ROV attempting to activate Deepwater Horizon Blowout Preventer
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May 17, 2010 by
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There have been no comments on the pipe freezing idea which I find strange because BJ Services develop a deepwater pipefreezing tool for use during pipe tie-ins, and such like operations. There scheme involved a submersible refrigeration unit and jacket to surround the pipe. So the idea is not so far fetched.
Shell Expro showed considerable interest in pipe freezing technology in the North Sea back in 1990/1991 when operators were having to tie-in numerous seabed valves on trunk lines as response to the Piper Alpha disaster.
In these cases, the scheme involved pushing a slug of gel fluid through the pipeline between pigs. A jacket surrounding the pipe was then fed with a cooling fluid, cooling the pipe wall down to minus 50C, and freezing the slug of liquid to form a plug. There was a paper about this at the Offshore Europe conference in 1991.
The system was trialed and shown to be capable of plugging high pressure pipelines sufficiently securely to allow the pipe to be cut and welded within a habitat. Moer work has since been done by BJ Services to permit the technology to be used in deeper water, with a submerged refrigerator unit. There is a paper about this on their website.
In this case the jacket could be mounted immediately above the BOP, and be fed from a submerged refrigerator unit. It would initially be used to cool the crude oil flowing from the BOP into the riser, which would thicken, so slowing the flow. Having slowed the flow it might be possible to introduce water and freezed it to provide an ice-plug. This would act as a temporary seal whilst the relief well is drilled.
The one question that arises is whether BJ Services ever built their submerged refrigeration unit, or whether it was a concept in development.
Any thoughts?
Freezing is very good idea
Paris tunnel was made under the Seine river in freezing the river soil
But I suppose that with very speed flow of oil, freezing device can’t be enough powerful for freezing the oil more speedily than the flow
Several things need to be determined,
1) Did the pipe rams close on the drill pipe?
2) If the pipe rams are closed is there a way on this particular BOP stack for an ROV to determine if there is pressure below them, and above them?
3) If there is a pressure above them, does it equal the seabed pressure at this depth? (would indicate that the rams are closed and sealing)
4) If this is the case that the rams are closed and sealing it would indicate that the drill pipe is fractured somewhere between the end that is protruding from the broken riser, and the upper or sealing set of pipe rams.
5) looking at the picture of the collapsed and kinked riser it could be pretty well ascertained that, that is where the drill pipe is broken, drill pipe is brittle and will not withstand a bend at that sharp an angle without breaking, especially if it’s close to a tool joint.
The most likely cause of the shear rams failing to function is that there is a tool joint located at them, even the best shear rams in the world won’t cut a drill pipe tool joint there is simply to much high alloy steel there. This would coincide with the location of the leak at the bent riser, just an eyeball estimate but I am seeing 30ft plus or minus between the shear rams and the kinked area just above the LMRP.
And looking at the picture again it looks to me that the riser collapsed before it actually dropped with the rig and kinked over, this would be consistent with the riser being purged with oil to the surface, the differential pressure at the well head with the riser full of oil would have been around 600psi as mentioned above, this far exceeds a marine risers collapse pressure.
If the crew were circulating the riser and wellhead to seawater, the drill pipe most likely is open ended with out a safety valve at the end. and the drill string was attached to the kelly at the top, the kelly would have been around 15 or 20 ft off the rig floor. When the rig caught fire it would not have taken very long for the drilling line to have burned through at the draw works and the blocks and kelly would have dropped driving the drill pipe downwards. This would have forced any tool joint in the collapsed riser to act as a broach and either punched a hole or forced the riser wall to crack.
Using this as a scenario plugging the exposed end of the drill pipe would be futile, as it would just force more oil through the crack at the riser kink.
An alternative would be to use shaped charges to cut the riser at the LMRP where it is still concentric and then cutting the drill pipe allowing it to drop until a tool joint hit the pipe rams and or it dropped to the bottom of the well, this done the shear rams could cut the pipe if it only dropped to a tool joint and allow it shoot out of the BOPs using well pressure or if it drops allowing the blind rams to close.
Even though shear rams lack an elastomer seal they will slow down a considerable amount of flow, if the piece of pipe left in the BOPs is in the way of the blind rams, an ROV could attach a cable sling to it prior to it being cut, so it could be pulled out of the stack from the surface, and the blinds operated then.
Keeping in mind this whole operation would depend on the rams still having enough hydraulic pressure to be able to function.
A couple of thoughts:
1) I’ve read that the riser climbs 1500 feet from the BOP before it folds back to the sea floor and that the primary leak is "after" the bend. If the riser could be cut off below the bend, perhaps using a water jet or shaped charges, then wouldn’t we be looking at a fairly straight pipe with it’s end roughly 3500 feet underwater, with water pressure approximately 2/3 of the pressure at the BOP? Would that somewhat simplify the task of either "capping:" the riser or make it easier to pump the oil to the surface after being captured in a "bell"?
2) I’ve also read that the drill tube is still within the riser. If the riser was cut and lifted away, maybe 100 feet above the sea floor, would the drill tube come with it?
Another idea to be thrown into the think tank. A mill on the end of a joint of heavy weight drill pipe. A sliding collar mounted above the tool joint to which a structure could be mounted to saddle the riser, stabilizing the mill until penetration into the riser is accomplished. The penetration could be at a point for the mill to enter the BOP. The mill could be configured to accomplish various tasks, such as mill off the riser, drill pipe, dislodge objects in the BOP and could possibly accommodate the closing of the annular or pipe rams providing a conduit to the surface.
