Fixing the Gulf oil spill problem

[Geigerclick]

Imagine the miles of geologic formations containing the the oil reservoir, in the worst case, as glass , i.e. brittle. Then what imagine the worst case outcome a large explosion in the 'glass' containment of possibly hundreds of millions of barrels of oil & gas down there.

Well, I know what I'll be having a nightmare about tonight!

 

[M Grandin]

No.

1) they can't glue steel tubes together especially while the well is flowing.
2) even if they could seal the tubes together the pressure acting on the surface area on the bottom of the tubes would blow them out.

CS

Thanks for comments! Maybe you are right regarding possibility "glueing/cementing" tube shells together in actual conditions - but I also mentioned possibility relying on the tube sections own weights. If the tubes are sufficiently long, they will of course stand the pressure - if 900 atm (that may have decreased by now) appr 1.2 km steel tubes stand the pressure. And in the beginning, when inserting the outermost tubes, the pressure may be much lower because of still decent flow through pipe, reducing pressure due to flow resistance in the well. I realize exact static and dynamic forces on tube sections are not easy to tell without knowing more. But If the total length corresponds to static pressure when flow is halted - the tube will not be lifted at any conditions - I dare say without being hydromechanics professional.

Possibly the tubes could be hanging down by help from "collars" at end of tubes - securing their position.

If the flow still cannot be fully halted, such tubes will at least reduce the flow considerably
and also prevent the original pipe from being eroded away - a very dangerous threat in the long run if the flow continues, an oil "expert" mentioned.

 

[Geigerclick]

If they can reallly reduce the flow by up to 90%, that would be a huge victory for engineering. 5000 feet under water, with ROVs, I'm amazed they've done what they have, with the cut and placement of the LMRP. I am willing to wait and see if finishing the work and adjusting the vents can allow for a greater capture of the oil.

 

[Bernie100]

BP gushing well flow calculation

Do we have a mechanical engineer here somewhere?

In my view, the flows provided to us are ridiculously low.

Am I not right that assuming a flow velocity of 10 fps, which I believe to be rather low considering the pressure behind this, for a 21" pipe would be more like 411,000 barrels per day and not anywhere close to 19,000 barrels per day being quoted in the media.

Could I have some feedback on this. If I'm anywhere close, this is a far greater catastrophe than the public is led to believe.

Based on the 19,000 barrels per day, the flow velocity would only be 0.5 fps which seems ridiculous.

 

[Buzzworks]

Am I not right that assuming a flow velocity of 10 fps, which I believe to be rather low considering the pressure behind this, for a 21" pipe would be more like 411,000 barrels per day and not anywhere close to 19,000 barrels per day being quoted in the media.

While the pressure of the oil is huge, it is significantly countered by the ambient water pressure at such depths. If you can just bring that oil pressure to the surface, the result would be quite explosive.

While I am not aware of the current figures presented by the media, I agree with your calculations. But remember, there's a constriction in the pipe before the broken end. So we may not expect the oil coming out from a 21" diameter area, effectively, but something smaller. The constriction could also create Bernoulli Effect, speeding up the flow velocity and making the leak look very bad, but not necessarily that bad. Although it is very bad, now that it has gone this long and the leak is still not stopped.

Anyway, seems like they've fixed it a bit, hope they can find a way to keep siphoning the oil in the stormy seas ahead.

 

[Bernie100]

Thanks for your response. I agree with you as far as the Bernoulli Effect but not completely.
The BOP just ahead of the cut pipe has some restrictions in it but let's not forget that the body housing this stuff inside is quite a lot larger. I don't believe that the design would allow for much pressure drop as this would constrict the flow and cut into big oil coffers. I am talking about a calculation based on velocity which shows 20 times more flow than they are stating. Am I to believe that the flow restriction in the BOP would reduce the flow down to 1/20th? Furthermore, the sea water does provide back pressure in the order of 2160 psi. However, the positive pressure from the well could very well be an additional 1000 psi greater or possibly much more. There is no question that BP knows that pressure at the well head. This would be normal instrumentation provided at every well head or well known by their engineers based on all the other flow data.
I appreciate your input.

