Tech Talk - The latest Canadian oil spill

Time was that I used to write, on Sundays usually, a Tech Talk over at The Oil Drum where I would try and explain some of the technical issues involved in oil recovery from the ground. Now that the site has effectively gone away, and I have had my couple of moments of frustration trying to explain why it isn’t because of the end of the Peak Oil story (here and here), the need for the occasional technical explanation still exists, and I still enjoy the chance to explain something. So as time permits and the need arises I will continue the practice.

On this occasion the post is seeded by a note from Luis de Sousa (h/t Luis) who noted a story in Mother Jones. That story, in turn, fed from one in the Toronto Star and is about surface contamination of oil, coming from the underlying tar sands and emerging as a watery bitumen mixture over at least four areas in the Cold Lake region of Alberta. The story is difficult to report, since the contamination is centered within the Cold Lake Air Missile Range, where the Canadian military fires and tests live weapons. Unfortunately, as written, it seems to have some technical inconsistencies.

The oil migration was apparently started by underground extraction wells that are being used to extract the oil from the oil sand, without having to dig it up first. There are two main ways of injecting steam through wells down into the oil sands that can produce the oil. The one that is most commonly discussed is the Steam Assisted Gravity Drainage (SAGD) process, but the more commonly one used in the past is often known as “Huff and Puff.” I have described both of these in some detail in an earlier post. In this case the process would appear to be the older one, and as a refresher, here is what I wrote about it a couple of years ago.

Surface mining of oil sand can only progress so far before the gradually deepening seams of the sand become too deep to continue to economically mine them. At the same time the viscosity of the oil is such that it does not flow easily to a conventional type of a well. This is not a new problem for the oil industry, which has had to address issues with the quality of the oil that it finds coming out of a well more than once over the past decades. One of the more easily applicable methods for improving the flow characteristics of the oil is through heating it. (And a quick caveat, the quantities of heat that I am talking about at the moment are significantly different from those that are needed in treating oil shale, and I will come to that topic in a couple or three weeks).

The example of the effect that temperature makes on the ease with which a fluid flows that always first comes to my mind is of a visit to the Nurse’s cabin north of Montreal one winter, a long time ago, when after struggling through waist-high snow, we sat and poured whisky from a bottle left there, as we waited for the wood stove to heat the cabin. When we started the Scotch poured as though it was a heavy syrup.

Viscocity of an oil is something that we usually only think about when we buy the engine oil that we put into the car on odd occasion. Buying the right oil means either looking for the little label that has the right description or reading the manual to get the number. But the oil that we buy for the engine is rated in part on how it behaves at different temperatures. We want the oil in the engine to easily circulate around the parts, and lubricate them from the time that we switch the engine on. But if the engine starts cold, and the oil is too thick, then it may not move easily around the parts, which may run dry for a while and wear more rapidly – which is not good. However if the oil becomes too thin once the engine reaches operating temperature then it doesn’t act as a good lubricant, and again engine wear is increased. And so manufacturers of the oil will adjust the contents, depending where in the country they plan on selling the oil, and what the temperature variations the oil can expect to operate under there. (And this is why oil is sometimes bought with two numbers – as in 10W-30 – the first number relates to the cold start, and the latter the performance at the engine operating temperature. And the higher the number the more viscose the oil is under those conditions.)

A typical oil found up in the oil sands of Alberta is much thicker, and more difficult to flow under normal operating conditions than that used in a car. For the areas of the province that are too deep for surface mining the temperature is not affected much by the changes in surface temperature, but the ground temperature is still low enough that the oil is very viscose, and production from a normal vertical well is usually too slow to justify the expense of putting in a well.

So how can the viscocity be reduced? For a simple example, take an apple, which has fallen in the butter, and you want to clean it off. If you take the apple and put it under a cold stream of water the butter sticks to the apple, but if you raise the water temperature, suddenly the butter melts and runs off the apple. This happens best at about 185 degF, and if you were to turn a pressure washer onto a greasy surface you would find that it works better if the water is also heated above that temperature. (Some pressure washers are sold that way).

Think now, if you will, of little Johnnie (helped of course by Jessica) having raided the orchard and spread butter onto all the apples, gluing them together and filling the kitchen full, right to the ceiling. How do we clean the butter off and get it back without taking all the apples out and cleaning them one by one (which is sort of what they do with the surface mined oil sand up in Canada).