Reno,
Capping the riser would be ineffectual, the wellhead pressure of an 18,000 ft well is about 3,000psi, the riser burst pressure is 500psi for new riser, this riser is damaged and leaking, so it’s burst pressure could easily be below 100psi.
The riser drops to the seabed for a thousand feet or so from the well, then rises up again to 1500ft above the seabed for a couple of thousand feet then drops back to the seabed, this hump is caused by a couple of things, the buoyancy of the oil in the riser, and there are in all likelihood flotation collars attached to the riser at that point, another is friction of the seabed at the free end, eg. the riser is setting there kind of like an inch worm stuck at both ends unable to move. The flotation collars are part of the riser package, the placement and number of them are dependent on the riser dynamics and are determined by computer model, riser dynamics are far to complicated to explain here, entire books are dedicated to the science.
Cutting the riser loose from the BOPs is going to have to be done in small sections, it is in a severe mechanical bind right now, and if cut off at the BOPs could well end up being a apocalyptic disaster in that it could whip loose and knock the BOP stack right off the wellhead, then it would be an unrestricted flow of whatever rate this well will produce at. The average well of this depth in the GOM is between 30,000 and 40,000 bbl/day, some as high as 70,000.
Ridgerunner,
There is no way to stabilize 5,000 feet of free hanging drill pipe in water the currents and wave motion would have it whipping around like a lodge pole pine in tornado.
Might be reallty stupid but is there a way to put SOME TYPE of collar around the leaking pipe head and then divert oil through attached pipes instead of trying to stop flow? Maybe flexible pipe. At one point there was a company called Flexpipe and they would lay their pipe on the gulf floor to strictly transport oil. Wonder if could be used to divert?
The cylinder proposed by How About2010 sounds feasible. A wall thickness of 3/16” sounds thin to me, but that is an engineering problem that could be easily solved. Let’s not get hung up on that. Rather than just letting the oil/water/gas mix rise to the surface, with the real danger of fire, I suggest piping it to the surface. A pipe (flexible?) attached to the top of the cylinder would carry the “product” to a subsurface connection point, then a riser would carry it to the surface for transfer to a collection barge or ship. This way nothing would be released to the environment. The connection point would have to be securely anchored to the seafloor, probably by piles, because it would have to withstand currents and the surface ship tugging on it. The riser could be solid pipe, or flexible if it is available. A dynamically positioned (DP) surface collection ship would minimize the loads imparted to the riser and the subsea collection point. Pumps could be included in the subsea collection point if buoyancy is insufficient to lift the product to the surface.
The matter of deploying anything to the bottom must be considered, because, as it has been pointed out, positioning a deployment vessel over the blowout location is prohibitively dangerous. I suggest using three DP cable-handling vessels to deploy it. Think of a large three-legged Y, with the cylinder at the bottom of the Y, and the surface DP vessels at the tops of the Y. The vessels could be a safe distance away from the release point. The cable-handlers would slowly pay out cable to lower the cylinder to the bottom. Three vessels would be required to control the cylinder’s position in the lateral plane. Several ROVs could follow the cylinder down and issue instructions to the cable-handlers so that it could be placed exactly over the leaks. Care and a soft touch by the cable-handlers would be imperative.
It might be advisable to construct several cylinders and try out the procedure on the pipe leaks before putting one over the BOP. This also would allow the team to practice before attempting to put a cylinder over the BOP. All the cylinders could be piped to the collection point.
The biggest drawback to this or any other scheme is the time required to engineer and build the system. It could take weeks to do, even on a crash schedule. And it MUST be engineered. People complain about the time required, but the last thing anyone would want to do is damage the BOP more and increase the flow of oil to the ocean. In the interim, containment booms around the rising plume may be the best solution.
If this, or some other capture and recover scheme can be worked out, then we can wait for the relief well to be drilled, which is the best and final solution. All the talk of intervening with the BOP becomes moot if the product can be recovered while waiting for the relief well to be drilled.
How About has had the basic framework for the temporary pumping solution figured out for about a day now. Details will be addressed along the way. This is not the same thing as long range planning for a drill several years away. The ejection of the oil and gases at the top of the collection pipe can be taken care of by a deflector. Anchor handling ships will be able to secure the pipe until a better method is developed.
We need to keep working towards permanent solutions aimed at capping the well. In the meantime, however, the authorities need to begin pumping oil/water without further delay. Remember, pumping does not have to capture all the oil, just most of it.
Rigdgerunner,
Thanks for the response. After I wrote my first post, I saw some diagrams of the riser deformation, and realized that my initial assumption was wrong.
Here’s another idea.
Instead of a "funnel", high pressure pump and 5000 feet of high pressure pipe, how about the functional equivalent of a hot air balloon?
Make some cylindrical bladders, 9 feet by 20 feet out of a strong, flexible material like kevlar. At one end, a simple two foot diameter spring-loaded butterfly valve, and at the other, a hose fitting. A bladder that size would hold about 1300 cubic feet of oil, or about 9500 gallons. Package these bags in such a way that they form a relatively compact package that can be slid down a cable to the well site and be handled by an ROV.
Build a 20-ton rig that is tall enough to straddle the existing BOP and riser, that includes a large funnel and a mechanism to attach, swing into place, and release the bladder’s "docking ring". This mechanism should be built to withstand 8 to 9 tons of upward force as I calculate the buoyancy of 1300 cu ft of crude to be a positive 14,000 lbs. It could even be designed with several radial arms, that allow the bags to be re-loaded by the ROV as they are used.
Lower the rig over the BOP, then use the ROV to set a bag into the mechanism, which swings it over the end of the funnel, and in doing so, automatically opens the butterfly valve.
