Deepwater Oil Spill - closing the well and the series

The operations to seal the Deepwater Horizon well in the Gulf have now succeeded in putting cement plugs into the well that have effectively ensured that it will remain dead. The well itself was effectively killed when the cement was injected some weeks ago, and the work since has been to ensure that some of the potential problems from subsequent failure of that cement, could not occur. And so the relief well had shown that there were no effective quantities of hydrocarbon products in the annulus, meaning that the well failure had purely been through the shoe and up the production casing, and not up the annulus. Much of the original thought had been that the failure was the other way around, and the caution in the approach has been, in part, in case there was at least some failure up the annulus. That turned out not to be the case, but the relief well injected cement that filled in the voids in the annulus, so that with the cement already injected into the casing, the well is, as the Bureau of Ocean Energy Management, Regulation, and Enforcement certified, now permanently sealed.

This does not end operations at the well. Both the original well and the relief well must now follow the procedures for abandonment of the site. The DDII has been preparing for this, but the procedures that must be followed are relatively standard. I am presuming that the plugs that have been discussed are those at the bottom of the well, but there also need to be plugs installed within the well to ensure that there are no possibility of fluids migrating from one horizon to another. To a large extent this has likely been achieved with the filling of the annulus between the end of the lined well and the top of the cement injected earlier this summer. The well is now effectively totally lined on the outside, and there is a plugged production casing in the middle, which retained its integrity over the course of the events.

Nevertheless the regulations will be followed. For your information the relevant bits are, perhaps:

(a) Isolation of zones in open hole. In uncased portions of wells, cement plugs shall be set to extend from a minimum of 100 feet below the bottom to 100 feet above the top of any oil, gas, or freshwater zones to isolate fluids in the strata in which they are found and to prevent them from escaping into other strata or to the seafloor. The placement of additional cement plugs to prevent the migration of formation fluids in the wellbore may be required by the District Supervisor.
(b) Isolation of open hole. Where there is an open hole below the casing, a cement plug shall be placed in the deepest casing by the displacement method and shall extend a minimum of 100 feet above and 100 feet below the casing shoe. In lieu of setting a cement plug across the casing shoe, the following methods are acceptable:
(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effective back-pressure control and shall be set not less than 50 feet and not more than 100 feet above the casing shoe. The cement plug shall extend at least 100 feet below the casing shoe and at least 50 feet above the retainer.
(2) If lost circulation conditions have been experienced or are anticipated, a permanent-type bridge plug may be placed within the first 150 feet above the casing shoe with a minimum of 50 feet of cement on top of the bridge plug. This bridge plug shall be tested in accordance with paragraph (g) of this section.
(c) Plugging or isolating perforated intervals. A cement plug shall be set by the displacement method opposite all perforations which have not been squeezed with cement. The cement plug shall extend a minimum of
100 feet above the perforated interval and either 100 feet below the perforated interval or down to a casing plug, whichever is the lesser.
In lieu of setting a cement plug by the displacement method, the following methods are acceptable, provided the perforations are isolated from the hole below:
(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effective back-pressure control and shall be set not less than 50 feet and not more than 100 feet above the top of the perforated interval. The cement plug shall extend at least 100 feet below the bottom of the perforated interval with 50 feet placed above the retainer.
(2) A permanent-type bridge plug shall be set within the first 150 feet above the top of the perforated interval with at least 50 feet of cement on top of the bridge plug.
(3) A cement plug which is at least 200 feet long shall be set by the displacement method with the bottom of the plug within the first 100 feet above the top of the perforated interval.
(d) Plugging of casing stubs. If casing is cut and recovered leaving a stub, the stub shall be plugged in accordance with one of the following methods:
(1) A stub terminating inside a casing string shall be plugged with a cement plug extending at least 100 feet above and 100 feet below the stub. In lieu of setting a cement plug across the stub, the following methods are acceptable:
(i) A cement retainer or a permanent-type bridge plug shall be set not less than 50 feet above the stub and capped with at least 50 feet of cement, or
(ii) A cement plug which is at least 200 feet long shall be set with the bottom of the plug within 100 feet above the stub.
(2) If the stub is below the next larger string, plugging shall be accomplished as required to isolate zones or to isolate an open hole as described in paragraphs (a) and (b) of this section.
(e) Plugging of annular space. Any annular space communicating with any open hole and extending to the mud line shall be plugged with at least 200 feet of cement.
(f) Surface plug. A cement plug which is at least 150 feet in length shall be set with the top of the plug within the first 150 feet below the mud line. The plug shall be placed in the smallest string of casing which extends to the mud line.
(g) Testing of plugs. The setting and location of the first plug below the surface plug shall be verified by one of the following methods:
(1) The lessee shall place a minimum pipe weight of 15,000 pounds on the cement plug, cement retainer, or bridge plug. The cement placed above the bridge plug or retainer is not required to be tested.
(2) The lessee shall test the plug with a minimum pump pressure of 1,000 pounds per square inch with a result of no more than a 10-percent pressure drop during a 15-minute period.
(h) Fluid left in hole. Each of the respective intervals of the hole between the various plugs shall be filled with fluid of sufficient density to exert a hydrostatic pressure exceeding the greatest formation pressure in the intervals between the plugs at time of abandonment.
(i) Clearance of location. All wellheads, casings, pilings, and other obstructions shall be removed to a depth of at least 15 feet below the mud line or to a depth approved by the District Supervisor. The lessee shall verify that the location has been cleared of all obstructions in accordance with Sec. 250.704 of this part. The requirement for removing subsea wellheads or other obstructions and for verifying location clearance may be reduced or eliminated when, in the opinion of the District Supervisor, the wellheads or other obstructions would not constitute a hazard to other users of the seafloor or other legitimate uses of the area.

This means that there will be some continuing work at the well, but not a lot, and thus from now on I shall only be intermittently posting on that topic, and will start to write about the more general topics that have been neglected over the past few months.

Deepwater Oil Spill - patiently waiting, Chilean drilling, and coal in Europe

Well, although the Admiral said that the intersection of the relief well with the Deepwater Horizon well would occur within 24-hours of his last press conference, and we are now past that, there has, as yet, been no word of the current status. BP noted that at 11:30 am on Thursday morning (Central) that DDII, who has the BOP on the failed well, has pulled its diagnostic tools from the well, until the interception is completed. Now the nature of those tools has not been explained, they were, if my memory serves, looking to fish out the dropped drill pipe that had been held by the shear rams in the original BOP. However, it isn’t clear whether even that operation had been completed. Remember also that if the drill pipe is sitting on the cement rather than in it (a function of when it fell), there is not likely to be enough space for any tools to get down to do anything inside the casing (such as perforate it to create a circulation path).

While the BP site notes that the DDIII – which is drilling the relief well – is conducting a ranging run, one should remember the Admiral noting that with the new method they are using they can do the ranging without pulling the drill string back the way that they had to do when they were further away. (It should also be noted that it would not be unheard off for the drill to miss on the first attempt).

It could also be that the well has been intersected, but that the condition of the wall of the well has created an unexpected problem (bear in mind that the relief well is trying to drill into the open hole section of the well, where there is no casing or cement liner on the wall, and the production casing is likely set away from the well wall.)

There are a number of things that can be postulated, we will just have to wait for some official word before we can find out what is happening. Even the ROV camera feeds can find nothing more interesting to show than poking the new BOP with a rubber hose.

