA psi means gauge and in other places bar means absolute. Maybe I am wrong. Maybe we drive on the left hand side of the road now and I am headed for a head on collision. The Deepwater Horizon Reponse team was asked to clarify but they didn't. But I still contend the numbers add up. And the ppg for the prodcution fluids was on the order of 5.0 ppg at the bottom of the well and 4.8 at the top. Make sure you include the influence of the 2,000 GOR of gas at the surface that is still in the liquid stage in the well. My pressure profile is based on a rigorous simulation of the casing with the drill pipe in it so I tend to believe it to be a bit more accurate than the back of the napkin calcs. They work good for incompressible mud but not so good for compressible production fluids. The production fluids compositon are from an analog lower miocene well in the close proximity and matched to the API gravity and GOR gas flow ratio at the surface from the production data from the Deepwater Enterprise that Secretary Chu released on his website. Don't think it was too far off from what BP eventially reported but I haven't doe a real close comparison yet. The original reservoir pressure was between 12,900-13,200 psia. My simulated number at shut in pressure was in psia. Therefore in order to get gauge pressure (or the psi at the wellhead with 2,250 psi opposing it you subtract the 2,250 from the psia and get the shutin wellhead pressure in guage measured by ROV at the seafloor or exerted pressure on the flexjoint.) Thus 9,977 psia - 2,250 psia = 7727 psi. Well over the hydrotest pressure limit for the flexjoint. Only because of the 750 psi pressure decline in the reservoir did the flexjoint not fail.
The explanation I heard BP give for the pressure readings from the well after the capping stack was installed was that they were coming from electronic pressure transducers in the cap. The sensors have no way of knowing what the pressure is on the outside the cap or how deep underwater the measurements are being taken. The same pressure sensors were used during the integrity test when the well pressure was lowered to what they called ambient. At that point (ambient pressure) the reported pressure reading was 2280 psi.
The highest pressure that was achieved across the flex-joint seals was around 5200 PSI. The highest pressure reading was around 7500 psi during the static kill.
I believe you are correct that BP's projection for the expected pressure upon shut-in was based on the assumption of a lighter fluid and a higher pressure producing formation. The calculation I made was based on the reported pressure and composition of the producing formation closest to the casing shoe.
As far as I know we can only guess what the actual manufacturer's pressure specifications might be for the Flex-joint on the DWH LMRP. But we do know that BP said they were prepared to see pressure as high as 9000 psi when the well was shut in. If it had gone that high the pressure difference across the flex-joint seals would have been a little over 6700 psi. We also know that they used what they called jacks (wedges?) to immobilize the flex-joint before installing the cap.
I will concede the point. Forgot that Roxar piezioelctric type can be direct psia or surface psig based on the oil bath pressure charge. They can be based on water depth but would create a flow path out on failure of the element which is frowned upon. Still have issues with the pressure being that low and the Admiral wanting BP to maintain constant monitoring on the well for integrity. 5K is a long way for 15K.
I think that is a legitimate question. My suspicion is they were concerned about underground blowouts. As I said in early May the BOP-on-Bop plan was on the table. That plan meant getting rid of the LMRP which includes the flex joint. A few weeks later the BOP-on-BOP plan was declared too risky. So what would be the risks involved in that?
I find the whole business of removing the failed BOP before the relief well intersect to be very puzzling action also. Suddenly the transition spool is declared to be a weak link.
There is definitely something not being told. I don't think we will ever find out, because part of any explanation is going to have to also include why the explanation was kept a secret for so long. But, maybe we will get lucky and somebody will spill the beans.
The real risk was the low TOC on the surface casing. By having open space between the surface and intermediate casing, I would assume that that would weaken the structural integrity of the wellhead and make it harder to resist bending moments. Look at the picture fo teh BOP stack and the LMRP on the barge on the Deepwater Investigation site. I stood next to T3 Services 15K BOP at the OTC back in the first week of and it made me feel rather small. I was talking with one of the T3 gents and we were discussing how to intervene through the choke and kill line. Next thing I know BP was proposing the top kill. I am sure that was just a coincidence. There isn't anything supporting the BOP otehr than the wellhead connection that I can see. See the support frame on the barge in the picture I referenced above. Would have had to construct a mud mat to support something like that and even then not much support in the seafloor mud. My best guess as tyo why they had to manufacture their smaller capping stack. As with all subsea work, weight is always a major consideration.
I don't know if BP's knowledge of shallow casing cement was part of the basis of their fears, but the evidence is that from the beginning BP was concerned that the real risk was an underground blowout. At the bottom I quote the testimony of B. Stringfellow, Transocean subsea superintendent. He participated in the ROV intervention to activate the failed BOP.
If BP had a concern about the weight and bending moments of a valve stack then that would have been a good reason to remove the LMRP and get rid of the flex-joint. I don't think the stack they put on was much lighter than an off-the-shelf BOP.
But I suspect the main concern was the damage that had already been done by the forces of the uncontrolled DWH on 4/20-4/22. I think they didn't want to put any additional pressure on the well until the relief well was close.
Waiting until the relief well was within a few feet of the well was not an engineering decision, but more of a PR decision. They didn't want the true structural condition revealed until they were in a position to show the world that there was a solution close at hand that would deal with it. In other words they preferred to postpone the integrity test because they guessed it would fail. It was a bad guess. It was a bad guess just like all their other bad guesses. They guessed their other solutions were going to work. They guessed this one was going to fail. If they had known it would work they would have done it much earlier.
******* BILLY STRINGFELLOW TESTIMONY - AUG 5 ********
In the early hours of the intervention,
BP was -- they weren't sure whether they wanted to
close it in or not because of what would happen in
the formation of the well...........
********** then later on cross-examination **********
Q. So going back to the question that your
counsel asked you when you said that early on it
wasn't clear that BP was trying to shut in the well,
do you remember that testimony?
A. I do.
Q. So you're talking about the first couple
hours after the explosion, BP did not immediately
try to activate the two ROVs that we've talked
about?
A. There were discussions within the well
construction group of what could possibly happen if
we did shut the well in, and --
Q. And the concern -- I'm sorry, go ahead.
A. And I think that was based on the fact
that there was unknown pressures, what would be
created by closing the rams. And the fear of
creating an underground blowout.
DE, gotta question your last statement: "Only because of the 750 psi pressure decline in the reservoir did the flexjoint not fail." The hydrotest pressure value is simply the pressure to which the flex joint was tested to, a proof value. One would not expect the joint to fail at test pressure plus a couple of hundred psi. I would think that is too close to the safety margin.
Thus, even without the decline in reservoir pressure isn't it possible for that flex joint have survived a significant overpressure field Condition?
duck
Duck, I think the gray area, the range of uncertainty about the strength of the flexjoint, extends both above and below the rated strengths of this unit. It is likely, as you suggest, that the flexjoint was actually much stronger than the 7500 psi hydrotest figure; presumably OilStates would have informed the response team of actual failure pressures from their own testing.
OTOH, the elastomer flex element was subject to extreme loads when the rig lost power and later sank, and it was held off-center for two months by the bent riser. I think the elastomer cuff was deformed by this abuse (it had to be forced back to center by jacks) and I assume deformation would have weakened it.
So, sure, maybe it could survive overpressure. Or maybe it sustained enough damage to make normal pressure risky, and made the team cautious about stressing it. I sure hope we find out what they were thinking through all of this.
OB, I totally agree with your comments about the added stress etc.
As far as the range of uncertainty, I don't agree that there is a negative uncertainty on a proof test pressure. That is a pass / fail test. That test says this S/N joint passed the proof pressure.
Now when you abnormally load that joint then all bets are off. Certainly, as you say if the cuff had been deformed it might have been damaged. But depending on the detailed design of that seal and the elastomer used, deformation does not automatically mean damage even with the exceptional forces involved.
I was simply questioning DE's somewhat absolute statement given the circumstances. Bit unusual in engineering circles. That's all.
I would suspect that if the actual design was tested to destruction as they do aircraft wings, the testing would yield a significantly higher failure pressure than the proof pressure. If proof and failure are very close then the proof testing fall out would potentially be large. Given the seriousness of the application I would not expect a test to destruction failure point to even close to the proof value.
And certainly given all the unknowns caution by the BP/CG team was the order of the day. I'm myself am a belts and suspenders kind of engineer. Tends to drive a lot of folk around me a bit daffy. But I dislike, intensely, physical failure of designs. I look on that as bad engineering / design.
duck
Duck, I guess I was trying to be too brief and clarity suffered. I agree with your responses, I would just add that as a crusty old school carpenter, I also dislike physical failure of designs because it can really hurt.
I am one of those engineers that believe that design pressure should never be exceeded. Even if teh code allows a certain number of excusions above a year for process piping under ASME B31.3. We establish that margin for a reason and part of that reason is uncertainty. The hydrotest is a short duration designed to take it up to a certain % of the maximum hoop stress and to ensure that everything was welded as planned. However, this may only be done once when it is new and other factors may be at work that can weaken the joints. One of those is HIC that can be brought on by cathodic protection. Too much and too many H+ protons running around in the metal latice. Can migrate to carbon in the steel and cause methane bubbles to form and internally crack the steel. A little is tolerable. Sort of like when you were a junior engineer and the x-ray tech was reviewing a weld. A certain number of occlusions per inch of a certain size was acceptable. Go over and the weld is rejected. Too much and the pressure retaining capacity is reduced. Normally once in production heat of the produced fluid can drive off much of the excess H+. But while shut in and cold, the process goes forward and once the cracks are formed they don't mend themselves. Ductile metal helps also, Tends to stretch better. I know this is looking at this in rather simplistic terms but sometimes easier to explain.
DE, understand your point. And I agree with your design pressure statement. From my view in extenuating circumstances understanding the absolute max pressure from a "most likely to rupture point of view" I was struck by the exactness of your 750 psi reservoir statement under the conditions, i.e. "Only because of the 750 psi pressure decline in the reservoir did the flexjoint not fail." It was the small number coupled with the did not fail that gave me pause. I don't think I might have made that statement. I might have said the 750 psi caused the total pressure to fall within the design limits (which I currently don't remember). So I'm NOT quibling with the facts of the statement just the seeming low margin of the statement. Matter of how we see degree. Under the circumstances I think that I would have been looking at the proof or near proof pressure as the "amazing that it did not fail" gate. AND NO engineers do NOT want to see operation under nearly all circumstances at the proof pressure and as you state and I mentioned, we don't know what has happened to the joint since the proof test. Even from a design pressure point of view, the abnormal stresses to which it had been subject may have and quite possibly could have reduced it's rupture pressure to at or below design pressure. Only by dissecting the design does another engineer have any idea of possible present condition of the joint and then it's a wild A$$ guess.
Well, like I said I was only interested, one engineer to another, what your frame of mind or reference was. Thanks.
duck
Deep eng
There have been a lot of posts on this.
I agree with jinn. I'm remote from my pc at the moment but from memory :
- Pressures are absolute. So the 7000psi shutin whp is 7000 psi inside the stack, and about 4800psi differential to seafloor ambient
- I calculated average reservoir fluid density in wellbore at 4.9 ppg from correlations. Bp quote it at 5.18 ppg
- initial reservoir pressure was 11900 psi from open hole logging (this is hard data)
- do the maths and the reservoir depleted by around 1500 psi. This is consistent with quoted size (stoiip around 150 mmstb)
DE, what I like about your analysis here is that it is based on what was known before the well was shut in. It's real helpful in trying to figure out why the response unfolded as it did. Even allowing for some disagreement about exact numbers, you've made a good case for the flexjoint as a potential weak link, which may explain some of the caution we saw in the slow progress towards capping and shutting in the well.
What you are saying in effect is that BP dragged their heels on the capping stack because they didn't want to reveal the weak point in the well.
I would say that is an likely to be very accurate assessment.
It was also a very foolish strategy. One would hope that if there ever is a similar blowout that sort of foolishness won't be repeated.
Had the capping stack been installed earlier they may not have been able to shut-in the well completely, but it would have made available several ports from which to collect the excess flow in a controlled way. The result would have been considerably less environmental damage.
Let's say they believed that 4000 psi (6200 absolute pressure) was the upper limit the well could stand. They would shut the capping stack as they did and then slowly throttle the flow from the one or more of the available ports. If the pressure rose to the limit they would then be forced to stop and not completely shut off the flow. Instead they would direct the excess flow from any or all of the multiplde ports. That would have made it possible to reduce the flow total and direct a larger percentage of what did flow to ships.
And the really stupid part of BP's foolish strategy was that because they were afraid to put a stack on early in the process (like middle of May) by unlatching the LMRP, they then later couldn't use that means of capping the well, because the obvious question would then be - why didn't you do that 2 months earlier? So they had to invent this whole narrative that it is a long complicated time-consuming process to put a valve stack on this well.
I believe they were planning and building the capping stack very early on and didn't know when it would be ready, and in fact, Wells seemed ecstatic when announcing it was ready. They were just trying other (stupid) contraptions in the interim.
Yup that is BP's story and they're sticking to it.
But on May 10 Tony Hayward said in a press conference that among other plans that they were considering was the BOP-on-BOP plan. He said they had the additional BOP already on site. Basically they would drop the other BOP onto the connector at the top of the failed BOP stack. Later that month both Allen and Wells said the BOP-on-BOP plan had been cancelled. Both said the reason was that it was too risky. Neither explained what the risks might be.
The connector that a BOP would be dropped onto is shown at the top of this photo:
http://www.flickr.com/photos/gcaptain/4991059854/
Yeah I suppose that would have the drill pipe sticking further up and made it even more riskier to set a valve of any arrangement onto.
I still believe they should've removed the whole defective BOP and swung a new one on. Doing so would've avoided the drill pipe interference.
Yes it probably would have meant snipping off some drill pipe that was sticking up. But that should be relatively easy compared to snipping the riser.
I'm not saying that at all, Jinn, I think I made my position clear above. Monday morning quarterbacking is easy; until we get the full picture I'm not going to second guess the response team's caution.
I would agree but at this point I doubt the truth will ever emerge.
The government has recommended that unlatching the LMRP and dropping a valve stack on to be a required response to a blowout in the future.
After months and months of the current investigation no one has even bothered to ask if unlatching the LMRP by ROV was even attempted on the Macondo blowout.
I will clear up one misconception. BP did know that the Flexjoint was lower pressure. On July 10th, a letter was faxed directly to bp's Bob Dudley at his fax number he put on his letter to the NIC (Admiral Allen). In that letter, which an excerpt is included below, suggested that they retry to release the LMRP and the calculated shut in pressure would be about 9,977 psi based on the original reservoir pressure. I have omitted some comments that are not germane to this discussion.
July 10, 2010
bp
Bob Dudley
President & CEO
Gulf Coast Restoration
501 Westlake Park Boulevard
Houston, Texas 77079
Dear Sir,
First let me express my sincere appreciation for the unlimited efforts and resources that bp has committed to resolution ......
"Second let me express a sincere desire to see this well shut in so that the continuing damage to the coastal states and marine environment can be limited to what has occurred to date and no more. Third I wish to express a concern that an opportunity to fully shut in the well may be being missed at this juncture if bp does not consider retrying to release the LMRP from the lower BOP stack. Fourth, because of the process that has been put in place for submitting ideas the ability of trained experienced engineers to interface directly with bp on ideas regarding the isolation of the well has been severely limited. Therefore, please forgive this direct approach."
.... "Using the information provided to the public both by the DOE, the US Congressional hearings, the MMS studies by West Engineering, pictures of the Deepwater Horizon BOP provided by Transocean and Cameron provided illustrations in their literature, to derive the type of Shear Rams being used, the failure of the BOP stack to shear the 5 ½” S-125 drilling pipe given the water depth and this type of failure is also highly probable. On the basis of these ... conclusions, I strongly believe that the flow from the blown out well is primarily up the production casing, with about 60% of the flow coming up the drill pipe which is crimped in two places. The remaining flow is up the production casing around the annulus created by the drill pipe in the production casing and is leaking through the various BOP pipe rams below the shear rams. This is supported by the pressure reading profile taken of the BOP stack and released by the DOE on June 8. I have made a reasonable simulation of the well utilizing a process simulator that reasonable match the flows at the low end of the most recent prediction ranges that have been reported by the government for both gas and oil flow."
"I have checked the calculations of the production casing and intermediate casing. On the basis of the profile I calculate, for a shut in wellhead, the pressure of the well would be slightly less than 10,000 psi at 9,977 psi. On the basis of these above assumptions and calculations, and the information publically provided the BOP stack and the well casings appears sufficient to handle the shut in pressure. There are some caveats to this statement. However there is one item that has not been made public and that is the pressure rating for the Oil States flex joint. On the basis of the online information provided by Oil States I am of the belief that this one item is the “weak link” and is only good for 5,000 psi. 7,250 psi with allowance for hydrostatic seawater pressure added. This is significantly lower than the 9,977 psi that the entire BOP and LMRP stack would see if the flow were shut off at the marine riser adaptor flange. This differential is above even the 40% additional margin for hydrotest so failure should be assumed. If the LMRP is removed, then the weak link of the flex joint is removed and the lower BOP stack is fully pressure rated to contain the well."
"It is my understanding that removal of the LMRP was attempted immediately after the sinking of the rig. Given the drill pipe trapped in the BOP, failure to open the lower connector on the LMRP was predictable. The drill pipe would have been holding the connector in compression due to the drill pipe crimped in the BOP shear rams and the bent section of the marine riser section above the marine riser adaptor flange. However, when bp cut the marine riser off the tension on the drill pipe was released. There is a higher probability that the LMRP connector can now be released. I notice that bp is going to try to use an overshot tool to put in place the latest cap. I am uncertain as to how bp is planning to handle the drill pipe in the LMRP stack."
"Based on reports on how the latest generations of rigs were designed to handle the operation of Deepwater BOP stacks, during an emergency disconnect the super shear (casing cutter) rams were suppose to cut the higher strength pipe. Then the rig was supposed to pull up on the pipe such that the cut off pipe would clear the normal shear rams for seal off. Given the House hearing testimony that the settings for the rig was in their EDS-1 setting to trigger the normal shear rams only, it is obvious this was not employed. Delays in tripping the emergency disconnect and the loss of emergency power due to the ingestion of methane into the diesel backup engines, and he subsequent overspeed and explosions, the proposed methodology may not have been viable anyway."
"A real question is that now that the marine riser obstruction and the tension on the drill pipe has been removed, should bp reattempt to disconnect the LMRP? If the LMRP can be removed the drill pipe might be pulled and possibly be severed at the shear rams. If the shear rams have closed enough to set the ST locks. The BOPs are designed to lock in place so that they are not released if hydraulic pressure is removed. However the shear rams not having fully closed may not be locked in place. The pipe rams probably are locked. Please note that only a 60 psi differential pressure is being taken across the BOP shear rams on the annulus side. Most of the resistance on the BOP annulus is being taken by the lower variable and test pipe rams. Removing the LMRP is the normal mechanism for performing an emergency disconnect of the rig."
"Three possibilities now exist. The first would be to pull the LMRP off and try to work the drill pipe back and forth to cause it to break at the shear rams. Assuming the shear rams are locked in the partially closed position. Then a hot stab of the shear rams might get them to close and seal off the well. The second is to remove the LMRP and then cut off the drill pipe at the top of the connector, and putting a 10K pressure cap or another BOP on the top of the BOP HC male connector. The third is to remove the LMRP and then thread a female connector welded to a 32 foot 24” OD pipe with 3” wall thickness with a reducer and 12” 10 or 15K valve added to allow flow through until it can be shut off. The last would take the longest and require the prefabrication of materials that are not off the shelf. It has been offered as an idea to the USCG but no response has been received to date."
"I believe that these options can lead to the best chance of full shut in of the well. ... If the casing hanger has not lost its integrity, which given the 14 ppg mud in the annulus and the higher pressure than the production formation at its base, makes failure up the annulus a low probability. Calculations should show that the production casing should not have been buoyant. I do not see a physical mechanism for the casing to have lifted into the BOP that some have surmised. I do see a mechanism for partially cured cement in the bottom of the well to have formed a micro-annulus inside the well and to have led to the failure of the cement plug and the shoe. Failure of cement shoes is a known problem that Halliburton has addressed in papers they have presented."
"To summarize, I believe a concerted effort to remove the LMRP should now be retried. If still unsuccessful the new proposed cap and Helix Producer can still be employed."
"If you wish to discuss my concerns or ideas further please contact me at ....."
In restrospect the 9,977 was psia versus psi, so the gauge pressure after subtracting hydrostaic pressure was 7,727 psi. This is why my earlier statement in a past thread was that the reservoir pressure decline and near bore pressure decline was about 750 psi and that is the only thing that kept it from exceeding the hydrotest rating of the flexjoint. Also when the Oil States flexjoint was manufactured the hydro test margin was 50%. Since about 2002 it has been about 40%.
Remember, this letter was sent before the well was shut in on 7/15 and the BOP stack later removed. In addition, at the same time Transocean and Oil States designated representatives were contacted and asked to review their data on the flexjoint. Because of the confidentiality agreements they had with BP it was noted that they probably could not say anything to an outsider, but were notified that they should contact bp immediately if the flexjoint was rated for 5,000 psi. If they did not and the flexjoint had been exceeded that would have been negligent on their part.
Bottom line is that while other people are just talking about it, professional people try to do something about it.
DE, I appreciate your post of this letter. It got to do double duty, as a timely heads up to BP and now as another big help to TOD readers trying to make sense of the blowout response. Please pass on my thanks to the writer.
One question, when a flexjoint is overpressured and fails, is it ruined or can it reseal when the pressure drops? I assume a huge spike would blow it apart permanently, but what about the slow rise it experienced when they shut it in? Could they have backed down safely if a small leak showed in the middle of the joint?
I guess hydrate formation could complicate the scenario.
edit to add: I just found this in the new Drilling Safety Rule that Brit310 posted at the thread bottom [my bold]:
Requirement for a subsea BOP stack equipped with Remotely Operated Vehicle (ROV) intervention capability (at a minimum the ROV must be capable of closing one set of pipe rams, closing one set of blind-shear rams, and unlatching the Lower Marine Riser Package);
I wonder if this new rule is a response to a problem earlier in the spill?
I find the letter somewhat amusing.