If the leak is about 140 gpm, or 18.5 cu ft/min, it will take about 70 minutes to fill. When full, trigger a bag release. As the bag floats away, the butterfly valve snaps shut.
The bag floats to the surface, where it is pumped out via the hose fitting, then repacked for transit to the bottom.
Yeah, some oil is spilled between each bag, but it would be minimal compared to what’s happening now.
Assuming the leak doesn’t get much worse through erosion in the 2-3 months it might take to drill an intersecting well, this would mean about 21 bags/day. The rig would have to be reliable.
Is this too crazy to work?
From BP’s website:
"BP has called on expertise from other companies including Exxon, Shell, Chevron and Anadarko to help it activate the blow out preventer, and to offer technical support on other aspects of the response. "
I have been in high level meetings with BP before and they are some of the most professional people you will ever work with. They will spend DAYS discussing scenarios to make sure that nothing falls through the cracks. I’ve also worked with most of the companies listed, and only have good things to say about their engineering staff. Mistakes can and will happen, but not through purposeful negligence.
I applaud the desire of folks to help out with ideas, but most of the people on here have no appreciation for the scale of this problem. This is not some water hose in your back yard with a leak. By the time any of these ideas could be implemented, the drilling rig moving on site will already be done with it’s intercept. The BOP is still the best hope of stopping or at least abating the flow of oil right now.
Thanks Horizon37 for helping to put these concepts into perspective. One question though, you mentioned the pictures show the riser on the sea floor, where are these pictures?
Inaction and days spent spitballing are why unconventional methods need to be attempted now. If the people responsible for this mess had the minimal foresight to figure out how to mitigat a deepwater spill before they started drilling at this depth we wouldn’t be having this discussion.
Preparation? A thorougly unprepared high school student who hasn’t done any of his homework when he shows up for school in the morning is more prepared than these people.
Is it any ideas about temperature around and inside the valve???
at 5000ft down?
VF
Horizon 37,
So let me get this straight, since I’m not in the deep ocean drilling business, just a chemical engineer. You’ve got a BOP on the ocean floor/wellhead that acts as an emergency shutoff device in the instance of a large pressure increase. What sort of shut off valves/secondary valves does the BOP have to cut the flow off? I’m assuming there is some sort of tube inside the BOP that the drilling tool is lowered through to get to the ground. I’m guessing that the shear rams act to slice this tube and whatever is inside to cut off the flow out of the wellhead. Now you said above, there is a possibility that some sort of tool was at the height of the BOP when accident took place. The drilling tool is composed of a high strength alloy which didn’t shear due to its high strength. Is this all correct?
Next, it seems to be that it would be no good to seal the end of the riser pipe where ever it lays on the ocean floor because due to the kink, the pressure will find a new exit, probably in the place where the riser has been fatigued due to the kink. I figure, if the wellhead had enough pressure, it would have a tendency to want to flow in a straight line up the riser tube, than flow through the kink above the BOP. Obviously the pressure out of the BOP is low enough that the riser tube will not stand up, and instead topples over under its own weight or due to MOI. With such a long riser tube, it would seem impossible to cover the entire area with a funnel because it is such a massive area, thousands of feet in length. So it seems the only alternative is to try to find a way get the oil flow concentrated in one single small area which would be easier to contain.
It would seem to me that making a calculated cut in the riser tube, somewhere before the second kink would have a few effects. Looking at it from a fluid mechanics perspective, it would seem that if you made the cut in the right place, you could get the riser tube to stand up without toppling over from any force that is applied to the riser, a low MOI. Sort of like trying to stand a pencil up on its eraser, it takes very little force to topple it over. Similar situation with the riser tube, there isn’t a high enough flow rate to keep the pipe standing straight.
similar to: http://www.youtube.com/watch?v=anoQ2Gd9JBg&feature=related
Only problem is whiplash, and that the riser could whip back once the cut is made. If proper mechanical analysis is done, you should be able to make the cut without any whiplash though. The cut should be made a far enough distance from the BOP it takes a reasonable amount of time for the riser to lift up and straighten. From fluid mechanics, you know the force that is placed on the kink from the flow inside the pipe, so you know how much force is actually going to be pushing the riser to straighten it. I’m no mechanical engineer, but cutting too close to the kink and you’ll have it whip up, cut too far and it won’t lift itself up.
Another option is making a cut closer to the BOP, below the first kink, keyword below. This would probably work because coming out of the BOP, the fluid has a velocity that is pretty much pointing normal to the ocean floor. If the cut is made at that point, the riser won’t have a tendency to whiplash in either direction since it will continue to point directly upward due to the flow direction. Now when you make that cut, you’ve got to pull the top half of the riser out of the way, just enough so it doesn’t land on the BOP below. I guess this could be done by first attaching a cable to the riser above your cutting location and then when the cut is made, the cable will be holding that section of the riser and then can be pulled in a little bit to move the riser out of the way. With the cut made, it would be a lot easier to funnel the oil out of a single relatively small location directly around the BOP, instead of such a vast area.
By the way, did anyone see this,
http://www.google.com/patents?hl=en&lr=&vid=USPAT5188177...
Looks interesting. Although I don’t know how well it would apply down there near the BOP.
concerned citizen2010 – "Preparation? A thoroughly unprepared high school student who hasn’t done any of his homework when he shows up for school in the morning is more prepared than these people. "
I’m going to try and keep my post respectful because I don’t know you. How you can honestly read the posts of the people on here that actually know what they’re talking about and come away with the conclusion that no preparation was done? You are being extremely disingenuous if you can say that with a straight face. Why do you think they spend millions of dollars on the equipment sitting on the sea floor to prevent these exact types of accidents? It’s estimated that they are spending roughly 6 MILLION dollars/day with their current efforts. The most brain dead 10 year old on the planet could tell you that it was better to spend a million today than half a BILLION tomorrow for the clean up. And that’s the current spend rate, that will spiral ever upward as this all continues.