Apparently I was wrong in my understanding of what is going on with the rescue of the Chilean miners. I had interpreted the intersection of a drill with a rock bolt as meaning that one of the smaller bores, similar to that which found the miners, had been drilling another small access hole for sending down supplies (such as the empanadas and steaks they will get this weekend to celebrate the 200th anniversary of the country).

However it turns out that there are a couple of other large drilling units on site that are now trying to reach the trapped miners. The one that had the broken bit that took a week to fish from the hole, is being drilled using a T-130 drill, which is reaming one of the supply holes already drilled from 5-inches to 12-inches. That step in the process should be perhaps completed by this weekend, but then the shaft will have to be widened in a second step out to the 28-inch diameter that the miners need to get out.

Reaming the hole in two stages has some advantages, since it does not force the large volumes of debris down the small initial hole,, where larger fragments might jam and stop the advance. The drill is already at the 1,640 ft mark, out of the 2,067 ft needed to reach the miners. The Strata 950 has only reached 1,050 ft.

Meanwhile a third option, using a oil platform drilling rig (Rig 422) has arrived and been set-up. It might be possible for this to drill a larger hole faster, and it is being located so that it has to drill a slightly shorter distance (1,958 ft) to reach the refuge. It can drill at between 65 and 130 ft a day. Apparently the roads over which the parts had to be carried were so bad that several of the haulage trucks arrived on site with flat tires.

And it is worthy of note that the European Union has decided that the last coal mine in Hungary will have to close at the end of this year. Since the mine feeds a local 240 MW power plant, which will immediately begin disassembly, this has implications for both the heating of the community this winter, and for future local unemployment. The argument has been made that because coal mining is subsidized (it used to be in the UK, that coal was subsidized, in part to keep the miners in employment, after the mines were closed unemployment in those regions of the UK was very high for a significant number of years). The mine is currently burning biomass with the coal, in order to reduce pollution, but that is no longer a sufficient justification for its continued operation. It supplies 5% of the energy used in Hungary.

This should be contrasted with plans in the UK to build a new 1.6 GW coal-fired power station at Hunterston in Ayrshire. It is a plan that has led to strong opposition but in all these debates, it is not clear if the reality of alternate supplies at the levels needed has been adequately considered. Given the strong objections from some locals over the siting of wind farms in South-West Scotland (farms it is actually difficult to see, as I have found), one wonders what source of magical power is expected to replace the diminishing contributions from North Sea oil and gas.

Deepwater Oil Spill - approaching the well, and the birth of Hope

With very little change since yesterday in the situation in the Gulf, it may be time to start spreading these reviews out a little more, of if the well is intersected this week, to consider moving to more general topics. The DDIII drilled 30 of the remaining 50 ft between the relief well and the original Deepwater Horizon well on Monday. The drill was then retracted to make a ranging run, and once that is completed, one can assume that they might just go ahead and do the intersection on the next drilling pass.

That will begin to generate the next set of answers to remaining questions about the well condition, and what happened when the well blew out. At the same time

The DDII continues to conduct diagnostic tests on the MC252 well, and final plugging and abandonment procedures are being worked through the approval process.

One wonders how long the approvals will take?

In regard to the progress down in Chile, there is a little confusion about the nature of all the holes that are being drilled. Apparently there are more of the smaller access holes (6-inch diameter) still being drilled as well as the larger hole that will then be reamed to the size that will carry the men out in a special cage. One of the smaller drills apparently broke a bit when it encountered a roof bolt as it approached the underground mine opening. To clear the way forward, the fragments of the old bit had to be removed from the hole using a magnetic fishing tool, before the drill could be restarted, It apparently took a week.

The President of Chile has also made another decision:

Mr. Piñera said he ruled out as too dangerous another rescue proposal involving blasting a hole in the mountain with dynamite. He understands that some would like to see faster progress, he says, but it is arduous work: "It's a very hard rock."

Since there is already a tunnel part of the way down, the excavation would only involve the section that had collapsed, but that is easier for me to say, than for miners there to do. One of the miners became a father today, and they called the baby Hope, or Esperanza.

Deepwater Oil Spill - the relief well restarts, and miners watch TV

Admiral Allen issued a statement today, in regard to the situation at the Deepwater Horizon well:

After extensive consultation between BP engineers and the federal science team, as well as reviewing data collected from measurements I authorized Friday, the Development Driller III today began the final steps towards the completion of the relief well that will intercept the Macondo 252 well and perform the bottom kill procedure.

This accelerated progress was possible after several discussions between BP and the federal scientists and engineers, leading to the installation of a lock-down device over the weekend, which resulted in the necessary conditions to commence the finalization of the relief well. I will continue to provide updates on the progress of the relief well, the final step that will ensure the well is fully and finally killed, as necessary.

Following this BP announced that relief well operations re-started.

BP re-started relief well drilling operations from the Development Driller III (DD3) today at 1:40 p.m. CDT following the successful installation of a lock down sleeve, a mechanical device that secures the MC252 well's casing hangar.

The lock-down sleeve was installed on Saturday, and successfully tested – though I am not quite sure what that would entail, since it is a bit like putting a locking nut above the retaining nut on a bolt, it stops the retaining nut from moving – but how to test?

The DDII is continuing to run diagnostic tests on the original well, as the relief well slowly drills forward, over the last 50 ft to make the intersection. Remember that with the very small target (the unlined section of the borehole annulus) the intent is to drill a short distance, re-survey the location and that of the well (determined from an electro-magnetic field generated in the production casing) to make sure that the well is moving on target, and then drill a little bit more. It will still take some time, perhaps four days, to get to the well, and then the circulation of fluid to determine what is really in the annulus will be one of the last stages, before the well is plugged with cement at the bottom, to fill the annulus above the current levels and provide no potential flow path from the reservoir.

Once that is completed, then the relief well can be also plugged both at the bottom and then at the top, and both wells can start the process of inserting plugs close to the seabed and then removing the wellheads and going through the process of abandoning the wells.

In regard to the miners trapped in Chile, it has now been reported that it may take as long as 3 hours for each miner to be lifted to the surface, which may make the process last some four days.

The miners have been sent a small tv set, through one of the three 6-inch diameter supply holes already in place, and are now being sent electricity as well as cooler fresh air, to help with the environmental conditions, which are otherwise very hot (88 degF) and humid (85%). And by using U/V lights they are apparently also setting up a day/night cycle for them.

Sadly the mine is reported to be broke.

sanctions may be hard to enforce. The mining company has filed papers to declare bankruptcy. The company also says it can't pay anything for the rescue effort, not even the wages owed to its miners.

I do remain concerned about water flows underground over that length of time, unless they have some alternate way of getting the water out of the mine, since I presume that the rock falls stopped any pumping operations that were ongoing. For example:

Morning showers require the men to climb aboard a bulldozer-type mining vehicle that rumbles 300 metres up the tunnel to a natural waterfall where they shower, shampoo and clean off the ubiquitous rust-coloured mud.

There is also another two sets of problems, evident from what is generally considered good practice. The first comes from the rescue effort itself:

Another group of men reinforce the mine walls and divert streams of water seeping into their refuge. Several of the drilling and communications tubes connecting the men to the surface use water as lubricant, meaning a constant stream of muddy gunk trickles into their world.

And then there are the other water needs, that are also provided.