The presumption that the letter writer has better insight than all of the assembled industry experts (not just BP) is not justified.
The letter writer admits to having no data other than what was found in public releases, while one might expect the real experts had every shred of data in existence.
The last comment is particularly ironic in light of the PE discussions here over the past week or so. Does the statement "professional people try to do something about it" while having no real information represent the way a PE is supposed to operate?
Geez, Salt, you are so quick to unleash the arrows and spears.
In fact the letter writer might have better insight than the assembled industry experts. They just might be way to close to the woods to see the trees much less the bark on the trees. Also, the group think, collective mind set (remember the Borg Cooperative) can be hard to change much less introduce an alternate idea into. Saw this many times in my Corp. Trouble shooting work. So yes it is entirely feasible even without direct access to the "real" data to see something different!!!!
As far as the "real experts" (why are they any more real then a PE like DE? And are the "real experts" actually PE's???? Have you checked their creds to see just how expert they are, or do you simply check the box because the are inside the corral of BP et al & CG et al. "real experts" by association???? And the RE's may be suffering from data overload so bad that that the few nuggets of important information, that might trigger different plans and approaches, are simply so buried in mounds of data such that while they had the data they never saw the data.
And yes from the stand point of perception it would have been better if DE had not made the PE action comment. I think maybe his frustrations with the whole week long debate on PE's may have simply fallen out of his keyboard.
duck
And Salt, outside of the Patch, in "regular" life engineers and Reg. engineers take a lot of guff / crap and bad mouthing simply because they are engineers and PE's. So sometimes our sensitivities can show through. The constant backwash does get old.
duck
Saltwater: What industry experts? Have you ever been given a listing of the "industry experts" that were on this supporting BP. Most of the real experts that I knew were not asked to help. Given the bent towards academia that the government (and BP in their efforts to placate the goeverment) had demonstrated it was obvious that they might not have enough practical experience to truly understand what they were dealing with. They seem to be ignoring the LMRP and only talk about the BOP stack.
The bottom line is that if one sees an unsafe act or practice about to be made one speaks up and takes it to the highest level required to get resolution. (i.e. the Stop Card!) It is also what PEs get told on an annual basis in the mandatory 1 hour ethics CEU that they have to take to keep their license. It flies in the face of the standard operating practice of the oil and gas industry which seems to be 1) keep you mouth shut, 2) pay attention to your own business, and 3) go along to get along. Sorry but that attitude got 11 men killed. Everyoine of those men on the rig drill floor had the opportunity to exercise a STOP. BP's David Sims and Pat O'Brien and Transocean's Daun Winslow were all on the platform. If asked by anyone of the men they would have have shut things down.
Only when you recognize that we each have a responsibility to use the knowledge and education we have to think for ourself, discuss the issues openly with others and share lessons learned with all can we hope to reduce the risk for all. Although only those qualified should be making key decisions, each should have input. The letter only made sure that BP investigated the flexjoint rating. The additional industry contacts were made to ensure that BP had the right data and was insurance. If wrong it was in the right direction. The response team had stated that the data they had on the BOP was not up to date. Why would you think the flexjoint, that was not listed on the Transocean Deepwater Horizon spec sheet, data would be available to them.
Not sure where you got your 11,900 psi as it was not released initially that I know of. Maybe you can clarify when it was reported and by whom. It was 12,900 - 13,200 psi across the pay zones based on the House Energy and Commerce committee testimony and the MMS/USCG hearing testimony. The Pore Pressure in the HAL Opticem reports at the payzone was 13,197 psi as well. Also the shut in calculation assumes there is no mud still in the production casing, although some heavier mud or junk fromthe junk shot might have been held in suspension depending on the flow profile.
The other question I would be asking is why did they need to worry that much about the integrity of a 15K well, if all the shut in was able to develop was 5K? Also the Admiral stated in one of his press conferences that the weak part was in the LMRP at 7,500 psi. Just a sanity check....
Just a note on my question about ballast systems for semis elswhere in the thread. I did pull the MMS accident investigation for the TH listing incident in 2005 along with my questions for issues on the ballast/bilge system for a new semi and sent an email to Mark Bly with BP. He did forward my request to one of his safety engineers who has forwarded my request for lessons learned to the Thunder Horse VP. I am encouraged that this may indicate a paradigm shift in BPs ideas on how safety should be addressed. e.g. a bit more open to teh industry. However, like trying to hit the ball straight with a golf swing, it is all in the follow thru.
DE, a few days after the blowout, a trusted local source in the industry told me that **** had immediately provided experienced deepwater PEs to BP, as well as other resources, as part of the industry effort to kill the well. The only catch was that the assistance and the individual engineers could not be mentioned because **** did not want its name associated with the blowout. I think that has already been reported here on TOD, somewhere deep in the archives.
A couple months back I got an update, that these **** PEs had been working with the government led response team that took over from BP, along with engineers from ++++, another company with lots of deepwater GOM experience. The same cloak of invisibility applied, that no mention of the company or the individuals was permitted. That is why there is no listing of "industry experts". After things cool down, I hope the info comes out; the PEs, other loaned employees, and their companies deserve credit.
I would like to see a review of the response to see if it was the best way to respond. Look at the suggestions received haow they were handled, and who lead the teams that were deciding how to respond to the incident. Might give insight into how to handle future high tech incidents. As for this being the first time we ever responded to issues at 5000 ft. There is a very capable team that retrieved an entire subsea kit from depth greater than that in the GoM. The leader of that effort was not asked to assist. Given his experience and background that left me with a bit of a concern. Maybe I am wrong. I was on the outside trying to look in and it was not fun. Usually I have been a part of many of the firsts..... Sort of miss that. But getting old and finding it harder to get traction. Majors are looking more for getting the younger ones involved due to the great crew change and they don't ask as many questions as us more seasoned gents.
In the old days experience was a valuable commodity, today youth is the valued commodity at much lower costs and the opportunity for these younger engineers to reinvent the wheel. I had many fresh out of school young engineers with a hard go get em' ideal. That's not bad, but you could expect within a few months of coming on board you would start to hear about proposals to do something different or solve a problem in a "new" way. Much of the time we had spent a lot of dollars correcting exactly the same implementation from a previous young engineer. So the smart young engineer hooks up with the Yoda the Older battle hardened engineer and tries to learn quickly. Those will be the really productive new engineers.
The questions only come after you have been run over by dozens of Mack trucks in your career.
duck
DE - FWIW just after the blow out began BP reported a MDT pressure reading in the reservoir of around 11,900 psi. Don't have the link now but I suspect someone will toss it out shortly.
There was a cluster of producing zones in a about 500' interval. The top most was a thin gas zone with pressure of something like 13,200 psi. The lower primary reservoir zones had measured pressures of 11,900. One of the complaints the BP investigation report had was that Halliburton that predicted "severe gas flow potential" used the pressure and fluid content of that top thin formation as the input into the computer model for all the producing zones.
jinn, you wrote:
One of the complaints the BP investigation report had was that Halliburton ... predicted "severe gas flow potential" [using] the pressure and fluid content of that top thin formation as the input into the computer model for all the producing zones.
While BP may have been puzzled by Halliburton's use of it, it wasn't the reservoir zone at 18,200' and density of 13.97 lbm/gal that drove the severe gas flow potential result. Halliburton used exactly the same data for the two 15 April reports, one of which gave a moderate gas flow potential prediction, and the other a prediction of minor gas flow potential.
It was the predicted channeling due to OptiCem's handling of centralizer inputs, hole geometry, and cement levels that differentiated the severe, minor, and moderate gas flow potential results among the three reports.
What the 1st paragraph, p64, of the BP report says is (italics are mine): "The OptiCem model predicted a "severe" gas flow potential, driven mainly by the possibility of cement and spacer channeling above a 13.97 ppg interval."
CV
I read that as BP complaining. I assume you agree.
I would suspect the higher reservoir pressure was a parameter that played some role in the OptiCem analysis. The implication of BP's complaint is that if all the pay zones were modeled at the correct pressures then the severe gas flow prediction would disappear. That would be easy enough for Halliburton to find out. But frankly I'm losing all confidence that any of the parties involved in this are really very interested in finding the truth, so it is unlikely we will ever know.
But to me it seemed the issue of channeling was mostly driven by the very low pumping rates. I believe there was testimony that some of the early Halliburton simulation models had higher pumping rates which produced no problems in the outcome. But those higher pumping pressures would increase the risk of lost returns. And lost returns would automatically by regulation trigger remedial work.
jinn,
The gas flow potential factor (GFP) is (as far as I know) equal to (1.67 L / D) / OBP, where L is the cement column height or length, D is the difference between the wellbore and casing diameters, and OBP is the overbalance pressure (hydrostatic pressure minus formation pressure.) The 1.67 factor has dimensions associated with it such that GFP is dimensionless for L in feet, D in inches, and OBP in psi.
You can see that if you keep the overbalance pressure constant, GFP doesn't change (everything else held constant) whether you use a formation pressure of 10,000 psi or 13,000 psi. To my mind, the sensitive driver in GFP is that skinny little D dimension. Change it from 1-1/2" to 1/2" and you treble the GFP. This is how centralizers come into play.
CV
Chuck,
That formula sounds too simple. I thought the "gas flow potential" was something that came out of the FEA model of the actual flow simulation of the cement. The well bore, pipe, shoe and centralizers would all be CAD geometry derived from the caliper data from logging the open hole section of the well.
Using your formula. If we assume the open hole to be 8.5" and the casing is 7" and the hydrostatic pressure is 1 ppg over the formation pressure and the cement is 850' we get :
(1.67*850/1.5)/940 equals about 1
That doesn't take into account centralization or pumping rate.
jinn,
The GFP definition is simple. Determining the effective values to use in it may not be so simple. If the casing is not centered in the borehole, you can't simply use the difference in diameters of casing and hole. When the annulus is thousands of feet long, with spacing variation along the whole length, determining the effective spacing is not trivial. On top of that, I'd think that GFP is almost an incidental fallout of the computational work OptiCem would have to do to determine whether channeling is an issue, and if so, its effect.
But let me take your example and modify it to reflect the actual annular cement column height used in the 18 April report; namely, 2164'. With 2164 in place of 850, the GFP = 2.56. (It's only coincidence that this is identical to GFP for the report with 21 centralizers). Secondly, you'd be lucky to get better than an 80% standoff, for which the 1.5" value would fall to 1.2" and GFP would increase to 3.2. With 25% standoff, GFP climbs to 10.25 (the 18 April report had GFP = 10.29).
(There's more to all of this than I've written.)
CV
Is the standoff percentage due to centralization a calculation made by OptiCem?
According to the BP report the TOC was 17,260 and the bottom was 18,304. Only about the bottom 300' of the open hole was at 8.5" dia. The upper part of the open hole was around 10" dia. Using an average for the diameter and 1044' for the height you get a result a little less than 1.
The logging data showed this part of the hole to be pretty close to vertical.
And the pumping rate is still not accounted for unless that is supposed to be the circulating pressure not the hydrostatic pressure. According to the testimony with higher pumping rates in early modeling there was no issue of gas flow or channeling.
jinn,
I would think that the standoff percentage, or effective D in the simple GFP definition, is something that OptiCem would have to calculate in order to output a GFP value. (One of the OptiCem options, though, is for the user to input the standoff.)
Halliburton's three reports gave these predicted depths for TOC:
15 April, 3:30PM: TOC = 16245' (923' into the 9-7/8" liner). This was with 10 centralizers. GFP was 7.65.
15 April, 6:12PM: TOC = 17258'. This was with 21 centralizers. GFP was 2.56.
18 April, 11:25AM: TOC = 16140' (1028' into the 9-7/8" liner). This was with 7 centralizers (Gagliano intended to remove 15 centralizers from his 21 centralizer report, but missed one and made the run with 7). GFP was 10.29.
BP's 24 May Washington Briefing and its 8 September DW AIR both give TOC = 17260' (done with only 6 centralizers, and virtually identical to TOC in the second 15 April report with 21 centralizers). That suggests what?
CV
The April 15, 3:30 with 10 centralizers report. That has the height (L in your equation) about twice what it should be. If you changed it to the correct L then wouldn't GFP be cut in half and drop to around 3.8?
The same thing with the April 18 report. The height again is about twice what it should be. That suggests the correct height would produce a gas flow potential of around 5 if the correct height was used.
The other thing about pushing cement up into the 9-7/8 liner is that the annulus becomes smaller in the cased hole. That means the D in your given equation becomes smaller and that also drives the GPF upwards. Also using formation pressure values higher than they actually are drives the GPF result higher.
The 21 centralizers was not Halliburton's idea. On April 15 after the first report. BP had located 15 additional centralizers and ask Gagliano to run the model again with the additional 15 added in. But it looks to me like the real reason the second run was so much better is that the correct TOC was used in that run. For all we know, the extra centralizers may be irrelevant.
It looks to me like it is likely the centralizers had very little to do with the high GFP. It appears more likely that all the other incorrect inputs are slanted towards making the high GPF in the reports that have high GFP..
If anybody involved in this investigation was actually interested in the truth, they would first resolve to some degree of certainty the question of whether the cement above the pay zones actually did fail. And then they would run the simulation with the correct height of cement, the correct diameters and the correct formation pressure inputs and find out if the model would in fact predict a severe gas flow potential when given the correct inputs.
jinn,
Sure, reducing cement column height reduces GFP, everything else held constant.
As regards the remainder of your post, let me set out some points in the hope that they'll clarify some things. It's going to look simple--almost obvious--but I spent a lot of time over several months trying to figure out how Halliburton came up with the fluid positions in its reports.
1.) BP specified to Halliburton what the TOC should be.
(I don't know the exact TOC given to them, but evidence points to something between 17260' and 17300'.)
2.) BP gave Halliburton caliper data for the borehole and data for some of the casing string.
3.) It was up to Halliburton to determine the volume of cement to achieve the specified TOC.
4.) All three of Halliburton's design reports used the same volumes of fluids. (The only variation at all was in the foamed cement, and it was only 0.14 barrels.)
5.) One of Halliburton's design reports, the middle one with 21 centralizers, predicted TOC to be within 2' of 17260'. The other two differed from 17260' by over 1000'. How come?
The answer to How come? only dawned on me a few weeks ago when I finally listened to the 24 August testimony of J. Gagliano and N. Chaisson. It was just one sentence that included channeling and height of cement.
This is my expansion on that little bit of information: OptiCem, given the parameters fed to it, predicted that the base oil and spacer pumped ahead of the cement would not remove sufficient mud (filter cake) to achieve the desired TOC. Instead it would be much shallower (higher above the casing shoe) because the borehole was effectively much smaller in diameter than its dimensions would suggest. Two significant reasons for that: 1) number of centralizers and placement and 2) pumping rate of fluids (kept low to stay under ~14.7 lbm/gal ECD).
Here's what I was driving at when I ended my previous post with That suggests what?
It seems to me that BP could counter Halliburton's persistent You didn't use the 21 centralizers that we specified! with: We used 6 centralizers and the actual TOC is what you predicted with 21, so the extra 15 centralizers is a non-issue. (That addresses the channeling aspect, but not the gas flow potential.)
CV
I'm not sure I get it. Are you saying that channeling was wthe only reason that there is way too high TOC in the simulation? I do see that channeling involves mud not properly being displaced by cement, but are you saying that something like half the mud was being left behind in the simulation with 7 or 10 centralizers?
OK. Leaving Gagliano's models alone for a second - What actually happened in reality? Did the relief well intersect just above the TOC? Did that cement achieve zonal isolation or is the picture BP is currently painting just a fiction? If Gagliano's model was correct then the relief well would have drilled into an annulus that was filled partially with the nitrified cement and partially mud.
I appreciate the time you have spent analyzing the production casing cement job. I hadn't looked much at that aspect of the disaster.
Have you gained a clear understanding of what "gas flow potential" means in terms of the consequences it predicts? If you do have such an understanding it sounds like you are already a step ahead of the BP engineers:^}
It was my assumption that "gas flow potential" was linked to channeling. That is if you left channels in the cement that would be where gas could migrate through the cement barrier. You seem to be suggesting that it is not related to channeling.
jinn,
Yes, lacking any other explanation, I believe channeling is the explanation for tops of cement in the 16000-ft range in the first and last Halliburton reports. As late as the release of BP's report I was under the impression that Halliburton did not use caliper data in running those two reports. For example, for the 18 April report, I could duplicate all the annular fluid levels in the report by using an 8-5/8" hole diameter from 18304' to the bottom of the 9-7/8" liner, where its ID then continued at 8-5/8" until it reached the 11-7/8" liner. The only deviations from a perfect match were that I came up 1.4 bbls short (wrt 72 bbls) on the spacer and 0.4 bbls high (wrt 47.75 bbls) on the foamed cement. The same scheme applied to the first 15 April report also matched levels, but was a bit worse on volumes: 1.5 bbls short on spacer and 2.3 bbls short on foamed cement. When the 8 Sep BP report said that all three reports used caliper data I was at a loss--until I heard Mr. G. utter that one sentence about channeling and cement level during the hearings.
Regarding your relief well intersect question: if the real TOC is at 17260', or 17300', or anywhere below 17223' (where I calculated the intersect to be), then I would expect the relief well to have met 14.3 ppg spacer--provided something hadn't disturbed it after the original pumping.
As for channeling vs. gas flow potential, I'll try a simple-minded differentiation between gas flow potential and what the Halliburton reps referred to as channeling. Channeling leaves voids in the cement due to foreign matter in the space you wanted to cement. Suppose the annulus is formed by a pipe centered in a uniform hole, but there's a strip of filter cake 3" wide and 2" thick running up the wall of the hole. You end up with a cement-filled annulus, but with a groove along the length of it--a channel. The channel could conceivably be expanded to include the whole circumference of the cement plug if the wall of the hole was uniformly caked.
The gas flow potential bit is intimately tied to gas in a formation punching into the cement before the slurry attains a certain level of static gel strength (SGS); specifically, a value of 500 lbf/100 sq ft. In fact, the GFP factor relation that I gave you is the definition for SGS, but divided by a pressure (the overbalance pressure) and with 500 lbf/100 sq ft substituted for the SGS variable. To clarify a bit:
SGS = (300 P D) / L; solved for P,
it = (SGS / 300) (L / D), psi.
Substituting 500 (lbf/100 sq ft) for SGS and dividing by an overbalance pressure (OBP), in psi, you end up with a dimensionless
(1.67 L / D) / OBP, the definition of GFP.
CV
Thanks for the explanation. I will have to listen to Gagliano's testimony again in light of this new understanding.
It seems to me that everything hangs on the true TOC. If the TOC is where BP says it is then as you say that is conclusive evidence channeling did not occur like the simulation said it would.
But it also means the values used to calculate the GFP were incorrect. The true height is close to half what was used for the GFP calculation and the D value is also off by a lot. In reality D is around twice what OptiCem calculations assume it to be. The actual diameter for most of the open hole was around 10.5" not 8.6". Plugging the true values into the equation would give a GFP around 2.5 not 10.29. And that is without changing the OBP which BP complained was too small. Make that number bigger and the GFP goes down even more.
But..... do we have any convincing evidence that the top of cement (TOC) is where BP claims it is?
jinn,
I won't comment further on GFP in OptiCem because I don't know how its calculation was actually implemented in the simulation.
I don't know how BP knows, or is led to believe, where the actual TOC is. On the two variants of BP's well schematic that I know of, TOC was given as 17300'. The BP Accident Investigation Report gives it as 17260', and the 24 May BP Washington Briefing also gave it as 17260'.
Tonight I tried finding Gagliano's channeling / height-of-cement sentence w/o listening to his testimony all over again. I didn't find it in the short time I devoted to it, but at about 1:30:54 into Part 2 he says ". . . the object was to get cement up to seventeen three, if I remember right. . .", which I take to mean to a TOC of 17300', which I further take to mean the TOC that BP specified.
CV
If we carry this thread much farther, the column width is going to be down to about three words.
I know what BP's narrative about where the TOC ended up. But is this just theory or is there evidence to support the BP story?
Is this the statement from Gagliano you were looking for?
***** Gagliano testimony Aug 4 *****
Q. Yes. I don't think we fully under that and
the implication to channeling. So could you briefly
explain it?
A. Based on the modeling with the centralizers,
cement would be in this case about 17, 3 with the
planned cement with the 21 centralizers in there you
minimize or limit the channeling which you would get
your cement top about what you want it.
With the 6 centralizers channeling
occurred so you're not displacing all the mud out of the
well. You're actually displacing the cement higher up
the wellbore because you leave mud behind which would
increase your cement lift pressure you would see on the
job. Did I explain that well enough?
jinn,
Please start a new thread. I noticed you originally started this incredible thread so I thought it would be best for you to make the new thread decision. In all honesty, text with 5-6 words per line is making my eyes cross.
<--- 31 annuli !
SCR flexjoint is for Steel Cantenary Riser (SCR) hangoff from the production rigs. Not the same flex joint as on the marine riser. I believe the hangoff forces and moments are from different directions than the marine riser. I've looked at both in the past on some of the combined drilling/production rigs that had both a marine riser and production risers. Similar but not the same.
DE, I could see they were very different flexjoints, but I didn't know why. SCR series hangs from the rig, Subsea series sits on the BOP. Thanks for clarifying that.
Jenn, not sure if this is an answer to your 1) question or not. The BP report, page 123, basically states that the BOP sealed off the annulus at 21:47 and barring any failures of surface equipment (the IBOP shut, the slip joint set to high, and the diverter routed to the starboard overboard line), modeling shows hydrocarbons would have quit flowing at 22:05.
NatResDr, from last thread:
Worse, it's based on a Greenpeace press release.
And you have to give Greenpeace credit for waiting until the boat reached port and preliminary testing was done.
NOAA started spilling its guts halfway into its expedition, after just 50 deepwater core samples had been taken: NOAA: No oil in sediment yet.