We could just stand in the hall and stick heaters up against the wall of apples, hoping that the heat would melt the butter and work its way back to the ones further into the kitchen. That sort of works, but burns the local apples and doesn't reach all that far. (They have tried setting fires inside oil wells, and we’ll get to that maybe next week). You could fill the kitchen with hot water, but while that washes out some of the butter, a lot of the heat goes into the apples and the water is cold before it reaches the back of the room. And the water doesn't have that much pressure to push the remaining butter off the apples.

What we need is something that will get through the gaps between the apples and keep its heat. So how about steam? So you go and get a steam cleaner (such as you use for carpet cleaning) and blow the steam into the apples. That works but as the butter starts to flow out it clogs the gaps and starts to re-harden except when the steam is right there. So you start to run the steam for a bit, stop and collect the butter that comes out, run the steam for a bit, etc. You can do this in an oil well and it has the exciting technical name of "Huff and Puff" (would I kid you?). To make the steam more effective it is heated to between 150 and 300 deg C. Where the rock is very permeable and the steam can, in time, work its way back through the particles (apples) this can recover a lot of our butter. But you still lose a lot of heat, which is expensive to generate, just in heating the apples.

The NETL shows how the process works, in three steps:
Huff

Soak

Puff - The 3 stages of the process as illustrated by NETL.

The problem is that this is still limited by the length of the borehole through the deposit, and because it is an intermittent process, it doesn’t give a continuous flow of oil.

In the current case at the Primrose Oil Sands project this particular leak came up under a body of water making it more difficult to control, but it was the fourth at the Primrose site, though earlier ones were in the Primrose East development. In their public statement on the issue Canadian Natural stated:

This spring bitumen emulsion was discovered on the surface and based on all the evidence gathered to date, we believe this rise to surface involves mechanical failures of wellbores in the vicinity of the impacted areas. A complete review is ongoing.

The location of the latest leak under a body of water seems a little hard to support that conclusion – though I am not that familiar with the project history.

What I do remember, however, from lectures that I have given on ground freezing when teaching ground control, was the great difficulty one can have in controlling the path of any fluid injected into the ground. I mentioned some of that in a post I wrote on permeability, some time ago. The gas used in the ground freezing is usually liquid nitrogen, and it is injected to freeze the ground around the injection point and along the path that the fluid takes. (In other words the reverse of that used in steam heating of the oil). But it has proved to be a very difficult process to control, because any small fissure in the ground can have a sufficiently lower permeability that the surrounding rock that all the fluid will flow to that channel. This is particularly a problem in the case of the oil sand, because if the steam finds an easy path to the surface (and the fact that this is the fourth instance suggests that the particular oil formation may be prone to such fissures) then as the steam migrates it heats and softens the bitumen so that it will flow with the steam, widening the channel and, over time, making the situation worse, if steam continues to be injected.

Fortunately, with the “Huff and Puff” steam is only injected for a short while, before injection stops and the oil recovery phase begins. Yet, in the latest case, that was sufficient to bring over 4,000 bbl of bitumen to the surface. It seems likely that the process will need to be modified to give better control to the steam paths, and the oil migration. This can probably be achieved by switching to the SAGD process, which is planned in later work at the project. In the interim they might want to steer away from using the technique in regions where the oil grade is higher, and there is the potential for the sand to outcrop or come close to the surface without a confining cap rock.

OGPSS - The Oil that lies Offshore California

Last week I covered some of the early history of the development of the oil industry in California, and briefly mentioned the difficulties in integrating an ongoing oil industry into a thriving surface community. I thought to take this ongoing debate offshore this week, since one of the remaining most productive regions in California (???*) is actually offshore. It is also where the “Drill, Baby, Drill” argument runs into fervent environmental opposition.

Oil and Gas Fields off Santa Barbara (CA Conservation )

The events following the Deepwater Horizon oil disaster in the Gulf of Mexico last summer were probably the first times that most folk realized that there are not only seeps of oil on land which have been used to show where oil might be found, but that these also occur out in the Gulf and in the ocean. Part of the discussion last summer was about identifying some of the plumes of oil found in the Gulf, to ensure that they did come from the Macondo well, and not from the natural seeps that continue to flow to this day. These seeps are also found off the coast of California, with the most famous being those around Coal Oil Point just off Santa Barbara.