After the (Chilean:Ukraine football) match was over, the men prepared to sleep. They walked down the ramp to the bathroom, an area kept constantly clean by a stream of fresh water that washes away the urine and faeces.

All that water has to be going somewhere.

They do monitor the gas content of the air around the refuge, and are preparing for when the big drill first breaks through to the mine with the pilot drill. That is now expected to happen in about 3 weeks, and then the miners will have to start removing the debris from the larger reaming bit as it moves down, enlarging the hole to the required size for the rescue cage. It could be as much as a thousand pounds of rock an hour, though the rates will hopefully and likely be kept slow enough that there is no risk of the pilot hole being jammed with too large pieces of rock.

Deepwater Oil Spill - locking the hanger and relief well role

A short time ago I wrote about the concerns with the casing hanger in the Deepwater Horizon well, and the risk that it might lift and allow whatever fluid is in the annulus between the production casing and the well lining to be released. In his remarks on Friday Admiral Allen discussed that situation. At some point there has to be a seal on the top of the well to prevent fluid escaping from the annulus. The solution that he, the science team, and BP have reached is that the casing hanger will be locked into place, so that it cannot lift off the seat. This was the illustration that I used back then:

Labelled section showing the parts of the casing hanger (note that there is an animation at the source site)

With the casing hanger itself looking like this:

Casing hanger.

The lack of a locking ring was a bit of a bone of contention when the initial Congressional hearings took place back in June, being one of the five issues that Congressman Waxman brought up in a letter to Tony Hayward. (The other four were the design of the well itself; the “centralizer” issue; the failure to run a bond log; and the failure to circulate possible gas-bearing mud out of the well. ) It may not have been necessary back when the well first started to flow (if the annulus is, in fact, still full of mud rather than oil) and the seal is currently working, but by putting a lock on the casing hanger so that it cannot rise out of the seat they are ensuring that it will not move, even if pressure increases in the annulus, after the relief well makes contact. Locking it can be carried out by running a string of drill pipe down to engage the top threads of the hanger, so that it can’t move. Alternatively it can be connected to the surrounding wellhead structure, perhaps by running a sleeve back up to the overlying BOP. It could have been locked with special locking screws that ran through the wellhead, but they aren't in play at this point.

Admiral Allen noted:

In essence, we're going to put a ring or what they call a sleeve around the top that'll lock that casing hanger in place, will not allow it to move. There is always concern that when we pressurize the annulus, that casing hanger would lift, allow free communication between the annulus up into the blowout preventer.

Cement in the annulus will be one way to preclude that from happening. But after some consultation and looking at various alternatives, the BP engineers and our science team agreed that if we could ascertain that the casing hanger had not been dislodged, in other words, where we need it to be, then we could actually put a sleeve around it and basically lock it down.

And the order that I issued to BP, I ordered them to take what are called lead impressions. You go down, you take an impression of the top of the casing hanger. And then that allows you to take measurements on where its location is. Based on that measurement that they took, it appears that the casing hanger has not been dislodged to the point where we'd have a problem with the seal, so we just need to lock it in place, and that would substitute for the pressure control that cementing the annulus would have provided.

Once BP tells the Admiral how long it is going to take to lock the hanger down, and it is done, then he will give permission to restart the relief well. The impressions of the seat were apparently made by lowering lead blocks onto the hanger and deforming them. This provided the required impression of the position of the top of the hanger, from which it was possible to decide that it hadn’t moved.

With that seal in place it is no longer necessary, at this time, to perforate the top of the casing to insert a cement plug, since the seal will itself provide a plug during the relief well operations. (The plug will still be needed for the abandonment part of the process).

MoonofA has illustrated the process that is now to be followed in complying with the Admiral’s instructions. I am copying the comments that go with two of the illustrations from that comment:

(This) picture shows what will happen in the next days.

1. The casing hanger lockdown sleeve will get installed (not shown).

2. Developer Driller II above the original Macondo well will put its drill pipe into the hole and will perforate the production liner long string just above the top-kill cement. (If the annular is pressurized from the reservoir it may take a kick doing this.)

Pumping cement into the annular in this state would be dangerous and difficult as whatever is in there now, mud or oil, has no place to go. To avoid any damage when pushing cement down in there we need some communication to be able to retrieve the stuff that the cement will replace.Therefore:
3. Developer Driller III doing the relief well will intersect below the outer casing into the annular between the long string and the well bore. This will then form a U-tube between the DDII down through the annular between the long string and the outer casing and up to the DDIII. Mud can then be pumped from one rig down the hole up to the other rig to test the communication through the annular.


4. Fresh cement (green) will then be pumped from the DDII down its drill pipe into the annular. As communication is established, whatever is then in the annular, mud or oil, can be pushed by the cement up to the DDIII.


With this the annular is then truly dead and The Admiral’s point 5 demand will be fulfilled.

However, to get the perforations just above the cement, the perforating tool has to reach that position, which it can only do if there is no old drill pipe in the way. We will see if any is found, and they fish for it.

Deepwater Oil Spill - a slight change in plan

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

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

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

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

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

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

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

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

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

Deepwater Oil Spill - and this week's TWIP

Admiral Allen helped with the release of some of the rescued turtles from the Gulf today before giving his press conference at Cedar Key, in Florida. He noted that while there has not been any final decision yet on what to do best in moving closure of the Deepwater well forward, some steps in that process are happening.

For example, the Blowout Preventer (BOP) from Development Driller II (the second relief well) is going to be needed at some point to allow drill pipe to be inserted into the Deepwater well, so that a top cement plug can be inserted. To that end the BOP transfer is now being expedited. At the same time the Q4000 and the Discovery Enterprise are being brought back over the well, for several purposes. Initially these will be used to flush other fluids from the BOP, the production casing and any other accessible volume within the well. (Note that this will likely not include the fluid trapped in the annulus since there is no easy way to displace this). Once the volumes have been cleared the fluid used to sweep them will be replaced with seawater, emulating the condition when the BOP is removed. By monitoring the pressures in the well during this process, and with the necessary safety valves in place, this will assure the scientific panel, and the Admiral, that removing the BOP and stack won’t cause a problem. Hopefully by doing this, among other things, it will resolve the problem of the slow bleedoff in pressure that has been occurring within the stack during the current testing process, but which is blamed on the escape of trapped gas. They will then decide whether to install the new BOP before completing the relief well. Since, in other words, nothing much has changed, let me go on to look at the new “This Week in Petroleum” which came out today.

As the adverts on television and the newspapers will tell you, summer is coming to an end, and school sessions are about to restart. Which means that we are coming to the end of the summer driving period and, as a result, demand will, likely in a couple of weeks, start to decline. As the latest TWIP (This Week in Petroleum) notes, we aren’t quite there yet, and demand is running some 250,000 bd above last year , for gasoline, but we are close to the turnover.


The oil companies can see the event coming, however since it occurs every year, and so the refineries are lowering demand for the season.


Which, given that domestic production continues relatively constant (but up around 200,000 bd over last year, at 5.4 mbd) means that there is a slight decline in imports. Though it should be noted that these are still running about 0.75 mbd above last year.


At the same time ethanol (which I haven’t tracked before so am less sure of the seasonal trends) continues at about 0.85 mbd.