PS: Ian MacDonald, from the Advocate article:
I found an interesting interview video of Samantha Joye. I don't recall seeing this posted before and it is dated 9/22. Mandi explains NOAA's results are due to location of sampling. LOL, this link is kind of tricky to find. After displaying initial page, scroll down to bottom center of page where it shows a photo of Mandi. In the text, after the words Horizon oil spill is available, is the link to interview. And grab a dish of Blue Bell beforehand because it is 54 minutes long.
http://www.uga.edu/
After mentioning controversies with administration officials in Washington, interviewer asks, "How has this changed Dr. Samantha Joye?" Mandi replies, "Dr. Samantha Joye would like to go crawl back under her obscure rock." Then Mandi goes on to explain importance of communicating to public what she has seen and reasons for controversy.
EDIT: added detail
This is a good interview, thanks for finding it. Here are some notes for those who don't want to take the time to watch it.
We have been discussing here some controversial and, IMO, misleading statements that have been attributed to Joye in the press recently. Toward the end of the interview she complains about being misquoted and having the "caveats" deleted from statements she made to reporters. I noticed yesterday a reporter writing, "Joye was unavailable for comment," so maybe she is pulling in her horns a bit.
Also toward the end she talks about "conflict" with NOAA, and apparently in conjunction with the recent observations about sediment. As far as I know, there has been no public criticism of those reports, except here, by me and other posters. So I surmise she has heard from Lubchenko or somebody privately. Joye's tone in these remarks was not confrontational. (Back in June (?), Lubchenco had criticized Joye's early statements about plumes as jumping the gun.)
--Methane plumes: the team didn't find them this time; they must have "migrated." With insufficient time and O2 depletion for them to be gone, methane must be somewhere. She didn't address Hazen's suggestion that much of the methane is in hydrate form, suspended deep and very slowly rising.
--Oil plumes and sediment: most of the suspended oil stayed within 60 miles of DWH, to the west, north, and east. They collected control samples of sediment from 100 miles south, where the bottom was normal. Then they sampled from an 85 x 45 mile area around DWH and found fresh sediment at most sites. She twice said emphatically this sediment was "not oil," but a couple of times slipped into calling it "oil," as she had apparently done in statements to reporters, leading to headlines like "Researchers Find 2-Inch Blanket of Oil Covering Floor of Gulf."
--She described the sediment as an "organic matrix" containing "some oil" and a lot of "mucus" or marine snow. It is fluffy and porous, with a structure that collapses with any mechanical disturbance. It has a HC odor and irritates the skin. It contains tar flecks and some PAH and BTEX. It releases a slight sheen when stirred into clean water. Thickest deposit found was 4", usually 1-2".
--Benthic fauna in the sedimented area suffered "severe acute" damage either from toxicity or smothering. All the tubeworms were dead and few living things were found. The water was anoxic at the sediment face but not just above.
--"Dispersant can facilitate sedimentation" as suspended droplets can be picked up by falling marine snow.
--Joye gets lots of emails from private citizens asking questions.
Gobbet,
In the months that I've been following these events, I feel I have learned more from your excellent posts than from most others.
Balanced, authoritative, accessible, wise.
My thanks are long overdue.
bignerd,
Thanks, it's especially gratifying to hear that from you, because I've gained so much from your crystal-clear explanations and crisp arguments over on the oil-patch side of these threads. However, I'll repeat my caveat emptor again--I have no training in science since high school in 1958, so please don't consider my posts as authoritative.
It's interesting that we have two parallel communities of discussion here, with most people reading and learning on both sides but only commenting on one side, unless maybe there's an outbreak of politics or suchlike.
What both of ya said (I stand to applaud two superb -- and superbly-generous -- teachers)!
Lavish thanks for this, Gobbet (been wondering when I'll have time for the video).
You know, I’m ver' curious about how south-of-the-well missed getting oiled. After all, in late May/early June (I think it was), the Loop Current moved up very near Macondo before Eddy Franklin broke free and gradually moved westward (thereby saving the Keys and the Atlantic). But a little oil reportedly made into the Loop at that point. If so, you'd think it would have left at least some traces south of the well too. Maybe those "oil-in-the-Loop!" reports were wrong?
Apparently the finger of surface oil that was pulled south was very thin, so that after a week or so without being nourished it was just light sheen and then nothing. The currents at plume depth never seemed to run due south, mostly WSW.
So I guess the prevailing winds were enough to account for that (at least the surface motion), huh?
No, as I understand, a little bit of oil did get caught in the loop current, but the loop broke down and the oil out there just hung around until it weathered away. North winds were rare during the spill. There was a brief spell of it around mid June, I think.
My comment about no south currents was about the deep water, the plumes.
Lotus, everything superGobbet said, plus this:
Some oil got into the outer fringe of the Loop Eddy and was carried clockwise, east and south. Little or no oil got into the main body of the eddy which was south, then west of the spill. One of the cool things about eddies is that their rotation effectively isolates the water within them from the water around them; the outer rim is essentially a wall of shearing currents around the eddy. This is how the Loop Eddies stay intact as they migrate toward Texas, rather than diffusing into the Gulf.
Early in the spill, any oil blown south towards the Loop/eddy got swept around it, this probably confined the spill for a few weeks.
lotus,
The following web page has animations of flow at multiple depths from 4/20 till today:
http://ocg6.marine.usf.edu/~zheng/research/subsurface_traj.html
Gobbet,
Thanks for the great summary.
I found another interview. Fortunately, this one is very short. It is a transcript of Science Magazine interviewing David Valentine and Richard Camilli on 9/17. There are multiple interviews in transcript, so you'll need to just search for Deepwater.
http://www.sciencemag.org/cgi/data/329/5998/1544-b/DC1/1
Valentine says 30% of flowing HC at wellhead was gas content and was ignored by oil budget. Also, they discuss different observations of Valentine, Hazen and Camilli.
Thanks, Brit. Here's the direct link (warning: for those who haven't seen it, it's an hour long, 105mb video).
I posted an 8 minute clip of the video here: http://www.youtube.com/watch?v=r0LTUvF6LwE
Edited (2X): In the youtube clip of the interview, Joye mentions Vernon Asper and talks about controversy with NOAA. For some background on that, see here: http://www.nature.com/news/2010/100804/full/466680a.html
BP's rejection of Camilli's samplers (noted here ) is especially comical in light of the conflict between NOAA and the crew of the Pelican over their samplers. From the Nature article:
I don’t know what to say except NOAA seems to have a knack for not finding oil.
What Janet Baran said was that NOAA hadn't found any visible oil--I take that to mean stuff that looks like oil. I'm sure nobody has found stuff that looks like oil in deep water. However, news coverage of remarks by Joye, Hollander, and others has led millions of people to think there is visible oil on the deep sea floor. I'm sure that if NOAA has sampled near the wellhead, they have found the same organic sediment that the Joye team found. I suspect Ian MacDonald knows all the above and is just being snarky.
Greenpeace is frankly an advocacy group and can't be expected to maintain high journalistic or scientific standards. I give them credit for immediately publicizing that they found no traces of oil in reef sponges in the Keys, and that they found the reef community of the Pinnacles off Alabama to be apparently in good shape.
However, this GP press release is pretty awful. They speak of "oxygen deficiency," which people are going to interpret as hypoxia, whereas actually there is only a slight and harmless reduction in deepsea oxygen so far. They give the impression of finding oil--and the press is reporting that they found oil--when actually they only found a reduction in oxygen. And their charges of dishonesty by the government are quite dishonest.
Could you define "visible oil"?
Does oil have to be visible to do damage to an aquatic ecosystem?
Is fresh non-weathered oil the only thing marine biologists should be worried about?
I can understand why NOAA has a credibility problem. Their spill flow estimates were so far off, it makes them look like they were either lying or incompetent. The fact that the NOAA used BP's charts on slick thickness rather than the figures in their own guidelines looks really bad.
I thought I adequately defined "visible oil" as "stuff that looks like oil." I suggested there is some reason to put it this way in that there is a widespread popular misconception, fostered by news coverage and careless statements by scientists, that there is lots of crude oil out in the Gulf, "sunk to the bottom" by BP. Nobody has determined exactly what the brown fluffy organic sediment is. Surely it contains some materials from the oil, but if oil is only, say, 5% or 10% of the sediment, then it is misleading to call the sediment "oil."
I don't understand your angle / hypothesis.
"there is a widespread popular misconception, fostered by news coverage and careless statements by scientists, that there is lots of crude oil out in the Gulf, "sunk to the bottom" by BP."
Are you arguing that effects of the oil spill are being exaggerated, or are you arguing that scientists and the media aren't using the term oil correctly?
Maybe the press should stop using the word oil. Perhaps "Macondo Pollution" would be a better term. Instead of finding oily residue in sediment samples, they could say they are finding Macondo pollution.
It doesn't matter to the general public if there is weathered oil or crude oil in the sediment. This is a nitpick. What matters is: does it come from Macondo and is it toxic or harmful to surrounding environment.
It doesn't seem like a nitpick to assert a difference between a "2-inch layer of oil on the floor of the Gulf" and "a 2-inch layer of fluffy organic matter that contains some unknown percentage of degraded oil materials." The latter is also Macondo pollution, as you say, but there is a big difference in meaning. Dr. Ed Overton said the brown floc material he examined was "not oil, but the result of the oil." Dr. Joye in the interview currently being discussed says it is "not oil." But in less guarded moments, she and other scientists have called it oil, and the reporters will quote and requote those bits. These reports encourage the folk belief that the spilled oil and dispersants are unchanging substances that are "lurking" in the Gulf and threatening people, poisoning seafood, etc.
"These reports encourage the folk belief that the spilled oil and dispersants are unchanging substances that are "lurking" in the Gulf and threatening people, poisoning seafood, etc."
I partially agree with you. Oil and dispersants are always changing, and all oil should probably be called oil in the process of weathering. The effects of weathered oil and weathered natural gases found in plumes and in sea floor sedimentation is not well understood. Weathered oil can still be toxic and harmful to its surrounding environment for years to come. It will probably take many years to understand the full extent of the environmental damage done to the Gulf by the BP spill.
Just because the oil is weathered, doesn't make it safe.
Well, I guess you had better cordon off all your asphalt roads cos' they contain weathered oil.
NAOM
Weathered heavy oil contains asphalt, but of course not just asphalt. In tar or other heavy residue, the % PAH content is elevated over crude oil because the volume of oil materials has been greatly reduced. On the other hand, the bioavailability of the PAH is much reduced in tar, which forms an inert skin, or in heavy residue that has been covered with sediment. Here is a good explanation:
http://www.epa.gov/oem/docs/oil/fss/fss02/neffpresent.pdf
The toxicity of the brown organic sediment is not known yet. Joye said she wasn't sure whether it killed benthic organisms by toxicity or by smothering. It will also make a difference whether this material continues to biodegrade or whether it is buried and goes anaerobic. Another question is how much of it was deposited in shallower waters where shrimp and normal finfish feed on the bottom. It's a good guess that it will do substantial an possibly long-lasting damage to benthic organisms.
However, it seems that a lot of the brown organic sediment was deposited offshore in deep water, where it seems to pose no threat to human health or material interests. The depths below 700 meters in the Gulf constitute almost a separate ocean, with very little movement of water or animals between the upper and lower zones. Of course the deepwater community has intrinsic value, and nobody wants to see the critters wiped out over 1000 sq. miles of bottom. But there is no reason for people to be afraid of sediment in deep water, however much or little oil materials it may contain.
I agree with this. It's worth remembering that smothering of benthos by marine sediments is a common and widespread phenomenon, caused by storms and floods washing sediment from land to sea. It's not good for the individual tubeworm obviously, but benthic communities have had hundreds of millions of years to adapt to these dynamics. Just one benchmark reference--Charles Darwin wrote an entire book on corals and noted that covering by sediment was a major cause of mortality to large patches of reefs.
In the CSM article on NOAA sampling, didja notice that the 4 million gallons of oil cited by Ranier Amon as "unaccounted for" is 2% of the 205 million gallons spilled?
the 4 million gallons of oil cited by Ranier Amon as "unaccounted for" is 2% of the 205 million gallons spilled?
:) He was quoted as saying "3 to 4 million," and I suppose he actually said, or meant, barrels rather than gallons. Either way, it seems like a silly thing to say. Does he suppose, for example, people would catch all the evaporated HC in bottles to measure and account for it?
WTF are you two blathering about?
AFIK, there is only one CSM article referenced in this comment thread and Ranier Amon is NOT cited in it as saying anything about '4 million gallons of oil,' and he is NOT quoted as saying "3 to 4 million."
That CSM article is truly a piece of crap but at least it wasn't written by our two fine resident science and journalism critics.
WTF are you two blathering about?
It is not clear whether Amon said "about four million barrels" or "between three and four million barrels" or whether the CSM reporter wrongly attributed an interpretation by the Greenpeace spokesman to Amon. In any case, we have another scare story on the loose that will be repeated.
http://www.csmonitor.com/Environment/2010/0930/Gulf-oil-spill-research-v...
http://www.greenpeace.org/usa/en/media-center/news-releases/-Independent...
http://www.google.com/hostednews/afp/article/ALeqM5jsABMT-ulj4vMMRpKrqE9...
http://www.greenpeace.org/usa/en/news-and-blogs/campaign-blog/wheres-all...
Right. Whatever "silly thing" Dr. Amon might have said, he didn't say it in that CSM article.
So you googled up some other articles, from some other sources, but none of them contain that quote you attributed to him.
That surprises me. I figured you must have seen it somewhere. I didn't think you took some idiot reporter's paraphrase as a direct quote.
Did you?
Sure--I assembled the snippets to show that. As you pointed out in a previous bit of snark, he was paraphrased, not quoted, by the CSM reporter as saying "about four million." But actually the reporter may not have even spoken with him and may have been paraphrasing the "three to four million" statement from the Greenpeace article, which sort of sounds like it is attributing the suggestion to Amon, but does not do so directly.
Yikes! Folks with Greenpeace don't even know how big an oil barrel is? Take that laptop away.
Yes, I made a sloppy-reading error of gallons where barrels was printed. Sorry.
I take that to mean Baran didn't smell, touch, taste, or otherwise test the sediment. She simply looked at it, through the glass, and said, "I see no oil. Alert the media."
And so now we have this meaningless statement from NOAA that there's no Castrol on the sea floor, and we get news stories that say:
But that's okay, because it's good news, just as it's okay for Dr Hazen to be funded by BP, but not okay for Dr Amon to be funded by Greenpeace.
Right, Gobbet?
Wrong, the italicized quote ("finding no traces") misrepresents Baran's statement ("finding no visible oil") in order to set up the journalist's he-said-she-said game and develop the hackneyed consensus storyline that I've objected to.
The statement that there is no Castrol on the sea floor may be nonsense to you, who understand what's going on, but it is not meaningless given that lots of people seem to think there is Castrol on the sea floor, and lots of media reports have encouraged that belief. I recall one article about Joye's account of the sediment cores that was illustrated by a picture of a white rubber glove dipping black petroleum.
Wrong again:
http://www.csmonitor.com/Environment/2010/0930/Gulf-oil-spill-research-v... (bolds mine)
From the article you link:
This was apparently from her primary statement; what you quote is in response to a question about Joye's findings. Do you not agree that there is an important difference between crude oil and unanalyzed organic sediment that probably contains some petrochemical residue? Do you not agree that the press and some of the independent scientists have (inadventently, I hope) created the impression that there is crude oil on the deep sea floor?
"Do you not agree that there is an important difference between crude oil and unanalyzed organic sediment that probably contains some petrochemical residue? Do you not agree that the press and some of the independent scientists have (inadventently, I hope) created the impression that there is crude oil on the deep sea floor?"
Sorry to repeat myself. The general public doesn't care about the technical language. They want to know did it come from the Macondo spill (to phrase it even more accurately: would it be here if there was no Macondo spill), and is its presence toxic or harmful to the environment.
The two statements don't mesh. The general public hopefully probably cares that they are being told the truth. If it came from Mancondo and/or is harmful is not the question journalists are answering. In which case the blame still lies with the journalists.
Whether there is thick black oil on the sea floor or not, is not answering the source and harm question. It might be related, but it isn't the same question.
One gets the impression that there is a set of journalists who do not care what the public may or may not want or need to know, but are intent on creating news to their own agenda, which includes continued misrepresentation of the facts if it suits them. If the scientists are not able to answer the question about source and harmfulness, the journalists are behaving unethically in creating ficticious news items that misrepresent the facts in an attempt to keep the news item alive. This isn't exactly something new.
In her response to a question from a reporter, Baran said, "We have not found any oil in sediments but we will continue to look." Notice how she uses the "O" word, without qualification.
It doesn't matter if her so-called "primary statement" is about "visible oil," since your tiresome scolding of Dr Joye never ceases despite the fact that her "primary statement" is about sedimented oil.
If you were consistent, you would hold Baran responsible for making "statements that inspired misleading
scarypie-in-the-sky press coverage"1 such as this: "a government-sponsored expedition isn't finding any traces from the Gulf oil spill, directly contradicting findings by several independent research teams."2But you are not consistent.
I take that back -- you consistently nitpick scientists and journalists bearing bad news about the spill.
Here are some excerpts from the happy-happy article by Guarino that you cite as an example of pie-in-the-sky coverage of Baran’s statement:
"Happy-happy?" I never characterized the article as a whole except to say it was crap. And breaking it down - the pie-in-the-sky stuff was "inspired by" Baran; the scary stuff by Amon and Joye.
You criticise Amon and Joye, but not Baran. But if it's wrong to make careless statements that reporters can use to scare people, it's wrong to make careless statements that reporters can use to lull them to sleep. And if it's wrong to accept funding from Greenpeace, it's wrong to get it from BP.
But Baran, Hazen, Lubchenco, and the like get a break from you. For Joye, Amon, MacDonald, and the rest, it's an unending hairsplitting attack.
duplicate, sorry
This has turned into a very interesting thread. I'm unsure what happened to Janet Baren because she wasn't at today's 10/6 USCG Update. Instead, Sam Walker represented NOAA.
The first questioner asked about the sediment. The answer was blah, blah, blah, I don't know...
The second questioner asked about the sediment Dr. Joye found. The answer was blah, blah, blah, I don't know...
That's it. No more questions.
The transcript made me think of Bill Cosby, so I went to youtube to watch the classic Brain Damage.
I think I have brain damage when I read the phrase "progress against the stated need." WTF is that? Walker says it a couple of times:
PS: When I miss Janet Baran, I just go to youtube. Here. Now, don't you feel better?
I blame Six Sigma and the Dilbert Jargonator. (Yes, I know, that's redundant)
comfychair,
Oh, you would have to mention Six Sigma. I have never understood why software paradigm authors don't go look at how software engineers do their job and focus on ways to improve the efficiency and productivity of what they see. A few years ago there was a huge effort to teach Six Sigma where I work. The effort was full throttle for about a year, then it went to idle for about a year and now it is ancient history.
I think I'll just stop here. I could write a book on this subject.
M Onan,
Thanks for the link. I feel much better.
At the end of the day, all the scientists are doing incredible work with very advanced technologies. It's just frustrating to wait so long to see the results of this work. I have direct experience with being told not to mention certain subjects or being told not to communicate necessary information because it will lead to additional questions so I can relate to what must be going on behind the scenes. Although it is easy to say whatever is known should be presented, the affects of doing this can lead to more harm than good. And I am truly thankful there are multiple sources of information on these topics. I would rather listen to multiple voices and figure out for myself what I should believe as opposed to hear one voice.
http://www.youtube.com/watch?v=9iB5JA_4l4I
Bossa Nova, you gotta love it. It can turn anything into a toe-tapper.
http://www.youtube.com/watch?v=NrD_TzRbygo
Brit, at this point nobody seems to know exactly what is in the brown fluffy organic sediment. NOAA is perhaps being excessively coy in refusing to describe it at all until they have lab results, but that's not a crazy policy either. The important practical questions are the PAH and BTEX content, which should be known soon, and then how much of this material is present inshore and on the continental shelf. If most of it is on the sea floor at great depth, that's the best possible (least bad) place for persistent toxic fractions to end up.
Sam Walker's gobbledegook is intolerable. I hope they keep him away from microphones in the future.
What NOAA should have been saying all along is something like this: There is inevitably a residue from any substantial oil spill. The residue will sink to the bottom through natural processes, not because of dispersant. Some of the residue will be tar, which tends to be deposited inshore where it picks up mineral sediments that sink it. Sedimented tar will be very persistent, and we will not be able to clean most of it up, but we expect any long-term harmful effects to be localized and not too severe. Some other part of the residue will be sedimented through biological processes, and the brown fluffy sediment probably contains some materials from the oil. We don't know what proportion of the original oil materials will be sedimented, but estimates for other spills of light crude are on the order of 20%.
We can expect some scientific controversy about the biogenic materials in the fluffy sediment and the processes that produced them. Eventually some important new understandings will emerge.
Gobbet,
What is being said in the press conference is doubly-puzzling because NOAA's website has logs of the sediment sampling ships. There is an interesting log on NOAA's website with sediment observations similiar to Dr. Joye. This is from Ocean Veritas (9/30) cruise.
The semantics for describing the sediment are slightly different. Here it is called fluffy mud instead of fluffy marine snow. Like Joye's samples, these will need to be sent off to lab for definitive analysis but I suspect there is a very small amount of HC. I would want to hear the definitive analysis before speculating about the short or long term impact. Without that analysis, too much can be left to the imagination.
The right side of page has a section called Categories with interesting links to other pages. These pages include logs for the three sampling ships Pisces, Ocean Veritas and Gyre.
DeepwaterEngineer, re the last post of the prior thread: http://www.theoildrum.com/node/6997/728221.
One of your musings was that the drill pipe string might have broken off during the BOP lift. That should have shown up as a quick drop on the Q4000 strain gauge, but I don't recall any of the ROV watchers remarking on it.
On the question of what a falling drill string would hit, there is a 9 7/8 by 7 crossover in the tapered casing about 4000 ft. below the string. I'd think it would likely hit the crossover shoulder pretty hard before entering the 7 inch OD / 6 inch ID casing below. There is a chance the 821 ft. of 3 1/2 stinger could slip past, but the 5 1/2 inch drill pipe behind it would have to be within a quarter inch of dead center to miss the shoulder.
As for our shared impatience about the LMRP release data, heck, we still haven't heard what the cement-like chunks that landed on the Damon Bankston were.
Keep up the good posts, DE.
Carried over:
lotus repeated Kallman & Grillo's five point test (from Francis in an earlier thread), and fdoleza countered:
(though he does say it passes the smell test).
