The Gulf of Mexico oil spill, a review and some progress

The last two days has seen what appears to be some progress in the capping of the Gulf oil leaks. BP is currently lowering the 100 ton dome that is intended to cap and capture oil from the middle leak of the three. The open end of the riser was also closed on May 4th by fitting a valve to the end of the pipe and closing it. There are however, two different results from the different methods of treating the problem.

Plan for sealing the second leak in the riser.

The oil is flowing out of the well, through the Blow-Out Preventer stack (BOP) which is mounted on the sea bed and into the pipe that would have initially carried the oil to the surface and the drilling rig. When the blow-out occurred, natural gas flowed up that riser, and was ignited as it left the pipe, on the platform. To help with understanding I am going to include a couple of items that I have been sent to try and give a better picture of the overall situation as well as where we are today.

UPDATE: There is a new website that is now co-ordinating information for the Unified Command, and, among other things they have posted this picture from late last night.
Cap for the second leak being lowered below the surface.

The site also has pictures from one of the initial test burns.


Firstly, to help with some of the discussion on the structure of the rig there are a couple of pictures, first of a sister rig while aboard a ship, so that you can see the pontoons, and then with the Deepwater Horizon in the water.


When the rig is in the water the lower parts are submerged, and only the legs and platform are above the water.


When the fire began it was fueled by the initial flow of oil and gas that came up the riser from the wellhead on the sea bed, through the rig floor and engulfed the drilling mast. As I noted earlier, there is some indication that the ignition came after the power to the rig was cut, and then the emergency generators kicked in. However, initially, as can be seen from the form of the fire, the fuel was coming up the pipe from the sea bed.


Over time, the vessel began to develop a list, as the fire continued to be fought



And by this time, on the second day, the heat had burned out parts of the aluminum structure (see the helipad for example)


The rig, as you know, sank shortly thereafter.

I am going to add some illustrations to help those of us who don’t do this every day understand some of the terms and conditions that are referred to either in discussion or in the media. (Thanks to Roland V).

The first of these is the casing shoe, which is the piece of pipe that is threaded onto the bottom of the casing to help guide it into place.

Some of the components used for the casing and cementing of a well (Schlumberger)

The other area that I want to address is where the well starts on the sea bed. Remember that when we are drilling a well mud is used to cool the bit, clear the cuttings and stabilize the walls of the well. Well this normally flows up around the outside of the drill pipe, but when it gets to the sea bed it is captured between the casing that was initially set into the sea bed to stop if falling into the hole, and the high pressure drilling pipes. Thus when one looks at the area around the wellhead there are actually several pipes going into the ground.

The first of these is a relatively low pressure outer casing, that holds the surrounding ground in place as the well penetrates through it and down towards the rock with the oil in it. Within that there is a second, higher pressure tubing that will carry the fluids down to drill the well, which may be an additional 20,000 ft deeper (at 1 psi per foot rock pressure perhaps) and which must contain the oil and gas flow that will then come from that site. As an example, you can see, from this view of a Cameron assembly, through a window in the lower pressure casing to the higher pressure fittings inside.


It can also be seen in this drawing of a section of a competing design from Vetco

Vetco Subsea well assembly

Notice that there have to be seals between the high pressure drilling/production line and the lower pressure confinement casing/housing. Should high pressure fluid get into the space behind the outer casing, then it could be sufficient to crack it, and there is not always monitoring equipment in place, subsea that can check to see that this has not occurred.

There is also a passage so that the drilling fluid which flows down the central bore to the bit, can also has to come back out of the hole, and be confined as it is carried out of the well and back up to the rig where it is cleaned of cuttings and re-circulated.

It should be born in mind that the BOP sits on this assembly, and that the lowest leak is about 50 ft above the BOP, so that there are apparently no leaks in this section of the structure, as far as I can determine, at this time. The current condition of the riser above the BOP has been badly distorted by the collapse of the pipe to the sea floor. And the difficulty in fitting a cap over the assembly can be estimated from the condition of that area.

Photo of the top of the BOP (I have color corrected the image)

When the production casing is floated into the well the high-pressure drill pipe is removed, and the production casing floated into the well. It will have the assembly shown in the earlier picture, and will be sealed at the joints along its length so that the cement flows down to the shoe, and then fills the bottom of the well, and then flows back through the gap between the production casing and the rock walls, displacing the mud and filling that gap. The intent is to ensure that all the oil and gas will be forced to flow through access holes that will later be inserted through the production casing and the cement liner, using shaped charges.

There are a couple of considerations when the wells get this deep, the first being that the rock is very hot at that depth, and so the cement chemistry has to be carefully controlled to ensure that it stays liquid long enough to totally fill the gap that it is being injected into. The second area of concern lies with the pressure at which the cement is injected. Because the rock is under a lot of pressure initially, and can also be quite weak, the cement must be injected at a pressure that will be enough to drive it up along the gap, but not at too high a pressure. If the pressure is too high, then the rock around the well can be cracked. In that case some of the cement can be pumped into the crack, and the full volume fill may not be achieved, and the circulation path for the cement back to the well head may be lost.

The shape of the wiper plugs are slightly different to those that I showed in the earlier post.



The plugs are activated by first causing the plug releasing ball to be locked into the plug, sealing the flow passage, and then the pressure of the cement/driving mud will push the plug down the casing, wiping the walls as it goes. When the plug gets to the bottom of the well, the ball in the bottom plug is pushed out, and this allows the cement to flow into the gap (annulus) around the casing.

Some of this additional explanation, as I have said, is more to help fill out the background to the ongoing story.

At the present the large cap is being lowered to the second leak, and we may not know if this works until Monday. It has one advantage over the first step in the process. When the initial seal was put over the end of the riser, it closed the open end of the pipe. However the riser was split in two additional places. It is the intermediate leak that is the current target. When the pipe was capped the pressure driving the oil up out of the ground did not change. As a result, since the other two leaks are still open, all the oil that was going out of the three holes is now flowing out of two.