As the driving season ends, so the US moves into the time when oil, particularly in the NorthEast is used for heating. TWIP this week is looking at the changes that may happen in that region as the various State legislatures look at reducing sulfur content of the heating oil to bring it into line with the regulations governing highway diesel, which are a lot more restrictive on sulfur content. (Note that it is the sulfur content of oil that gives it the “sour” designation, and the world is moving away from easy, cheap supplies of the preferable “sweet” crude which has a low sulfur content.) . As the TWIP notes:

Initially, the change to ULSD for heating oil may limit import supply sources, as many parts of the world do not produce ultra low sulfur distillate fuels. During the winter (December through February), high sulfur distillate imports into the East Coast account for about 20 percent of this region’s total heating oil demand on average, and about 50 percent of distillate imports. Furthermore, during past cold snaps when supplies run short, high sulfur imports have provided most of the relief to the increased heating oil demand.

The transition will present other challenges. Some refineries supplying the Northeast with heating oil will need to make investments to produce ultra low sulfur distillate fuel for this market. Terminal transitions to low sulfur heating oil will need to be made, as well as changes to supplies of low sulfur additives or blending components to create winter-blend heating oil.

Given that the world's supply is increasingly sour this will only make the problem worse, and will further mandate changes in refineries to cope with the change in demand, without which a bottleneck may develop within the system of supply.

Deepwater Oil Spill - the two options

So who makes the decision? BP are now faced with a couple of problems that may have arisen because of a false assumption early in the process, about the condition of the well. They have now been led to two different choices, as to how to proceed with the final steps. Let me explain what I mean and how, I believe, these came about.

At the beginning of the disaster, when the plans were being made to bring in a relief well to seal the bottom of the flowing well, it was necessary to make a number of decisions. One of these had to be where the relief well should intersect the well that was flowing.

If you go back to those times there was an increasingly dominant viewpoint that developed in the early weeks that the failure had been in the cement surrounding the production casing, and that, as a result, the oil and gas was flowing up the outside of the production casing, through the gap between it and the liner segments higher in the well, and then through a failed seal in the BOP, down into the main flow channel and up through the center of the BOP.

Accordingly when the relief well was planned, it was assumed that there was a flow channel that had developed down through the cement in the annulus to the reservoir. The path of the relief well was therefore aimed so that it would intersect the annulus a the top of the gap below the last lined segment of the well. Once there it would allow a check that there was flowing oil, and could then be used to force mud and then cement into the annulus to displace the oil. The cement would push the existing fluids down the well, back into the reservoir, and thus create an 800-ft long plug in the annulus. If there were indications that there was still some flow up through the production casing, then the relief well would have re-drilled through the injected cement, and then, using a milling bit, cut an access slot through the casing.

In the same way, as before, the relief well would then have injected mud, firstly to kill any driving pressure in the well, by filling the well with mud, and then killed the flow by driving the oil back into the reservoir, and then injecting cement to kill the well. At this point the bottom of the well would be sealed with a known amount of cement in both the annulus and the bottom of the production casing. For this method to work, however, there had to be a pathway that would allow the mud injected either into the annulus, or the casing, to displace the oil in the well back into the reservoir.

In the initial arrival at the annulus injected mud would push the oil both up along the anticipated existing annulus flow path to the BOP, and then fill the casing as the mud displaced the oil downwards in the production casing. The injected mud would also push down, through the flow path through the cement around the production casing, pushing that oil more directly into the reservoir.

This scenario should have worked ff the leak had been through the annular cement and up through the outside of the production casing. However some snags have now arisen. The first is that the leak was not apparently mainly up the annulus, but rather up through the production casing. That poses the first problem with the trajectory for the relief well. Because if the flow did not go up the annulus, then cement could not be sent down the annulus to stop it. Thus, I suspect, the decision to send the cement down the production casing. At least this way the reservoir and flow path could be sealed off, and should there be a need to temporarily abandon the well due to a hurricane, then there would be no significant chance of a leak. So that was done.

But now it has left BP and the oversight panel with the problems that I have mentioned in the last two posts on the subject (here and here). Because with the bottom end of the production casing sealed, and it having been determined that the annular seal under the BOP is still intact, there is no good and easy way to get the oil (if there is any) from the annulus and replace it, first with mud, and then with a cement plug of suitable, and known, size. Injecting additional fluid into what is a sealed system doesn't work very well.

One thing that could be done is to sensibly shrug the shoulders, say to heck with the bottom – we know it is currently sealed, and just do a conventional plug and abandon at the top of the well. This would require removing the existing stack, and the original BOP and the 3,000 ft of drill pipe (DP) suspended below it in the well (but now surrounded by drilling mud). Then putting a new BOP in place that would allow a new DP to be run down the well. This could be fitted with the necessary tools to put a cement plug in both the production casing, and in the annulus beyond it. It would also allow any remaining superstructure above the plug to be removed, according to regulation. That operation would, however, come under a different jurisdiction.

This would, I gather, now be a route that BP might prefer to move along. But Admiral Allen has been fairly adamant about having the bottom plugged with the relief well. But his latest directive to BP is beginning to work to give them wiggle room in changing this option. He sets out four directions:

Provide me a plan for a pressure relief system to prevent excessive pressurization of the Macondo well stack (capping stack, LMRP, and BOP), including any necessary containment option, Contingent upon the approval of the plan, this system will be installed before the intercept of the DDIII relief well.

Because the seal is still in place at the top of the annulus, and the cement is sealing the bottom of it, when the relief well drills into the annulus, any imbalance of pressure could cause flow into the original well. This would increase the pressure in that well, and cause the top seal that is currently intact to likely open. This in turn could increase the contained pressure within the stack assembly.

Because we have seen the very small leaks on some of the joints in the stack, any increase in pressure could possibly cause a greater failure, and a fluid leak into the Gulf of significant size. To ensure that doesn’t happen, the Admiral wants to be sure there is another form of pressure relief in place, or a way of capturing fluids, so that they don’t get into the water.

The next direction is to be ready to have the DDIII able to continue the completion of the relief well, when directed.

The third directive, however, addresses the change in the stack to a more regular BOP to allow a top plug to be inserted into the well.

Provide me a plan for an ambient pressure test and analysis to assess the stability of the well during the period of time after the removal of the current Macondo well stack and its replacement with a new BOP package.

In other words tell me how you can be sure that the well won’t flow after you take the stack and BOP off. The question of the fluid in the production casing has been answered by the pressure tests on the cement plug, and I believe that the negative pressure test, has shown that there would be no flow up through the annulus. It just needs BP to couch the results in the form that the Admiral requests.

And the final direction is

Before the current BOP stack is removed, prove to my satisfaction that the Macondo annulus does not represent a potential pathway for hydrocarbon flow; or, if the potential for flow can’t be proven, identify the conditions under which flow could occur and the risks of those events occurring.

This is where the judgment call is required. Can BP provide a logical answer to satisfy the Admiral and the science panel?

There are offsetting risks in the two approaches being considered. Drilling into the annulus will identify whether there is any communication (flow path) from the reservoir up through the annulus to the BOP. But it runs the risk of overpressuring the seals in the BOP and higher elements of the stack that could rupture and dump up to 1,000 bbl of oil into the Gulf. On the other hand accepting that the annulus is currently sealed, so that the BOP can be removed to inject the top plug, runs the risk that, if the seal at the top of the annulus were to fail during the operation, then seawater could flow down the annulus, displacing the lighter oil and causing it to flow up out of the well and again dump it into the waters of the Gulf.