Valid point in the literal sense fdoleza addresses but in no way invalidating the other test points. E.g. I've signed nondisclosure agreements but can still consider whether I would tell my mother or national TV if allowed (say Mom signed too :-).
Well, Catcher and fdoleza both slid right by my legal-ethics fave, but I still think it's trumps:
Would you mind seeing that on tomorrow's front pages?
Yipes, sorry, didn't mean to. I was just being brief and using the examples that illustrated following the spirit of the test in spite of distracting technicalities. I suppose I ended up skipping your fave precisely because it was worded so well.
I suppose I ended up skipping your fave precisely because it was worded so well
Not sure I know what to make of that, Catcher, but I'm sure awarding it style points! ;~}
Hey, I'm not above a bit of sucking up to wheedle a little attention to my other posts (though only when it's true 0:~) (is that how you do a halo?). And as apology for being a newbie.
But seriously, I am trying to search old threads and weed conflicting posts, but I'm time-limited by not having internet at home (not TOD's fault!). I will try to make my engineering comments address points not yet resolved elsewhere as much as I can.
But I really am interest in ways to improve the problem solving process. E.g. listing prior suggestions with perhaps brief analysis should have reduced duplicate proposals (and perhaps chatter elsewhere, such as mine here), as well as encouraged people with genuinely new ideas or improvements to old ones that proposing them wasn't a waste of time (I've seen passing mention of this on TOD; I'll try to search for it some more).
Added pre-screening of suggestions is an example that could reasonably have saved $1B+ for well under $1M total to administer. If there are legal issues or whatever to sort out first, shouldn't we look at them before we get in the next bind? I'm not even sure if TOD would want to host that discussion, but I've seen enough posts here to know the expertise is there, at least to maybe advise another site for it.
Ben Raines: Offshore world looks good after Gulf oil spill, scientists say (with video)
With a glimpse of a whale shark and the secret to determining a fish's age (whoa!).
Katherine Sayre: In wake of BP oil spill, scientists track a fish used for pet foods, supplements
The graphic doesn't work well online, drat it, but if you think your household doesn't consume menhaden, think again.
Lots of good news there, thanks lotus and Ben. Ben Raines's videos have been amazing me for five months.
Ben Raines's videos have been amazing me for five months
Me too, and I enjoy his voiceovers as much as his photography (they always send my shoulders down a couple of inches, if you know what I mean).
Hey, Gob, more good news from/about Gulf Shores' Shrimp Festival:
http://blog.al.com/live/2010/10/national_shrimp_festival_start.html
I am worried about the menhaden or pogy. I believe its oil is used to make the limiter in my cattle feed. I know there used to be a plant in Cameron, La. csuse weh I went through there was thsi overpowering smell. Haven't been back since Katrina and Rita so don't know if still there.
DE, not just cattle feed, menhaden makes up about half of commercial chicken feed. It's also about half the total commercial fish catch in Louisiana, by the pound (and over a billion pounds from the entire northern Gulf in 2009). The Cameron plant seems to still be in operation.
This article indicates the spill may not have affected them much, so your feed should be safe:
http://blog.al.com/live/2010/10/oil_spill_gulf_menhaden.html
You might find this link interesting, more than most of us need to know about pogies:
http://www.iffo.net/intranet/content/archivos/63.pdf
Excellent book on menhaden here
http://www.amazon.com/Most-Important-Fish-Sea-Menhaden/dp/1597261246
Poking around, I fired up the NOAA IncidentNews page about Deepwater Horizon. It was published 4/21.
Incident Details
Spill, potential spill, or other: Oil Spill, Potential Oil Spill
Cause of incident: Fire / Explosion
Products of concern: Diesel, crude oil
Total amount at risk of spill: 700000 gallons
Also the DWH spec sheet (.pdf), for those who've not already saved it.
http://www.deepwater.com/fw/main/Deepwater-Horizon-979.html
DE
RE your final post in the last thread, I'm very interested in this too.
It does actually look like the both the blind and casing shear rams did operate at some point. BP state that the blind shear rams most likely operated just before the rig sank when the auto-shear function was triggered by an ROV severing a control rod. This feature is described here :
http://hydrilpressurecontrol.com/pressureControl/controlSystems/controlS...
Inspection of the recovered BOP revealed completely severed drillpipe trapped below the blind shear rams, and completely severed drillpipe trapped below the casing shear rams. Some of the people on the IRC channel linked some videos of the inspection. Some stills are shown here :
http://www.theoildrum.com/node/6936#comment-716935
If there was no tool joint above the VBRs or the VBRs were had not operated properly, then it is likely that the drillpipe fell there and then. Otherwise, it may have been eroded by flow past the VBRs and dropped at some point during the 3 month flow period or during the pulling of the BOP. Evidence of severe drillpipe erosion was provided by BP from a section recovered from the severed riser :
What I find most surprising is that the BSR appears to have failed while being operated during high well flow rates, with the ram packer elements exposed to the erosional stream. My money would probably have been on the BSR being effective even under these circumstances so this failure mode is intriguing to me.
To address your other points :
- I don't think the different colours of the streams would have been due to entrained mud. I would have thought that mud in the wellbore would have been unloaded very early in the process, and even if there were some retention due to low flow velocities / turbulence there simply would not be enough mud to allow this effect to persist for many weeks
- I'm not clear why the dropping of the pipe was important as a cause of casing breach - the blowout had happened by this point and apparently the well was flowing via the shoe-track - I think I misunderstand you
- The triggering of the BSRs apparently happened 3 hours before the sinking, and reviewing video from that time it was not very apparent to me that the blaze had decreased much. I suppose its possible that if the BSR was initially effective that there was some afterflow from the fluids already in the riser, and from burning of fluids already vented and of other flammable articles on the rig
- I don't think they were purposefully taking advantage of reservoir depletion to reduce shut-in pressures. I think it is very likely that there were real fears over the integrity of the surface casings. There have been documented cases of well integrity problems due to surface casing failure, with the additional loadings imposed by deep water risers considered to be a factor. This well had absorbed loadings far in excess of the norm during the rig drift / sink. As you say, the surface cement jobs may have been less than adequate; I believe incidentally that they were also foamed, though this may not necessarily have been a factor.
No BP Aid For Laid-Off Shallow-Water Rig Workers
I am currently reviewing a ballast system for a new design Semisub rig. Has any information been released on how they think that that the firefighter caused the DWH to sink? ie. how did they fill the tanks by just putting water on the rig? Any ideas?
Would water entering the leg above the ballast tanks have any way of draining out? If the leg is hollow with, say, the bottom 1/4 sealed off to form a ballast tank you still have 3/4 of the leg to fill up and sink. There was a video posted of the original rig that was damaged in the Hurricane and that showed list due to water in the legs that had to be pumped out to right the rig. ISTR something, somewhere about issues with valves and pipes not being connected correctly on one of these rigs, sorry to be so vague on that bit but it might jog someone's mind that does remember.
NAOM
And something about hatch doors left open in the rush to evacuate?
They ought to fill those legs with foam, tennis balls, or whatever stays inflated in 100 feet of water, to avoid sinking when they get flooded.
DWE - We beat on that question pretty hard right after the explosion. I don't think either side (flooded by the fireboats vs. pontoons damaged/flooded by debris falling due to the fire) was able to present enough evidence to win the other side over. I didn't favor flooding by the firefighting effort. Not that a continuous spray of water directed through an open hatch couldn't do it IF IT WERE DONE LONG ENEOUGH but that didn't seem to be the circumstance. You should have a better instinct than me: would any significant amount of water falling on the deck make its way to the hatch and then down the leg? My guess is not likely.
Another round of oil spill hearings from Captain Nguyen and company begins today (Oct 4).
Here's this weeks witness list:
http://www.piersystem.com/go/doctype/3043/54031/
A bit of color commentary on this week's hearings:
http://finance.yahoo.com/news/US-investigative-panel-meets-apf-373710227...
'Line of Death' 35 Feet Below Gulf of Mexico, video
" Propylene glycol is known to exert high levels of biochemical oxygen demand (BOD) during degradation in surface waters. This process can adversely affect aquatic life by consuming oxygen aquatic organisms need to survive. "
http://en.wikipedia.org/wiki/Propylene_glycol
" Large, 'accidental' releases into the environment, have the potential to rapidly deplete oxygen in confined surface waters. "
http://www.dow.com/PublishedLiterature/dh_0031/0901b80380031ac4.pdf?file...
Perhaps something important not mentioned in the video is the difference in availability of DO for something like a fish, which is able to move, and barnacles/fans/etc living on the platform that are stationary, and bound to whim of available DO in surface waters. I would think those areas would bounce back at some point soon. Hoping.
Interesting. The top 35 feet or (another site) top 65 feet were dead-looking. In a Ben Raines dive video off Alabama or MS in June, he examined a platform where the top 35 feet were OK, but a dead zone began below that. Seasonal anoxia sometimes occurs in those waters without oil spilling, as it also does west of the Bird's Foot and along the coast to Texas, owing to the nutrient load in the MS River. The big seasonal dead zone is worst at a depth of 35-60 feet, because the surface layer gets oxygen from the air.
In the video Snake just posted, it's the surface layer that looks worst. That does seem to point toward toxicity from oil dispersed from the surface slick, which certainly could poison sponges and corals.
I wish they had given more precise locations. And film from another platform an unknown distance away doesn't provide much of a control. You would like to know whether freshwater surface currents influence the site that was filmed.
ominous voiceover says :
... but noone knows for sure ...
.. but ok, let's get someone on camera who is willing to give us the speculation sound bite that we are looking for anyway. kthxbye
yeah, might have been an effect. The "line of death" doesn't look all that clear on the second platform. Do we know the conditions of life on these platforms before April 20? Could some other local phenomenon be responsible, or at least contibutory? Can any of these observations be tied to observed oil slick flows? Lot's more questions. Few answers so far. Yet speculation is rampant.
Don't they teach science in school anymore?
I'm looking for temperature log data for the Macondo well in the interval 17,200 to 18,300 feet. Anyone out there know where I might find it?
The BP well schematic includes temperatures from 5,312 ft (48F) to 11,585 ft (162F), but then jumps to TD (262F).
CV
I would try 1° for every 62.73 feet.
Don't hold me to it though. Just a rough guesstimate.
Better hold up until someone else ats smarteran me in maths comes along.
Thanks, Mainerd. Your guess could be in the ball park, but I was looking for actual data, as I found no consistent trend from the six data points on the well schematic.
(Over successive intervals of 905', 1720', 1032', 2616', and 6777' the change in depth per degree averaged 53', 59', 37', 65', and 68', respectively.)
CV
Oops. Well, since those temperature readings would have been in a particular Schlumberger Cement Bond Log (CBL), a CBL that BP didn't have them run, and put Schlumberger on the chopper, well, I'd say you'll have to calculate, extrapolate, and interpolate with the information you have at hand.
Unless I missed something. And I could have, very easily, as I have been known to do. How bout some feedback from younger brains round here? Hello!
I'm sure I missed something. Wouldn't they have logged the payzone and read temperatures? Surely.
Oh crap. You're needing temperatures in the rathole, aren't you. There is a water zone there and I'd suppose it'd be cooler.
They may have been "logging while drilling" but surely at some point they also ran a logging tool in the payzone.
(been editing a lot here. pay no mind)
"Wireline Logs and Reservoir Characteristics
BP spent four days performing and evaluating wireline logs after drilling stopped on April 10th, 2010."
http://www.energytrainingresources.com/data/default/content/Macondo.pdf
------
48° at 5,312'
65° at 6,217'
94° at 7,937'
122° at 8,969'
162° at 11,585'
262° at 18,360'
http://www.energy.gov/open/documents/3.1_Item_2_Macondo_Well_07_Jun_1900...
Still missing the payzone, and for any high quality logs BP will most likely claim as "proprietary" info.
But I'm still looking.
Interesting call for more research on effects of dispersants, quoting Lisa Jackson (EPA), Nancy Kinnear (U New Hampshire Coastal Response Research Center), and Mary Landry (USCG).
http://www.ogj.com/index/article-display.articles.oil-gas-journal.volume...
Based on what we know so far, it seems the deepwater injection of dispersant was a solid win for everybody, except probably the animals living below 1000 m depth. Compared to surface application of dispersant, injection reduced dispersant exposure and oil volatiles exposure for workers at sea. It reduced air pollution by encouraging the dissolving of solubles at depth--solubles tend to be toxic volatiles. It reduced exposure to dispersed oil droplets for organisms in the near-surface layer, which is the most important layer ecologically. Compared to no dispersant use, it reduced the slick and thereby reduced the damage to marshes and their fauna, estuaries, birds--perhaps also turtles, dolphins, and whales, that must break the surface to breathe.
I wonder if they should have done more deepsea injection and little or no surface application. Dispersed oil droplets in the near-surface layer were expected to--and almost certainly did--do a lot of damage to plankton, eggs, and larvae, and the animals that eat those minutiae.
Something I've never seen mentioned: dispersants do not actually disperse any great proportion of the oil. The government oil budget guessed that only 10% of the spilled oil was chemically (as opposed to naturally) dispersed. I read a report of an experiment where plain oil was dumped into one pond and oil/dispersant mixture in another; dispersant only increased the amount of oil in the water column by 10%. This was a 1:5 mixture (20x what was used in the Gulf), and the chemicals were mixed in a barrel before being dumped.
So it's possible that people may be exaggerating both the benefits and the harm of using Corexit. Substantial natural dispersion occurred anyway, especially with the violent turbulence at the wellhead.
Consolidated wildlife recovery/mortality report from Unified Command agencies:
http://www.restorethegulf.gov/sites/default/files/Consolidated%20Wildlif...
Here's the NOAA research vessel mission log, a series of daily blogs from the ships out on science missions. Gives a good sense of the sampling being done on the ships, some human interest, nice pictures for that book you're writing, and no inferences as to meaning of the samples before they're analyzed. This is worth bookmarking to check from time to time.
http://missionlog.noaa.gov/
Additionally, there's a touching account of a shipboard memorial to the DWH victims and info on a related Facebook page and fund set up for the families.
I can't resist commenting on the monarch butterflies "perhaps blown over the ocean by the strong winds." Perhaps also migrating to Latin America, as happens every autumn. I'm watching them fly southward at my house daily.
Well, I'll make an inference, that at least one of the vessels is finding the type of fluffy organic material we've been discussing and that the press has been calling a "layer of oil."
I envy you, Doc. I'd love to see bunches of Monarchs together like that. They have an amazing migration AND reproduction schedule--so dependent on Earth's things working right (enough) to get to where they need to be when they need to be there. I'm sure there are many who think it doesn't matter. I am not one of them. Like the tiny turtles, they are "belovable." If more people loved them, and our fellow humans, we wouldn't have stuff like the DWH blowout.
Link to really good documentary about the monarchs:
http://www.pbs.org/wgbh/nova/butterflies/
Aw I like the butterflies.
Okay, let's keep-the-oil-away-from-the-butterflies.
Keep Halliburton away from em too.
Among other things, they found a tiny "shrimp-like creature" 0.02 inches long that was unknown five years ago, both off the Atlantic coast of Africa and 8,000 miles away in the central Pacific. Some stunning photos here, including one of the dragonfish, which "even has teeth on its tongue. They would be terrifying animals if they weren't the size of a banana." My favorite of this batch is #8, the transparent sea cucumber.
The census has its own Web site, with a huge photo gallery, and there's also a big batch of videos. The latest release is a heartstopping five-minute underwater video.
I don't understand how the folks who are intimately involved with this incredible wealth of fantastic undersea life keep their sanity knowing what we're doing to the oceans. It must be just excruciatingly painful.
Swift,
Thanks for links to awesome photos and video of sealife on the census website. Of other photos, some that caught my eye is a crab with fur coated claws, a seadragon with leafy appendages, And that Fathead looks like someone I know. LOL...
that Fathead looks like someone I know
Oh, isn't he magnificent!
How big a fish is the fathead? I wish someone would think to add a penny or a dime to a photo like that so I could see how large/small it is. He sure is a character, isn't he (she?). And the crab with fur on the claws and many others are amazing. All school children should be soon doing a whole 6-week study based on this "census" (just for starters). Geograhy, science, write a poem or draw a picture? To see the "magic" of the real world would be good for them. I will be at that web site for some time to come, myself. Have sent it to the kids and grandchildren, too. Thanks, Swift.
How big a fish is the fathead? I wish someone would think to add a penny or a dime to a photo like that so I could see how large/small it is.
Good point. (I was also wondering--afraid to ask--if it was still, you know, with us when the photo was taken.)
All school children should be soon doing a whole 6-week study based on this "census"
Is this something you know about, or just that you're wishing for? I couldn't agree more that they should be. All the networks should be doing big specials too. The amazing thing is, what they've found so far isn't everything, not by a long shot.
I'm not at all religious, but boy, it's hard to look at that stupendously extravagant variety of critters and not think some tremendous source of creativity is involved somehow.
SL, this reminds me of Terry Erwin's discovery of over 955 new beetle species in one tree species in Panama thirty years ago. It was an amazing number by itself, but Erwin realized it was just a tiny fraction of the undiscovered insects worldwide. Erwin made a well reasoned extrapolation that there could be tens of millions more arthropod species out there. Blew me away at the time, as does this oceans survey.
Overview of Erwin's study:
http://www.learner.org/courses/biology/textbook/biodiv/biodiv_4.html
Abstract of his paper:
http://people.uncw.edu/rotenbergj/Class%20Documents/430/Tropical%20Fores...
Just jaw-dropping. The last paragraph of the overview of Erwin's study points out that there are also gazillions of mites and fungi and microbes that we haven't cataloged. And then if you look up, sheesh, we've got gazillions of not just stars but galaxies. It's as if we were living in the midst of an incomprehensibly huge Mandelbrot set.
oilfield brat: When asked by an Anglican Bishop what he had learned about the "mind of God" after 50 years of study, J. B. S. Haldane, the British geneticist and evolutionary biologist, is reported to have said: "He has an inordinate fondness for beetles."
Brilliant quote isn't it?
Welcome back, E L, you've been missed.
Swifty: Nice! Very nice! Thank You. I, as you, find it a hard thing to view and not wonder of this great source of creativity and design! Pretty cool, if you ask me. Again, thank you.
Sweet links, SL, thank you, thank you. Nice to see all those water critters without having to hold my breath.
Nice to see all those water critters without having to hold my breath.
Heh. I was just thinking how fabulous it would be to see them for reals instead of on a monitor. But they're breathtaking either way... ;)
Thanks so much for posting this gorgeous stuff. I hope lots of people check it out.
I'm glad to have the term "whale fall," though it may be hard to find an occasion to use it.
Nice stuff, SL.
What strikes me is, regardless of how "advanced" humans like to fancy themselves, that most life forms in the sea barely give us any passing condideration (in spite of all the junk we keep dumping into their back yard).
'BP interfered' with cap efforts
Harry R. Weber | 5th October 2010
What? BP couldn't call one of its refinery safety officers? They could have gotten a good rule of thumb radius in a couple minutes. Not that the ROV crew couldn't figure out how close was too hot pretty quick themselves.
Why a refinery safety officer? We have a whole host of offshore engineers that can do that calculation and do it all the time in the form of flare radiation calculations. Given the composition of the material (known base on prior drillstem tests or other analog wells should have been able to do the calculation in the time it took the guys from Smits to mobilize. However, BP was so busy trying to control the flow of information they were refusing assistance from former contractors that could of helped.
However, in this case they had supply boats putting water on the fire. Just take a few temperature reading to see what the shielding effect they were getting from the water curtain being made by the firewater spray. If necessary put two boats fogging water between the platform and the ROV tender vessel. Water is a reasonably effective radiation shield.
DE, no slight of offshore engineers intended, I was just tossing off an example of one resource BP had an abundance of who could give them an answer fast.
OT, Stuxnet
Secrets of the Stuxnet Worm's Travels
I keep wondering, Snake, if just maybe Stuxnet was a test, only a test. Are they debugging it now? Looking at how all the analysts are analyzing it, looking at the maps, examining how well the thumb-drive thing works, etc. Such patience would not be expected, of course, in today's "I want it all and I want it now" world. But would a two year test be worthwhile if the stakes were high enough? If so, they are getting a lot of help from the good guys. Just thinkin'.
Gail had linked to a good article about the new Salazar announced rules over in Drumbeat a few days ago and I just found the rules themselves.
The Drilling Safety Rule
The Workplace Safety Rule
Well bore integrity
-Ban Halliburton from operating in the Gulf.
-Run casing and cement top to bottom. Non of that hanging it from the bottom of the previous casing BS.
-Float shoe plus two or more float collars, and all check valves must be rated double expected working pressure.
BOP
-Double expected working pressure, all of it.
-Use additional sonar activated shear rams system from service boats, as the Norwegians and Brazilians do. Drill ship ROVs can't be expected to be operated while the rig is on fire, not yet anyway, perhaps in the future when they get outfitted with sentient auto-pilot.
-No swapping shear rams with test rams.
Where do I post my public comment for their consideration?
And no more grafting BOEM personnel.
And on second thought, ban Halliburton from ponds too.
I suggest the trash can would be the most appropiate place to post your comments.
And your assessment is based on what, ExDrllgMgr, besides the fact that I've neglected to upload a pic of my oilfield trash belt buckle?
I have a few questions if your serious. Are you serious?
If so why would you ban Halliburton from the Gulf and not BP, Transocean, Weatherford, Cameron and any others that may have been even more involved?
Do you think that not having casing and (annular) cement from top to bottom on the Macondo well had anything to do with this blow out? Any proof?
Do you think the blind/shear rams didn't activate? How do you explain the cut pipe that was supposedly found in the BOP's? If the blind shear rams on the Horizon did activate, then how would sonar activated shear rams changed anything in this case?
Can't there be situations where running liners and not trying to cement to surface on certain casing strings be safer than the alternative?
Has this been posted?
BP educates Terrebonne students on oil spill
Transparency request.
1. Release Zoom-able satellite images of the Gulf of Mexico. Google maps can zoom in tight enough to see a small bush in your yard, but the public cannot zoom an image in close enough to make out a giant oil rig. I don't see how older unedited satellite images could possibly pose any kind of threat. At least, start releasing images capable of being zoomed from this point on (even if they have to be on a 2 day delay for whatever reason).