 

[mheslep]

... for a 21" pipe

That's the outer diameter of the pipe. ID of an undamaged pipe would be 19", and this one is both slightly crushed and has internal obstructions (at least before the pipe cut). More importantly, only a fraction of the effluent is oil (vs gas).

 

[Geigerclick]

That's the outer diameter of the pipe. ID of an undamaged pipe would be 19", and this one is both slightly crushed and has internal obstructions (at least before the pipe cut). More importantly, only a fraction of the effluent is oil (vs gas).

Do we know yet what the relative fractions are?

 

[Bernie100]

Thanks for your input. The gas portion is a very valid point. However, the gas is compressible but many multiples under these pressures including the sea water pressure. As far as i know, in mechanical piping the quoted line size is the inner diameter and not the outer diameter. An example is that a schedule 80 pipe which has a thicker wall than a schedule 40 pipe has a larger outer diameter but the same inner diameter.
Thnks again,

 

[stewartcs]

Do we have a mechanical engineer here somewhere?

In my view, the flows provided to us are ridiculously low.

Am I not right that assuming a flow velocity of 10 fps, which I believe to be rather low considering the pressure behind this, for a 21" pipe would be more like 411,000 barrels per day and not anywhere close to 19,000 barrels per day being quoted in the media.

Could I have some feedback on this. If I'm anywhere close, this is a far greater catastrophe than the public is led to believe.

Based on the 19,000 barrels per day, the flow velocity would only be 0.5 fps which seems ridiculous.

They're not ridiculously low. 411,000 barrels per day is ridiculously high. There are no wells in the GOM that can produce any flow rate that high. The highest reported in that block is around 30,000 BPD - so the estimates seem quite reasonable to me.

CS

 

[stewartcs]

Thanks for your response. I agree with you as far as the Bernoulli Effect but not completely.
The BOP just ahead of the cut pipe has some restrictions in it but let's not forget that the body housing this stuff inside is quite a lot larger. I don't believe that the design would allow for much pressure drop as this would constrict the flow and cut into big oil coffers. I am talking about a calculation based on velocity which shows 20 times more flow than they are stating. Am I to believe that the flow restriction in the BOP would reduce the flow down to 1/20th? Furthermore, the sea water does provide back pressure in the order of 2160 psi. However, the positive pressure from the well could very well be an additional 1000 psi greater or possibly much more. There is no question that BP knows that pressure at the well head. This would be normal instrumentation provided at every well head or well known by their engineers based on all the other flow data.
I appreciate your input.

The body of the bop is actually smaller than the ID of the riser. The bop has an 18-3/4" nominal ID. The riser is at least 19" nominal ID (depending on the wall thickness).

CS

 

[Bernie100]

Thanks for your comment and I sincerely hope you're right. The difference though might be that normally the flow has to be brought to the surface with the full 5,000 ft. of head at the well head considering the pipe frictions. In this case, the flow is unrestricted as far as the pipe frictions.

 

[stewartcs]

Thanks for your input. The gas portion is a very valid point. However, the gas is compressible but many multiples under these pressures including the sea water pressure. As far as i know, in mechanical piping the quoted line size is the inner diameter and not the outer diameter. An example is that a schedule 80 pipe which has a thicker wall than a schedule 40 pipe has a larger outer diameter but the same inner diameter.
Thnks again,

Nope, it's the other way around with pipes. The ID is a function of the schedule. The nominal pipe size is the OD and the ID will vary depending on the wall thickness (or schedule).

CS

 

[stewartcs]

Thanks for your comment and I sincerely hope you're right. The difference though might be that normally the flow has to be brought to the surface with the full 5,000 ft. of head at the well head considering the pipe frictions. In this case, the flow is unrestricted as far as the pipe frictions.