Seeps off Santa Barbara (Bubbleology – the COP Seep Field )

The presence of the seeps is detected onshore through the oil slicks that appear on the sea surface, and the tar balls that wash up on the beach. And without seeking to defend the oil industry, they were coming ashore before there was a well offshore CA, and will continue to come ashore long after the wells are abandoned. (Not that this will stop the protests). Natural gas can often also bubble out from these seeps, and with recent concerns over climate change, this is helping drive additional studies of them .

As oil exploration spread up through California from Los Angeles it reached the town of Summerland and the early wells were drilled onshore. However producers noticed that the wells nearest the coast were the more productive and so, in 1887 H.L. Williams ran a jetty out into the sea some 300 ft, and sank an oilwell from it. It came in as a producer and, as the postcard below shows, before long there were several such piers running out into the sea, with the longest being some 1,200 ft. Other companies tried to access the oil offshore through slanted drilling from onshore wells.

Tinted postcard of the oilwells off Summerland CA

The first fully offshore drilling platform and well was carried out in the Gulf of Mexico in 1947, a region I will come back to later, but it provided the tool to help further develop the resources off-shore in California. The first offshore well in California was drilled in 1956. (Platform Hazel) (which seemed to attract fish ). It was removed in 1996). Unfortunately those early wells were plugged and abandoned as the oil ran out before current regulations were in place. And so there is some concern at present that the 400 wells that lie along the coast from Summerland to Santa Barbara may have started leaking – as there has been a recent increase in oil coming ashore.

(the wells) were left for dead, with a wide variety of rather inadequate capping techniques such as using logs, trash, telephone poles, and rocks to block up the oil-spilling sea-floor sores.

Acknowledging this situation, the county’s head of the Office of Emergency Services, Michael Harris, told the supervisors “The wells were either just abandoned or capped inappropriately … really whatever they could do to stop the leaking was used.”

The ongoing questions as to where the oil is coming from (old wells or from natural seeps) is therefore a continuing concern along the Western Seaboard. But it was not the leakage from abandoned wells that has had the greatest impact on American oil production. That came on January 28, 1969 in the Santa Barbara channel, when the third worst oil spill in American history (after the Deepwater Horizon and Exxon Valdez spills) occurred on the Union Oil Alpha platform.

pipe was being extracted from a 3,500 foot deep well. The pressure difference created by the extraction of the pipe was not sufficiently compensated for by the pumping of drilling mud back down the well, which caused a disastrous pressure increase.

As the pressure built up and started to strain the casing on the upper part of the well, an emergency attempt was made to cap it, but this action only succeeded in further increasing the pressure inside the well. The consequence was that under extreme pressure a burst of natural gas blew out all of the drilling mud, split the casing and caused cracks to form in the seafloor surrounding the well. A simple solution to the problem was now impossible; due to the immense pressure involved and the large volume of oil and natural gas being released a “blowout” occurred and the 1969 Santa Barbara oil spill was under way.

Around three million gallons of oil escaped before the injection of mud stopped the flow. Because the flow was so close to shore the oil reached nearby beaches along 35 miles of the coast, layering oil up to six inches thick onto them, and causing a catastrophe to local wildlife. Public outrage was immediate, and the Environmental Movement was given an immediate boost with the creation of the National Environmental Policy Act of 1969, and the formation of the Environmental Protection Agency (EPA) followed in 1970. Within California the Coastal Commission was formed, and the State Land Commission banned offshore drilling in coastal waters for 16 years. The first Earth Day was held that year.

However, further offshore (beyond 3 miles) the Federal Government has jurisdiction and the first Outer Continental Shelf (OCS) well had been drilled in federal waters in 1967 (Platform Hogan). By December 2009 that platform had produced 20.4 million barrels of oil and about 20.8 billion cu ft of natural gas, with 12 wells in production on the platform. In 2003 23 of the 27 platforms offshore were in Federal waters and all supported multiple wells.

Drilling multiple wells from individual platforms is common in this region, and, among other things has the advantage of limiting the obvious visual impact of the rigs on the view. There is considerable concern over new drilling in coastal waters, and even drilling slant holes from existing wells to reach oil has been frowned on by the Lands Commission. There are moves in the US Congress to encourage more development off California, but it remains very controversial. Further the recent controversy over the impact from hydraulic fracturing of gas wells has now reached Santa Barbara and is raising concerns, even onshore.