The best engineers, geologists, and scientists at these companies are working on a solution. I’m pretty sure if you were a PhD in Ocean Engineering, they would take your phone call. Just don’t be offended that they’re not taking yours.
Because the crude oil has particles of nickel, vanadium and other metals,so outside the pipe(or valve) the magnetic field from permanent (or electro)magnet can be use to create inside the pipe a plug.
At least -decreased the ID of the pipe.
I’m a mechanical engineering consultant working for one of the major oil companies with 35 years experience in the oil industry.
What is the likelihood that there’s something inside the BOP preventing the rams from closing? What might this be? Produced sand, cement rubble. Could the crimp in the riser be part of the problem in that it’s retaining debris inside the BOP?
Has it been ascertained that there’s adequate hydraulic pressure left in the accumulators to close the rams?
Was the drill pipe in the casing when they were displacing the drilling mud with seawater?
Is it possible that the kink in the riser is preventing the blowout flow from clearing any obstructions in the BOP?
Is it possible to view the bore of the BOP in-situ by radiographic examination to determine if any obstruction is present?
Is it possible to move the BOP rams at all? Even fraction of an inch?
If there’s an obstruction inside the BOP that might be cleared by the blowout flow, then a possible approach is to disconnect or cut off the riser at the top of the BOP, let the increased flow clear the BOP, and then close the BOP. However, we should first do everything possible to ascertain what could be obstructing the BOP (if anything) and that the BOP is capable of moving the rams upon removal of said obstruction.
Horizon 37
The cause of the 1979 Ixtoc BOP stack failure that happened in the GOM was found to be exactly what you mentioned regarding the tool joint location relative to the shear cutters. The cutters just could not shear through the extra material at the tool joint. I believe that the Horizon BOP stack has much stronger cutters than the Ixtoc rig, but don’t rule out that the 9-5/8" casing string is also in the path of the cutters. If the cement job let loose, it could have blown out the casing string high enough to block the shear cutters. Now it has to cut through heavy wall casing AND drill pipe, something it was never designed to perform.
I have witnessed quite a few BOP stack tests in my career and these always included testing of the blind/shear rams. This "testing" was only a check that the rams stroked and they sealed off pressure from below. I have NEVER witnessed a drill pipe shear test where a section of pipe was deliberately sheared off. I once asked why not ? The answer made sense then, but now in light of what has happened, it appears as an irresponsible answer. Basically, if you did this as a routine test, the cutter blades would wear out and loose their ability to shear and also seal. The cutters were supposedly tested at the factory (in this case in 2000 or 2001) before they shipped to the rig, and this was good enough. Replacing the cutters would be a lengthy (and expensive) job. It’s kind of like testing an old bullet, the only way to fully test it is to fire it off and then rebuild it over again.
I have also never seen a routine test of the emergency blind/shear hot stab receptical that is located on the ROV panel. This plumbing circuit relies on a shuttle valve that has to "shift" and divert the hydraulic fluid to the ram piston. Shuttle valves are notorious for sticking and this one may be a biased version, which is even worse for dependability. Something better than this needs to be designed, in addition to the accoustical system.
The Ixtoc blowout lasted for 295 days. Let’s all pray that BP and all of it’s technical support can get this thing snuffed out much sooner…..
Thanks Hountsi for support of the pipeline freezing and reference to the freezing operation used in tunnel work in Paris.
Your comment about the problem of freezing due to flow through the riser is valid, but this may not be an impossible obstacle because my estimate is that the flow velocity through the riser is somewhere in the region 3-5 metres per minute at the moment, which is quite slow. This rate would gradually decrease as the crude is cooled and become more like tar.
Just to reiterate the idea, with additional information from recent blogs.
A cooling jacket could be put mounted around the vertical section of riser coming up from the BOP. Apparently this section could be as much as 1000 ft high, so this would put the cooling jacket around 4000 ft below seawater.
The cooling jacket would be fed either from a refrigeration unit on the surface, or by a submerged unit if this were available. The aim would be to reduce the pipewall temp to minus 50 deg C. (the sea temp will help here because its quite cold in these deepwater, possibly 0 deg C)
The company BJ Services is know to have been developing such a submerged unit and their marketing manager, Dan Daulton, sits on an influencial deepwater committe that advises the US Secretary of Energy.
The cooling jacket would chill the flow of crude oil in the riser, making it more viscous and thus reducing flow rate towards the laking points.
Water could then be injected into the riser below the cooling jacket, and this would freeze to ice particles as it passed by the jacket, possibly initiating some hydrate formation, which would further restrict the flowrate.
With any luck this would eventually allow an ice-plug to form at the freezer jacket, to block the riser and halt the leak.
Of course, this solution should run in parallel with all others, including attempts to close the BOP, construction of a funnel to collect leaks, and drilling of a relief well.
But investigation of the freeezing option would not impair any of these other soltions.
One point to remember, is that offshore operators devote enormous energy to maintaing flow from wells (flow assurance) by trying to deal with wax and hydrate formation. What we would be seeking to do is to take advantage of these issues.
MarineEngineer2010
Your idea is very feasible, but there is no existing location to inject the water below the cooling jacket and effect a good seal against the riser pipe. One method that comes to mind is called a Hot Tap that is used to repair pipelines that are still under pressure. We are looking at an OD of 21", so I am not sure a Hot Tap exists for this size. Also, has anyone thought of using liquid nitrogen as the source to freeze the pipe ? Perhaps this could be injected into the Hot Tap and then the refrigeration unit would not be required.