However when the intermediate cap is placed over the riser it will capture some of the oil, and depending on how the pressure in that cap is controlled, by drawing the oil to the surface, it might be possible not only to capture that portion of the spill, but also to reduce the pressure at that point a little, relative to the third split, so that the flow from it is also reduced a little.

It has been suggested that this idea is relatively novel, and the patent on the idea is relatively recent about 2000) though it appears to have been quite successful at shallower depths. The technique is a variation on the Riserless Mud Recovery System (RMR) that has been successful in a number of earlier wells, though at shallower depths. We will wait to see how it works this time, though I can't at the moment, see why it should not.

Ash in Iceland, and the oil spill in the Gulf

There are now two stories that are developing that are competing for my attention. Given that I am hoping to be flying on Thursday, the increase in activity at Eyjafjallajokull in Iceland, is of concern and there is more information available on what is going on in the Gulf of Mexico.

Earthquakes around the eruption site in Iceland (Iceland Met Office)

As a result the ash cloud has grown and flights from Ireland and now Scotland have been grounded. It now depends on the wind directions as to what additional impact this increase in activity might have.

UPDATE: Despite some continuing earthquakes at the site, the ash cloud is now considered no longer a threat, and flights will resume after lunch. One can therefore turn attention back to the Gulf situation, where the first major attempt to reduce the leak is underway as the first dome, built to capture the oil from the major leak, leaves Port Fourchon.


This, the first of the three systems that BP hope will be able to cap the leaking riser has been build and will be shipped out today. There are three points at which the riser is leaking oil. The main leak is some 600 ft from the well head apparently. Part of the concern as to how well it will work, even if it does get put in place by the end of the week, lies with the relatively soft seabed at the point where the cap will be placed.

Nate Hagens has a good description of what it intended, showing both the plan for capping each leak:

How it works
•

The system is made up of a 125-ton, 14’ x 24’ x 40’ structure that will be set on top of the largest leak source. This leak is located at the end of the riser, about 600 feet from the wellhead.

• Equipment at the top of the system is connected to a 5,000 foot riser that will convey the hydrocarbons to the surface ship, the Deepwater Enterprise.

• Once in place, oil will flow up into the containment system’s dome to the surface ship.

• Once on the surface ship, the hydrocarbons will be processed and oil will be separated from water and gas. The oil will then be temporarily stored before being offloaded and shipped to a designated oil terminal onshore.

• The Deepwater Enterprise is capable of processing 15,000 barrels of oil per day and storing 139,000 barrels.

• A support barge will also be deployed with a capacity to store 137,000 barrels of oil.

• This system could collect as much as 85% of oil rising from the seafloor.

and there is a picture of the cap itself:

Source Nate

While the impact of the spill has not stopped other companies who are drilling in the Gulf. it has caused the Governor of California to shelve plans for off-shore drilling in California, for the present.

The report from a fisherman who was fishing near the rig at the time of the explosion states that the rig first vented water, and then natural gas, and that after the lights on the rig went out, the explosion came possibly as the emergency power generator kicked in.

There has been some significant attention paid as to whether the rig should have been fitted with an acoustic remote control system for the BOPs – though in one discussion I heard there was some confusion as to what this would have changed on the rig, since there were BOPs in place. The acoustic system has the following benefit:

The ACS system is a redundant receiver/transmitter for communication with the rig through acoustics. It is interfaced to the BOP control pod so that different sets of emergency functions can be executed to shut down the well and avoid a pollution. If the regular umbilical is broken and normal communication with the BOP is not possible, the ACS is the last and only means to shut down the well. If a function is executed from the ACS, signal goes to a solenoid that activates a big valve on the BOP; the valve is then energized by air pressure bottles on the BOP.

In this case that doesn’t seem to be likely to have helped, since there was, apparently, a signal on the rig floor that the BOP had activated, though obviously it had not worked the way it was intended. The reason(s) for the BOP failing to work as anticipated is still a matter of conjecture.

UPDATE: There does now appear to be some conjecture as to whether the BOP was, in fact, activated before the rig lost power, and thus whether it was the damage that the BOP then took, which stopped them from working, rather than the alternative which has also been suggested, that the system was not powerful enough to shear through the sections of pipe within it at the time of the failure.

However there still remains the question as to how the oil and natural gas managed to penetrate into the well after the production casing was cemented into position. Haliburton issued a statement noting that the cementing of the string was completed 20 hours before the incident, and that the integrity of the casing (I presume including cement) had been completed. There are thus now a multiplicity of folk that are being considered potentially to have some part of the blame for the incident.

With both the Icelandic volcano and the oil flow in the Gulf, we are in a period of waiting for what will happen next. Given that I will, volcano permitting, be flying back to the States later in the week, and am starting that journey, posting may be a bit shorter for the next couple of days.

Gazprom and Ukraine - natural gas and the shale gas potential

Well now that is interesting. Quietly, while everyone’s attention was, increasingly focused either on the British Election or the oil spill in the Gulf (this was before the attempted bombing in NY) Russian Prime Minister made one of those almost un-noticed Friday announcements. He suggested that Gazprom, the Russian gas company, merge with the Ukrainian natural gas company Naftogaz.

In February the election in Ukraine switched the country from a Westward leaning Administration to one that favored Russia This could be one result of that, and it has a couple of implications. Firstly it ties the country much more tightly to Russian energy strings. Secondly it stops the embarrassing headlines that have occurred in recent winters as Ukraine and Russia have quarreled over the price Ukraine will pay for its natural gas.

The statement has apparently caught many Ukrainian administrators a little off guard. They might perhaps want to take the hint.

“It’s no secret that Russia continues work on its two pipelines by-passing Ukraine, specifically the South Stream project, which is soon to take off the ground. We’ve finished preparing all legal documents. What will this project mean for Ukraine? Serious losses,” Peskov explained. 