The pipe friction is no where near high enough to reduce the flow from 411,000 BPD to 30,000 BPD. Most production risers are around 6" in diameter IIRC.

CS

 

[skumar26]

This should have been solved a long time ago. It would be a simple matter to use a valve attached to a piece of pipe the right size and fit it to the pipe at the well with wedge blocks and bolts with the valve open and then once attached the valve could be closed. This type of wedge clamping is not at all uncommon in the hydraulic and high pressure steam industry.
Since the pipe is standard sizes for well heads it seem rediculous that they don't have devices assembled and in stock for just this kind of event.

i am agree with you i was thinking the same yesterday. These money makers can't think such a small thing. This is common sense no pipe structure is designed without valve controlled system why the bloody hell these engineers designing such type of valvless gas flow underwater system.

It is completely ridiculous

 

[xxChrisxx]

i am agree with you i was thinking the same yesterday. These money makers can't think such a small thing. This is common sense no pipe structure is designed without valve controlled system why the bloody hell these engineers designing such type of valvless gas flow underwater system.

It is completely ridiculous

It does have a valve. The valve failed, I've not been able to find any information as to why exactly, most likely massive overpressure.

However there was a failure of a key pressure test, meaning that production should not have gone ahead. Either someone did a botch repair job, and it passed a retest only to fail again (this isn't the valve it's something else) or it wan't repaired and the go ahead was given.

 

[stewartcs]

It does have a valve. The valve failed, I've not been able to find any information as to why exactly, most likely massive overpressure.

However there was a failure of a key pressure test, meaning that production should not have gone ahead. Either someone did a botch repair job, and it passed a retest only to fail again (this isn't the valve it's something else) or it wan't repaired and the go ahead was given.

I highly doubt it was overpressure. The BOP is rated for 15,000 psi. They were drilling with 14 ppg mud weight if I recall correctly and the well was in check at 18,000-ft or so.

Do you have a reference for the failure of the pressure test? Those tests are required by MMS every two weeks and the charts are signed by the engineer performing the test on board as well as the company man (BP rep. on board in this case) and logged.

CS

 

[xxChrisxx]

I highly doubt it was overpressure. The BOP is rated for 15,000 psi. They were drilling with 14 ppg mud weight if I recall correctly and the well was in check at 18,000-ft or so.

Do you have a reference for the failure of the pressure test? Those tests are required by MMS every two weeks and the charts are signed by the engineer performing the test on board as well as the company man (BP rep. on board in this case) and logged.

CS

It was a negative pressure test, I don't have any specific link, just heard about it at work. I've just googled 'negative pressure test' and lo and behold BP came up as the first link. There are three pipes, what the seal failure means is the the pressure was not equally distributed. Which possibly led to the gas rising and the subsequent explosion, and probably meant that at auto shut off of the valve did not occur.

The BOP may be rated to 15000psi (meaning the metal may not fail) but if you have overpressure that shags the seals (higher than design pressure can make an oring extrude out of it's groove and past the device that's meant to stop it) in the valve then you get problems. But like I said it's know known to the masses why the valve did not work.

EDIT: Don't know if the Tech Update has been posted yet about what BP is up to, linky below:
http://bp.concerts.com/gom/kentwellstechupdatelong053110.htm

 

[stewartcs]

It was a negative pressure test, I don't have any specific link, just heard about it at work. I've just googled 'negative pressure test' and lo and behold BP came up as the first link. There are three pipes, what the seal failure means is the the pressure was not equally distributed. Which possibly led to the gas rising and the subsequnt explosion, and probably meant that at auto shut off of the valve did not occur.

The BOP may be rated to 15000psi (meaning the metal may not fail) but if you have overpressure that shags the seals (higher than design pressure can make an oring extrude out of it's groove and past the device that's meant to stop it) in the valve then you get problems. But like I said it's know known to the masses why the valve did not work.