It is difficult, at this time, to predict the future for this region – environmental pressure is great in restricting further development within the coastal areas under State control, and there are a number of known fields that lie within that limit. Beyond it lies the OCS where the pressure of rising prices might help encourage further drilling, sadly emotion may have greater impact than reality. At the same time with all this potential activity, the reserves offshore are seen by the EIA to be falling. (H/t jjhman )



However, as JoulesBurn noted in commenting on my last post, 77% of Californian production now comes from Kern County, and so we’ll have to wander up to Bakersfield next before leaving California.

The BP Deepwater Horizon Oil Spill and Offshore Drilling Commission

Courtesy of MoonofA, I am able to tell you that this past weekend the final act in the closing of the Deepwater Horizon well was the placing of a steel cap on top of the well, after the top plugs had been put in place, and the well was ready to be abandoned.



And on Monday the Oil Spill Commission began two days of public hearings.

As part of this, the Oil Spill Commission has issued its preliminary conclusions which are:

• Flow path was exclusively through shoe track and up through casing.
• Cement (potentially contaminated or displaced by other materials) in shoe track and in some portion of annular space failed to isolate hydrocarbons.
• Pre-job laboratory data should have prompted redesign of cement slurry.
• Cement evaluation tools might have identified cementing failure, but most operators would not have run tools at that time. They would have relied on the negative pressure test.
• Negative pressure test repeatedly showed that primary cement job had not isolated hydrocarbons.
• Despite those results, BP and TO personnel treated negative pressure test as a complete success.
• BP’s temporary abandonment procedures introduced additional risk.
• Number of simultaneous activities and nature of flow monitoring equipment made kick detection more difficult during riser displacement.
• Nevertheless, kick indications were clear enough that if observed would have allowed the rig crew to have responded earlier.
• Once the rig crew recognized the influx, there were several options that might have prevented or delayed the explosion and/or shut in the well.
• Diverting overboard might have prevented or delayed the explosion. Triggering the EDS prior to the explosion might have shut in the well and limited the impact of any explosion and/or the blowout.
• Technical conclusions regarding BOP should await results of forensic BOP examination and testing.
• No evidence at this time to suggest that there was a conscious decision to sacrifice safety concerns to save money.

Needless to say these conclusions have not all been met with complete agreement, even the first has been challenged by Halliburton. The report on the test of the cement is revealing:

We asked Halliburton to supply us samples of materials like those actually used at the Macondo well so that we could investigate issues surrounding the cement failure. Halliburton provided us off-the-shelf cement and additive materials used at the Macondo well from their stock. Although these materials did not come from the specific batches used at the Macondo well, they are in all other ways identical in composition to the slurry used there. Chevron agreed as a public service to test the cement slurry on behalf of the Commission. Chevron employs some of the industry’s most respected cement experts, and it maintains a state-of-the art cement testing facility in Houston, Texas. Halliburton agreed that the Chevron lab was highly qualified for this work.

We attach Chevron’s report of its laboratory tests, and we have invited one of its experts to discuss that report with you at the public hearing on November 9.

Chevron’s report states, among other things, that its lab personnel were unable to generate stable foam cement in the laboratory using the materials provided by Halliburton and available design information regarding the slurry used at the Macondo well. Although laboratory foam stability tests cannot replicate field conditions perfectly, these data strongly suggest that the foam cement used at Macondo was unstable. This may have contributed to the blowout.

Halliburton has stated publicly that it tested the Macondo cement before pumping it on April 19th and 20th, and that its tests indicated the cement would be stable. When Chevron informed us of the preliminary results of its tests, we asked Halliburton to give us all of the data from all tests it had run on the Macondo cement slurry.

The documents provided to us by Halliburton show, among other things, that its personnel conducted at least four foam stability tests relevant to the Macondo cement slurry. The first two tests were conducted in February 2010 using different well design parameters and a slightly different slurry recipe than was finally used. Both tests indicated that this foam slurry design was unstable.

Halliburton provided data from one of the two February tests to BP in an email dated March 8, 2010. The data appeared in a technical report along with other information. There is no indication that Halliburton highlighted to BP the significance of the foam stability data or that BP personnel raised any questions about it. There is no indication that Halliburton provided the data from the other February test to BP.