“Ukraine is interested to have a co-owner, Gazprom, for its Naftogaz. On the other hand, Gazprom is interested in Ukraine’s pipelines undergoing modernization and operating at full transit capacity,” the Russian official argued. 
Gazprom wants to merge with Naftogaz as it will provide a guaranteed route for meeting Gazprom’s obligations with regard to clients in Western Europe, the official said.

The first paragraph is, I suspect, just to ensure that Ukraine understands the underlying ground rules. And it is reported that this was no sudden whim, but rather has been under consideration for some time.

"We have talked about integration in the nuclear field. We are prepared to do the same in the gas field," Putin said. "I propose merging Gazprom and Naftogaz."

Although a spokesman for Azarov described Putin's comments as "impromptu," Putin's spokesman, Dmitry Peskov, said the proposal was in fact "a thought-out, calculated proposal."

Such a merger would allow Moscow to control its own gas transit to Europe, 20 percent of whose gas imports flow through Naftogaz's pipelines.

One point that is perhaps adding a little momentum to the discussion is the growing interest in gas shale and other resources. Gas shale may make Poland independent in energy and there is Western interest in providing some support.

EuroGas, Inc. today announced that through its subsidiary, EuroGas Polska sp.z o.o., it has entered into a confidentiality agreement with Total E&P Activites Petrolieres (Total), a wholly owned subsidiary of Total S.A., one of the world’s largest oil companies. The agreement was entered into in connection with the evaluation and possible acquisition by Total of certain rights held by EuroGas Polska’s wholly-owned West Ukrainian subsidiary in an onshore region in Western Ukraine. Total has also been evaluating the Bieszczady concession in Poland, in which EuroGas owns a 24% interest.

These properties are, however, coal bed methane related, and thus more readily accessible.

But at the same time there is a potential to break the dependence on Russian natural gas.

The International Energy Agency has estimated that Europe, which gets 25 percent of its gas from Russia, has around 35 trillion cubic meters of unconventional gas reserves – half of which is in shale. That’s around six times its remaining conventional gas reserves.

Energy giants such as ExxonMobil and ConocoPhilips are parked in Ukraine’s backyard. ExxonMobil is already drilling in Germany, ConocoPhillips is exploring in Poland and Austria’s OMV is test drilling at home.

The new technology requires work in wide-open spaces, making it more suitable to a country like Ukraine, which could possess some of the most promising shale deposits, than densely-populated Europe.

Russia had already agreed to lower the price it charged Ukraine for natural gas by 30%, provided it extended the lease for the Russian Black Sea Fleet.

As for Poland, it was at the end of last year that the energy advisor suggested that they could be self-sufficient in 4-5 years.

We already know ConocoPhillips, Exxon Mobil and Marathon among big players (and there are plenty of independents: Aurelian, San Carlo, BNK, 3 Legs etc)are investing in Poland. December 9 saw what should be the story of the month, where the energy adviser to the Polish Prime Minister predicted enough gas to export in 4 to 5 years.

The whole of Europe is undergoing a geological re-evaluation to determine the potential for natural gas from shale, and with the high cost of developing some of the larger deposits in Russia, thinking particularly of Yamal and Shtokman, shale may also be attractive to Gazprom.

Shale gas has even fueled interest up in New Brunswick

North of the border, oil and gas companies are beginning to pour money into surveying, drilling and producing gas from land in British Columbia, Alberta, Saskatchewan, Quebec and the Maritimes in the hopes they'll discover the next jackpot.

In March, New Brunswick issued its largest tender to date for oil and gas exploration - more than one million hectares of land - to Southwestern Energy Co. (NYSE:SW), a Texas firm known for pioneering exploitation of the Fayetteville shale in Arkansas for natural gas.

The Canadian division of Houston oil and gas major Apache Corp. (NYSE:APA) is interested, too, and plans on drilling two wells this summer for shale gas near Elgin.

But this international move to indigenous resources does not install confidence in the Kremlin that they can sustain the markets which they need to generate the funds to support their budgets. And so, in the hope perhaps that the change in Administration in Ukraine will help them, they have begun to possibly look at other ways of keeping themselves in business.

Progress on the Gulf oil leak and comments on cementing pipes

BP held a press conference yesterday in which they reported on progress in trying to stop the oil leak in the Gulf of Mexico, following the blow-out and sinking of the Deepwater Horizon. The well was in the final stages of being closed down, after having been completed, so that the initial drilling rig could leave the site. This meant that the pipe that would ultimately carry the oil and gas to the surface, the production casing string, had been put into place. To hold that pipe in place, and to make sure that it is sealed so that no fluid can flow into the gaps between this tube and the rock walls left by the initial drilling of the hole, the casing had been cemented in place. I am going to repeat part of the post where I talked about that, to explain what this involves. I begin as the hole is still being drilled.

As the bit goes deeper we add additional lengths of drilling pipe to form the drill string, and the bit penetrates through rocks that are of different types and some of these will have fluid in them. Water, whether fresh, which might be the supply for a local community, or salt, is quite common. The hole cannot be left open any longer, because the water flowing from the surrounding rock into the well will dilute the mud, so that it no longer works as it was supposed to, plus, we might start losing some of the drilling fluid into the surrounding rock. Plus different layers of non-drinkable water can work back up the well into the drinking water aquifer.


To stop this from happening we have to stop drilling and seal off the rock on the sides of the well from the well itself. This is known as casing the well, and running casing will hopefully (but not always) be only needed once before we get to the bottom of the well.

So we pull all the drill string out of the hole, remove the drill and lower steel pipe into the well to encase the well, from the bottom of the conductor pipe down to where the bit has found (and hopefully drilled through) the rock that is giving us the problem. (Hence the name casing). Having this continuous length of casing in the hole will likely stop, say water, from getting in and diluting the drilling mud, but if this was all that we did, then it would still leave a problem, since the steel pipe does not completely fit up against the rock wall created by the drilling bit. In other words there will be a gap between the casing and the rock wall, that will allow fluids to travel up or down. This gap has to be filled, and the filler is normally a special form of cement.