The BOP is not negatively pressure tested.

What three pipes are you referring to? The BOP (stack) is just that, multiple BOPs stacked on top of each other. The bodies and the rams (together make up a valve) are also rated for 15,000 psi which includes their sealing elements. So it's not just the bodies.

They don't use o-rings as sealing elements in the ram either.

CS

 

[xxChrisxx]

The BOP is not negatively pressure tested.

What three pipes are you referring to? The BOP (stack) is just that, multiple BOPs stacked on top of each other. The bodies and the rams (together make up a valve) are also rated for 15,000 psi which includes their sealing elements. So it's not just the bodies.

They don't use o-rings as sealing elements in the ram either.

CS

Kill and choke lines from the BOP and up the riser to the rig (I think they run through a manifold similar to the one they used for the top kill). There are two or three usually. In this case it appears there were three, and the tests indicated a leak that meant there was a higher than expected pressure in the drill pipe.

I gave the o-rings as an example of how higher than designed pressue can shag a seal. I also make no bones about not acutally knowing why valves failed. I thought annular BOP use rubber seals. On top of there there is the '**** or bust' hydraulic ram that basically shears off the pipe and wedges it closed, but there are only 1 or 2 of these on a stack as far as I am aware.I'm also still learning about this stuff so don't shoot me if it's wrong. I design penetrators and I'm fairly new to the industry, so anything not directly related to my job I am just picking up as I go.

 

[stewartcs]

Kill and choke lines from the BOP and up the riser to the rig (I think they run through a manifold similar to the one they used for the top kill). There are two or three usually. In this case it appears there were three, and the tests indicated a leak that meant there was a higher than expected pressure in the drill pipe.

There are only 1 choke and 1 kill line in any subsea BOP system, not three. There may be a mud boost line but it is only rated for no more than 5,000-psi. The choke and kill lines are rated for 15,000-psi.

Those are the lines they use to pressure test the BOP every two weeks with. So if the BOP passed, then they must have passed too. Also, the isolation valves (two each in each line at each entry point into the stack) are tested to 15,000-psi as well. Esentially all of the rams and valves get tested every two weeks in the GOM.

I gave the o-rings as an example of how higher than designed pressue can shag a seal. I also make no bones about not acutally knowing why valves failed. I thought annular BOP use rubber seals. On top of there there is the '**** or bust' hydraulic ram that basically shears off the pipe and wedges it closed, but there are only 1 or 2 of these on a stack as far as I am aware.

The annular is a spherical BOP. It has a solid rubber annular sealing element with a rigid steel backbone structure. A piston assembly collapses it in on itself to seal around the drill pipe or on open hole.

The annular will be the highest preventer in the stack. Typically there are two and they reside on the LMRP.

The blind shear ram will be the first preventer (from the top) on the stack that seals and locks. It is meant to shear drill pipe of a certain size and diameter. It can also shear some casing but it is geometrically limited.

Beneath that there will typically be a casing shear ram (which neither seals nor has any locking device). Then usually 3 pipe ram preventers which do seal and have locking devices.

I'm also still learning about this stuff so don't shoot me if it's wrong. I design penetrators and I'm fairly new to the industry, so anything not directly related to my job I am just picking up as I go.

If you have specific questions please feel free to ask. I've been designing and analyzing subsea systems for over a decade.

CS

 

[baywax]

Can we just set a charge and blow the thing shut? Seems to work above ground.

If this has been queried please forgive my ignorance.

By the way, every time I start my car I feel responsible for this catastrophe. As long as we keep feeding the anaconda, it will eat us.

 

[ViewsofMars]

If you have specific questions please feel free to ask. I've been designing and analyzing subsea systems for over a decade.