Any thoughts ?
HowAbout,
Your idea is good … for shallow water, the weights and forces involved in a 5,000 column in open ocean water, are beyond most folks comprehension.
Let me try this again. I am sure you grasp this concept. what you are proposing is hanging a 12ft diameter canvas tube from the surface down to 5,000 ft, the materials involved here will not handle their own weight at that length. Wet canvas weighs about 2lbs per square foot, a 12ft cylinder is roughly 38ft in circumference, that = 76lbs multiply that by 5,000ft gives you 380,000 lbs!! your canvas would most likely tear apart a few hundred feet above the well head, also the current dynamics would tear it to pieces. currents in that area of the Gulf are notorious, where several different currents are flowing at right angles or opposite directions at different depths. It is comparable with trying to hold back a river with a bed sheet.
haveacorona
Here is the photo of the riser where it’s kinked over at the LMRP, also is a schematic showing the general layout on the seabed.
http://www.flickr.com/photos/uscgd8/4563035602/in/photostream/
Here is a photo of a BOP stack similar to the one we are dealing with, just so some folks can grasp the size of the equipment on the bottom.
oilstatesintl.com/_filelib/ImageGallery/Products_Services…
subsea1,
The MMS rules for BOP testing for the last 20years require that he blind rams be tested, this is done with a BOP test plug, it’s a solid chunk of tool steel with a couple of ‘o’-rings on the outside, it’s the same OD as the casing hanger pocket in the wellhead, this plug has tool joints top & bottom, normally a couple of stands of heavyweight drill pipe are attached to the bottom, and the top joint is made up loose with very little torque, this plug is run in and seated, then the running string is backed off and pulled above the BOPs the blinds closed and then tested to the required pressure through the choke or kill lines, usually both so they are tested at the same time. The shear rams are usually just stroked at this time as well, there are electronic surface indicators to show that the rams closed and opened, some are even more high tech and show the actual ram positions on a graphic display. since all reports I have seen are that this is a 20,000psi stack ,the tests pressures would be 15,500psi for 15 minutes each, this is an all day affair, as there are at least 30 tests, which includes the choke manifold and all of the subsea choke and kill line valves. In my 25 years offshore I have witnessed many hundreds of them.
From the info I have been able to gather, the 9-5/8 was already done several weeks before this happened, they had run and cemented a 7" liner the day before the incident, and the general consensus they had run a retrievable bridge plug into it, and and were preparing the wellhead and riser for running a cap, and were circulating the riser to seawater, as I previously stated in all likelihood the bridge plug did not set properly and the well pressure increasing because of the lose of 5,000ft of drilling mud hydrostatic being replaced by seawater forced it out of the liner and into the 9-5/8, or the liner hanger packer failed, either case would have the same results. The well came in and flowed oil to the surface, and if they were tripping the pipe or some other operation where the kelly was disconnected from the pipe even if the pipe rams and annulars had closed there would have been unrestricted flow to the surface through the open ended drill pipe.
concerned,
I can understand your frustration, but the scale and scope of this problem, if approached with knee jerk reactions will just compound the disaster.
Subsea1engineer
Good point about injection of the seawater. My understanding is that Subsea 7 have developed a grouting system for hot taps, but I’m not sure of the maximum pipe size that it can handle.
Lat September Statoil completed a couple of hot tap operations in large diameter subsea pipelines by remote control in deepwater for the Ormen Lange field. However, this operation was to pre-installed tees, and (simply!) involved a pipe cutting operation. The machine was developed by ClearWell (I think).
However, it might be possible to custom build some sort of bolted clamp to form a tee, and then use the Statoil pipecutting machine to complete the hot tap.
Thanks for your feedback.
Subsea1engineer
Your point about liquid nitrogen is also valid. Liquid nitrogen is routinely used for pipefreezing in onshore plants. However, my understanding was that when Shell Expro were carrying out R&D
on pipefreezing in the late 1980s they had ruled out pumping liquid nitrogen to the seabed because of the lack of suitable insulated hoses.
This may not be the case today, because Nexans are working on vacuum insulated hoses, that can be submerged, for possible use in the transfer of LNG at sea. However, its unlikely that these are difficult to manufacture, and its unlikley they would be available in time.
The solution proposed by Shell Expro in 1990/1 was to ship bulk liquid nitrogen to a support ship, and use this to cool a secondary fluid to be pumped to the seabed. But this project was only looking at about 150ft water depths.
BJ Services have done some more work on this subject, and their Technical Manager Dan Daulton is one of a panel advising the US Energy Secretary, so he should be able to provide some input.
As far as the freezing idea that would not be likely to work. If the well is flowing at 5,000bpd (it’s probably more), that is roughly 913lbs/min of oil. In order to freeze this 200plus degree oil it would take a refrigeration system that would probably be the same size or larger than the BOP stack.
This oil will most likely not freeze to a state of being a viable restriction until it is chilled well below the freezing point of water. this would require a chiller on the order of a million BTU or more, about the size of the refrigeration plant, for an ice skating rink, that would somehow have to be converted to work in 5,000ft of seawater. Liquid nitrogen is out, it will not vaporize at 2,000psi without heat input, keeping in mind that the seawater temp at 5,000ft is around 48degF defeating the chilling operation.
My estimates on the cooling rate were 1410 kW and I’m sure that is still too low. That would be a mighty impressive operation for the middle of the ocean. Figuring a flow of 470kg/min, and a heat capacity of about 2 kJ/kg K, and dropping the temperature about 90 degrees C and hoping it freezes to some extent at 0C, you have like 86400 kJ/min which is 1410 kW.