The way that the cement is placed is simple in principle, but a fair bit more difficult to do properly and effectively. Think of the long thin tube of casing, filled with a cement that acts something like toothpaste. This cement has to be pushed down the tube so that it squeezes out of the bottom and then flows back up between the casing and the rock wall, filling all the gaps as it is pushed back up to the top or surface. (Hence the name surface casing). Particularly when this casing is run, it is important that the gap is fully filled. This is because this is the casing that seals the well from local groundwater, used for domestic and industrial supply. Since the cement will move more easily thorough a larger passage, than a very narrow one, this gap has to be above a certain minimum size. Small centralizers will be attached at points down the steel casing to keep it in the middle of the hole, rather than pressing up against one of the walls (since this might leave an open channel up through the cement). There are also “scratchers” which are put on the casing so that when it is rotated in place it will scratch the walls of the borehole and remove any mud cake that might have formed, so as to give a better bond between the cement and the rock wall.

Cementing plugs

A small plastic plug (the bottom plug) is put into the casing ahead of the cement. This separates it from the mud that is already in the hole. It is fitted with wipers, that clean mud from the walls of the casing, and it is pushed down to the bottom of the casing by the cement that is pumped into the well behind it. There are some pictures of some of the tools and descriptions of the process here, here and here.

Once the bottom plug gets to the end of the casing, there are ports it passes that allow the cement to flow out of the casing and back up the outside. Once the cement has been pumped into the casing a second, top plug, also fitted with wipers, is put into the casing and this is then pushed down by the conventional drilling mud. As it is pumped down it forces the plug down, and the cement out and back up to the surface. Because of possible variations in hole size and other possible problems, perhaps about 50% more cement might be pumped into the well than the calculations might suggest. When the top plug hits the bottom plug, then there is a pressure spike at the pumping station, telling the operator that it is finished. The rig then waits on cement (WOC) until the cement is hardened. The drill pipe can then be put back in the hole and drilling can restart.

Illustration of a cased well

But whoops, the bit won't fit in the hole any longer! For the sake of discussion lets say we ran half-inch thick casing. And that we had an inch of cement behind it all around the casing. Then the hole we have available to get the drill through down to the bottom is now only 6-7/8th inches in diameter. So we now might use a 6-5/8th inch diameter bit to continue drilling (since we don't want it rubbing against the casing wall).

If we run into another layer of problem rock as we drill down to the bottom of the hole, then we are going to have to run another set of casing. This is known as intermediate casing, and the process is the same, and it leaves us with an even smaller hole through which to get a drill bit through.

That describes a little of the process of how a casing is cemented in position. The well that the Deepwater Horizon had drilled had reached the zone where the oil was, and in preparation for leaving the site had, as I mentioned above, run in the production casing. Let me add the post on well completion to explain this a little more.

There are a number of different steps, after the well has reached total depth that have to be gneo through before we can finish what is commonly called, the completion, of the well. At this point in the process the bottom of the well is still an open hole. And one of the first things that we do is to flush out the drilling fluid, and then clean the walls of the well – firstly be washing the remaining mud from the well down in the production zone. That means that the rock wall is exposed, just as it was drilled. There are several issues that can come about as a result of this. The first is that the rock we have drilled into can be fairly weak. This is one of the peculiarities of geology. To a degree the richer in oil the rock is, the weaker the rock will be. (And that also holds true for oil shale - of which more at a later date). Why is that?

Well let's talk a little about the rock structure, particularly in this post the porosity that it has. (I’ll talk about permeability next time). There are, simplistically, two types of rock, that oil is usually found in and for now, to make a simple generalization, I am going to call them sandstone and carbonate (as I said holding shale until a later time). Sandstone rock is made up of relatively large grains that are glued together at the edges with various different types of natural cement. The grains do not fit that well together (think apples filling up a room, and connected where they touch). We call the gaps between the grains, the pore space of the rock, and it is these gaps that the oil fills up to form the reservoir. And so we can calculate the "free volume", as it were, of the rock as the (relative amount of free space in the rock, you can get this by subtracting the weight of the rock from the weight of the same sized piece cut from solid quartz and it will tell you how much empty space there is in the rock, and thus, how much oil there could be in that volume.

Section of sand with oil in the pores –this is actually an oil sand, so the grains aren’t that well cemented together. (Syncrude)

So say we had a core that weighed 144 lb/cu ft and the weight of solid quartz (flint) is 220 lb/cu ft. Then only 65% of the rock (144/220) is solid rock and the remainder is what is known as pore space. Now these holes can be connected or totally separated, with each pore surrounded by a solid piece of rock. Normally the percentage given is reversed, i.e porosity = proportion of void space to total volume, or in this case 35% of the total volume is not rock. (Another picture showing porosity of a sandstone can be found here. Now in the reservoir rock this space is going to be filled with a fluid, either gas, oil or water. For now let us assume that it is filled with oil.

What I have described so far is known as primary porosity,i.e. that which is created by this initial structure of the rock. With carbonates more than sandstone there is a secondary porosity, and this is the porosity induced by rock movement and the dissolving of channels and holes in the rock by the movement of fluid over the rock through the millennia. Again put simply the oil found in a sandstone will occur between the grains of the rock. In the case of the carbonates, which normally have a much smaller individual particle size, the oil is more often usefully found in the cracks and joints formed were the rock bedding planes were created (and which can be seen in exposed rock in a lot of road cuts along the highway).

The voids and spaces in the rock are also formed from the spaces from what might have been old coral reefs, or where water dissolved holes through the rock. But sometimes the two methods of formation mix, and I would like to quote from Kenneth Deffeyes book "Hubbert's Peak" (my favorite text as an explanation of the geological case).