CS

Hi stewartcs. One of my major concerns pertains to the health of individuals that are on the frontline of this disaster. Do you take into account when designing and analyzing subsea systems any of the OIL SPILL RESPONSE RESOURCES that are made available by the National Institute for Occupational Safety and Health Education and Information Division or CDC? If so, would you be so kind as to expand on that for us? Thanks in advance for your consideration in this matter.
http://www.cdc.gov/niosh/topics/oilspillresponse/

 

[stewartcs]

Hi stewartcs. One of my major concerns pertains to the health of individuals that are on the frontline of this disaster. Do you take into account when designing and analyzing subsea systems any of the OIL SPILL RESPONSE RESOURCES that are made available by the National Institute for Occupational Safety and Health Education and Information Division or CDC? If so, would you be so kind as to expand on that for us? Thanks in advance for your consideration in this matter.
http://www.cdc.gov/niosh/topics/oilspillresponse/

No not normally. The oil spill response plan is created typically by the SHE department of the operator (BP in this case) in conjunction with, and approved by, the local and federal government. The resources required to be available are determined from the results of that plan.

Engineers that design the BOPs, Riser, Tensioning systems, etc. do not normally consider the response of the oil company and government due to a catastrophic disaster. We deal mainly with the safe and effective design of the equipment used to control the well. Note that the designers of this equipment do not work for the oil companies or the government.

CS

 

[gmax137]

Do you have a reference for the failure of the pressure test? Those tests are required by MMS every two weeks and the charts are signed by the engineer performing the test on board as well as the company man (BP rep. on board in this case) and logged.

CS

The impression I got from the interview on 60 Minutes a couple of weeks ago was that there was a failure in the valve control circuit (1 of 2 redundant circuits). Sorry if I have the terminology wrong, I really don't know anything about this. A question I do have is, what are the required actions if they fail one of these surveillance tests? In my field (nuclear power plants) the deficiency must be corrected in a specified time (varying from 1 hour to 31 days, depending on the nature of the failure) - and if it can't be corrected, the plant has to be placed in a condition where the failed component/system isn't required.

 

[mheslep]

Can we just set a charge and blow the thing shut? Seems to work above ground.

If this has been queried please forgive my ignorance.

By the way, every time I start my car I feel responsible for this catastrophe. As long as we keep feeding the anaconda, it will eat us.

https://www.physicsforums.com/showpost.php?p=2748367&postcount=90

 

[stewartcs]

The impression I got from the interview on 60 Minutes a couple of weeks ago was that there was a failure in the valve control circuit (1 of 2 redundant circuits). Sorry if I have the terminology wrong, I really don't know anything about this. A question I do have is, what are the required actions if they fail one of these surveillance tests? In my field (nuclear power plants) the deficiency must be corrected in a specified time (varying from 1 hour to 31 days, depending on the nature of the failure) - and if it can't be corrected, the plant has to be placed in a condition where the failed component/system isn't required.

There are two control PODs. Both are fully capable of completely operating the entire system. They are redundant both hydraulically and electrically. If one were to fall of the other could still be used to secure the well.

Additionally, there are two PLCs in each POD that are completely redundant as well. They control a solenoid valve to fire each function. The PLC outputs are wired to separate coils in the solenoid as well.

If a function fails in one POD then drilling is stopped to assess the situation. If drilling can be continued safely then it will. If not, the POD or LMRP will be retrieved and repaired. Once repaired it will be redeployed and drilling will commence again.

In any case, the Operator (BP for example) must agree to commence drilling. IIRC MMS has some rules that do require the system to have redundancy at all times, but not for every component. Some components are not necessary for safety. In other words there are multiple ways to secure the well that can be used if a desire method isn't available. For example, there are typically 3 pipe rams on any stack. If one fails, the other two provide the capability (as intended with their design) to secure the well.

There are multiple components that could fail that may have more than single redundancy that would not require stopping operations. For example, if one of the PLCs in one POD failed, it would not be necessary to retrieve the POD or LMRP. However, the Operator may require you to anyway. But strictly speaking, the system is still fully redundant even though one out of the two PLCs in that POD failed.