2. Get rid of the no-fly zone. Why do we need it?
The high resolution Google images are not from satellites. They are from low-flying airplanes. Virtually all of the high resolution images come from routine mapping activities sponsored by state land management departments and similar organizations. Google more or less seamlessly blends the transition from satellite to airplane images as one zooms in on specific areas.
As Salt says above - the high res stuff is airborne, not satellite. Unless someone paid for the photometry flights over the gulf they never happened, and no such imagery exists. It would be very unlikely anyone can make a useful business case to do so.
The next part of the question is, to whom is the request directed? Is is all well and good to make a "transparency request" but who is it who is being asked? Clearly it can't be BP. They don't own any suitable satellites. If you want commercial Earth observation satellite imagery, there is no suppression, but you are expected to pay. There are of commercial resellers of such imagery. Try here for a start at what is available. http://wgiss.ceos.org/lsip/index.shtml A lot of data is being made available for free now, so you may be in luck.
If you want images taken by NASA owned satellites, you can usually access the data, but you are mostly on your own processing it. NASA don't do the high res stuff you want however.
After that, you get to the spooks. If you want imagery from a KH-7 or similar satellite you will be waiting until the sun goes cold. It isn't a matter that any image contains interesting or potentially damaging information. One of the closely guarded aspects of these birds (apart from the fact they their existence is not actually admitted) is what their imaging capability is. Even the most pedestrian image reveals a great deal the spooks would rather you didn't know.
I was looking for images like these: http://mediagallery.usatoday.com/Satellite-images/G1647,A7121?loc=inters...
These images are in .5 meter resolution (the legal limit in the US I think).
Then go here http://www.geoeye.com/CorpSite/how-to-purchase/Default.aspx
They will sell you images from their satellite.
This is the point. There is no restriction on access to the images. Geoeye-1 has a 3 day revisit rate - which is very fast - and will have lots of images. However they are a commercial operation. The satellite is not government funded, and they need to pay for operations. So the onus is really on you to decide the value of the data you seek, and purchase it if you feel a serious need.
You might be able to convince the satellite owners that it would be a public good making such images freely available, but I suspect that they would regard this as an imposition on their time and resources. They make the odd publicity image available, but not the raw data. If you want to monitor oil slicks you would be much better served with access to the multi-spectral data than a processed image. You would need to understand how to process and interpret this data. That isn't a simple issue, and is typically the province of area specialists.
There was a special on the MOL program on PBS last night. Apparently they had satellite image resolution down to 3" in the 1960's.
I assumed the government had dozens of surveillance satellites circling the earth. I'm not going to try and pay for any images. Maybe the government has an archive of the event that will be declassified in 30 years. I think it would be interesting to have a timeline view of various plumes, slicks, and response vehicles at the Macondo site (I know we have a low resolution view of the slicks already).
There might not even be anything worth seeing going on right now, but I don't know. I don't understand why there is still a no fly zone in effect. The well has been completely shut in for weeks and no one is looking for surface slicks anymore. Why?
One point about satellite images. The very high resolution ones do not provide all of earth coverage. Indeed I'm not sure that even some of the medium res ones can. There are a host of operational and physical difficulties involved.
The critical one that besets many is that they watch and transmit - if you are not under the satellite when it is sending down the data, and listening to the data, the data is lost forever. Because they are in low earth orbit, you need to be within a few hundred miles of the satellite's path in order to hear it. More modern satellites will store a significant amount of data for later retransmission, but this places constraints on the amount of imagery they can take, both due to the amount of on board storage, and the time available to transmit the data to a ground station as it passes. The high resolution spy sats have to to be moved into position over the target, and only provide a very narrow field of view. They do not provide anything like all of earth coverage. Indeed the logistics of getting a spy sat into position is a significant operational restriction. If a new trouble spot opens up in the world, it may take some days before the spooks have high quality coverage. And they have to move a bird from a different, possibly important, area to do so. The early 60's spy sats used film based cameras, and the film was actually dropped from orbit and processed on the ground. With obvious operational restrictions on what could be covered.
Those birds that do offer continual all of earth coverage still need someone on the ground listening to the images, and only provide coverage once every 18 days (typically.) The revisit rate is governed by the orbital mechanics of the sat, and isn't something that can be easily designed away.
It is only a small nit to pick but there has never been a "no fly zone" in the GOM, although this is how many sources erroneously reported it. There has been a NOTAM (Notice To Airmen) establishing "temporary flight restrictions" (TFR) below 3,000 feet (to quote the NOTAM, "From the surface up to and including 3000 feet AGL").
The TFR are posted at http://tfr.faa.gov/save_pages/detail_0_5100.html
Note that you could/can always fly (subject to normal rules and procedures) above 3,000 feet.
The CT crowd started pushing the "no fly zone" meme and it stuck. Also, the MSM phototogs contributed to the meme when they complained loudly because they want to fly much lower (buzz the rig and some of the vessels) for better shots. In any event, the meme stuck.
Good question though about when the TFR will be removed. I've heard no speculation.
During one of Allen's last public appearances - at the Washington Press Club iirc - he was asked what were some of the lessons learned, ie. what would he do differently in a similar circumstance. His answer included "institute flight restrictions sooner." In this event it was done only after there were eight(?) too-close-for-comfort incidents within a short period of time.
The airplane images noted above are available at resolutions at least as good as 6 inches in many parts of the country. I don't think Google uses that resolution, but the mapping agencies have it. I am not aware of any resolution legal limits in general, but there are some restrictions for "sensitive" locations.
Resolution restrictions apply to satellite imagery. The US has tried for years to protect/restrict high-resolution satellite imaging capabilities of commercial satellites because of their intelligence value to foreign governments and non-state potential enemies.
Interesting history here including the US government buying up exclusive rights from the commercial imaging companies of even their 0.6-meter images for war zones during times of conflict to deny their intelligence value to enemies.
You might try playing around with AVISO, although I don't know if you will find what you are looking for.
http://las.aviso.oceanobs.com/las/servlets/dataset
In addition to various imaging and radar sensors from satellites, NASA also flew missions over the GOM with their various sensor-equipped aircraft, including their research U-2 (see http://www.nasa.gov/topics/earth/features/oil20100527.html)
They also have other aircraft equipped with various sensors that were tasked with building data sets too.
The NASA data is fairly widely shared among scientists. I'm sure much of it will find its way to the public eventually.
NRO imagery (from our national space-based assets) will likely not be made available for several decades. It is rarely shared with anyone and when it is, then the take is usually shared only in a de-graded form to even many of our allies. The capabilities and performance of these birds are one on the USA's more closely guarded secrets.
There is some educated guesses about the capabilites of the birds that surface every now and then by various experts but it is mostly speculation. About all that is ever said (and, even then, not officially) is that they are "pretty damn good."
I understand the reasons for the secrecy and concur fully. However, it's unfortunate; there is a lot of good science in these data sets.
There have been some carefully-declassified release of certain satellite intelligence imagery after time has passed. Often these are 30-to-50-year old data but still have value even after this amount of time. For the NRO press release, see http://www.nro.gov/PressReleases/prs_rel.html and for examples, see http://www.nro.gov/corona/imagery.html
USGS offers some of the images for sale at http://eros.usgs.gov/#/Find_Data/Products_and_Data_Available/Declassifie...
and a paper published using this imagery can be seen at http://www.asprs.org/publications/proceedings/pecora17/0013.pdf
Note the KH-7 class satellites are 1962-1967 technology. Some of this imagery actually has been released.
See http://en.wikipedia.org/wiki/File:United_States_Capitol_KeyHole-7_25.jpg
At the end of the KH-7 GAMBIT series, about 1967, resolution improved to 0.6-meter (started as 1.2-meter in the first of the series) which is about the capabilities of the commercial satellites today (or a little better).
Other long-retired generation NRO imagery gets released for various reasons. See the link in my other posting above on this topic.
KH-13 is the current generation which is a major upgrade to the KH-12 series.
However, I do take you point about "similar satellite" and using KH-7 as a metaphor for all US intelligence birds, regardless of their current generation. Some of our most closely-guarded secrets are just how good these birds are.
BTW, what isn't a secret is that the Hubble telescope is based on a civilian copy of part of the design of the KH-11 KENNAN. NASA changed its Hubble design from the originally-called-for 3-meter mirror to instead use a 2.4-meter mirror to save fabrication cost since the 2.4-meter mirror was already in use for the KH-11. This saved a whole new generation of tooling and processes that NASA could use for the Hubble mirror instead of starting from scratch on a 3-meter mirror design.
Some have conjectured that the overall size/shap of the KH-11 looked similar to Hubble.
The whole HST mirror debarcle showed just how much was shared between the HST and the KH-11. Especially when Hughes Danbury borrowed the optical test rig (and misassembled it) from the black side of the company.
The other story of the HST I heard (only as a rumour) was that NASA needed a shipping crate to move the assembled satellite to the launch facility. Given that such crates are rather specialised things with complete environment control and act as a mini clean room, they are not cheap. They were told "well we just so happen to have one that will fit already sitting around - but you must cover it up when in use."
The other bit that angered more than a few about the HST, was that the KH-11 guys already knew that the design of the HST's solar panels was flawed and would cause the bird the shake as it moved from shadow to sun and back. All the KH birds had solid gallium arsenide panels, but NASA used the bigger, flexible silicon ones used on most other satellites, and only learned of the problem once in orbit. It took two servicing missions before the HST got proper panels. I remember some sharp questions in the senate on this issue.
(And yes, KH-7 has become a bit of a mneme for all the optical spook sats.)
That was pretty brave of BP to stand up and take the heat.
Also, "Students who answered Clifford's questions correctly received a prize - a BP hat or pen." There's a motivator for you. All the cool kids in SE Louisiana are wearing BP hats.
Evacuation on doomed oil rig went well, Coast Guard official says at hearings
Pitchfork and Torch Department:
Anti Dispersant Demonstration
Location:The Tampa Convention Center
Time:12:00PM Tuesday, October 19th and 12:00PM Tuesday, October 20th
Petro disasters, tax dollars not at work
Natural gas pipeline crisis plans kept from public
By SHARON THEIMER
Associated Press Writer
Panel: Transocean thwarting efforts
By The Associated Press
The Times-Pic has an interesting story about the Bobbyberms with the first pictures that have been published in months. The state has given up on gaining approval for the full 100-mile project, but wants its emergency permit extended to finish the 40-mile project for berms off the Chandeleurs and Scofield Bay, which in on the west side of the Bird's Foot about halfway up. Only 5-1/2 miles have been completed, though the target date for completion, IIRC, was Halloween.
The arguments advanced by state officials show how the tabloidized news coverage of scientists' comments about oil residues has practical consequences. Garrett Graves says, "There's still millions of barrels of oil in the Gulf that's been confirmed." Spokesman Steve Mathias then refers to Samantha Joye’s comments about sediment, Ian MacDonald’s claim that 50% of the oil is still in the Gulf, and the claim attributed (wrongly?) to Ranier Amon that 4 million barrels of oil remain unaccounted for. Then the reporter does some reporting:
But the cutline writer editorializes on behalf of the berms:
http://www.nola.com/news/gulf-oil-spill/index.ssf/2010/10/gulf_of_mexico...
The 40 mile project IS the full project, as most people understand it. It is the portion that BP is funding to the tune of $360 million.
Jindal is just making a show of dropping the extra 60 miles that he wasn't going to get anyway.
"We will face an increasingly harder task of turning resources into reserves, and reserves into production. At $70 plus per barrel, most oil resources except ultra deepwater, oil shales, oils in arctic areas and oils derived from various liquid conversions remain economic—although I would add that the additional control and oversight that deepwater operations in general can now expect following the Gulf of Mexico accident will undoubtedly add cost. "
(...)
"In the Gulf of Mexico the continuing effect of the US moratorium has led to a dramatic reduction in activity and revenue due to our high market share in deepwater. While some marginal increases are possible we do not see any material improvement until next year. In contrast, we have seen continued improvement in US Land activity and a strong rebound in Canada."
(...)
"Overall in deepwater operations, the Macondo accident in the Gulf of Mexico has led operators to exercise increased caution before accepting drilling rigs as fit for purpose, and this has engendered delays in drilling programs. We have not, however, seen any programs canceled as a result of this."
--Schlumberger Chairman and CEO Andrew Gould
http://www.slb.com/news/presentations/2010/2010_0915_agould_barclays.aspx
I like it when journalists' feet are held to the fires they start.
Cryptome was hacked over the weekend. I'm taking the liberty of reposting the entire article here, just in case.
http://cryptome.org/0002/myrtus-v-myRTUs.htm
tsk tsk
These implications of unsophisticated code are adding up to my suspicions it's all the workings of a ten year old computer whiz, who is probably wondering "Does Iran have a Disney World? Dang, I don't want see a nuke plant."
It's not perfect but that might be a bit of an overstatement. It's not huge but it is ~500KB of code.
does anyone know for sure what Stuxnet does? If so, could they explain it in layman language. Thanks.
In a small nutshell, it's designed to make (apparently Siemens) controllers go haywire. Imagine a factory where lathes suddenly start trying to turn at 50,000RPM. Imagine what could happen in a power plant.
So, it seems the kid wants the rides to go faster too, eh.
:-P
Yup. Stuxnet + ULTRA TWISTER = thrill ride with probable fatalities. Actually, the code could conceivably be altered by hackers and/or spooky agencies to not limit itself to specific conditions, or to change the conditions under which it executes successfully. It's actually extraordinarily dangerous, at least potentially. There's no widespread blanket defense yet against this type of software once it's managed to become installed.
Whoa kid! Those centrifuges already spin at 100,000 rpm (i.e. ULTRA TWISTERs).
http://science.howstuffworks.com/uranium-centrifuge.htm
You would think so. Siemens and others have the virus, the software it infects, and the hardware it controls. You would think they would know.
But all we have is speculation. As far as we know (afaik, at least), Stuxnet hasn't actually made anything go boom.
No, but we do have proof of concept, as it made something go boom last week during the demo. So it can do what people have been afraid of under the right circumstances, which appears to be what the authors intended.
Bawoon animals, beware. I'm hunting wabbit.
signed Elmer J. Stuxnet.
Here's a very good layman description of Stuxnet worm in a Bloomberg interview of Richard Falkenrath, former NSC and Homeland Security official.
Even though the focus is on the Iranian reactor, the target of malware is a Siemens industrial control system. The same control system is used in many industries such as oil, auto, energy, space and many others. Rumors claim an Indian satellite was put out of commission by this virus.
StuxNet is a very sophisticated multi-million dollar software project designed to 'takeover' Siemans Step 7 Industrial Control Software in order to reprogram PLCs (Programmable Logic Controllers) that are controlled by the Step 7 software.
Symantic monitored StuxNet's 'phone home' traffic and found that Iran was the primary target. However, most of the target host machines (Windows machines) are not expected to be connected to the internet, so most active infections would not be able to 'phone home' due to lack of an internet connection.
The speculation is that StuxNet has targeted Iran's nuclear program, delaying its implementation. Symantic believes that StuxNet's initial penetration and infection was successful prior to its detecion.
Symantic's write up:
edit:
I tried to include a link to Symantics write up, but it was deleted when posted. Let try again:
http://www.wired.com/images_blogs/threatlevel/2010/10/w32_stuxnet_dossie...
"These implications of unsophisticated code are adding up to my suspicions it's all the workings of a ten year old computer whiz,"
.. might not be far off, actually. You would probably get a kick out of the book "@Large". 1 severely learning disabled, possibly mentally retarded teenager drove the authorities crazy, but I wont ruin it for ya'.
http://search.barnesandnoble.com/At-Large/David-H-Freedman/e/9780684835587
I don't think a kid could have pulled off the heist of two valid security certificates.
You're probably right about that, it sure wouldn't say much about their security, but I do recall reading somewhere's that those certs were floating around in the nether regions of the internet for quite some time, things like that tend to get passed around.
It may be harder to acquire than a keygen, but never underestimate those young whipper snappers.
Panel: Gov't thwarted worst-case scenario on spill
By DINA CAPPIELLO, Associated Press Writer
Oh now, now. That suggests a conspiracy. *shakes head*
Q: What is a group of lions called? A: a pride.
Q: What is a group of geese called? A: a gaggle.
Q: What is a group of walruses called? A: a huddle.
Q: What is a group of politicians called? A: a conspiracy!
"But Jerry Miller, head of the White House science office's ocean subcommittee, told The Associated Press in an interview at a St. Petersburg, Fla., conference on the oil's flow that he didn't think the budget office censored NOAA."
"University of South Florida oceanographer David Hollander, who was also at the St. Petersburg meeting of 150 scientists studying the oil flow on Wednesday, said he was surprised to find that the White House budget office gagged NOAA. He said public disclosure would have helped scientists to figure out what was going on."
http://www.msnbc.msn.com/id/39539761/ns/us_news-environment/
http://www.washingtonpost.com/wp-dyn/content/article/2010/10/06/AR201010...
http://www.nytimes.com/2010/10/07/science/earth/07spill.html?_r=1&src=tw...
Here are clips from part 1 of Working Paper 1 by the presidential panel. It is about flow rate estimates, and to me seems very well done.
So there was no even half-way serious attempt to estimate the flow for a freaking month. What were they thinking?! And the press doesn't do metric, even with Google Converter at hand.
http://www.washingtonpost.com/wp-srv/politics/documents/WorkingPaperAmou...
And here are clips from part 2 of the report (working paper 1 of the presidential panel), on the fate of the oil:
An interesting speech on 30-Sep by Jane Lubchenco to the American Bar Association section on environment, energy, and resources, gives a piece of news and then summarizes NOAA's responsibiliites and responses to the Gulf oil spill:
http://www.noaanews.noaa.gov/stories2010/20101001_lubchenco_seer.html
Hayward gets Award. Wow!
http://news.blogs.cnn.com/2010/10/06/dodo-trophy-goes-to-bps-tony-haywar...
wild, I bought a dodo necktie specially for a meeting at which I knew I was going to be demoted. My boss didn't get the joke.
NRD, Let me see if I understand this correctly. You were going to a meeting, with more than two people? where you were going to be tied to a stake in the courtyard of the meeting room and publicly demoted. Tell me I'm wrong and you work for a Company with better management practices than that. Please tell all of us that your company is better than that.
duck
No, but the boss is gone, and I'm promoted again. I still have the crappy tie.
NRD, I'm newly confused, why do you still have the tie? By now we would have expected you to get a flat rate USPS box, wrap the tie in freshly oil soaked tissue, placed carefully in a piece of light plastic in the box, and shipped off to the rightful recipient. Doesn't he live in Merry Ol' England?
duck
The tie now has sentimental value, related to my love of deep irony. Besides, I might need it again.
Does anybody know whats left in GOM above Macondo well, have BP removed the replacement BOP, are the 2 relief wells killed??
How many ships/rigs/ROVs are still there?
We in UK don't seem to know anything about whats going on there now
Topics being covered at the Joint Subcommittee on Ocean Science and Technology DWH science workshop on October 5-6, 2010, in St. Petersburg, FL:
1) oil/dispersant extent and fate; 2) oil/dispersant impacts and mitigation in coastal and offshore environments; 3) oil/dispersant impacts and mitigation on human health and socio-economic; 4) oil/dispersant impacts and mitigation of living marine resources; and, 5) use of in situ and remote sensors, sampling, and systems for assessing the extent, fates, impacts and mitigation of oil/dispersant.
No details appear to be available at present, and the main purpose of such an event is communication among the researchers, not publications. Maybe there will be news coverage in the St. Pete Times.
US DOI written statement by Jane Lyder on 28-Sep to the Oil Spill Commission on impacts to fish, wildlife, and habitats:
There's more.
WaPo article from today's Drumbeat (also linked by Mainerd above):
And from the working paper itself (The Amount and Fate of the Oil):
More on the "gov't withheld oil flow data" news frame. This long article gives a particularly nuanced treatment of the story. Here are two portions that add to what we've discussed.
It sems fair to say that there were enough confusing and contradictory statements to support all the conclusions made.
http://hosted.ap.org/dynamic/stories/U/US_GULF_OIL_SPILL?SITE=FLPET&SECT...
This administration has proven to be remarkably incompetent at managing the media. Here they should have just said, "We announced the possible worst-case outcome of 100,000 bbl/day" and played the tape of Thad saying that. Instead they say "We don't think anybody told anybody not to announce the possibility of 100,000 bbl/day," which obviously invites the press to discover a supposed cover-up. Meanwhile the fact that they did annouce a worst case will be ignored in most press reports.
APNewsBreak: Blowout preventer testing not started
By HARRY R. WEBER, Associated Press Writer
This thread is a another good read for theoildrum.com. Join in discussing other engineering challenges and topics on sustainable energy at http://engineersphere.com
Checked it out and not much on sustainable energy. If you like assembly language or how to calculate electrical circuits this is your site.
I think that's a spam-bot post. Ain't the internets great? /me rolls eyes
I will probably be fading from view on this site. Work is picking back up for me. I have two day jobs. One running my farm with 36 head of cattle and the other as a chief engineer for an oil & gas engineering firm in Houston. Both are picking up. Hauled over 280 bales with the neighbors and rebuilt the floor of a barn to store it. Why I was not always there to respond. I do want to thank all who took time to comment both pro and con. I shared more than I probably should have but I had to practice a bit of what I preached. I learned a lot from this bunch and have a deep admiration and respect for all. Yes even Jinn. Keep up the good fight.
As for the PE requirements, I got the opportunity to discuss my strong beliefs with my state legislator today and a representative from my US Congressman's office yesterday. I do not believe that much will really change because of the strong influence that the industry lobby has. Money still buys a lot of influence in Austin and in Washington. However, I am told by an internal source at the LAPELS Board, the Board is doing an investigation on DWH and the role that the "industry exemption" played and may consider a strengtening of the requirements for PEs in their state.