Fine grained calcium carbonate mud usually gets consolidated into massive limestones, usually with little or no porosity. . . . . . . .About 10 percent of ancient limestones do have porosity. . . . . . .Most massive and nonporous limestones contain textures made by invertebrate animals that ingest sediment and turn out fecal pellets. Usually the pellets get squished into the mud. Rarely do the fecal pellets themselves form a porous sedimentary rock. . . .I twisted Aramco's collective arm for samples from the supergiant Ghawar field. . . . .Examining the reservoir rock of the world's biggest oil field . . .a small part of the reservoir was dolomite, but most of it turned out to be fecal pellet limestone. I had to go home that evening and explain to my family that the reservoir rock in the world's biggest oil field was made of shit.

So there you have it. And the reason for the quote is that the rock at the bottom of our well can be very weak, and may be left in poor shape by the oil drilling bit that just passed it by. Now remember it is this wall around the hole that is the barrier through which all the oil in that rock must pass to get into the well. So before we leave it we have to ensure that it is in as good a condition to allow that flow as possible. (Hence the reason for the removal of the mud and the cleaning of the wall). We also have to isolate the production zone from the rest of the well, and we do this with what is known as a completion or production packer.

Production packer (B.J. Services ) - the three rings swell out and fill the gap (pack it) between the tool and the rock wall of the hole acting as a seal to separate the well below, from the well above – note the internal pipe to allow flow from the underlying part of the well.

One of the problems is that the drill bit may have overly crushed the rock, so that fine carbonate particles are pushed into the cracks and pores of the rock, right around the bore. These can block the passages that will allow the oil to enter the well. And so, in order to get rid of these particles, a strong acid can be poured into the bottom of the well. This acidizing dissolves these fine particles and opens up the cracks leading out into the surrounding rock, so that the oil can flow into the well bore more easily.

Process of isolating and acidizing the formation.

Another problem is that the rock may be very weak, since a lot of its strength comes from the oil that fills the holes within it. This oil only provides strength as long as the rock is totally confined on all sides, but when the pressure is removed on one side (think of popping a champagne cork) then the oil can flow away, taking the support for the surrounding rock with it. If the rock bridges that are left are weak then they can crush. This will cause the crushed rock (sand) to mix with the oil, which will require a de-sanding process at the surface, but it will also close some of the passages through which the oil is flowing to the well. A well operator that speeds the flow of oil out from the rock around the well, can reduce the support that the oil gives to the surrounding rock to the point that it crushes, and permanently reduces oil flow into the well. We can put in a screen that will hold the rock in place, but allow the oil to seep through slots in the screen wall.

Completion screen

Or, to stop that rock crushing from happening and to reinforce the rock , we can pump a layer of concrete into the bottom of the well, cementing a steel liner into the rock, just as we cased the well higher up the well. The steel liner, or production casing, has, however, one problem. Once it is cemented into place, there is this hollow tube all the way to the surface, but there is no way that the oil can get through the cement and the steel into that passage.

And this is where Her Majesty's Explosive comes in. Small, specially designed, explosive charges, known as shaped charges are now put together into specifically designed charge packages, and lowered down into the well into the completion zone.

Arrangement of shaped charges (the yellow cylinders) – when the explosive goes off the cones collapse and small liquid metal jets shoot out of the open end, through the casing, concrete and into the rock, creating a channel. (Core Labs)

Here they are detonated, sending small jets of metal against the wall of the casing and perforating the steel and concrete into the surrounding rock. There is an animation that shows the jet being produced (see also information here) .

Representation of shaped charges firing and penetrating the casing, cement and wall (OSHA

At the time that the explosion occurred on the oil rig, it appears that they had cemented the production casing in place, and were cleaning the mud from the well, prior to putting a temporary cement cap at the top of the well. This would allow them to leave the site (abandon the well), with the well ready to be connected to the pipes that would more permanently carry the oil and gas from the well.

Thus this rig would not carry out the perforation of the well that I have just described, and the production casing should have been surrounded by a cement jacket, that would help seal, temporarily, the bottom of the well. It is the condition of this cement that is, I gather, why Haliburton, who were responsible for that part of the operation, are now in the picture.

The latest report from Upstream, suggests that there have been a number of attempts to get the current BOPs on the well to work, and that they may be providing some restriction to the flow, or this may be coming from the kinks in the riser above the BOP. However they have cut off the riser to give a better target, and they will do this again before lowering a new BOP arrangement that will “stab” onto the initial structure, and allow them to possibly seal the well with that (depending on how good a seal they can achieve with the stabbing operation – these are normally fairly tight).

They will still have to drill the relief wells, and are apparently already drilling the first well, while a second rig is completing another well in the Gulf, and then will come over and provide a back-up to the first in drilling a second relief well.

Unfortunately I am carrying a new laptop, and I forgot to bring the passwords that allow me to reactivate Strata, which is the modelling program I use, and so won't be able to put in new illustrations until later in the week, Sorry!

Further comments on the Gulf of Mexico oil well disaster

The oil spill in the Gulf is continuing to get worse, and there are some questions that have been raised on what could have gone wrong, and how it can be fixed. I am in the same position as most, in regard to getting information – it comes from news reports, in the main. But there are some points that can be picked out as the focus of those reports switch to the impact that the oil is going to have on the coast and businesses that are going to be severely damaged. But there is enough information now available to draw some conclusions.

Pictures of the oil flows (Drillingahead )


Firstly, in regard to the post that I put up earlier about the blow-out preventer not working effectively, an early story noted that the BOP had recently been tested (thanks Gail).

Mr. Hayward said the blowout preventer was tested 10 days ago and worked. He said a valve must be partly closed, otherwise the spillage would be worse.

There are a number of things that can go wrong with a blowout preventer, said Greg McCormack, director of the Petroleum Extension Service at the University of Texas, which provides training for the industry.

The pressure of the oil coming from below might be so great that the valves cannot make an adequate seal. Or in the case of a shear ram, which is designed to cut through the drill pipe itself and seal it off, it might have encountered a tool joint, the thicker, threaded area where two lengths of drilling pipe are joined.