However, all functions must be working prior to deployment.

CS

 

[gmax137]

Thanks, stewartcs. Complete explanations appear to be beyond the capabilities of the 60 Minutes producers.

 

[ViewsofMars]

No not normally. The oil spill response plan is created typically by the SHE department of the operator (BP in this case) in conjunction with, and approved by, the local and federal government. The resources required to be available are determined from the results of that plan.

Engineers that design the BOPs, Riser, Tensioning systems, etc. do not normally consider the response of the oil company and government due to a catastrophic disaster. We deal mainly with the safe and effective design of the equipment used to control the well. Note that the designers of this equipment do not work for the oil companies or the government.

CS

Thanks stewartcs.

Here’s a quote from a letter dated June 8, 2010 from the National Commander Deepwater Horizon Reponses - Admiral Thad Allen, National Incident Commander to Dr. Anthony Hayward, Group Chief Executive BP:

“The BP Deepwater Horizon oil spill is having a devastating impact on the environment and the economy of the Gulf Coast states and their communities. As one of the responsible parties for the event, BP is accountable to the American public for the economic loss caused by this spill and related events. I recognize that you have accepted responsibility for the spill and that you are committed to paying all related expenses.”
http://www.deepwaterhorizonresponse.com/posted/2931/NIC_Letter_to_BP_CEO.621247.pdf
(I found that pdf off of this link: www.deepwaterhorizonresponse.com[/URL])

Also, a quote from a BBC article, Gulf spill: [B]Salazar testifies at Senate safety hearing[/B], on June 9, 2010:
“Mr Salazar announced a number of new safety regulations on Tuesday.

“Among them, oil companies drilling in US waters will now have to inspect their blow-out preventers and provide safely certificates.

“The failure of the blow-out preventer on the Deepwater Horizon rig led to the oil spill, the worst in US history.”
[url]http://news.bbc.co.uk/2/hi/world/us_and_canada/10273904.stm[/url]

The BBC article gives me the impression that Oil companies drilling in US waters haven't ever had blow-out preventers inspected and retained a safely certificate. Is that correct? The Deepwater Horizon rig did not have a safely certificate. Who and what department is responsible for inspection and safely certificates for blow-out preventers? Also, would you or someone else be so kind as to give me further information about safely certificates?

I'm also wondering about who are *all* 'the responsible parties for the event'. And, what are *all* the 'new safety regulations' that Mr. Salazar announced? Does any PF member know? A list would be helpful.

Thanks in advance for your help.
Mars

 

[stewartcs]

The BBC article gives me the impression that Oil companies drilling in US waters haven't ever had blow-out preventers inspected and retained a safely certificate. Is that correct? The Deepwater Horizon rig did not have a safely certificate. Who and what department is responsible for inspection and safely certificates for blow-out preventers? Also, would you or someone else be so kind as to give me further information about safely certificates?

I'm also wondering about who are *all* 'the responsible parties for the event'. And, what are *all* the 'new safety regulations' that Mr. Salazar announced? Does any PF member know? A list would be helpful.

No that is not correct. The BOPs are certified by the OEM after they are made and the data books with these certificates are kept on file by the owner of the BOP. The BOPs on the Horizon did have these certificates. The Stack is also surveyed at the beginning of each well by a 3rd Party Inspector.

MMS is the only department in the US that requires them to be inspected. However, API requires that they be certified in order to meet their specifications.

What the DOI is requiring now is that all BOPs be re-certified by a third party inspector (in addition to the other requirements listed in the documents below).

The new recommendations are on the DOI website:

http://www.doi.gov/deepwaterhorizon/loader.cfm?csModule=security/getfile&PageID=33598

http://www.doi.gov/deepwaterhorizon/loader.cfm?csModule=security/getfile&PageID=34536

CS