It appears that the Admiral is asking for the arguments on both sides. But these focus on whether or not to allow the relief well to intersect the original well or not. The need for the top plug is still an abandonment requirement.

Deepwater Oil Spill - is the well dead already?

Much of the focus of recent efforts at the Deepwater Horizon well site have been focussed on getting the relief well down to do a bottom kill of the well. However, in recent remarks the possibility has been raised that this may already have been done, and that the well is effectively dead already.

In his press conference on Wednesday, Admiral Allen noted, relative to the understanding of the conditions at the bottom of the Deepwater Well, that there may have been some communication (in other words a passage) from inside the production casing, out to the annulus outside the casing.

Following the cementing of the casing itself in the well last week and successful pressure test, we had discussion between the government science team and BP engineers, we believe there may be a chance that the cement that was forced down through the casing of the well entering the reservoir might have actually moved over and come back into the annulus which is the area outside the casing but inside the well bore.

We want to understand the condition of the annulus before we actually drill into it so we are working with BP right now to establish procedures to do a pressure test that will tell us whether or not there’s free communication between the annulus and the reservoir itself or there’s cement that actually works its way over there from the static kill.

He also noted

Just to project out a little bit further for everybody’s information, once the well is killed it is no longer a threat of discharge at that point it will no longer be considered part of the response to the oil spill per say because there won’t be any source of the oil.

In other words if the production casing passage is sealed, and the annulus is adequately sealed then the well is no longer a threat, and no longer part of the response activity. At that time the well moves into the jurisdiction of the Department of the Interior and their regulations, which have been discussed here earlier, of the steps needed to abandon the well.

The problem that the Admiral relates to is actually in several parts. Let me try and explain them in a little detail. Firstly we will start, this time, at the bottom of the well, where the shoe sits that was meant to seal off the inside of the production casing. Very simply, at the end of the operations with the Deepwater Horizon, the bottom of the well might have looked a bit like this (which is definitely not to scale, but drawn just to illustrate some thoughts)


At the end of the drilling a plug of cement had been pushed down the production casing and out of the end so that it flowed back up the annulus several hundred feet. The well should have been plugged at the bottom.

We now know that there was a failure at the bottom, since all the cement that was injected went down the production casing. This means that there had to be a passage between the well and the oil-bearing sandstone. I show this as green and it has eroded a path through the cement down to the bottom of the casing and then up the inside of it to the BOP and thence to the Gulf.


Note there has to be a passage through the annulus to the sandstone from the central section of the production casing for the oil and gas to flow.

Now consider that in killing the well the cement was pumped down to the bottom of the casing and 200 barrels then went out into the annulus, and up into the oil-bearing sandstone. That may have been enough to totally seal the passages to the bottom of the casing but also any erosion that had taken place eating upwards along the outside of the casing through the annulus to the top of the cement.

I wrote about that the other day, and as a reminder, this is what it may look like.


Now the original assumption had been that the leak was up through the annulus of cement to the Gap that I show – but that turned out not to be the case. And remember that this is 800 ft above the shoe we were just talking about.

So if the relief well intersects here it has to drill a fair way down to check on conditions at the bottom of the well, if the cement lining at this point has integrity. If there is no oil found here, which means there was no passage down to through the annulus (at this level, obviously there was at the bottom of the well) then as insurance they can inject cement back through the gap and annulus, but in reality the well is already dead.

However if that is the case, and they want to fill the annulus here with cement, they have to be careful. For the outer annulus up at the BOP is protected by a seal. The Admiral described the problem and solution.

The casing in which the drill bit and the well and the well pipe sits (hang) from the top of the well head. And then they kind of telescoped down to the smaller diameters. In that mechanism where they hang off the top of the well head, there was a seal and if enough pressure is applied from the annulus, this is outside the casing, on that seal it is meant to give way so it won’t cause damage to the well bore.

In other words it’s like a relief valve, and the seal which completely circles the casing at the top of the well if enough pressure is exerted will rise up and allow oil to flow. One of the theories was that somehow sometime during the explosion or what happened that that pipe was lifted up to allow that seal to be opened. It might have allowed oil to move up into the blow out preventer, it might have been the source of the hydrocarbons coming up other than the actual casing itself.

We don’t think that’s the case right now we think it’s seated where it should be but what we wouldn’t want to have happen is to start pumping mud and cement into the annulus at the bottom is filled with cement and you have stagnate oil there. And we increase the pressure as we’re doing that so that stagnate oil is forced up and that forces that seal to rise up open itself and go into the blow out preventer.

And as you know we restricted the pressure on the injectivity tests in the top kill to be less than 8,000 psi. The cap itself is rated at 10,000 psi and what we want to understand is we go ahead with the mud and the cement for the bottom kill is there any chance at all that that would force stagnate oil up to the point where it would lift that up again, open those seals, push that up into the blow out preventer and the capping stack and at some point erode, approach pressures that might be a concern to us.

We think it’s a very low probability outcome but the discussion of those seals and whether or not that pipe has ever been lifted is something that’s been discussed for some period of time. But we think we just need to rule it out before we go forward.

By the Thursday press conference the storm had largely passed, the storm packer was being removed from the relief well, and a negative pressure test was being carried out at the top of the well, under the BOP, to ensure that the cement had no problems, and to see if with that lower pressure there was any flow out of the annulus. They are anticipating that once drilling restarts it will take 96 hours to intersect the annulus.

The science team believe that there is a “low probability” that the leaks through the annulus to the well were sealed by the cement injected during the static kill (which suggests they still believe there was a passage up to the gap at the top of the cement) but the results of the test may indicate whether they were right or wrong. However, as the Admiral noted,

I guess what I'm saying is if the cement is already there it would obviate the need to do the bottom kill because the cement from the top kill had worked its way into the annulus. That's what we're trying to find out.

The way that they are doing this is to lower the pressure above the hanger that the production casing rides on, so that the seals to the annulus open.

lowering the pressure in the stack enough where it would raise those seals on the hangar which would allow oil to flow up and if there was communication with the reservoir we would see an increase in pressure.

That would tell us there is no cement in the annulus and we should proceed with the bottom kill. If for some reason the pressure stays level that would indicate that we have some kind of a static condition in the annulus and that would present the possibility that the cement had entered the annulus and we might either a full or a partial kill from the bottom accomplished with the static kill. . . . . . . .
What we hope we'll find out is there will be an immediate rise in pressure which will tell us there is hydrocarbons being pushed up from the reservoir and we should go ahead and proceed with the bottom kill.

It will be more problematic and quizzical if there is no discernable change in the pressure readings. That would indicate that the oil is being held in place and its' static. That won't tell us how much cement and to what extent the communication between the reservoir and the annulus may have been filled with the static kill.

And at that point there will have to be a determination made on whether or not we'll go ahead and proceed to drill in with the relief well and be prepared to go ahead and put the cement in. That will be a discussion that we'll have with the BP engineers when we know the results of the test.

That may still leave up to 1,000 barrels of oil trapped in the annulus, but this could be recovered during the plugging operation later in time, and under another jurisdiction. But the well would be dead, and no further steps, including intersecting the bottom, might be needed. But they will likely do that any way, just to be sure.

Deepwater Oil Spill - relief well intersection version 2

Both Admiral Allen and Kent Wells (audio only no transcript yet) held press conferences today. The primary focus in both cases was the weather, with the currently approaching storm producing waves that are causing a halt to operations.