Still, Mr. McCormack said, “something is working there because you wouldn’t have such a relatively small flow of oil.” If the blowout preventer were completely inoperable, he said, the flow would be “orders of magnitude” greater.

However oil is now flowing through the BOP and out into the water immediately above the well site on the sea bed. When the site was visited by a small remotely operated vehicle with cameras they showed(see below) that the riser, the pipe that normally carries the oil from the sea bed to the surface, had kinked over when the rig sank, and oil was coming from three places:

The Coast Guard said it had not detected oil coming from the well Friday and assumed post-accident efforts to activate the blowout preventer “a huge stack of valves sitting atop the wellhead on the sea floor” had been successful.

But later trips by the remotely operated vehicles (ROV’s), discovered oil shooting from the end of the pipe-like riser that had connected the rig to the blowout preventer.

A second, smaller leak was found in a section of drill pipe near the wellhead.

That 21-inch-diameter riser had become detached from the rig when it sank. In the process, it was folded over at a 90-degree angle just above the wellhead, which had the effect of kinking it like a garden hose and constraining the flow of oil from the well. It now sits in a long, meandering mess on the ocean bottom. This helps explains why oil was not initially thought to be seeping.” . . . . . . The preferred option, he said, is still to find a way to engage the blowout preventer. That fix, if it works, could be handled in a matter of days, he said.

But if that doesn't work, the other option is to drill a deep “relief” well into the damaged well and stem the flow of oil, though that option could take several months, Suttles acknowledged. He said his team would spend the next several days trying to determine the best method.

The problem lies, in part, with the capabilities of the ROV’s and their ability to get access to the well site on the sea-bed.
There is a report from a survivor (h/t Fractional Flow) that says that the well was shut in and they were going through the process of separating the rig from the well, and moving it off. They began by cleaning out the drilling mud from the riser, replacing it with sea water. However, when they re-opened the valves at the top of the well, the pipe in the well had become filled with gas from the well, under considerable pressure, and this “Kicked” the well as the valve opened. Gas, as the pressure gets less as it moves up the pipe, expands much more than oil. And unfortunately in the process of disconnection, the pressure to hold the gas, which comes from the density of the drilling mud in the riser initially, had been removed as part of the disconnection process.

So the high pressure gas was able to blow all the sea water in the riser out onto the deck of the rig. (This happens extremely quickly, well below a minute) The gas then followed, and as it flowed out of the pipe at the top of the well there was some hot source that caused it to ignite. (This could even be from a static electricity spark). Because of the depth of the well, the pressure in the bottom of the well was in the 30-40,000 psi range.

Part of the problem that arises with flows at that pressure is that any abrasive particles (such as small pieces of rock) will cut through metal at the speeds at which it is carried. (Such jets were used to remove the damaged tops of the wells in Kuwait after the Gulf War, for example). So that it is possible that as the BOP started to function the high-velocity flow may have eroded part of the system to allow some fluid to bypass the plug that the BOP inserted. If that happened then the continued flow would just enlarge the passage again fairly quickly, so that the BOP will become ineffective.

However there are pictures of the leaks available.

Pictures of the oil flows (Drillingahead )

At this stage there does not appear to be that great a driving pressure for the oil coming out of the well. (If there were the flow would be more directed horizontally) This suggests that the BOP did at least partially function, and that the passage may have been eroded by the particles in the gas and oil now escaping.

There is a recent report that the accident may have been caused by a poor cementing job by Haliburton:

After an exploration well is drilled, cement slurry is pumped through a steel pipe or casing and out through a check valve at the bottom of the casing. It then travels up the outside of the pipe, sheathing the part of the pipe surrounded by the oil and gas zone. When the cement hardens, it is supposed to prevent oil or gas from leaking into adjacent zones along the pipe.

As the cement sets, the check valve at the end of the casing prevents any material from flowing back up the pipe. The zone is thus isolated until the company is ready to start production.

The process is tricky. A 2007 study by the U.S. Minerals Management Service found that cementing was the single most-important factor in 18 of 39 well blowouts in the Gulf of Mexico over a 14-year period. (But) . . . .
But at the time of the accident, "well operations had not yet reached the point requiring the placement of the final cement plug, which would enable the planned temporary abandonment of the well," the Halliburton statement said.

However it is hard to see from what is known, that this was a cause in this case.

Coal reserve considerations

I am still travelling but have found a book that will help me with the discussion of historic mining that is the usual current fare on Sundays (an autobiography from 1910 that is illustrated). Wanting to include some of this in the next post, I am going to step a little away from the topic this weekend and instead post again an earlier comment on coal reserves. It is also a topic that I will expand on in the future, but here is some background.

So you want to start a coal mine – where to begin? The first thing that you need is some coal, and in most cases today the coal seams that are exposed at the surface are known and owned by somebody else. So you will need to drill some exploratory boreholes down into the earth to find some suitable seams. For the sake of example I am going to use a project in South Africa. Other than having found it on the Web I know nothing about the coal, or the company so please don’t think of this as any endorsement or otherwise of the property.

Quite often new developments are based on where folk have found coal before. If there is a mine then, with deposits such as coal there may well be more coal, out beyond the boundaries of that original property. This is because of the way that coal was formed as vegetation spread over a large swampy area that ran for many miles. Unlike oil, once the vegetation was put in place, and slowly buried, it changed composition in place, and so coal seams may well run for many miles, although they may get different names in different places. Thus, for example the Pittsburgh seam extends over perhaps 8,000 sq. miles, while the Herrin seam in Southern Illinois has about the same range (And this does not include cannel coal, some of which is found in Kentucky, which was moved from the original site by the actions of water).

Because these quasi-horizontal seams were formed over such a large area, and because the stratigraphy (order of the rocks as you take a core down through them) will remain relatively constant, in many cases, it is not necessary to make the exploration holes that close together. Thus in the example above, the boreholes were placed some 4 km apart and the volume of coal inferred from the thickness of the beds found, and assuming that they ran continuously from borehole to borehole.