Horizon37
I am very familiar with the BOP test tools. Without revealing which company(s) I have worked for, I have actually designed several types of these tools and they are still in use. I also understand the MMS testing regulations. But here’s the point I was trying to make. Just because the rams can stroke and the gates seal from below doesn’t prove that the cutter blades are still capable of doing one of its primary functions and that is can they still cut the same way as they were designed for when brand new ? So during the hundreds of times that you have witnessed these tests, was a shear test made to validate if the drill pipe could be completely severed in two ? I am not limiting this to being done subsea, but also when the stack is sometimes locked on to the test stump at the surface. Unless the blades are hardfaced with a tungten carbide material that resists many years of exposure to corrosion, I would seriously question the condition and capability of the cutting edges. Also, was the emergency hot stab receptical ever routinely checked as part of the testing regimen ?
Thanks for views from Horizon 37 and Hoodyz R about problems with pipefreezing. No doubt that it would require an enormous refrigeration capacity, and chilling fluids would most probably have to be supplied from the surface.
Two thoughts on this:
(1) Cooling the oil will have an immediate effect of increasing viscosity and reducing flow, albeit to a small extent. This, however, will introduce a virtuous circle, with reduced flow, so refrigeration needs are reduced, etc, etc. The surrounding sea could also have a cooling effect, which would be subject to the same virtuous circle.
I’m no expert in the science, but I do know that many subsea production systems located in cold water suffer from problems due to the viscous nature of oil, and wax and hydrate formation, In fact, it is usual to inject chemicals to maintain flow. There have been incidents where sections of subsea pipes have needed to be cut out because they have been completely blocked with hydrate.wax.
(2) There is an enormous, and growing, expertise within the marine industry and petroleum industry of refrigeration and cryogenics, due to the transport, offloading, and production of LPG, LNG and other liquid gases of various types.
This expertise includes the development of large bore flexible hoses that can convey cryogenic liquids. These hoses are being developed most specifically for transfer of LNG from the new generation of floating LNG production vessels, being designed by Shell, FlexLNG and many other companies.
Ok, on land they use explosives to kill a burning oilwell. What about bringing a large conventional explosion or a small nuclear explosion right on top of the drillhole? I mean, when thinking allong this line of action, could there be any positive result? Can an explosion be directed, guided into the seabed, so that it will destroy the opening to the deep oilreserve now flowing out?
Dril a 50 to 250 meter deep hole say 20 upto maybe a 150 meters away from the well and put a large explosive device in there. Then detonate it. It might shift the local seabed over the drillhole.
Anything like this probably can be done in quite short time. You can even try it several times, just start to drill holes arround the well and start putting explosive devices into it. Try them one after the other. When the first one does not close of the well then try the second one and so on, till one of the explosions shifts the seafloor at sufficient dept over the drillhole.
When you apply the exposion deep enough you will not get debry, but just shifting of large segments of seafloor.
Pressure of the rock might very well close the drillhole. Damaging the well itself is very unlikely there it is many thousands of feet under the seafloor.
As far as pipe freezing, can a refrigerant be pumped a mile down? Also, in the amount of time it would take to get the oil down to freezing temps, wouldn’t you suddenly be creating, essentially, a ball of oil as a matter of decreased viscosity?
As for using explosives, all I can see happening is expanding the size of the gusher from that of the pipe to perhaps the size of a football field. Or worse, it might collapse the roof of the well and suddenly ALL of the oil comes pouring out.
I haven’t seen Halliburton’s name come up in this lively debate, yet. They’d poured cement twenty hours prior to the incident. Here’s what they had to say:
http://www.halliburton.com/public/news/pubsdata/press_release/20...
Disingenous….hmm….. an interesting choice of words. It actually means the opposite of calling it like you see it.
Anyway, back to the pumping idea. I am interested to know the special risks this type of approach carries with it that are different from or greater than the various plans to actually stop the leak. To reiterate, the basic concept here is to engineer a stop gap measure to collect spillage without coming into contact with any of the pipes or other apparatus at the wellhead.
Also, if there is a specific aspect of How About’s or other pumping proposals that won’t work (ie. long flexible collection hose/membrane is too unsteady) please identify and indicate possible fixes. Thank you.
Hydrallic pressure to the rams seem probably insufficient; it may of reduced due to line failure below the required psi when the inital event occurred or the reserve may be inherently too low. Reversing the rams is too dangerous and risks a tangle. Id repressure the hydrallics first with a seal swelling compound to increase the pressure rating of the rams. The rams mating surface may not be the flat cutting type but the pipe sealing type, the elastomer coating may not seal that properly if their was a irregular pipe angle involve
Im not familiar with the access points for the hydrallics on this BOP . A navy sub standing off, using the rov as technican, with its substancial hydrallic system(ie missile firing pressure capabilities)a backstopp flow valve and line could provide that increased pressure slowly and directly into unit bypassing the standard inflow system of the hotstab if there was sufficient working room to access boreinlet.
1)Going on the assumption that the only thing preventing the BOP from closing is the drill pipe/connections jammed inside it. (may possibly be verified by gettin the ROV to pump the BOP open and closed to see if it moves even a fraction of an inch).
2)Going on the assumption that the only thing preventing the jam inside the BOP from moving is the kink in the riser. (makes sense to me).
A) Get the ROV to back off the BOP gate so the jam inside is free to move when the kink is eliminated.
B) Install a shaped charge just below the 1st kink in the riser so when detonated, the remaining riser sticking out will be straight.