Halliburton conducted two additional foam stability tests in April, this time using the actual recipe and design poured at the Macondo well. We believe that its personnel conducted the first of these two tests on or about April 13, seven days before the blowout. Lab personnel used slightly different lab protocols than they had used in February. Although there are some indications that lab personnel may have conducted this test improperly, it once again indicated that the foam slurry design was unstable. The results of this test were reported internally within Halliburton by at least April 17, though it appears that Halliburton never provided the data to BP.

As was brought out in the hearing, the resulting protocol that was implemented for the abandonment of the well at that time also put additional pressure on the cement.

BP’s temporary abandonment procedures at Macondo could have introduced additional risks, such as putting more pressure on Halliburton Co.’s cement job by removing mud and replacing it with seawater, setting the surface cement plug 3,000 ft deep, or deciding not to run a cement bond log test immediately, he continued. 

“What is of additional concern for us is that the procedures for temporary abandonment were changing up until the very last minute,” said Grimsley. “It is not clear to us why decisions on these procedures were changing in the days before the blowout. You have to make choices on the fly when conditions are changing offshore, but this apparently was not the case here.” There also was no indication that anyone at the rig called to shore in the three hours after the negative pressure test ended and the well blew out and said that test readings were odd, he indicated. 



Bartlit said BP’s decision to halt drilling nearly 2,000 ft short of the well’s original intended depth may have been based on concern that it had to keep mud and cement from leaking into adjacent formations, which could have fractured from unusually high pressure in the well. “They stopped because they were interested in well integrity and safety,” he said. Surprises in the reservoir can cause you to make changes which can affect what happens later. As near as we can tell, talking to experts, BP did the right thing here.”

Halliburton have issued a comment on the testing of the cement.

Halliburton has only recently received and is continuing to review the results, which it believes raises a number of questions. Halliburton is issuing this press release to provide information about the content and its preliminary views regarding Chevron’s cement testing report and the letter.

Halliburton believes that significant differences between its internal cement tests and the Commission’s test results may be due to differences in the cement materials tested. The Commission tested off-the-shelf cement and additives, whereas Halliburton tested the unique blend of cement and additives that existed on the rig at the time Halliburton’s tests were conducted. Halliburton also noted that it has been unable to provide the Commission with cement, additives and water from the rig because it is subject to a Federal Court preservation order but that these materials will soon be released to the Marine Board of Investigation. Halliburton believes further comment on Chevron’s tests is premature and should await careful study and understanding of the tests by Halliburton and other industry experts.

With respect to Halliburton’s internal tests, the letter concludes that “only one of the four tests” showed a stable slurry. Halliburton noted that two of those tests were conducted in February and were preliminary, pilot tests. As noted in the letter, those tests did not include the same slurry mixture and design as that actually used on the Macondo well because final well conditions were not known at that time. Contrary to the letter, however, the slurry tested in February was not “a very similar foam slurry design to the one actually pumped at the Macondo well….” Additionally, there are a number of significant differences in testing parameters, including depth, pressure, temperature and additive changes, between Halliburton’s February tests and two subsequent tests Halliburton conducted in April. Halliburton believes the first test conducted in April is irrelevant because the laboratory did not use the correct amount of cement blend. Furthermore, contrary to the assertion in the letter, BP was made aware of the issues with that test. The second test conducted in April was run on the originally agreed upon slurry formulation, which included eight gallons of retarder per 100 sacks of cement, and showed a stable foam.

BP subsequently instructed Halliburton to increase the amount of retarder in the slurry formulation from eight gallons per 100 sacks of cement to nine gallons per 100 sacks of cement. Tests, including thickening time and compressive strength, were performed on the nine gallon formulation (the cement formulation actually pumped) and were shared with BP before the cementing job had begun. A foam stability test was not conducted on the nine gallon formulation.

Their release concludes:

Well logs and rig personnel confirm that the well was not flowing after the cement job. BP and/or others, following the misinterpreted negative tests conducted after the cement job, proceeded to displace mud in the production casing and riser with lighter seawater, allowing the well to flow. Given these numerous intervening causes, Halliburton does not believe that the foam cement design used on the Macondo well was the cause of the incident.

The Commission web site has some beautifully rendered animations of the drilling process, among others. However, apart from taking over an hour for me to download, the drilling animation, among other things, shows the drilling bits creating holes larger than they are, and at the same size beyond the cased section as the well had before the casing was inserted. This does not happen, the well continues at the bit diameter, which is itself smaller than the internal diameter of the casing inserted into the hole over the interval.