This is referred to as:

Reconnaissance Resource: is quantified as a minimum one cored borehole with coal quality data per 400 ha (approximately 2km spacing) for multiple seam deposit types, while for thick interbedded seam deposit types a reconnaissance coal deposit is quantified by a minimum one cored borehole with coal quality data per 1,600 ha (approximately 4km spacing).

In this case the property was drilled over an area that required 402 boreholes, and it identified 5 seams of coal that could be produced. However it brings me to the point of this post, which is how much of the coal can be counted and as what type of reserve. This is quite an important distinction, since in the debate that I have had with others in the past, including David Rutledge, the confusions of what has been counted and how it is defined is often overlooked. This is how the information was reported:


So what are the different definitions of the reserves? Isn’t this coal all a reserve, well no, the coal seam is divided into different quality of reserve, depending on how far it is from one of the proving wells. Let’s consider the official definitions:

Points of Observation This is the point where the coal presence has been physically seen either at an outcrop or in the recovered core from a borehole.

Inferred coal reserves are those that can be extrapolated from a Point of Observation but to a distance of no more than 2 km.

Indicated coal reserves are those that can be extrapolated from a Point of Observation, but to a distance of no more than 1 km.

Measured coal reserves are those that can be extrapolated from a Point of Observation, but to a distance of more than 500 m.

So that, when we are assessing the amount of coal that we consider available at a site, if we are conservative, we are only reporting the measured coal reserves as that within 500 m of each of the boreholes, even though the consistency of the seam has seemingly been proven over many kilometers. It is a very conservative system, note that only 17% of the likely coal is considered a measured resource. To make this post more comprehensive, and to include some definitions that I will come back to in later posts, let me now go on to include the ranges of economically recoverable coal (in terms of thickness and depth) that are currently accepted.

In terms of international definition of resource the US Geological Survey has set up some definitions, that have also been adopted by the Federal Government, in their Code of Federal Regulations, which were just revised. The new regulations are a little more inclusive than the older ones (at the USGS site).

(5) Coal reserve base shall be determined using existing published or unpublished information, or any combination thereof, and means the estimated tons of Federal coal in place contained in beds of:
(i) Metallurgical or metallurgical-blend coal 12 inches or more thick; anthracite, semi-anthracite, bituminous, and sub-bituminous coal 28 inches or more thick; and lignite 60 inches or more thick to a depth of 500 feet below the lowest surface elevation on the Federal lease.
(ii) Metallurgical and metallurgical-blend coal 24 inches or more thick; anthracite, semi-anthracite, bituminous and sub-bituminous coal 48 inches or more thick; and lignite 84 inches or more thick occurring from 500 to 3,000 feet below the lowest surface elevation on the Federal lease.
(iii) Any thinner bed of metallurgical, anthracite, semi-anthracite, bituminous, and sub-bituminous coal and lignite at any horizon above 3,000 feet below the lowest surface elevation on the Federal lease, which is currently being mined or for which there is evidence that such coal bed could be mined commercially at this time.
(iv) Any coal at a depth greater than 3,000 feet where mining actually is to occur.
(6) Commercial quantities means 1 percent of the recoverable coal reserves or LMU recoverable coal reserves. . . . .
(19) Logical mining unit (LMU) means an area of land in which the recoverable coal reserves can be developed in an efficient, economical, and orderly manner as a unit with due regard to conservation of recoverable coal reserves and other resources. An LMU may consist of one or more Federal leases and may include intervening or adjacent lands in which the United States does not own the coal. All lands in an LMU shall be under the effective control of a single operator/lessee, be able to be developed and operated as a single operation, and be contiguous.
(20) Logical mining unit (LMU) recoverable coal reserves means the sum of estimated Federal and non-Federal recoverable coal reserves in the LMU.
(21) Maximum economic recovery (MER) means that, based on standard industry operating practices, all profitable portions of a leased Federal coal deposit must be mined. At the times of MER determinations, consideration will be given to: existing proven technology; commercially available and economically feasible equipment; coal quality, quantity, and marketability; safety, exploration, operating, processing, and transportation costs; and compliance with applicable laws and regulations. The requirement of MER does not restrict the authority of the authorized officer to ensure the conservation of the recoverable coal reserves and other resources and to prevent the wasting of coal. . . . . .
(23) Minable reserve base means that portion of the coal reserve base which is commercially minable and includes all coal that will be left, such as in pillars, fenders, or property barriers. Other areas where mining is not permissible (including, but not limited to, areas classified as unsuitable for coal mining operations) shall be excluded from the minable reserve base.
(24) Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of coal.

It is important to note item 23, since no underground method of mining will remove all the coal from a seam, but will leave significant quantities of the coal in place as pillars to hold the roof up, and thus protect the miners and their equipment from the roof falling in. (In the African example the percentage of coal that might be recovered is about 50% of the reserve volume).

I should be back with some quotes from the book, and discussion of the considerable progress that has been made in mining since the early days, starting back next week

The Gulf of Mexico oil rig disaster

I am still travelling in the UK, and thus have not been able to follow, in any detail, the environmental disaster that is unfolding along the Louisiana coast, as the oil from the Transocean Deepwater Horizon fire and sinking spreads across the Gulf of Mexico.

However I thought that it might be useful to explain where part of the problem might lie, and so am going to repost one of the technical posts from the past, where I explain what a blow-out preventer is. Then I will add a couple of comments on why it might be that they did not stop the leak in this case.

Blow-out preventer (Schlumberger )

This post is going to deal with some of the problems that a driller encounters as he reaches the layer of rock (the reservoir) in which the oil or gas is being held. And what I want to talk about is something called Differential Pressure, but to explain that, I need to drag you back to High School for just a minute.