C) Install a 2nd shaped charge between the first bend and the second bend in the riser. Charge should be placed so when detonated, the long section of pipe will be just far enough away to clear the BOP when it falls.
D) Detonate the 2nd charge first and 1/2 second later, detonate the 1st charge closest to the BOP. That should negate and "whiping" of the riser close to the BOP. If necessry, enough air bags could be added to the short section of loose pipe before detonation to prevent it from falling on the BOP.
Once that is accomplished, the blockage in the BOP should either fall down inside or be blown out by back pressure, and clear of the BOP gate. Get the ROV to pump the gate closed.
The only problem with this scenario I see, is if the BOP still cant be closed, it will make the leak worse by freeing the restriction caused by the kink in the riser.
1 adam twelve expresses doubt that refrigerant can be pumped a mile down, and fears that the oil would form a ball. Others have expressed views that liquid nitrogen would be inappropriate for pipefreezing. So here are more thoughts.
Many traditional merchant ships are fitted with large refrigerated cargo holds. These vessels would have central refrigeration plant, possibly using brine as a circulating medium to cool the holds. So would it be possible to position an old refrigerated cargo ship above the well site, and pump brine refrigerant from its central plant down through flexible line to a cooling jacket on the riser?
Insulation of the flexible supply and return lines would obviously be a major problem, as would ice formation on the flexible line. But I sure that engineers could provide accurate estimates of these effects.
Answer 2. The cooling would act on the outer wall of the riser, and so it is likely that crude oil will be cooled in an annular space around the wall. So its unlikely that the oil would form a ball. My guess is that the flow pattern past the cooling jacket would resemble that through a slowly contracting nozzle.
"BP executive: Company will deploy containment system for spill within week"
Link: http://www.short-link.de/17576
The ROV hotstab utility for closing the ram is designed for when the usual circuit fails not for an obstruction. Novel adaption of the male fitting to increase psi is probably a requirement for this situation if a more direct accesspoint is unattainable. An increase in psi over that provided by conventional rov hotstab is probably required too.
The BOP description on GE’s web site is an impressive thing. Aside from being big to deal with the forces involved, it appears fairly complicared with lots of redundant pieces. (It also has software, which is a little scarry.) Still, it seems the best tool available to control the flow until another hole can be drilled.
It seems certain that the shear rams didn’t close. Do we have any evidence to say why not? Something in the throat, or lack of hydraulic pressure, or maybe something else?
Perhaps the BOP has sensors which were relayed up to the platform as things were happening. Maybe some of this information was relayed to shore?
Perhaps there is a way to reconnect to the electronics to check it’s state?
Baring this, Xraying seems the best way to figure out the shear valve state. (If the Xrays don’t damage the electronics.) Is Xraying at 5000 feet something that’s normally done in subsea work or do we need to see if some odd corner in the gov’t happens to have the capability?
Also,
If you could put a canvas chimney over the leak, what would happen when a gas bubble entered it at the bottom. It seems that going from 2800 to 14psi would expand the bubble 200x in volume. I’m not sure if this is a great pumping mechanism, or a problem. I guess the BP brains have looked at this with a simulator.
A couple of thoughts I’ve had:
1. Putting a couple of things already mentioned here together: Use the ‘hot tap’ idea to inject dispersant chemical directly into the flow. Admittedly this would only affect the flow in the riser and not in coming through the drill pipe however perhaps a good start.
I’m not sure if the tethers for the ROVs’ can carry fluid or not perhaps these are a potential carrier. Maybe they can be modified to flow fluid…
2. The riser / dp and BOP are currently in a stable balance, something that, when you think about the flows and differential pressures we’re talking about, must be delicate. Any change to this system like cutting, moving, plugging elements will have follow on effects.
3. I think also that we have to take advantage of the luck experienced being left with a standing BOP stack. If this BOP is still operable it is by far the best bet to seal the well.
Subsea,
I am not being critical, just didn’t know if you have been out of the game for a while 😉 my description was mainly for others benefit.
I have worked with pretty much every major oil company and drilling company, and even the cheap shots, will totally redress a stack prior to engaging a deep water well, the potential for a screw up is just too expensive. The base day rate for this rig was $502,000.00 this doesn’t include fuel, and other supplies & materiel, probably closer to a $million per day inclusive, it takes roughly a week to round trip a BOP stack at 5,000ft, it costs about $180,000.00 to redress a 20,000psi BOP stack if no major components have to be replaced, in my experience with Transocean, (SEDCO, FOREX, Transocean) they redress their stacks before each well, this would include removal and inspection of all of the rams and all new elastomers for them and other components in contact with the well bore, especially if the previous well used oil based mud, was a sour gas well, or if they had to kill a kick. As you know there will be a BOP log book at Transoceans HQ, the only other equipment as thoroughly documented on the rig would be the power plants, drilling line and top drive. As to an actual test of the shears, I have seen them done several times during onshore stack overhauls, seen them used 3 times live on the rig, I have never witnessed a failure. One thing I have not heard mentioned is did they try the variable rams to see if they would staunch the flow?
On freezing, the major problem with freezing oil in pipe is that the oil self insulates, as it starts to freeze at the pipe wall, it builds up a layer of frozen oil, this inhibits the heat transfer from the unfrozen oil to the pipe wall, this is further exasperated by the velocity of the oil in the tube, as the frozen layer builds up it increases the oil velocity (the hole for oil flow gets smaller) and the velocity increases as a square of the oil volume vs decrease of the ID of the restriction, this friction will result in the frozen oil at the wall being stripped off and pushed downstream. Also oil is a very crappy heat transfer agent for chilling. Could it be done? probably, but by the time the necessary equipment was built, shipped out and installed, the relief well would be completed.