The strongest argument I have for licensing is this. Refusing to do what your employer or client wants you to do will subject an engineer to possible loss of his/her job or contract. If you want him/her to stand up and object when their emnployer or client proposes an action that may put the public at risk then the public had better be able to offer an equally tough punishment if the engineer does follow his employer/clients desired action to offset the potential loss of job if he doesn't. By requiring an engineer to be licensed to practice engineering and taking that away if they do not practice responsibly such that they cannot practice engineering at all, makes it a more dreaded outcome. A reasonable person put in this position will want to chose the lesser of the two evils. Thus they wil be willing to say no to their employer or client and not risk the safety of the public. Not what industry wants to see I am afraid. But it is what the public expects.
If any want to contact me directly contact me at info@deepwatereng.com. Thanks to TOD for making this forum available for us to discuss these important issues.
I learned a lot from your contributions, thanks. My oilfield is way different from yours but nevertheless the same and after 50 years, from digging ditches to dry holes and everything in between, I am always amazed how much there is to be learned, still.
The boy I understand has moved off and the girl has returned; its through raining for awhile in Texas. Keep the hay, I suspect you will need it come spring.
Good comments Deepwater Engineer. My only observation to add it would be that if your recommendation was enacted licensed professional engineers would have to demand iron clad contracts or they would have to be protected under strong whistle blower laws or maybe both. I would think that some engineers would purposely not get licensed and the ones that were needed to be licensed, well they would highly compensated by employers for the added risk.
I have talked to older company men in the field (offshore GOM) that said that they were going to retire if it looked like they had too much risk of personal fines and/or jail time under any new rules or laws enacted by Congress or BOEMRE. I have actually seen a few experienced deepwater company men go to some of these shale plays on land and in Deepwater plays overseas and they now refuse to go back in the GOM, ever, because the added risk and BS is too much for them to deal with.
So we could see a struggle to find qualified supervisors when we get back to whatever normal is going to be in the OCS GOM.
Does anybody know whats left in GOM above Macondo well, have BP removed the replacement BOP, are the 2 relief wells killed??
How many ships/rigs/ROVs are still there?
We in UK don't seem to know anything about whats going on there now
There is nothing on BP Macondo's web site about above, just clean up info
"Does anybody know whats left in GOM above Macondo well, have BP removed the replacement BOP, are the 2 relief wells killed??"
You could probably find answers to your questions by looking back through the posts on this website.
"How many ships/rigs/ROVs are still there?"
http://www.marinetraffic.com/ais/
There is still something going on out there from what I can tell.
I wonder why? It doesn't take that long to P&A the relief wells and leave, unless somethings wrong!
Government withholding key data on Gulf seafood testing, scientists say
Excerpt:
The reporter has done some digging and deserves credit for that. The angle that gives me pause is the absence of uniform standards and protocols being applied to the opening of state waters. In state governments (and I'm especially suspicious of Louisiana), agencies with scientific and technical responsibilities probably tend to be even more susceptible to political influence than federal agencies--with exceptions, of course. In the present case the states may have a motive to cut corners where the feds do not.
I'll repeat my point about journalists framing stories by choosing verbs of attribution to advance the standard story line--dishonest government exposed by brave independent scientists. Granted, Raw Story is supposed to be a scandal sheet, but MSM reporters are doing the same thing every day.
multiple independent scientists . . .revealed that government claims of sufficient transparency are wholly misleading.
Elllman, staff scientist at the NDRC, noted. . . she pointed out
Vs.:
FDA officials maintain
government claims
Federal officials publicly claim
federal officials continue to publicly claim
NOAA toxicologist John Stein averred
No Visible Oil Found in Offshore Sand Cores
USF researchers surveyed areas in shallow waters just off beaches in the Panhandle and Alabama.
This is rather surprising good news. Although only 64 sites were sampled, they were selected for proximity to heavily oiled beaches. They found no visible oil residue in any of the 12" cores nor on the sea floor in the vicinity of the sampling sites. They sampled sediment at depths of 3-15 m off the beaches and a few sites in Pensacola and Perdido bays.
Centralizer squabble, down the garden path.
BP engineers decided to spread out stablizing devices rather than add more of them
(emphases mine)
inexcusable.
This harks back to my earlier comments about process in the BP run operations. Who on earth gave Walz the authority to make such a decision. In many ways that is the far greater sin than Walz simply making a mistake. The inexcusable bit is that BP should have a clear process where significant changes to the operation, especially changes that relax safety margins, must be reviewed and signed off. Again, in a software engineering process no software engineer would ever have the authority to simply unilaterally decide that a new software artefact could be deployed without passing a designated set of tests. Software engineers know all to well that such action will inevitably lead to grief. Software is far more brittle than pretty well any other engineered artefact, so we are more careful. But, OTOH, the minimal repercussions of this decision would have been a couple of million dollars of lost rig time, as they performed a squeeze job, versus the the few hundred thousand saved by not doing the CBL.
However, in mitigation, Rockman has opined more than a few times that a CBL is not a very good metric of quality of the cement job, and that whilst the external perception of the CBL as a critical arbiter of the integrity of the cement might make such a decision appear quite inexcusable, the reality seems that experience shows that it isn't nearly as useful or reliable as its press makes out. The only real test is actually applying pressure.
Francis,
Glad you brought up Rockman's take. It's fairly easy for real world stuff to get shoved aside when lawyers are trying to distribute causation to advantage.
+10
"The only real test is actually applying pressure."
Francis, I hate to say it but I think Rockman is wrong about CBL's and pressure test in this particular situation.
You can't pressure pressure test cement on the annulus of a casing string. You can pressure test the casing and BP did that, but all that tells you if your casing integrity is good. You can even have a good casing pressure test with no cement in the annulus. Now a negative test can tell you if you have enough integrity to hold the well back in an underbalanced situation, but even a good negative test can't tell you if the cement job is good unless other barriers break down along with the cement.
When your dealing with a casing or liner that's not going to be drilled out for further drilling, the CBL is about the only test (that I know of) that you can do to see if you have cement bond in the annulus.
But a Cement Bond Log wouldn't be able to detect bad cement below the float collar. Would it?
If below the level of the float collar is where the failure(s) occurred then would the CBL tell them anything useful?
Jinn, a CBL would not tell you that you have a bad cement job below the float collar, but a pressure test or negative test would not normally tell you if you have a good cement job below the float collar either. If your wiper plug lands, your casing integrity is good and your floats hold you don't need any cement in the annulus or even in the shoe tract for any type of pressure test to hold.
So if you run a CBL and it shows good bond all the way to the float collar you should have good bond below it. In most completions that I have seen the production casing or production liner float equipment is below the production interval anyway. If the CBL shows adequate zonal isolation above and below the pay sand that's cement job has been deemed a success.
So if you run a CBL and it shows good bond all the way to the float collar you should have good bond below it.
___________________________________________________________________________
I think what you say is correct, but it looks like some of the producing zones were below the level of the float collar. And there may be evidence that the cement above those zones was good.
If it turns out that at the point where the relief well intersected they found the original 14.3 ppg spacer that was pumped ahead of the 4/19 cement, then that will be pretty good evidence that the upper section of the cement was good* and that it is likely that even with a positive CBL results soon after the cementing the failure was going to occur anyway.
*edit: "good" means isolated the producing zones from the upper annulus.
I agree Jinn, and I have heard speculation that there might have been a very large productive sand in the area of or below the float shoe that MWD/LWD and wireline logs didn't locate. I don't know if I go along with that speculation. I would say that BP wouldn't knowingly have huge productive sands that they purposely planned on having behind pipe in an area that they couldn't produce it.
So if the blowout came from a prolific formation that could produce like the Macondo well did, either it was the target sand that they knew about, or it was a sand that no logging tool ever saw. Does that make sence?
I don't know if I go along with that speculation. I would say that BP wouldn't knowingly have huge productive sands that they purposely planned on having behind pipe in an area that they couldn't produce it.
________________________________________________________________________
But it sounds like it did happen. And no it wasn't purposely planned that way. It is my understanding they planned to drill deeper to get below all the producing zones but they had huge losses in their attempt to drill the bottom of the hole. I read somewhere that they may have lost $3 million dollars worth of synthetic mud in drilling out this last section of hole. They had to lower the mud weight to very close to the highest reservoir pressure to stop the losses. That gave them a very narrow window for pressure for doing the cement job. They had to pump the cement very slowly to keep the pressure low.
I don't know if that story is true but the BP report well schematics do show 2 of the producing zones to be below the float.
Jinn, I'm wasn't in on the information about productive zones below the float collar. If that's true BP was very sloppy on this well, even more so than I knew.
wildman - I have to agree with you...I'm full of crap. LOL. Not really. I've never run a CBL on a well I just production cased before rigging down for a very good reason: I didn't need to know if the cmt was good AT THAT TIME. As you say you can't do a positive pressure test if you don't drill out the shoe. And in 35 years I've never seen that done with the drill rig. But, then again, I've never left newly cased hole undebalanced. Since I've always left the same mud in the csg I used to drill the reservoir with there was no chance of a blow out. Now moving back on with a workover rig is a whole new game. I always run CBL on the completion side. And even though I've never drilled out and tested cmt during the completion phase it wasn't very critical since I had a heavy completion fluid in the hole that would prevent a kick. So I run my production tubing, lighten the fluid to a tad underbalanced and perforate. And this would be after I've run the CBL and sqz'd the cmt if I thought there was a problem with it.
So to clarify: I don't run a CBL on a newly cased hole before moving the drill rig not because the CBL isn't important AT THAT TIME. Because I don't need it at that time. A drill rig can cost 2X to 3X more than a workover rig. If I've got remedial work with the cmt I'll do it with the cheaper rig. Of course, this is a different world than a DW well with a riser to displace. But again, if I'm not going to leave the well underbalanced after riser removal than cmt integrety still won't be so critical AT THIS PHASE. BTW: I still have relatively low confidence in a CBL log telling me how good a cmt job is or isn't. I've seen "good" CBL cmt leak like a seive and "bad" CBL cmt hold just fine. IOW I don't trust cmt regardless of the CBL. I trust an LOT better but then just to a point.
Rockman I agree with your statement, but I think that some here don't understand what your saying. What I'm saying is that pressure test either positive or negative don't evaluate prodution cement jobs, unless you have a path for some communication with the annulus.
To clarify I have a question. If I run a production liner and go through all the steps of cementing except I don't actually pump any cement. The plug lands and the floats hold and the liner packer sets, which is the best test to see if there is any cement in the annulus a positive test, negative test or a CBL?
My answer would be that I have seen positive test and negative test hold on cement jobs that failed, because the casing and the floats held, as they were supposed to. It was only the CBL that told us we had NO zonal isolation.
Rock, if you agree with what I'm saying maybe I should have told Francis that I don't think you understand Rockman's thoughts about pressure test versus CBL's.
wildman- i think we're all on the same page to some degree. I was responding to Francis as much or more so than to you. It's more of a question as to when CBL's are run. You know this and maybe Francis too: We pressure test every liner we run with an LOT or FIT. Why we never run a CBL on a liner set: the pressure test is far superior. But as you say you don't do that on a production csg cmt job because you can test the cmt w/o drilling out and nobody does that. That's why the completion crew runs the CBL.
I dion't think there is any disgreement amongst us chickens. Just some poor wording on my part perhaps.
But I still think CBL's suck. LOL.
In my view you run the CBL like you say as part of the completion, but if your on a deepwater well and your getting ready to leave a well in an underbalanced situation so another rig can come in, I think we now know that you had better do a CBL prior to the T&A, along with positive and negative test. Better yet just keep the rig on location, complete the well with that rig and don't take the risk of your multiple barriers failing.
I brought it up before but I think it needs to be exposed for what it is. Deepwater and shallow water operations in the GOM in recent years have started using indirect displacements when switching from drilling mud to completion fluid. For those that don't know what that is, you have drilling mud in the cased well, you then pump in sea water and clean the mud out of the hole, you then shut down for sometimes two days of so and clean the rigs pit system you then take on brine you then pump the weighted brine in the well. Many times the well is completely wide open while the sea water is in the well. I often asked the company rep prior to this operation if he feels comfortable doing a two day "negative test" without a packer and with the BOP's open, normally I get a dumb look because they don't have a clue what I'm saying.
We get complacent when we have a cased hole and that's the bottom line!
wildman - Exactly. And that was my point: I'm not going to leave a DW well underbalanced. Even after jinn explained the need to set the liner in sea water and not mud it still wouldn't make a difference to me: I would either spot a pill sufficient to balance the well during displacement or I would set a plug. And would do so even with a perfect CBL log (remember I've seen more than one "perfect" CBL bond leak). Can you imagine any operator putting a well, cased or not, into an underbalanced condition, even short term, without being 110% certain of some barrier. Hard to imagine the feds not making it a requirement on all future wells. After all, the extra expense won't stop a company from drilling every well they already have planned. And it doesn't cost the feds a penny. Why wouldn't they institure such a policy?
BP engineer defends decision to reject oil well safety advice
Slightly different presentation.
TECHNICIAN CHALLENGES BP'S CLAIM ON KEY DEVICES, By Harry R. Weber, The Associated Press, Thursday, October 7, 2010; 7:04 PM
BP almost abandoned Macondo
For those who are not reading the presidential committee's working papers, here are some clips that I thought were interesting from WP 2, on command structure and decision making.
http://www.oilspillcommission.gov/sites/default/files/documents/Working%...
I posted clips from Working Paper 1 here and immediately below this linked post:
http://www.theoildrum.com/node/7012/729607
http://bigpondnews.com/articles/Business/2010/10/08/White_House_dismisse...
Because this topic (charge that government suppressed information) fits in with the universally-accepted storyline, there are 1950 hits on a Google News search for "NOAA worst-case."
The commission's working papers contain lots of interesting and even provocative stuff, including the suggestion that showboating and mau-mauing by Jindal and Nungesser may have hampered the response. But a search for that topic yields only one hit, to a left-wing site in Louisiana.
This illustrates the type of herd behavior that Bob Somerby has been criticizing for years.
Maybe they're searching for this story:
NOAA Head: Oil Spill Commission Report Is ‘Misleading’
*** PDF warning
Sorry for lack of clarity--I meant my search turned up 1950 hits--everybody's writing about the big bad coverup.
Ah, I see - that makes more sense. I thought you had looked-up the search incidence. Definitely not:
People have more important things to think about:
" People have more important things to think about "
You sound angry and jaded my friend. It's okay, science is always diligently marching ahead.
http://www.newscientist.com/blog/shortsharpscience/2008/07/jelly-music-s...
That's the sound of one hand searching.
The top search term on Google Images in the US this week is for "girls." Here are the detailed results (no pics, just stats).
And the herd is growing ... by 1:30pm CDT today (Friday, Oct 8), the Google index how show 125,000 hits on the "NOAA worst-case" search term.
A new, embarrassing, and newsworthy finding in Working Paper 1 was that BP supplied the estimate of 1000 bbl/day with no documentation; then the 5000 bbl/day estimate came from a NOAA scientist with no expertise in spill estimation; he volunteered it and Adm. Landry accepted it. According to my Google News search (bp 1000 landry 5000 noaa scientist), no journalist has picked up this story. Then in WP 3 there is a suggestion that EPA impeded containment efforts with its interventions concerning dispersants. I already mentioned that WP 2 criticizes state governments' boom mania and blames them for the wrong and inefficient use of boom. But onward to the White House with torches and pitchforks!
That must be the result of a Google web search of 'NOAA worst-case', without quotes. It would include every mention of 'NOAA' and/or 'worst-case'.
You currently only get 81 results when you search the web for "NOAA worst-case" as a single term (with quotes) (although Google likes to inflate the results and often ignores them, and other search restrictions).
Edit: Added blockquote.
No quote marks, but News rather than Web, which limits it to recent days since the documents were published.
My comment was a reply to bbfellow - it had nothing to do with your news search.
But your news search, in and of itself, is just as meaningless. Google searches return news and "related news." Do a search for 'White House says it didn't withhold oil spill information,' and you'll get around 1962 articles. Many will be the same ones you get in a search for 'NOAA worst-case.'
Now that the Lubchenco letter that I linked above is out, stories dealing mainly with it will start showing up in your 'NOAA worst-case' searches.
Not quite Batterload. Google Boolean logic is a bit obscure and, BTW, results are also case-sensitive.
Without the quotes for searching the exact phrase, Google defaults to the AND Boolean.
Using Google's Boolean logic operator options:
The OR Boolean [NOAA OR worst-case] is 29,700,00 results.
The OR Boolean [noaa OR worst-case] is 28,000,00 results.
The AND Boolean [+NOAA +worst-case] is 85,900 results.
The AND Boolean [+noaa +worst-case] is 125,000 results.
The exact phase ["NOAA worst-case"] is 87.
The exact phase ["noaa worst-case"] is 210.
Yes, I was checking the general index, not just the news.
Note that results were from the Google cluster that resolved my query at the time and not all of their clusters are synched from instance to instance. So, mileage may vary a bit.
Yeah, no sh*t, as in I get 81 results at 3:12, and you get 87 results 40 minutes later.
Thanks for educating me about Google.
I have a client that wants us to closely watch their indexing in Google for them (they run on one of our Content Management System products). So, our NOC runs standard queries once an hour for the last week. In one set of clusters, they show 125 pages in the index; on another set, 3,500 page. Go figure.
The shear size of Google's operations and data centers makes it very difficult for them to keep everything synced.
If you're interested on Googles query logic see, http://www.google.com/support/websearch/bin/answer.py?hl=en&answer=136861
Discussion of the commission staff's charge that OMB censored NOAA's worst-case flow estimate got off on a tangent about search techniques, which is OK. But it seems to me that the staff report (Working Paper 3) went a bit haywire in triggering the big bad cover-up story.
1. There was no withholding of worst-case discharge estimates. These were announced by Allen and Salazar quite early.
2. Therefore there was no higher-up decision to "withhold the figures," contrary to suggestions in the staff report.
3. The phrase "worst-case discharge models" causes confusion between flow estimates and models of geographic oil distribution. It enters a discussion of flow rates and was treated by some press accounts as a suppression of flow rate estimates, but what's at issue is models of how far the oil might spread.
4. It does look like the OMB delayed publication of NOAA models of where the oil might go and asked for changes in methodology. A model based on a flow estimate of ~60,000 bbl/day, adjusted for containment activity, was published on July 2. The hypothetical probabilities for oiling represented here are as of around Sept 1 and assuming the flow is stopped a month earlier.
The model report:
http://www.noaanews.noaa.gov/stories2010/20100702_longterm.html
These "working papers" are interesting, but they probably should not have been released to the public. They consist of a lot of raw inputs with some undefined analysis. The basic purpose of such working papers is to feed the official commission members with information to help pursue the questioning of witnesses, fully on the record.
I wonder if there is a political message in the release of these papers. I suspect the commission is a bit steamed that they did not get subpoena power.
Information is good, but I think the up-front controversy will ultimately hurt the credibility of the commission findings.
Salt--Having read all the staff working papers so far, I'm generally impressed with their directness and clarity of analysis. The presidential commission's job is to point out what could have been done better, so they are supposed to be critical. Thus, broadly speaking, we are seeing a good-government process in action. I think it's OK that the staff reports were published without going through what will probably be some degree of blanding-out by the commission proper. As far as I know, this is an unusually transparent procedure.
In the case of this particular issue, I think it was inappropriate to publish this anonymous whistleblower claim without asking OMB and NOAA to respond. As you suggest, it is possible that some staff or commission members were happy to suggest the White House was up to no good, knowing that this is the sort of thing the media would pounce on and magnify.
Gobbet:
I just want to say how much I appreciate your consistant, intelligent, and balanced coverage of the effects of the spill, clean up, dispersants, etc. I'm a rock guy, so that stuff is way outside my knowledge base. You do a good job of filtering the BS from the real info, and I have learned much from reading your posts.
Thanks!
Alaska_geo, I'm grateful back-atcha for the chance to learn from all you smart oil-patch folks about things I was completely ignorant of. Thank you.
http://www.myfoxhouston.com/dpps/business/doubts-build-over-bp-oil-spill...
Doubts Build Over BP Oil Spill Report
OT, Stuxnet
EU Agency Analysis of 'Stuxnet' Malware: a Paradigm Shift In Threats and Critical Information Infrastructure Protection
http://www.redorbit.com/news/technology/1928897/eu_agency_analysis_of_st...
NB: none of the URLs referenced in the article seem to be working currently.
Interesting piece by David Kay, http://nationalinterest.org/commentary/the-worm-turns-4168
Makes a decent case for Russia and China as possible sources.
" Nuclear plant in Hartsville shut down by coolant issue "
HARTSVILLE — A South Carolina nuclear reactor shut down after regulators say a motor that powers a pump to cool the reactor malfunctioned.
Randy Musser of the Nuclear Regulatory Commission says the reactor at H.B. Robinson plant in Hartsville shut itself down early Friday when the problems developed. Backup coolant systems took over, and Musser says two other pumps are working.
The reactor remained shut down Friday afternoon. Musser says the NRC will do a full investigation of the plant, which is owned by Progress Energy of Raleigh, N.C.
Robinson shut down last month after a control problem with one of the plant's turbines. Earlier this year, two electrical system fires led to a nearly four-month shutdown of the plant, which reopened in July.
http://www.goupstate.com/article/20101008/articles/101009714
-----------------
Possible Stuxnet is here already and just not being acknowledged in the media ? There seem to be an awful lot of " accidents" in the world lately...
Mostly OT.
Hungary Sludge & Chemical Spill as Large as Gulf Oil Spill
Read more: http://www.thirdage.com/news/hungary-sludge-chemical-spill-large-gulf-oi...
NOAA's Jane Lubchenco, reversing earlier statements on oil and dispersant entering the food chain, said the situation is "not what it looks like."
"I feel helpless" she confessed, adding later that "there [is no] hope." "This damage is done" she said.
What? This is nonsense.
You are absolutely correct, what she meant to say was :
http://www.youtube.com/watch?v=hU0QZQRTNr0
And now for something completely sensible:
http://www.youtube.com/watch?v=Wd8qzqfPfdM
And later there is a passage that, when played backward, says "Paul is dead and I miss him." (I am the walrus.)
For those of you who were NOT alive through the "Paul is dead" hoax, see http://www.paulisdeadhoax.com/ and http://en.wikipedia.org/wiki/Paul_is_dead
This crap was stuid then just as it is now.
Cranberry sauce.
This is a fourth post on the preliminary reports by the president's commission to investigate the spill response. For the others, do a page seach for "working paper." These documents contain new information and evaluations that are being ignored by the press, except for the cover-up claim.