And one other note, it appears that even though the moratorium on drilling has been lifted, no permits are available.

Ensco Offshore claims that since the ban was lifted Oct. 12, the government has not issued a single permit that would allow the resumption of any previously suspended drilling activities.

The government doesn't seem to dispute that allegation, saying in a late Monday filing that it must ensure applications meet regulations toughened after the Gulf of Mexico oil spill.

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 - nearing intersection, hurricanes, the TWIP and gold

Progress on the Deepwater Horizon well is going well enough that the Admiral considers it likely that the remaining work (other than plug and abandon) may be completed within the next four days.

just to summarize again, in the last 24-hour period we proceeded to go ahead and drill to the intercept. At the time we started drilling we estimated that we were 3.5 horizontal feet away and 50 feet away from the intercept. We drilled down (inaudible), we went through the drill string, we put in a ranging tool just to make sure that we wanted to calibrate what the ranging tool told us versus the equipment that now allows us to do some ranging measurements from inside the drill bit.

The drill string is now packed and it’s commenced drilling so the air at this moment as we’re speaking drilling that last 20/25 feet and they are almost touching the well at this time. That’s the report I got just before I came out here. When we do the intercept, which will be imminently I will say in the next 24 hours because they may elect to pull that drill bit back do another ranging run, which would add time. That’s the reason I’m not going to say it’s going to happen in the next hour.

Sometime in the next 24-hour period, we should do the well intercept. Once the well is intercepted, we’ll have to understand from the pressure differentials and the drilling fluids the nature of the annulus. Once that’s been determined decision, will be made on cement and then once it’s cemented the cement will have to adhere and be pressure tested.

That entire element from this morning I would estimate to be about 96 hours.

It is good that the remaining critical work will be done in this time. Right at the moment there are two Category Four hurricanes in the Atlantic (something that hasn’t happened since 1926). While both of those are likely to head North up the Atlantic, Tropical Storm Karl may turn into a Hurricane after it crosses the Yucatan, which may be some cause for concern because, when it re-enters the Gulf, it will be quite close to the offshore Mexican wells, where over 2 mbd is produced.

The possibility that global warming is causing an increase in hurricane intensity, if not overall numbers, is something that climate scientists continue to debate, but the possibility of another series of hurricanes of the likes of Katrina and Rita clobbering the oil supply/distribution network, regardless of cause, is something that the EIA has to consider, and that is the topic of the front page of the TWIP, this week. The EIA is introducing a Hurricane page, which will, on a hurricane specific basis, show the projected path of the hurricane, and the facilities that might be at risk.


As an example, they showed this illustration from the recent path of hurricane Earl ( a larger version is available here

And speaking of the state of the refineries, with the driving season over, inputs to the refineries have fallen, with most of the drop coming from imports, domestic production even had a slight uptick.


Gasoline production remains constant for the moment:


Although demand has begun its seasonal fall.


Fuel ethanol production continues to rise,


Some of that increased production is going into rebuilding stocks, which had been falling until recently.

Distillate demand is also rising seasonally, and is significantly ahead of where it was last year.


Speaking of things rising, I note the record price for gold on Tuesday, though it has since fallen a little. But it may show what happens when a product that is in demand, passes beyond the point of peak production.

And finally, speaking of mining metals, it appears that the trapped miners in Chile, will have a lot of job offers when they get out safely. We can only hope that this comes sooner rather than later.

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 - evidence of erosion

There was, apparently, no briefing today on the Deepwater Oil Spill. However RockyPaloma has put up a number of videos on Youtube showing an internal video inspection of the blowout preventer (BOP) with pictures of severe metal erosion.

Erosion within the BOP (RockyPaloma )

Some of it seems to have eaten around the plate of the shear ram, in at least one place, though I have not watched this in real time and am not sure of all the locations.

Possible erosion of the BOP wall around the shear ram plate. (RockyPaloma)


The video sequences include one of the shear ram plates retracting )

And one showing the deformed drill pipe surrounded by the eroded annular preventer, gives some indication of the extent to which sand in the oil/natural gas/water mix was eating out the internal surfaces of the BOP, and allowing the leak to increase in size, over time, a point that I made, quite early in the proceedings.