Gathering potential storms (National Hurricane Center)

The storm is not seen as being very threatening, to the point that the riser will not be disconnected. However the drill pipe is being withdrawn, a storm packer inserted into the hole, and the riser filled with sea water. As a result, if there is a problem, the drilling rig can release from the well without creating further complications. But it allows a faster recovery if nothing untoward happens.

The relief well had made it 50 ft beyond the casing and has been surveyed. In the next step it will go another 30 ft before a survey, and then (getting closer to the original well) another 15 ft and so forth. At any time it may intersect the well, and so it might be appropriate to explain (as both parties did) what is expected, and where the intersection can occur.

When I had earlier written about the intersection and the injection of the cement into the bottom of the well it was before the well had been killed from the top. The situation at the moment is that the bottom 5,000 ft of the well inside the casing has been filled with cement.

So that if I go back to the original situation at the intended intersection point, what it may well look like at the moment is this:


The vertical gap between the two outer cement linings which (for simplicity) I have shown as very short is actually likely to be a couple of hundred feet long perhaps. The inner cement plug within the production casing stretches several thousand feet above the intersection point.

The bottom of the well is some 800 feet further down the production casing. At the present time the well is being held at 4,200 psi pressure at the BOP to check and see if there are any leaks. Just as an observation when you put that much pressure on that long a solid confined column it will dissipate out to side loading long before it gets down to this depth, so the test does not have that much value in these particular circumstances. As far as testing the integrity of the central concrete plug neither will the negative pressure test which they intend to follow the current positive pressure test with. In this case they will lower the pressure in the well to 2,300 to 3,000 psi, and see if the well makes fluid. Again, because of the length of the concrete column in the production casing, that drop in pressure will not extend down to the intersection point (let alone the bottom of the well) and thus won’t provide that much information on the conditions at the reservoir.

What it will do, however, is provide some information about what might be going on in the annulus and particularly what might be in the gap, and the condition of it before the relief well runs into it. If the integrity of the production casing remains, (except potentially at the bottom of the well) and all the mud and cement flowed down it, and into the formation, then there may be no way for the fluids in this annulus to have escaped the well. (I have colored them an off yellow since we don’t know if they are oil or mud). If they are the original drilling mud, and the lower cement lining around the production casing has retained enough integrity to seal this zone off from the bottom of the well and the reservoir, then this may even still be the mud used just prior to the cementing of the production casing.

In that case the well is really already well sealed, although for insurance they will likely pump cement into the well to fill the gap and back up the annulus a few hundred feet with more cement. Doesn’t matter then what the condition of the bottom of the well is – there is no path for fluid to get up the well.

If on the other hand they find some oil in the gap then this could indicate that the cement had lost some integrity, and allowed some oil passage (but then how did it then get into the solid steel pipe of the production casing?) But again, pumping cement into the well to fill the gap will provide a permanent seal without needing to go much distance down into the lower cement lining to assess its condition.

Because the original well could well now be a sealed system then the actual fluid in this section will be determined by looking at what comes back up out of the relief well as it drills into the gap.

There is a caveat to this, however. If there was a massive failure of the lower cement liner down to the reservoir, then when the relief well strikes the gap there will be a path for mud to flow down into the well, pushing the fluid before it down into the reservoir. The mud weight that they are using is a 13.8 ppg mud, and so this should displace down to the reservoir. By monitoring the flow and the pressure it will be possible then to determine the size of the flow channel, and other values. If that happens it might complicate the analysis of what actually is the condition of the bottom of the original well. But the treatment remains the same. Stabilize the well, then inject the cement to form a plug in the gap and back up the annulus, and the well is sealed.

Because of the currently anticipated storm it is expected that there will be a delay of perhaps a few days more before the intersection occurs, but with the condition of the rock around the well in the unsupported (unlined) section somewhat unknown it is not going to be possible to accurately predict exactly when that intersection will occur.

Deepwater Oil Spill - details of the cement kill

New facts continue to emerge from the press conferences of Kent Wells and Admiral Allen in regard to the current state of the killing of the Deepwater Horizon well.

Admiral Allen held the first and shorter conference on Friday, and there were only two external questions, so perhaps interest is now fading fast as the well is now effectively plugged. It is not yet legally plugged and the need for certain procedures to comply with regulation was part of the discussion today.

Admiral Allen noted that after injecting the well with cement, a separating fluid was injected and then the cement pumped down to the bottom of the hole by injecting mud behind the separating fluid. He again spoke to the finding that the cement had only gone down the production casing, and not the annulus.

As I’ve told you in previous briefings, we’re starting about 4-1/2 feet away from the well horizontally, and we’ll drill down at a very, very slight angle. If for some reason they penetrate the annulus in the process of doing that, they’ll prepare – they'll be prepared to go ahead and assess the condition of the annulus at that point and go ahead and submit the well in.

We do not believe that the second try will be needed to go into the casing pipe because the indications are from the cement that was put in from the top is that the casing has been filled with cement down at that level, but we will not be sure of that until we finish the pressure checks that I mentioned earlier. But if the – if the pressure checks hold and we have indication the casing has been sealed off with cement, then the killing alone would require only going into the annulus. But we will not know that until the pressure checks are complete on the – on the cementing that was done yesterday and we actually enter the annulus itself and understand what the condition is at that time.

The sense of those comments is that if the cement followed the oil path and sealed it, then there wasn’t a leak in the annulus, since all the cement went down through the casing. Thus he likely is now expecting that when the relief well intersects the annulus and the cement within it, it is not going to find any hydrocarbons. (These will be detected in the returns of the mud to the surface as they continue to circulate fluid through the drill bit on the relief well).

It is going to take another week or so to reach and penetrate the annulus and assess its condition, but after that the finale will come quickly. Kent Wells noted that the relief well has drilled beyond the last set of casing, that was just set, for an additional 15 ft, and this has given them the space to run the cement bond log and the first ranging run to ensure the positions of the wells remain as desired. The next drilling run (of about 30 ft) will likely take place on Sunday, and he too felt that the intersection would be in the August 13-15th time frame. (Incidentally the finding that the leak was from the cement in the shoe of the well, and not in the annulus could well mean that the cement bond log test, even if run, would not have found the original leak in the Deepwater well, since it was below the range over which the instrument would run - as the need to drill out the cement in the relief well before running it illustrates. Similarly the discussion about the number of centering pieces on the production casing may also no longer be pertinent to the failure).

However, if the oil flow was constrained only through the center of the production casing, then there should be no hydrocarbon in the annulus, and to verify that they may, perhaps drill longer and further down the annulus than otherwise planned. (This to get down to the area of the shoe to ensure that the cement job already completed has sealed off any possible paths upwards outside the casing).

In response to a question, Kent Wells stated that BP had pumped 500 barrels of cement down the well, and of this roughly 200 barrels went into the formation, with 300 barrels left in the casing.
At the time of the conference ( 3 pm Central) BP was running the pressure test on the well, having raised the pressure above the plug, it was being held constant, watching to see if there is any leakage that would drop the pressure and indicate the need for a fix.)

He also pointed out that for the abandonment procedure required for the well, BP will have to replace the current BOP with a functional one that would allow them then to insert a new drilling pipe into the top of the well. They will use this pipe to create a second plug up near the top of the well, prior to carrying out the removal of the top sections of the casing (as I showed in an earlier presentation) at a level below the sea bed. This will provide the original BOP for forensic examination. The final top plug might look something like this:

Side view showing the removed top part of the casing and the two cement plugs required to seal the well below the seabed.