This is about the paper on dispersant use. My notes, not quotes as in previous posts. Google "BP working papers" for the originals.
The staff criticizes the lack of prior contingency planning for large-scale dispersant use by NOAA and EPA. It cautiously concludes that there is no evidence that goverment decisions during the emergency were unreasonable.
The paper discusses EPA's "find a better dispersant" order but does not clearly explain what happened. BP answered within 24 hours, remarking on the problem of undisclosed proprietary ingredients in most dispersants. Later EPA's testing concluded that Coredxit 9500 was about as good as any.
On May 20 EPA ordered BP to stop spraying dispersant at the surface except under rare circumstances. However, Adm. Allen developed guidelines for granting permission that led to routine use. (pp. 11-12) Apparently there was some conflict between EPA and the CG. One CG person expressed the belief that EPA's interventions had led to delays that allowed preventible shoreline oiling to happen (p. 14).
"EPA's preliminary analyses. . . support the possibility that the benefits of dispersants outweighed the costs" (p. 17). Benefits may include reducing VOC exposure for offshore workers and reducing oiling of shoreline and wetlands. Tests seem to indicate that dispersants are not unduly toxic. No dispersant chemicals were found near the coast.
Lack of clarity in government messaging contributed to the mistaken public perception that "BP was making the decisions based on its own interest" (p. 21). This perception created real fears that had real economic consequences. [I'm not clear on how rumors and folklore are the government's fault.]
The staff found no evidence that BP used dispersants without permission or outside of guidelines, such as no nearshore spraying (p. 16).
http://www.oilspillcommission.gov/document/use-surface-and-subsea-disper...
Didn't follow the story for some time, but how the current ecological situation can be described ? Did fishing resume as before for instance or not ?
Some federal waters offshore from the delta and including the well site are still closed to fishing and shrimping. Some of the LA waters are still closed to oystering. Sport fishing has been very good even in the oilier parts of LA. Except for limited areas of Louisiana, things look pretty good so far across the northern Gulf coast, but no telling what damage is yet to manifest itself.
Thanks a lot for the info, overall normally used extracted oil do much more damages to the environment than oil spills, in fact ...
Contractor: Activity on busy rig obscured key data
By HARRY R. WEBER
Associated Press Writer
This may be out there, but I just recieved this from BOEMRE so it's new to me. I only posted part of the summary which states that the new safety rules for the oilfield in federal waters must be developed by the oil and gas companies. Boy they sure showed them. I thought self regulation was going to end!
4310-MR-P
DEPARTMENT OF THE INTERIOR
Bureau of Ocean Energy Management, Regulation and Enforcement
30 CFR Part 250
[Docket ID: BOEM-2010-0046]
RIN 1010–AD15
Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Safety and
Environmental Management Systems.
AGENCY: Bureau of Ocean Energy Management, Regulation and Enforcement
(BOEMRE), Interior.
ACTION: Final rule.
SUMMARY: This final rule establishes a new subpart under the Bureau of Ocean
Energy Management, Regulation and Enforcement (BOEMRE) regulations to require
operators to develop and implement Safety and Environmental Management Systems
(SEMS) for oil and gas and sulphur operations in the Outer Continental Shelf (OCS).
Unified Area Command Weekly Update
SEDIMENT SAMPLES
Total deep-sea sediment samples: 50
Off shore sediment samples: last week 37 - today 145
Near-shore sediment samples, last week 1,174 - today 1,313
More than 743 tons of recyclable waste, including oily liquid & oily solid waste, has been processed.
To date, 90% of federal water in the Gulf are open to fishing.
Approximately 104 miles of Gulf Coast shoreline are currently experiencing moderate to heavy oil impacts-approximately 95 miles in Louisiana, 9 miles in Mississippi and 1 mile in Florida.
Approximately 485 miles of shoreline are experiencing light to trace oil impacts-approximately 224 miles in Louisiana, 81 miles in Mississippi, 60 miles in Alabama, and 114 miles in Florida.
Shallow Water Moratorium News...
Although shallow water NTL06 approved permits have continued to be sluggish, there was a significant change in permits today. Four permits for new wells were approved today. The total approved so far are 11 new wells and 1 sidetrack.
Also, there is good news regarding newly submitted applications for permits. In the last two weeks, 6 new well permits and 1 sidetrack permit have been submitted.
BOEMRE Well Permits Website
Can somebody tell me why they did no live streaming of this week's hearings? I'm sure I just "missed it," but I would really like to know. Thanks, Lizzie
erainh2o,
I have been wondering the same thing. I have been unable to find either video or transcripts for the last session of hearings. The investigation website has older videos and transcripts. I guess they will eventually get posted. The Media Advisory for hearings seems to allow media to videotape but it doesn't appear anyone has done so.
Jerry Cope, HuffPo's favorite tin foil hat oil spill pseudoscience enthusiast, is still humping those Dauphin Island Corexit containers.
Jerry's ESL lessons apparently aren't going too well.
"Corexit Use Still Appears to Be Prevalent in the Gulf, Despite Official Statements"
http://www.huffingtonpost.com/jerry-cope/corexit-in-the-gulf_b_739547.html
Cope and the Oil Truthers have really got the goods on BP here:
Let's see, thats %80/bbl for 800,000 bbls or $64 million. BP really cleaned up on this operation, especially after they write off $40 billion in spill expenses..
Retailing that kind of stuff suggests that Cope is not a deluded moron, he's a liar playing HuffPo and their readers for morons. Florida Oil Spill Law has also been featuring videos by the inventive John Bean.
from which BP pledged their share of the net revenue as a donation "to create a new wildlife fund to create, restore, improve and protect wildlife habitat along the coastline of Louisiana, Mississippi, Alabama, and Florida."
http://www.bp.com/genericarticle.do?categoryId=2012968&contentId=7062799
OK lets try it in a new thread.
Does anybody know of any evidence that indicates that the top of cement (TOC) landed at 17300' on in the early morning hours of April 20 when the Macondo well production casing cement was poured?
According to Haqlliburton's Jesse Galiano if the TOC ended up at 17,3 that means no channeling. That would also mean that the cement job had adequate number of centralizers.
***** Gagliano testimony Aug 4 *****
Q. Yes. I don't think we fully under that and
the implication to channeling. So could you briefly
explain it?
A. Based on the modeling with the centralizers,
cement would be in this case about 17, 3 with the
planned cement with the 21 centralizers in there you
minimize or limit the channeling which you would get
your cement top about what you want it.
With the 6 centralizers channeling
occurred so you're not displacing all the mud out of the
well. You're actually displacing the cement higher up
the wellbore because you leave mud behind which would
increase your cement lift pressure you would see on the
job. Did I explain that well enough?
October 9th 2010 Copiapo Chile 05:10 PDT USA - The plan B drill has broken through successfully to rescue miners. Tuesday the 12th is seen as the accepted earliest possible rescue basket travel.
The plan B drill has broken through successfully to rescue miners.
Not to take anything away from the courage of the miners, but before any of them are brought up, two guys from the surface are going down to supervise the operation from the bottom. It just boggles my mind that anybody would willingly put themselves in that position. Major kudos, and Godspeed to them all.
Yeah, I heard that and thought the same thing - and boggles is a great word! I think I heard 45 minutes per basket trip - or more.
I'm not sure I understand the necessity of them going down; but, then again, I have no idea of the skill levels of appraisal within those already trapped. They seem pretty healthy and experienced from this non miner's PoV ;-) Perhaps, they know the drill route is good for at least one trip down and need someone to make a decision as to whether it needs to be lined for safe extraction? g
I read the first two are a doctor and a rescue expert. CBS News says 16 people will be lowered into mine. Three are paramedics and 13 are mining rescue experts. Together, they will determine the order of men going up. Whether two or 16, the courage and bravery of those going down is without question.
The CBS News article also contains great videos describing rescue operation with view of rescue capsule used to rescue miners from Somerset, Pennsylvania mine in 2002.
Thanks brit. Boy, I'm even more ignorant than I thought. I have an outsider's view for sure. That just seems like way too much traffic for a tube into unstable geology. g
Hate to bother you folks, but I don't think CBS got the story right. After I read this post I went looking at other sources, because this was the first mention of additional folk going downhole. ALL the others describe one of two scenarios. For sure a paramedic is going down. All stories confirm this, some say only the paramedic but the balance mostly talk to a second rescue expert going down to help verify the order of leaving with the underground leader being the last of the crew to come up. I think the 13 folks the CBS article refers to is the balance of the basic elite rescue team that is to be at the top of the shaft to basically act as a triage unit, to do an initial eval of the miner to decide which of the adjacent facilities to send him to based on his condition. Some will be allowed time with limited members of their families if conditions warrant. If you stop and think about it if they were to send 15 folk downhole before starting the exodus that would delay the exodus another 12 to 15 hours, probably not very palatable politically.
Here is a lift from a CNN story.
"Then, authorities will lower a doctor and a rescuer into the chamber, Health Minister Jaime Manalich said. Medical and rescue personnel will be in place to start extracting and treating the miners Monday night, he said.
Once the miners have been extracted, they will undergo about two hours of health checks at a field hospital set up at the mine."
I don't think CBS got the story right.
Yeah, that sounded like way too many. Thanks for checking it out.
From AP:
Driller from Denver becomes Chile mine rescue hero
Nice piece. He was drilling water wells for the Army in Afghanistan when they called him to Chile to run the Plan B drill. Click on the photo for a slide show. Not very many good pictures of the equipment; mostly it's people hugging each other (including policemen hugging the relatives). I wish they'd wait to celebrate; it seems like tempting fate to get all excited now. I'm gonna have my fingers and toes crossed and nails bitten to the quick until they get them all out safely.
Another good piece on the breakthrough in the NYTimes:
Drill Reaches Trapped Miners in Chile, but Risks Remain
Says the trip up will take 11-12 minutes, which is not so bad.
It's going to feel like a long, long time, but a lot shorter than 45 minutes, the thought of which gives me the yips.
Here is another lift from a BBC article.
"Preparation
The rescue team includes 10 employees of Chile's National Copper Corporation, Codelco, two local mine rescue experts, and three Chilean Navy paramedics.
Final plans are still being determined but one of the experts could be lowered into the shaft first in one of three Navy-designed "Phoenix" rescue capsules to test it.
Before any miner comes up, a paramedic will be sent to examine the men and divide them into three groups: those with the most technical know-how, the weakest and the strongest characters.
Rescuers want to bring the men up in that order."
Note total is 15 of which only two going down.
here is the article link which is complete with clickable graphics etc. Excellent article
http://www.bbc.co.uk/news/world-latin-america-11493800
complete with clickable graphics
The most helpful is #2, with details on how they'll be "kitted out" in the capsule and a diagram of the capsule itself. And this bit of semi-reassuring info: "If the capsule gets stuck, the men will be able to release a series of levers inside and be winched back to the bottom of the mine."
They're going to be almost brutally regimented, it seems to me, once they reach the surface, by the medical people: first triage, then 2 minutes with one or two family members, then 2 hours at the field hospital being examined, then a longer meeting with two family members, then choppered to a hospital and kept 48 hours for observation before they're released. I guess they'll be so glad to get out of the mine they'll go along with it, but boy, I hope they're treated gently.
awildduck,
It's no bother for me. I agree and was somewhat surprised to see CBS claiming that many people going down. I didn't think it made much sense to send that many people down due to the delay it would entail before bringing the others up. And I didn't see any other stories confirming this number.
Thanks for the BBC article above. That's a very good article and what it says makes much more sense.
EDIT: Added paragraph.
"Hate to bother you folks, . ."
Bother?? I have no problem with crazy sounding numbers turning out to be crazy. I'm too ignorant about mining to object and figured sloppy reporting would be revealed. No personal investments in unverified data is a good rule for me to follow and I don't attach articles personally to the people linking them as discovered information. They did not write them, but like yourself, they were courteous enough to make them easily available. And I thank you and SL et al for doing so. g
Just trying to not be my normal overbearing self.
But on the flight time from cavern to surface. I think there is ~2160 feet to the surface and at 11 minutes that would mean the guys are traveling at almost 200 feet per minute. In an uncased raw hole that really seems quite excessive and is going to lead to a rather bumpy ride. I would be in a panic, myself thinking about all the things that could go wrong. Remember most of these guys have traveled in and out of mines in a bit larger cage but they know what can go wrong when you try to go too fast. 200 feet / minute are mid class elevator speeds with tracks and rollers and excellent guidance. The rollers on the capsule appear to be fairly hard material. No doubt an elastomer but still relatively hard. Allowing the cage to bump around in the hole is simply not a good plan as it is sure to dislodge a few rock. If the entire hole were cased that would be a horse of a totally different color. The originally talked about numbers like an hour plus or minus per trip up. Trip down with empty cage can be a lot faster but still no bumping should be allowed. I suspect the original numbers were for a round trip so at 30 minutes for the 2160 feet we get a travel speed of about 70 fpm. Still fairly rapid but most likely tolerable, especially if the rock is really tight and it sound like much of it was. Now that they have run video of the hole and decided that they only need to case the first 300+ feet they probably have a pretty good idea of how fast they can let the capsule travel. So it will be interesting to hear and see the real numbers.
As far as the regimentation is concerned, I would speculate that allowing these miners 15 or 30 minutes with a very few family members, especially the wifes and kids, would be far more stress reducing than keeping them caged up for a few more days. These guys are not returning astronauts. They are just simple people that do mining and caught an 8 ball.
at 11 minutes that would mean the guys are traveling at almost 200 feet per minute. In an uncased raw hole that really seems quite excessive and is going to lead to a rather bumpy ride.
Well, the latest AP article says 1.5 to 2 hours. Maybe they read your comment and reconsidered. ;-) As I vaguely recall, that was the first estimate some weeks ago; it's gone up and down and up and down since then, at least as reported in our highly dependable media.
SL, I was just reading the latest from the mine and they are still talking 24 to 48 hours to remove the miners. So I'm thinking that the low end of travel time is in the range of 30 to 40 minutes plus the return trip which can go faster.
They also mentioned that the capsule was going to rotate, which somewhat surprised me as I would expect they would be using cable that doesn't twist and untwist as it is spooled on and off the winch drum. Not clear why the rotation, but again another reason for a slower trip versus faster.
I'm thinking that the low end of travel time is in the range of 30 to 40 minutes plus the return trip which can go faster.
Our comments crossed in the mail...latest from AP is 20 minutes, FWIW. The range we've heard about in news reports is now from 11 minutes to 2 hours. I hope the miners are being given firm and accurate information about how long it's going to take, because we sure ain't gettin' it.
As to the rotation, the AP article said it would rotate "around curves"; the path of the drill hole isn't straight, especially near the surface. Maybe the curves have something to do with it? My spatial sense is terrible, so I can't visualize it.
Miners argue over who's out last
Newly updated AP article says 20 minutes. Sheesh.
Fascinating stuff in this piece. They're "squabbling" over who gets to go up last--not first, as you might expect--apparently out of "solidarity."
The folks on the surface are concerned about blood pressure and blood clotting because the ascent will be so fast; the miners will be taking aspirin, and they'll be on a special liquid diet to prevent nausea, because the capsule will turn around completely about a dozen times as it ascends.
Panic attacks are the biggest concern. The capsule will have a little video camera focused on the miner's face so they can keep tabs on his mental state, apparently. But there'll also be two-way voice communication.
The ascents are supposed to start early Wednesday and will take about 48 hours in total.
Hey swifty, kind of like that moniker, picked that up from another posting. I just gotta think that these journalistic brains, for whom English is a second language, or is that the ultimate language, but math is on a distant planet, just have problems with numbers. Assuming that assent is 20 minutes and they literally let the cage free fall on return for 10 minutes the round trip time is 30 minutes and the miners are all out in 16.5 hours plus que time. Ridiculous. I think we need to return a few, maybe the whole lot back to school for lots of refresher courses. First check your math. Opps.
But bad reporting is just that bad reporting. 5 demerit points.
duck
Hey swifty, kind of like that moniker, picked that up from another posting
'Twas Rockman who originated it, way back when I first joined TOD at the beginning of the oil spill and had finally worked up the nerve to ask him a question. I was honored to be nicknamed (nickhandled?) by him.
Assuming that assent is 20 minutes and they literally let the cage free fall on return for 10 minutes the round trip time is 30 minutes and the miners are all out in 16.5 hours plus que time. Ridiculous.
Yeah, I agree. Initially I wasn't fazed by the NYTimes's even more ridiculous 11-12 minutes, just relieved that it wasn't going to take as long as I'd thought. But now that you and others have dissected the timing so thoroughly, the shorter estimates are obviously cuckoo.
I do think, based on your really excellent longer comment below, that perhaps more time than we're figuring on is going to be taken up with adjustments and debriefings between ascents, and the 48 hours is probably allowing for multiple snags of one sort or another, technical and/or medical and/or psychological. Sounds to me as though that last is what's really scaring them, although the whole thing is just incredibly delicate and difficult.
New article from the NYTimes, a nice color piece on the goings-on at the camp, which are really quite remarkable:
Edit: typos.
"Just trying to not be my normal overbearing self. " = Ha! No problem ;-) Thanks. At first it sounded snarky to me as though you thought that was my or brits thinking - or, that either of us even approved of the reports we read. I can't speak for brit, but I think a lot of reporting is 'off the wall' and doesn't meet my smell test.
Also, I have opinions; unfortunately, without reliable source data, they are just opinions. For instance: I don't think the reporter meant the cable will - twist or spin - as a rule (but of course it will to some small degree with environmental variance) because the wheels appear to be like inline skate wheels parallel to the length of the rescue basket. The reporter may have missed the concept that the basket just wasn't going to travel a perfectly straight line. Again, I'm only looking / reading from the outside and NOT degree'd in this engineering science. All this takes too much time to post and explain; so, I generally just shut up when around a data driven and higher-education oriented web thread.
Ya' see what i mean? loris and duck already addressed the 'twisty cable' issue while i was posting ;-)
Standard practice would indicate that they will make one or two trial runs down and up with the escape capsule with a dummy weight (sandbags). They should when sending the capsule down put sandbags in it to help keep the cable taught.
I would also expect then to attach a cable to the bottom of the capsule so that it could be pulled free from down in the mine if it got stuck. Another reason not to be the last man out.
Non-rotating wire rope is constructed to keep the the rope from rotating when a load is put on it. But non-rotating wire rope will still rotate some but less than standard wire rope.
Thanks ez, that is pretty much what I imagined. Also, I saw somewhere that the capsule splits in two for more complex and severe constriction problems. I'm in awe at how fast they got through this mess and am keeping my fingers crossed for a (now over-expected) favorable final outcome.
If you are in the know about this, have they ever embraced the idea of painting a (self hardening) resin coating on the wall of the tunnel shaft, to help secure integrity. I'm thinking in stages and a little at a time (maybe each pass through) so as not to be too toxic. I have NO IDEA if this could be applicable, but I have seen it used in a much smaller venue in landscaping. I'm not sure of the chemical compounds used or if it's technically even resin. Just curious. TIA g
'Lo Gus, I think your thinking is fairly close to on target. I also think the reporters are talking to each other about stuff they don't have a clue about. So....
Speed. I have seen the 48 hours,that SL reports, several times now, . So let's use that.
Assume that is the total elapsed time so 48/33 = 1:45 per round trip / miner. Now assume that the trip down empty is more of a don't care about bumping and we can go twice as fast, thus we get a 2/3 :: 1/3 apportionment of time. That is we would allot 69 minutes for the up trip, that works out to about 30 ft per minute or a half foot per second. This is a very reasonable rate for the hole conditions. It does not seem rationale for the surface folk to want to subject the miners to pressure changes due to a foot per second in travel velocity.
Again keep in mind that these guys are used to traveling to work in a rapidly moving cage, but a cage more like a screened elevator. My view is traveling in a small tube is going to be a new experience and I really hope they find the one or two who might be claustrophobic out before the trip starts and give them something to slow down the anxiety. If you have never experienced claustrophobia you can't imagine the impact.
Twisting: I can still not formulate a rationale for the cage spinning in the hole. I can understand the cage curving through the twisting hole. Gee, are we on the mountain of death roller coaster? And then it is easy to see a Columbia school of Journalism (that's MO for those not in the know) grad not getting the physics right. As you point out the rollers are in-line not set at an angle. So that leaves the cable, which I noted before I would expect to be a cable type that does not exhibit twist / untwist characteristics. So I am going to fall on the side that these are the reportings of a non-technical wizard trying to cope with the technical and not understanding.
Blood pressure/ atmospheric pressure change. For sure, these guys are going to experience a significant pressure change over the 2100 feet, so I'm not at all surprised that the medico's are concerned. Having existed for nearly 60 days at the advanced pressure and then suffering a sudden pressure drop is going to cause some problems. No bends for sure but physiological repercussions. I'm betting they get to clean the cage out more than once. But we will never hear about those events.
Separable cage. Yes, the cage is designed in two parts with a built in winch to allow the personnel carrier to be detached and lowered back down into the mine. Then they will feel free at the surface to jerk on the cage to free it up. I have not seen any mention of a cable to pull it back down. But it seems entirely plausible to assume they can use the lower escape winch to pull the capsule loose, once the man-cage has reached the lower cavern. One of the speculations is that a loose falling rock could jam the cage, so it seems that the ability to back the cage up i.e. down into the cavern might be essential.
Blood clots etc. I don't think the assent rate is the issue, I would have to believe the immobility issue is the root for the clots, etc. It's the old sitting on the airplane problem. In this case it is standing in one single position for over an hour that is at issue. And it is in a position that is conducive to blood stagnation in lower extremities leading to clots . So if they are providing elastic stockings etc. that would be a good approach, on the prevention side. There is just no way we can have them leave their window seat and walk up and down the aisle a half dozen times to get the blood moving. Further the constant vertical motion is going to want to cause the blood to pool in the legs.
Travel time: I think they are going to end up winging it. They are looking to bring up a couple of the more fit miners first. I would expect them to debrief them on the trip and from that feed back, make adjustments to the assent rate.
duck
They may simply not have the right type of cable available or are concerned that there may be other causes such as the drill cuts in the hole.