MoonofA has given a more concise, yet comprehensive picture of what the camera saw, together with a sketch of the ram assembly showing what the various parts are that are shown in the video. Ricx also adds an interesting question.

For those who need reminding of the structure of the BOP, PhilMB has put up a graphic section of the structure, so that you can tell which view corresponds with what.

The problem, of course, is that it is not clear when the different stages of erosion occurred. While there is some, there is not a lot of difference in wear surface patterns under differing flow regimes, containing different abrasive concentrations at different flow speeds. Because the erosion took place over the relatively long time intervals that it did, I am surprised in a way that it did not do a lot more damage than it did. Certainly some of the gaps might have been filled if the top hat “junk shots” had been continued longer than they were.

View of the crushed DP with surrounding erosion (RockyPaloma)

The investigation is, however, still in its early stages, and I imagine that there will be a lot more expert testimony on the structures (which likely means that at some time they will be cut apart to provide sectioned specimens). That is not going to be a simple short-term operation or investigation. And at the same time the pressure is now no longer on the relief well to seal in the oil and gas, so that too is likely to proceed at a gentler pace.

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 - what will the relief well find?

With Labor Day weekend, and the recovery of the blowout preventer from the Deepwater Horizon well in the Gulf of Mexico, the remaining parts of the operation are going to be increasingly directed at plugging the well, so that it can be abandoned. Part of this operation will be to ensure that the bottom plugs at the reservoir end of the well have adequately sealed off the bottom of the well. To do this the relief well will be used to intersect the top of the unlined section of the original well, and determine the condition and fluid content of the annulus surrounding the production casing at that point.

There was concern that when the relief well intersected this annulus and then injected fluid into it as part of a possible additional plugging process, that this would increase the fluid pressure in the annulus. This could have raised the fluid pressure to the point that it might have been able to flow past the top seal at the well head, that was separating the annulus fluid channel from the path through the production casing. It was along that second path that the cement travelled to plug the bottom end of the well. Now that a BOP has been installed that can handle 15,000 psi fluid pressure in the well, the concern that a leak in the seal could allow oil to flow into the Gulf is of less consequence. So the relief well can proceed.

At the same time, it is likely that work will continue to prepare the top of the well for additional plugging so that the well can then be abandoned, according to regulation.

One of the remaining issues that will be resolved when the relief well intersects the annulus is over what type of fluid is actually in that channel. In the original sequence of events, before the well failed, the well was full of mud, and then a cement plug was pumped down the center of the well, to the bottom, from where it flowed up the outside of the production casing, filling the lower section of the annulus. In the process it pushed the mud that was already in the well, up the annulus ahead of the cement. As that cement started to set, and filled the annulus, there should have been no flow path up the annulus to the well head. Thus the fluid in the annulus should still be the original mud that was in the well ahead of that first cement injection.

In a large part of the early thinking of how the well failed, there was a preponderance of opinion that the fluid flow in the well developed up through the cement in the annulus, from the oil reservoir. This then flowed up the outside of the production casing, dislodged the hanger seal at the top of the well, and flowed on up into the BOP and on. But when the second set of cement was sent down the well, to seal it after it had stopped flowing the cement, apparently following the path that the oil had taken in leaving the well, only flowed down the production casing to the bottom of the well, and thence back up to the oil reservoir. This suggests that the early thinking which would leave the annulus full of oil and natural gas, was not correct, and rather than oil, the annulus still holds mud.

We won’t know which is right until the well is intersected, but once the information is available, then it will make it easier to decide what steps to take to complete the final stages of plugging the well.

At present the DD2 is preparing for these plug and abandon procedures. It is also, given past problems, testing the new BOP to ensure that it is fully functional before the process restarts. With there being sensibly no further likelihood of oil from the well escaping into the Gulf, the pressure to complete the process has diminished, and there is no urgent need for the relief well to be completed (apart that is for such matters as the amount of money that both the drilling rigs are costing BP every day).
As the Admiral instructs, it will be interesting to see when, and what the relief well finds as it completes its mission in the next week or so.

Deepwater Oil Spill - BOP on board

First it was hoisted to the surface

Note the actual size of the Deepwater Horizon Blowout Preventer as it is held just above the support frame, after having been raised through the moon pool of the Q4000. Compare the size of the folk standing around. (The BOP is the large frame with the yellow legs on the corners, being held just above the red platform with the four vertical bracing colums).