Deepwater Oil Spill - Waiting for the cement to set

BP began pumping cement into the Deepwater well at 9:15 am CDT on Thursday and stopped the operation at 14:15 CDT, having thereby pumped cement into the well for a period of 5 hours. The intent was to fill the well and any wormholes and voids that had developed in the reservoir during the leak. The cement has to harden before it can be tested to insure that it has integrity.

During the process Admiral Allen held his press conference and commented that the wait for the cement to harden would likely be in the 24 – 36 hour time frame, after which the relief well will start to drill forward into the annulus. The process of going down, intersecting and then cementing the annulus, and then doing the same for the production casing is apparently further confirmation that the well flowed up the production casing, which implies a shoe failure, rather than the annular failure which was the predominant theory of failure earlier in the summer.
Note the Admiral’s comment on where the mud and cement from the static kill went.

Absent of what we've done in top kill, the assumption is you would have to go in, pump mud and cement into the annulus. But that hardens. So you've got that locked down. And you will come in and drill again into the casing.

Once we get in there we will know how much of an effect we've had with the mud and the cement from the top. That could shorten and make more simpler the bottom kill. That was one of the reasons to do it, and also reduce the risk of the bottom kill. Exactly.

However, the final confirmation will not come until the relief well finalizes the kill, which is still the plan.

I have stated over and over again, let me be perfectly clear. I am the National Incident Commander. I issue the orders. This will not be done until we complete the bottom kill.

With the well cemented shut, once the pressure tests are carried out to validate the seal will hold, then the well can be considered effectively sealed, even though it is going to take another two weeks (one week to intersect, check and cement the annulus, then another week to do the same for the production casing) before the fleet of ships can disperse, leaving the well itself to history.

At the same time the fleet of ships that has been capturing the spill will move closer to shore, as the last of the oil that flowed into the Gulf is likely to be more evident now at some distance from the well.

The latest distribution of how the oil has fared is shown in this pie chart:


There will continue to be a lot of controversy over these numbers. Some of them are based on actual measurement, some on models, and the residual is a catch-all covering the difference between the estimated flow and the volumes in the other slices of the pie. I would still like to see the inside of the BOP, presuming that it will at some time come to the surface, to see how much erosion went on, and thus whether there was a build in the flow rate or, as has been suggested by the Admiral, a higher earlier peak in the flow.

It is welcome news that the well can now, if necessary, be left without any further risk of oil leakage into the Gulf. Given that the possible storms are multiplying, and that we are moving into the more intense period for hurricanes, the relief felt by most at having reached this stage (assuming that the cement proves out, or is – if necessary – re-injected with a finer grade to ensure a seal if not) must be tangible.

Potential storms and Colin (NHC)

It will also allow me to start looking again at some of the other concerns that are developing around the world that are of concern as we stare into the tea leaves predicting the available fuels for our energy future.

Deepwater Oil Spill - Cementing the well

The Deepwater well has now reached a point where the mud inside the well is applying enough weight to the fluid in the formation that the flow of fluid, when such exists, is now from the well back into the rock. The well is sufficiently secure that, just before 7 pm CST Admiral Allen issued the following press release:

Based on the successful completion of the static kill procedure and a positive evaluation of the test results, I have authorized BP to cement its damaged well. I made it clear that implementation of this procedure shall in no way delay the completion of the relief well.

In his press conference today Kent Wells described the steps to kill the well, and what is currently happening as the work moves toward sealing the well.

The crew is now running the drill pipe within the relief well, but must first run a test of the Blow-out Preventer (BOP). There is a regulation, which the other drilling rig did not follow earlier in the process, that is, no doubt, now being practiced.

The Transocean Development Driller II (DD II) working for BP, received one INC (Incidence of Non-Compliance) because it had not alternated between control stations for BOP testing. MMS regulations require that the regular 14-day BOP tests alternate between the BOP station on the rig floor and the remote station located at another site on the rig. On the DD II they conducted the BOP pressure testing only from the driller’s control station for the last two tests. They did perform function testing on the remote station, but the pressure testing was only performed using the driller’s station. MMS has ordered the rig to alternate control stations in the future. . . . . . in addition, as a condition of its drilling permit, the rig will be required to conduct increased testing of the BOP stack and Remote Operated Vehicle (ROV) intervention both on the rig and on the seabed.

I presume that it is this scheduled BOP test that is currently being planned. After it is over then the excess cement that is still in the casing will be drilled out. This will allow instruments to then move over the full length of the injected cement to ensure that the cement was placed properly (using a cement bond log – something that was controversially not done by Schlumberger before the well failure of the Deepwater Horizon). In addition there will be a leakoff test, to test the strength of the surrounding rock.

Simplistically the pressure in the bottom of the well is slowly increased until the fluid in the well starts to penetrate the rock, shown when the pressure no longer steadily increases as fluid is added. This is then used to determine the weight of the mud that will then be used to drill the last section of the well (to ensure that the well pressure isn’t high enough to reach that pressure that will fracture the rock, and lose fluid to the formation).

With that in hand the well will start the short advances, then be surveyed, then advance again, to ensure that the relief well remains on target to hit the original well, first along the annulus, and then to penetrate through the production casing to allow a cement seal of the whole bottom section of the well.

The static kill was carried out with a flow rate of 5 bpm, and Kent Wells noted the success that was achieved.

We were able to watch the pressure continuously and (see it) gradually decline. We were able to watch as the – if you remember, I mentioned the word we injected for the injectivity test, base oil. We were able to watch as the base oil and then the mud actually hit the reservoir. We were able to see (the well) pressure up, and then we were able to see that pressure come back down.

And these were all very encouraging signs. And then what we kept doing is we kept injecting it as five barrels a minute, injecting more of the oil that was in the casing and actually mud, and continued to inject it into the reservoir for a period of time to try to get – make sure we'd cleaned out all of the oil that we could out of the casing.

And so we pumped for a number of hours. And then as we got confident that we'd actually got the well into a static condition, we actually increased the rate up to 10 barrels a minute, and then ultimately 15 barrels a minute, and we did that to give ourselves confidence that, if we chose to go ahead with the cementing procedure, that we could actually pump at higher rates, because that will give us a more effective cement job. And so that went well, as well.

So we spent some extra time yesterday pumping more fluid in, just to give ourselves more information and confidence. So by the end of the whole process, we had injected about 2,300 barrels of mud, and a lot of that was actually designed at just cleaning out the casing and making sure that we could move forward with the cement job with confidence, if we choose to do so.

In earlier posts I had worried that injecting cement after the static kill could cause problems, because the mud might require higher pressures before it would flow into the formation, and this could cause the well to fracture (see the leakoff test comment above). However BP had designed the mud so that it would flow into the rock, as they have demonstrated, and thus would be displaced by any cement that was injected into the well to seal it, as the Admiral has now authorized.

The cap itself can’t be removed, since the pressure balance is achieved at sea level, not at the sea bed, and the system is being maintained, with small injections of more mud (75 barrels at 5 bpm every 6 hours) to keep the fluids mobile and stop any settling.