PeetD,
Explosives are used to put out well fires as a last resort these days, the lessons learned in Kuwait were invaluable, they had the opportunity to test many different methods, and the most effective and safe was developed by a friend of mine, it snuffs the fire with high volumes of nitrogen or CO2 and cooling water. The explosives or nitrogen method only put the fire out, then the crew can approach the well and cut off the junk, and put on a control head to stop the flow.
For the refrigerant idea, it seems you’d have to look at the convective heat transfer coefficient on 2 surfaces to determine how much area you’re going to need to cover on the outside of the riser. This situation is almost like cooling a tube and shell heat exchanger from the outside. You’re putting a cooling jacket around the shell, and trying to cool both the shell side fluid and tube side fluid. I haven’t done any real calculations, but that seems like you’re going to need quite a big jacket in order to try and cool to the center of the drill pipe. I don’t think the jacket could go all in one piece because of the connections in the riser. So you’d have to the jacket in sections, but first cut the choke and kill lines out of the way so you could make contact with the riser. I have no experience in trying to connect up a cooling jacket with refrigeration lines under the ocean, and I don’t think many do so I’m not sure that it would be a quick solution. Plus you’ve got to deal with the fluid moving ~8 ft/min. So assuming that the cooling jacket covers like 40ft on each section, you’ve got like 5 minutes inside the cooling jacket to remove your heat in each section. All this needs to be looked at further for the refrigeration idea. Someone should calculate the surface area and length that the jacket will need to cover in order to see if its feasible.
Also, since I don’t have much experience, I don’t know how feasible this is, but along with the cooling idea, what if we were able to tap the line near the BOP and introduce some sort of coagulant almost like a blood clot in the line. I don’t know exactly what we’d use. I figure if you already are going to introduce water into the flow to freeze it, you could add something else that would change the viscosity of the fluid, or even react with the crude oil to create some sort of blockage, like an endothermic reaction or something to help get things cooled down for freezing. Just throwing some ideas out.
Very good ideas. Lets get something deployed. The collector and umbrella rigs would work and a HDPE pipe to the surface would be 10.5 hrs to fabricate on site. We are working with equal pressures as this is an open system relying on the differential of buoyancy between oil and water. Seems like an easier idea to collect the leak at the site or at least most of it then waiting for it to rise a mile and spread out.
Coagulant to slow the flow in the pipe, dispersant to break it down once its out of the riser / drill pipe. How do these chemicals react together?
That could be a start however there is still the issue of putting lives and rare vessels into the explosive atmosphere where the oil/gas mixture comes to surface in order to pump these chems down to sea floor.
Remember though that any stop or pressure control however has to be at or below the BOPs as the riser has no pressure integrity…
X-ray the crap out of those BOPs, find out the situation inside and if they are operable, clear the obstruction / fix the BOP… shut in the well.
We need some smart thinking people who know these BOPs backwards to work their magic.
the outer cover of the rams cyclinder could be removed as probably seen on left of picture with sprocket on rov. The piston should be down the cylinder enough for A circular ram to be inserted into cyclinder against hydrallic rod/piston and done on the opposite side. If both these external rams were pressed using an external force such as a large hydrallic ram the working pressure could be increased dramatically of the shearing rams. The limitation would be the strength of the connecting rods but as shown in testing the ram units are meant to be capable of slicing thick pipe
Horizon 37
No harm done ;-). I am still active in the oilpatch, but mainly on the subsea tree side of things. You certainly know your stuff, and I would not be surprised if we have conversed a time or two in the past.
psome and others,
Radio-graphic inspection of the BOP stack is not possible, it is very difficult even with the stack disassembled on shore and under ideal conditions. The source has to be placed in the center of the spool and films taken all the way around it. To take a picture of an in situ stack from one side to the other would require a radioactive source that would kill everyone within a mile of it when opened, even if you could get the camera to remain motionless in a 4knot current, it would be too far away to get a clear picture. I think many of you do not grasp the physical size of this BOP stack. so here is a pic of one similar to the one we are dealing with.
oilstatesintl.com/_filelib/ImageGallery/Products_Services…
Opening the BOP ram bonnets is also not possible, many pieces of the frame and control lines must be removed and a very large impact wrench used to remove the bolts, this is far beyond the capabilities of an ROV. Not to mention that when those bonnets are open it exposes the well bore as the rams themselves are retracted back into the bonnets, and the bonnets can not be opened with the rams extended, without first removing all the bolts and the hinge pins. also I must remind you that the pressure inside the BOP stack is 3,000psi or more right now.
if the covers could be removed the piston retreating should seal the cover exit and reduce psi allowing application of external force (the cover is smaller than piston). The retreat of the ram could though permit any material in the BOP to escape increasing loss which would be the trade off in case the ram did not shut but then the blinds may work.
in regards to the bolts us navy underwater weilding unit or laser
BP has published a cross-section diagram of surface and sub-surface operations @ http://www.bp.com/genericarticle.do?categoryId=9033573&conte...
Horizon37 previously presented these:
Here is the photo of the riser where it’s kinked over at the LMRP, also is a schematic showing the general layout on the seabed.
http://www.flickr.com/photos/uscgd8/4563035602/in/ph otostream/
Here is a photo of a BOP stack similar to the one we are dealing with, just so some folks can grasp the size of the equipment on the bottom.
oilstatesintl.com/_filelib/ImageGallery/Products_Services…
Fourth Idea
http://www.PROinvention.com/BP-jack-cap.jpg
You fix a jaw on the pipe
Jaw have pivot for putting level with half of cap
You push the level with a jaw for example and so the half of cap close the end of pipe