And then it was lowered and latched into place on the red platform, that can help to move it and support it.

Meanwhile the LMRP that sat above the BOP is still on its way to the surface.

Deepwater Oil Spill - changeover completed.

Well, in one day the progress on the Deepwater Horizon moved significantly further towards the end. First the capping stack was removed from the well, and then, after a strong initial tug on the BOP, and transition spool, they were unlatched and moved away by the Q4000. As they left it was clear that there was no pipe, or hydrates under the BOP, though there was a thin film of a liner inside the BOP mount. This was then cleaned off, and a new gasket inserted. Once that was in place, then the new BOP (from the second relief well) was brought to the well, and lowered until it into place. (There is a Youtube video of the separation with the mount and BOP clearly separated by 3 minutes into the tape.)

Waiting for the new BOP

There was no drill pipe under the BOP, when it was lifted, nor any evidence of one or of any hydrates in the casing of the well itself. Thus some of the concerns that I had turned out to be unwarranted, but we did not know until the BOP was gone, what the conditions were likely to be. The next step in the process is to ensure that the BOP is working properly, and then the relief well will be completed at the beginning of next week.

With the "new" BOP in place.

That will likely be when we find out whether the annulus between the production casing and the well liner is full of oil or drilling mud. Given that a number of my concerns over the condition of the well have turned to be worse than the actual condition, I think I will hold off, at this time, on making any on that one.

Deepwater Oil Spill - stack off, but another incident

Once again I am indebted to MoonofA, who is giving a more detailed hour by hour report, of some of the incidents that I miss. Fairly rapidly on Thursday afternoon, the team of ROV’s and surface vessels moved forward with the removal of the existing infrastructure over the Deepwater Horizon well, with the intent of replacing it all with a functioning blowout preventer from the 2nd relief well (which now looks to be no longer necessary at all). One of the first steps was to move the methanol feed (used to dissolve and remove hydrates from the internal structures of the stack) down from the rams of the top stack to feed into the original BOP. This was used to ensure that the different parts of the stack, such as the rams, were able to function, when needed. And now, I presume, the hope is that it will similarly ensure that the BOP rams can function if needed.

Removing the line from the stack


Replacing line on the BOP

Once the feed line had been moved, then the Enterprise came in and lowered the latching device that has been floating just above the stack for the past few days. It did not take long (and by doing so did not convey the difficulty) to drop the cap over the top end of the stack, and not long thereafter the stack was released and lifted away from the underlying transition and the original BOP.

Approaching the stack

The more interesting part of the exercise will come when they start to lift the original BOP and the transition spool. There are a number of different scenarios that have been proposed, depending on what happens, and why, as the first lift begins. If they can lift the BOP with the underlying drill pipe (DP) still attached, then they appear ready to grab hold of the DP after the BOP has risen a short distance, and cut it off. This will make it easier to get the BOP to the surface, and means that a more conventional fishing tool can be used to capture, and bring up the remaining length of the DP. Toolpush, for example, mentions some of the options available.

Sliding into place

The capping stack was released at about 4:30 pm Central, whereupon Admiral Allen issued the following statementz:

"Under the direction of the federal science team and U.S. government engineers, BP has completed the capping stack removal procedure – an important step in the process to remove and preserve the damaged BOP. This procedure was undertaken in accordance with specific conditions I set forth in a directive authorizing the capping stack removal and BOP replacement last week. BP will continue to follow these required conditions for the BOP removal procedure, which is expected to commence this evening. I will continue to provide updates as necessary."

One of the problems with the feeds from the Q4000 is that they are not time-stamped, so that it is hard to know if the latest glance at the feed below the moon pool, which shows that the pipe hasn’t moved since I last looked, is current or not.

The other significant news today was of the fire on the Mariner Energy platform in the Vermillion block of the Gulf of Mexico. The fire now appears out and there was apparently no leakage from the wells that were connected to the platform. The platform is in 340 ft of water, and was fed by 7 wells collectively supplying 1,400 bd of oil and 9.2 mcf of natural gas, that is now shut in.

I note that they were apparently waterblasting the rig and repainting it. One of the things to be careful of in those cases is the static electric charge that can build up in water vapor around the operation. From the Coast Guard report:


However, at this time, that is just conjecture, and we will have to see what the investigation reveals.