Again the injection of cement is likely to be an ongoing event as I write this post – so we will see what the morning brings. If they do run the cement, it is likely, as Kent Wells noted, that after the injection they will run a positive pressure test to see if the seal holds against higher pressures (without letting mud flow into the well), and then perhaps they will run a negative pressure test to see if, as they drop pressure above the cement, any fluid from below the cement makes its way through the cement and up the well.

Deepwater Oil Spill - start of the static kill

Progress on the relief well at the Deepwater Horizon well has now reached the point that BP have started the procedures for the top static kill of the well. There was a little delay in the installation of the casing for the relief well because, during the time that the well had been left untended during the last storm, the sides sloughed a little, and about 40 ft of debris accumulated in the bottom of the well. This was obviously more than had been expected, since the clearing run to remove this and condition the well took longer than originally planned. However that clean-up operation is now complete and the next step in the process, the initial flow testing of the original, now sealed, well to see how it behaves as fluid is injected, is now starting.

I am going to review some of the comments made both by Admiral Allen, and earlier by Kent Wells about the procedures that are now starting. I will also try and expand a little on the determination of what is happening as the oil, and then mud, are injected into the well.

Vessels located around the three wells in the Gulf (BP)


There are still a significant number of vessels around the wellheads of the three wells out in the Gulf. However the ones that are critical for the next phase of the operation are the Hos Centerline, the Blue Dolphin and the Q4000. However, in the best of circumstances the Hos won’t be needed, since it is largely there to provide a large quantity of mud, if necessary. The hope, however, is that it will not be needed.

It should take less than 2,000 barrels of mud to fill the well, and the Blue Dolphin has more than 8,000 barrels on board, so the Hos is more in the nature of insurance. Not, however, that the first stage of the process will use mud, instead it will inject oil back into the well.

To prepare for this, as Admiral Allen noted:

we had to remove all the gas out of the Q4000 riser pipe. We had to pressure-test the Horizon blowout preventer, critical in this process. We had to rig down the Q4000 production line to bring the hydrocarbons up and actually rig up for pumping operations that would allow us to put both oil and pumping mud back down.

Part of that involved making sure the yellow pod controls, which control the valves on the subsea portion of this work, that all the valves and the flanges have been tested to proper pressure ranges and that the pressure gauges that we're going to be looking at, they're going to be very, very important as we move forward, are all tested, calibrated and operating properly, and to make sure that we have backup and duality of measuring pressure.

There was a small leak in one valve, that had to be corrected on Monday, and the process is ready for the first phase of the test.

Both phases will feed fluid into the well through the kill line on the BOP, it is one of the purposes that the line serves in a conventional well. The fluid will initially be oil, and will be pumped very slowly (a barrel a minute) into the well. At this point, since the well has shown itself to be in good shape, apart from where the oil has been leaking into the well, the test has a simple goal.

Fluid flow path to the well (BP)

If the only exit from the well that is now open is the rock through which oil and gas were flowing into the well before the well was capped, then injecting oil into the well at the top, should force an equivalent volume of oil at the bottom of the well back into the rock.

The first test will therefore first find out if oil can be pushed back into the rock. By starting at a relatively slow flow rate the flow should start with very little additional pressure applied to the well (the science team have put a cap of 8,000 psi on the pressure that will be allowed in the well). After running for a short while at the slowest flow rate, the rate will be increased first to two barrels a minute and then to three.

The result should show that with little change in pressure, that the oil added is causing an equivalent outflow at the bottom of the well, and should (by looking at the pressure required for the flow rate) help determine how fast the well can be filled with mud (since the oil it is displacing has to flow back into the rock). The well flow will be kept slow for several reasons. One is that higher flows require higher pressures, and there is the bound that has been set; the second is that higher flow rates down the well will generate some frictional force that the fluid will also have to overcome as it moves down the well. Too high a value for the friction – which is additive to the driving pressure – and the well starts to approach the limiting pressure allowed for the exercise.

There is a third objective to the tests, but it is one that will be probably easier determined when the fluid is changed to mud. If the well had been completed properly then its structure would have an outside liner made up of a steel casing surrounded by cement, then there is a gap or annulus, then there is a central steel tube, known as the production casing, that is supposedly cemented firmly in place at the bottom of the well. The well has a leak at the bottom which is feeding oil either into the annulus, into the production casing or both.

By adding fluid at the top of the well, and seeing how the pressure changes as larger volumes of fluid are added, particularly with the mud injection, the changing pressure should show which column(s) are taking the mud, because the oil is flowing out of them back into the rock at the bottom of the well, and which are not.

As the mud injection continues the change in pressure (since the mud exerts weight on the bottom of the well it will lower the pressure needed for injection at the top) with inflow should tell the monitoring engineers, for the amount of mud injected, how long (roughly) the mud column is in the well. Knowing the relative cross-sectional areas of the annulus and the production casing, and the volume injected, this will allow the engineers to then know down which column the mud is displacing oil back into the formation. And since it can only do this if there is the leak at the bottom (since the cement should have sealed both), this information will be very helpful in telling those running the relief well what to expect when that well runs into the original one.

As the Admiral noted

What there should be is a slow pressure decline, and that would tell them that they're slowing overcoming the pressure of the hydrocarbons with the weight of the mud moving forward. That decline will be less with the amount of volume if it's in the entire annulus, so about five or six hours into this, the pressure readings are going to be very, very significant on whether they know they're filling the pipe, the casing, or the annulus moving forward.

At that point, once they have ascertained exactly what it is they're doing, they will finish putting the mud in. The fourth step, if it is decided, would be whether or not to put cement in. That would be done based on the results of the test and whether or not the mud is required to fill both – fill the drill pipe, the casing and the annulus.

Given that the evidence from the experience with the relief well is that the sides of the wells can slough into the well and that the annulus that the relief well is drilling into was left partially open so that it could have sloughed down onto the original cement, making it difficult to possibly ensure a good seal in that area, I am not sure that the cement injection would work well from the top, and might be better left to the relief well.

Fortunately the next major storm may go East of Florida, rather than into the Gulf, which may give more time for the RW to reach and do the final kill, but time is still not a friend in these operations. But the time required for the next phase should be relatively short. Again quoting the Admiral

They think it's going to take about four hours to evaluate the data from the injectivity test, in other words, to understand exactly what the pressure means, what the pump rates are, and what the maximum pressure that was measured in the capping stack.

It could be less, but they're assuming four hours. And then they're looking at about another five hours to do the initial pumping, start pumping mud in at two barrels per minute. That will start getting them to a threshold where they should be able to start – they have these curves on whether or not it's the annulus and the casing or just the annulus or just the casing and how the pressure should perform and decline.

So as they pump those two barrels per minute in over the next first five or six hours, they're going to try and discriminate exactly which pressure line they're on that would tell them they've got an issue with the annulus or the casing or both. That entire period will take about five hours, so you're four plus five.

Then, depending on – once they understand that, whether you have to fill the entire casing and the annulus (up and it splits), it could either be on the low side, take you about 33 hours to complete it, or as much as 61, if they have to pump enough mud and it would fill both the casing and the annulus. It kind of diverges at that point.

The next 24-hours should therefore be very productive, especially since BP has promised to keep us informed of the progress. Once the initial results are in, it is then intended to keep adding mud until the pressure at the top of the well falls to zero, meaning that the driving pressure of the reservoir has been balanced by the weight of the overlying mud. That will be the operation that will take the 33 to 61 hours.