Change in pressure should not be an issue, think elevator/aeroplane, but they may have trouble doing a Valsalva Manoeuvre in a tight cage, hope they teach them swallowing and yawning techniques, oh and give them a sweet.
I wondered if the cage may need a hose out but I also wondered if those magic fluids that NASA has prepared for them include a little of mother's little helper to calm them down plus a bit of dramamine.
Blood pooling seems far stretched but if they are stuck for a while it may be an issue, they probably are trying to cut down risks rather than avoid problems. I heard they would run the fit miners first, then the least fit followed by the middling ones.
NAOM
I agree that the pressure change shouldn't be a big deal. Ski lifts climb farther and faster at comparable altitudes. The lift cages look nicely made, but slight wheel misalignment and cable twist as it rubs on the curves could make for an interesting ride. I can't think of any folks who would be better mentally prepared for this than miners, though.
NAOM - "other causes such as the drill cuts in the hole."
Ah! Good point! So the fluting left behind from the drill-bit could cause a rifling effect to the capsule - especially if those 'in-line' wheels settle in to them? So, they may indeed want a 'spin-able' type cable with more play than 'non-spin' type. Not being experienced with seeing drill marks in soil on a repeated basis, but now recall having seen them in the distant past, I'm grateful for your input.
duck - Thanks for the sanity check and reaffirmation Re: reporters, time and clotting. Also,I have what I call 'wandering-acrophobia' and used to do a fair amount of climbing. My friends would laugh hysterically at me stuck and trembling in a chimney or anywhere else with sewing-machine legs; it would pass eventually. But, I can relate in thinking claustrophobia is quite similar. And, if ANY phobia won't pass and goes into a traditional feedback loop, it can be truly tragic and not even close to the neighborhood of funny. g
Hi Duck,
Just a comment re the air pressure consequences of a 2000 ft difference in atmospheric air pressure. Duck I am a long term pilot, and I can assure you that 2000 feet pressure differential is of no consequence. I hope this is helpful. cheers juan
Minister says Wednesday rescue likely in Chile
They've now decided to reinforce only the first 315 feet of the rescue shaft.
Notice of Intent (NOI): Federal Register: 10/8/10
[Docket No. BOEM–2010–0036]
Notice of Intent To Conduct a Review
of Categorical Exclusions for Outer
Continental Shelf Decisions
AGENCY: Bureau of Ocean Energy
Management, Regulation and
Enforcement (BOEMRE), Interior.
ACTION: Notice of Intent to Conduct a
Review of BOEMRE Outer Continental
Shelf (OCS) Categorical Exclusions
under the National Environmental
Policy Act (NEPA).
http://edocket.access.gpo.gov/2010/2010-25377.htm
SUMMARY: The Department of the Interior (DOI), Bureau of Ocean Energy
Management, Regulation and Enforcement (BOEMRE) is announcing its
intent to conduct a broad review of its categorical exclusions (CEs)
for Outer Continental Shelf (OCS) decisions. This review is being
conducted in accordance with section 102 of the National Environmental
Policy Act of 1969 (NEPA), as amended, 42 U.S.C. 4332; the Council on
Environmental Quality (CEQ) Regulations for Implementing the Procedural
Provisions of NEPA, 40 CFR parts 1500-1508 (Nov. 1978); the CEQ Draft
Guidance on Establishing and Applying Categorical Exclusions under NEPA
(February 18, 2010); and consistent with recommendations provided by
CEQ in their ``Report Regarding the Minerals Management Service's
National Environmental Policy Act Policies, Practices, and Procedures
as They Relate to Outer Continental Shelf Oil and Gas Exploration and
Development'' (August 16, 2010). Furthermore, this notice provides the
public an opportunity to comment on the issues that should be addressed
by BOEMRE during the review of its CEs and their application to OCS
decisionmaking. The BOEMRE will use and coordinate a commenting process
to ensure public involvement.
(delete)
jinn,
To escape the ever-narrowing window of the previous thread, I've started this one.
In response to your last post (http://www.theoildrum.com/node/7012#comment-730421):
I don't know what evidence, if any, BP may have to support TOC at either 17300' or 17260'. I seem to recall an "est." (for estimated) tag associated with a drawing showing 17300', but I'm unable to find it now.
Yes, that's the Gagliano response I recalled. Do you have the part and time for it?
CV
BP's well schematics are not evidence of anything but what BP hoped would happen.
The Gagliano testimony was one of the last questions he was asked. It is on page 406 of the transcript.
http://www.deepwaterinvestigation.com/external/content/document/3043/903...
The follow-up question is also of interest.
+++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
Q. Is there some specific lift number you would
be looking for to define channeling? 'Cause someone
mentioned that had Haliburton recorded a hundred psi?
A. Again, it would be kind of hard to determine
what the lift was and what the friction pressures were,
you know. It could be difficult to see that.
I mean, the major concern with the
additional lift was we were exceeding the ECPs that was
given by BP. I was given 14 top, stay below that. And
the model predicted channeling and with that model we
would go over that ECP limit.
+++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
This answer suggests that Halliburton might have a good understanding of how much (or how little) channeling occurred and where the TOC landed from the recorded pressure readings, but those pressure readings don't fit with their narrative about lack of centralization so they are discounting them.
jinn,
I was hoping you had an audio, not transcript, reference. The transcripts--which I think are just voice recognition software (closed caption) outputs--are often questionable. For example, from your message:
". . .I was given 14 top, stay below that. And the model predicted channeling and with that model we would go over that ECP limit. . . ."
I have to ask 14 what? And ECP?
You'll find that the 14.7 ppg limit for ECD that I mentioned hearing is written into the transcript at line 14 on page 282, at the link you provided.
CV
Chuck,
Yes, the transcripts are not very good. The link below is the video for August 24. the 4th session at 1 hour and 56 minutes is where the question was asked. It is much clearer when you listen to the testimony.
Gagliano does say 14.7 and "ECD" - the transcript is wrong.
http://www.deepwaterinvestigation.com/go/doc/3043/898815/
Do you agree that if Gagliano's simulation was even close to being accurate then the relief well would have intersected a point in annulus that contained some part nitrified cement and some part mud cake from the lost circulation material (LCM)that was pumped around April 10? The 14.3 ppg spacer and the lead cement that was pumped ahead of the nitrified cement would have been pushed much higher in the well.
From what I remember and my memory my be faulty(CYA), but the pressure readings at the end of the last Macondo cement job were rather low. I don't think that we can glean any good information from those pressure readings to help extrapolate the TOC, because the cement on this job is an energized fluid (N2 Foam). This fluid can either be compressed or in some circumstances it can even expand into voids or loss zones. So what was the downhole density? Who knows!
One problem I see with having low pressures and more specifically low differential pressure at the end of a primary cement job, is you don't have very much differential pressure holding your floats(check valves) closed. One thing that has been overlooked over and over again, is that the float equipment on the Macondo well must have failed if the flow came from the inside of the casing string or the lower part of the casing somehow collapsed and ruptured after it was tested (I don't buy that). I'm going with float equipment not checking and one reason is due to low differential pressure to help hold the check valve closed.
Any thoughts?
There was calculated to be 38 psi back-pressure on the float check valves. This is the u-tube difference of the casing to annulus. It was reported that when they bled off the pressure they had a good test that the check valves.
There is also the issue of the very high pressure needed to convert the float (3200 psi) and the low circulating pressure after the conversion. That raises the suspicion that something broke in the shoe track.
jinn and wild,
jinn - if the cement job pumped like the 18 April simulation, then the relief well would have intersected foamed cement. Evidence (e.g., claimed TOC at or near 17260') indicates that the job did not pump like the simulation. It would be nice if someone were able to lay hands on the post-job report.
To address fluid levels and hydrostatic pressures in the annulus and casing for the three Halliburton reports, I've put up a page here (screenshots from a spreadsheet):
http://mysite.verizon.net/yenrav/macondo/
The only real variable in the pressure calculations is for the average density of the foamed cement. For each of the reports I've put in red the foamed cement density required for the annulus to balance the casing and the density required to achieve the annulus overbalance that the report indicated. In all three cases the density required for the overbalance is unreasonable (case 1: 14.86 ppg for 35 psi; case 2: 15.35 ppg for 18 psi, and case 3: 14.84 ppg for 38 psi.) Recall that 14.7 ppg was the limit for ECD's and these are static densities.
CV
Jinn, 38 pounds is basically nothing when talking about gauges in the oilfield. The hydrostatic pressure of fluid in the pumping lines from the rig floor to the Halliburton cement unit was probably 38 pounds.
You can't have a good test on the check valves if you don't have a reasonable differential pressure across the valve, because to the test floats (check valve) you bleed off the internal pressure from the casing and see if the annulus flows back. The annulus can't flow back if the well is in balance and 38 psi, well that's balanced.
I didn't make the determination that it was a good test. I said "It was reported" they had a good test. The rig deemed it to be a good test.
But looking at it from a strictly mechanical viewpoint, the check valves are spring loaded so they should close and seal unless something broke.
It seems to me a good part of the problem is one that Chuck is pointing to. Given that it is hard to predict exactly how much the foam lightens the slurry at depth and exactly where the TOC ends up you don't really have an accurate hydrodtatic pressure for the annulus.
jinn,
One point of the page of calculations I posted was to show that, for a simple-to-calculate thing like hydrostatic pressure, it was not possible to confirm the annulus overbalance pressures that the three Halliburton reports gave without using unreasonable values for the foamed cement density. Since the reports give the fluid levels and all the densities except the average foamed cement density it should be an easy matter to confirm the results using reasonable values.
As for foamed cement densities, the 18 April report, in section 5.8 Final Annular Fluid Density, gives the foamed cement density and quality that OptiCem calculated for 11 depths between 16356.4' and 18107.5'. The density and quality range is from 14.29 ppg and 19.5 % to 14.44 ppg and 18.61 %.
I have done foamed cement calculations for 4 depths in the above range, plus one at 18304'--primarily to see if I could replicate the results given in section 5.8. (I can, to a very close approximation.) The trick, once you have a depth, is to approximate the pressure at that depth and then, given the base slurry and nitrogen quantity used, to find what temperature OptiCem was using when it did its calculations. If anyone is interested I can add those results to the page I did earlier today.
CV
If you post your calculations I will take a look.
I'm not sure I understand when you say:
"it was not possible to confirm the annulus overbalance pressures that the three Halliburton reports gave without using unreasonable values for the foamed cement density"
I don't know what a reasonable number would be.
The Halliburton Lab results (appendix J) gives the foam density as 14.5 ppg and the foam quality 12.98%.
But again to be meaningful any calculation will depend on knowing where the TOC is located. If the foamed cement density was 14.5 ppg and if the TOC was where the final 4/18 simulation predicted it would be, then the annulus would be just slightly over balanced with respect to the casing. But if the top of cement ended up where BP says it did with the same foam density then the casing hydrostatic pressure was something like 40 psi greater than the annulus.
Your analysis is beginning to make it look like Halliburton is screaming about centralizers to cover up the fact that they really screwed up the cement job. Is it possible that Halliburton's simulation was grossly inaccurate in predicting what did happen in reality? Did they rely on an inaccurate model and mix a cement slurry that was not appropriate for the application?
jinn,
Regarding your I'm not sure I understand when you say:
"it was not possible to confirm the annulus overbalance pressures that the three Halliburton reports gave without using unreasonable values for the foamed cement density".
I meant reasonable in the context of the Halliburton OptiCem outputs. I went on to say in the next paragraph that ". . .the 18 April report, in section 5.8 Final Annular Fluid Density, gives the foamed cement density and quality that OptiCem calculated for 11 depths between 16356.4' and 18107.5'. The density and quality range is from 14.29 ppg and 19.5 % to 14.44 ppg and 18.61 %. . . ."
In that context, and for that range of depths, no average foamed cement density over 14.44 ppg is reasonable, or possible. All three Halliburton reports would require an average foamed cement density over 14.44 ppg just to have the annulus hydrostatic pressure balance that in the casing.
CV
Oh no, Jinn I realize that what you only wrote what they reported and I'm glad you did. I apologize if I made it out to sound like the "god test" was your determination. I just want folks to realize that 38 psi on a Halliburton cement unit gauge is nothing.
As far as the springs in float equipment I've seen float equipment fail even when a differential was across the valve, so with no to little differential at all it would not suprise me if the floats failed.
As far as I know there is no pressure gauge involved. It is purely a matter faith that the correct calculations were made that place the fluids in the right place.
At the end of the cement job the gauge read about 1500 psi. That is due to applied pressure on the top plug. When that pressure is bled off the pressure applied to the check valves is whatever the overbalance is in the annulus. Even if the overbalance were 100's of pounds there is no way to see that on a gauge if the check valves do their job. If the annulus is underbalanced compared to the casing there is no way to observe that either as long as the top plug isn't leaking.
Jinn the pressure on the cement units gauge just before the plug lands on the collar is the "lift" or differential pressure minus the friction pressure. So yes there is a gauge that you can observe the underbalance just before you "bump the plug". After the plug bumps then the floats shut and act as a barrier, then your correct about not having any way to see the pressure at that point. Before the plug lands and added pressure to land the plug was applied, then you would normally observe the pump pressure at a very low rate and this would give you the differential.
I didn't realize the 38 pounds was from of the design or the opticem. I would think that the actual differential was probably pretty low too.
In theory yes when the fluids transfer from the casing to annulus you should see an increase in pressure of about twice the difference in hydrostatic pressure.
There was testimony that they saw a lift pressure of 100 psi. I haven't seen a pressure log so I don't know if that is accurate and I don't know what lift pressure the OptiCem model might have predicted.
Gagliano when asked declined to speculate on what the lift pressure meant in terms of where the TOC ended up. Obviously how high the cement went in the annulus affects the lift pressure. And Gagliano's model had the TOC something like 1200' higher than where BP claims it is.
I think what ChuckV's analysis shows is that the cement density may have been designed for where the OptiCem model said the TOC would be. That means if the cement did not go that high, then the annulus may not have been overbalanced. If that were the case you would also expect less lift than predicted.
But you also have to consider that all the circulating pressures were lower than predicted after the float was converted. that suggests something broke and the flow path was not what it was supposed to be.
I don't remember who said it but at some point one of the witnesses said the nitrogen itself creates lift. I assume that is because it is compressible and the density changes depending on the pressure changes due to depth and pumping pressure gradient.
Wild, I'm wondering how the report of chunks of cement landing on the deck of the Bankston fits into this. If the top plug was sitting on the float collar, there shouldn't have been much cement to throw out if the blowout came through an open check valve.
Just wondering how strong the float collar was. How many psi could it hold if the check valves did close? And was there enough pressure differential during seawater displacement to break through it, or could it have been weakened by the 3200 psi applied to convert, as Jinn suggests?
Oilfield Brat, in many situations you leave some cement on top of the wiper plug. I would say that two bbls of cement in the cement pumps and lines is customary before you displace, unless the operator needs rat hole for the planned completion and he doesn't want to drill out any cement. So no I'm not suprised about the chunks of cement on the Bankston.
Float equipment can usually handle fairly high pressures even after hours of circulating. I would have to know the exact float equipment used on this job to know for certain, but I think it was Weatherford's equipment.
One thing that's often done when bleeding off the pressure inside the casing after a primary cement job is openning the bleed off valve on the cement unit very fast to assist in "rocking" the floats closed. If you slowly open the bleed off or choke and "take it easy" (as some "worm" drill reps may insist) you have much more chance for failure of the float equipment.
Forensics
Swiss firm to probe Macondo well
WSJ
NEIL KING JR. And KEITH JOHNSON
An Oil-Thirsty America Dove Into 'Dead Sea'
Boy, that's another good article from WSJ.
John Hofmeister, former Shell President, calls for energy policy to be taken out of government and placed in hands of an independent energy committee analogous to the Federal Reserve for financial sector. The status quo policy seen by the juvenile antics of the reckless right and ludicrous left is facing a day of reckoning. Hofmeister predicts gasoline pump prices rising to $4-$5 per gallon just before the next presidential election in 2012.
Here's a very insightful, eye-opening and frank lecture by John Hofmeister discussing the future of energy on 9/28. (53 minute VIDEO)
A caveat about Hofmeister. I watched him defer to Matt Simmons' judgement about using a nuke to kill the well since Simmons was *the* expert. He may be right about $4-$5 per gallon but I suspect he's not the most highly perceptive analytical mind out there.
And I'm not at all sure that an organization that pursues opaqueness as SOP is a great idea when it comes to manipulating energy markets.
snakehead,
It is very troubling to hear Hofmeister supported the idea of nuking the well. Following oil issues is a new endeavor for me, so I'm slowly gaining experience with the various mouth pieces regarding these issues. I would think the current debate of too much govt vs too little govt concerning energy issues is very emotional and may not lead to best solutions. Perhaps a more pragmatic approach would be taken by an independent regulatory regime that doesn't report directly to any of the branches of govt. I certainly don't have the answer and am only trying to spur the discussion and appreciate the great comments I read here.
Could you discuss the manipulation of energy markets a little more? I was interested in your point of view regarding such. I don't see manipulation as a bad thing unless one group gains a monopoly with it. I would hope for checks and balances among multiple manipulators with best ideas bubbling to surface and worse ideas kept buried. And it is an important concern as to whether an independent energy regime would gain a monopoly to manipulate.
'Boom Blaster' triples speed of cleaning booms
http://www.news-leader.com/article/20101010/BUSINESS05/10100351/-Boom-Bl...
NatResDr,
That was a great story to read. It shows necessity is the mother of invention!
Been looking at literature on marine snow, which is a component of the "sedimented oil" pictured at http://gulfblog.uga.edu/. It's worth looking carefully at these pictures. They appear to show two components: flakes of oil residue amid a mass of orange-white floc. It seems likely that this floc is conventional marine snow (organic detritus) that is colored by oil residue too small to be visible as flakes.
We'll eventually see several important publications based on the huge sampling effort under way to map and describe the oil-spill fallout. Those reports will identify the composition of the sedimentary layer that includes residual fractions of the oil after decomposition. Meanwhile, it's informative to see that there are hundreds of publications on the composition, dynamics, and deposition of marine snow.
Normally the main source of marine snow is biological production in the sunlit photic zone. Exudates and detritus from these organisms are nutrient-rich. They form clumps or aggregates that are are fed upon by other organisms (not only microorganisms like bacteria but also copepods, euphausiids, ostracods, amphipods, and anchovy-like fish) as they settle or are circulated through the water column. Thus they are an important food source and the locus of much recycling of materials and flow of energy in the marine ecosystem. The material eventually settling out at the seafloor consists of motile organisms such as dinoflagellates and ciliate protozoa, heavy-walled resting spores of diatoms, empty diatom frustules, miscellaneous exoskeletons such as crustacean molts, planktonic fecal pellets, and small detrital particles.
We should expect two distinguishable marine snowstorms to have resulted from the BP DWH oil spill, one from the huge release of hydrocarbons at (and near) the surface and a second from the large subsea plumes of dissolved and suspended droplets of hydrocarbons at 1100-1300 meters depth. Both portions of the spill should have caused massive plankton blooms while biodegration of the oil fractions ensued. It seems likely that both marine snowstorms would have been unusual in their magnitude. In other respects, however, the dynamics and composition of the surficial snowstorm might be expected to have been similar to normal warm-season ones, whereas the deepsea-sourced snowstorm may have had unusual characteristics.
A useful review article on marine snow is JT Turner 2002 Zooplankton fecal pellets, marine snow and sinking phytoplankton blooms. Aquatic Microbial Ecology 27:57-102.
http://www.int-res.com/articles/ame/27/a027p057.pdf
This is a long and fascinating read. For example, planktonic fecal pellets and other sedimented materials contain ample anthropogenic pollutants, including trace metals, radionuclides, chlorinated hydrocarbons, polycyclic aromatic hydrocarbons, and fly-ash particles from coal-burning power plants.
Sediment traps in the Mediterranean, Black, and North seas received marine snow containing cesium radionuclides from the Chernobyl nuclear power plant accident.
Also cited is paleontological evidence of fossil zooplankton fecal pellets, in black shales 11 to 300 million yr old, associated with phosphate, oil, and coal deposits.
Thanks for reading up on this; you'll be in a position to help us digest the research on Macondo sediment.
It will be important to learn how much of what fractions of oil materials are in the organic sediment, as well as how they got there. We already know there are (apparent) tar flecks visible in Dr. Joye's samples; that would be expected. Joye also seems to have a hypothesis that a lot of whole dispersed oil droplets were trapped in marine snowflakes and sedimented. She seems to believe that the Macondo snowfall has an unusually large component of polysaccharide mucilage secreted by the bacteria that bloomed to eat the oil. Someone else recently suggested that phytoplankton may have secreted an unusual amount of mucilage as a stress reaction to oil pollution. (See the "sea snot" coverage last week.)
I had a question about your comment
Is there any significant amount of plankton at 1000 m depth where the plumes mainly were? I would guess any snow originating at those depths would consist of bacteria, their exudates, and oil materials--stuff that might stay suspended until it collides with heavier flakes descending from above.
Thanks, a good question to clarify terminology, since it's easy to confuse plankton and the subset that are phytoplankton. From wikipedia:
At and near the surface, phytoplankton dominate the planktonic biota, and they dominate the ecosystem dynamics since they are fixing carbon (as hydrocarbons) driven by solar energy and thus producing the foundation of the food web. Because light is absent at 1100-1300 meters, the consortia or communities there exclude phytoplankton but include most other groups, with bacteria especially abundant. The food web of these deeper plankters is derived from food imported or introduced from elsewhere, usually as marine snow dropping from surface blooms but in the deepsea GOM plumes as fossil hydrocarbons driving (non-phyto) plankton blooms at depth.
Although production of extracellular mucilages is ubiquitous, we need to be careful not to conflate the GOM dynamics with the extraordinary Adriatic "sea snot" phenomenon. The latter refers to nuisance amounts of mucilage produced by algae (phytoplankton) in surface waters of the Adriatic Sea. In addition to the news accounts referenced on TOD, the Adriatic phenomenon is documented in ample recent scientific literature (and some over a century old).
So far I have not found any research characterizing marine snow from a deepsea-sourced plankton bloom. Perhaps should search the literature on natural oil seeps. If there's none there, maybe the present case will write a truly new chapter.