Let's, in fact, go back to Newton's Three Laws. And, for those who slept through that part of the Physics class in school, don't be too ashamed - I have seen the desk where Newton whittled his name, being similarly bored. Let's start with the first law, which is probably the most relevant.

Every object in a state of (rest or) uniform motion tends to remain in that state of (rest or) motion unless an external force is applied to it.

Except that I want to change external force into pressure (which is force divided by area) since it is the way we normally think of it. (Note: I added rest which is a special case of uniform motion since that is specific to the oil we want to talk about). In other words, nothing is going to move unless something pushes it. It is what does the pushing and what does the moving that this is all about.

And now our drill, is down through the casing, drilling the well open hole and using the circulating mud to carry away the cuttings as it continues to go deeper. I had stopped progress last week just before we went down to total depth (TD) of the well, or into the pay. And the reason I did has to do with this differential pressure. But first, the bit about how you calculate pressure.

As you go deeper into the earth, the rock at any layer is carrying the weight of all the rock vertically above it. For rough calculations we generally consider that this rock weighs 144 lb a cubic foot. So that 10 ft down the weight of the overlying column on a square foot would be 144 x 10 = 1,440 lb/sq ft. But through convention we reduce the area that we talk about to a square inch (144 sq in= 1 sq ft) so with this division the weight on a square inch would be 10 lb. A remarkable resemblance to the depth number (grin). This means that we can assume, as we go deeper into the earth, that the pressure on the rock increases by 1 lb/sq. inch (psi) for every foot we go deeper. This means that at 6,000 ft, the rock is under a pressure, from the rock above it, of 6,000 psi.

Now water does not weigh as much as rock, but can be approximated to roughly half the weight. So that, by the same argument, under water, for every foot of depth the pressure goes up roughly half-a-psi. So that at 6,000 ft under water the pressure is 3,000 psi (roughly twice the water pressure in the wand you use at a car wash). Now because we have increased the density of the fluid in the well (the mud) to help lift the cuttings out of the hole it weighs a bit more than water, but for the sake of working the example I'm going to use the half-psi measure for now. We are now at the point where the actual amount that it weighs becomes important.

Simplified sketch of an oil bearing layer in the ground.

I have made a very simple sketch of the layer of rock that we are going to drill into. In order to trap the oil it is shaped into a dome, and the sketch shows a vertical slice through that dome, viewed from the side. It has a layer of oil in it (the reddish layer), but above that is a layer of gas that has diffused from the oil (brownish), and below it is water (bluish) which may have been there when the algae died and which has stayed with the remains as they turned into oil under the temperatures and pressures deep in the rock. Oil floats on water, and gas is lighter than oil, so we have the three layers. At the moment the well has not arrived and all three fluids are sensibly in equilibrium at the same pressure.

Now why do we need to know this before we reach our layer of oil-bearing rock? Well first let's go and interpret that first law a little more.

If a person on either side of you pushed you with equal force at the same time, you don't move, because the two forces balance out. It is only if there is one force, or if one of the two pushes harder, that you move. In other words, where there are a number of forces acting on a body, it is the size of the difference in pressures, and the direction of that difference, that controls the movement.

Consider, here we are drilling merrily away (and have cased the well near the surface, and hit no more fluids on the way down) and at 6,000 ft. we penetrate the rock that is capping the well, and enter the rock with the oil in it. The oil (in the rock) is at some fraction of the overburden pressure, since it is trapped in the rock, and for the sake of this example I am going to say that it is at 5,000 psi , the fluid in the well is at 3,000 psi, the height of the mud column.
There is a difference of 2,000 psi. We are drilling a hole some 6-5/8th inches in diameter. That has an area of about 34.5 square inches. The total force we have suddenly applied to the bottom of the well (bit and fluid) is thus (area x pressure difference) 34.5 x 2,000 = 69,000 lb (or 35 tons).

Oil rig blowout in Turkmenistan (Energy Industry Photos)

Sadly most catch fire and the rig is destroyed (there are more pictures of such damage at the EIP site)
It's called a blow-out, and sadly, as we have just seen in the Gulf, they can still happen.

This is why we approach the oil/gas producing zone of the rock with caution. And bear in mind that the driller that is controlling the progress of this well is at the surface, trying to guide the bit at the bottom of the hole, with, historically, little immediate information to help.

Based on the surveys that brought the crew to the site in the first place he knows roughly how thick the layers of rock are, and probably what rock they are, but the only real information on where the bit is in that sequence, is from the returns (cuttings) that come out of the well, and there is the lag, we mentioned before, while those chips make their way up the 6,000 ft pipe. (This is why Measurement While Drilling [MWD] has been such a relatively recent boon to the industry ( though not all rigs have it).
By monitoring a number of pressure gages the driller can gain a sense of what is happening at the bottom of the well.

If he senses that there is going to be a problem, then he can do one of several things, based on the way the well is set up. The first thing is to increase the density of the mud. By making the fluid in the well weigh more, the difference in the pressure across that face is reduced, and the change in conditions is easier to handle. However weighting up the hole has the disadvantage that it becomes much slower to drill with a heavier mud (it is a poor bottom-hole cleaner among other things). And, if done during drilling, bear in mind that once the heavier mud is added to the well it won't be fully effective until it has had time to get down to the bit and then fill back up the annulus between the drill string and the casing all the way to the surface.

So that is an expensive and slow option. Let us take the game a little more interesting and say that there is a gas pocket above the oil, and that the hole is going to go into the layer at A. Gas will enter the well at the down-hole pressure, but as the bubble rises, that pressure is reduced, and the gas expands, pushing the mud above it out ahead of itself. Another potential source for big-time trouble. And this one (which is known as a kick in the well) happens much faster, so there is less time to react.

How do we handle this? The answer is to invert the problem. Gas or oil flows into the well because the well is at a lower pressure than the fluid in the rock. The fluid in the well is, initially at the pressure created by the depth, and by the weight (density) of the mud in the hole. However, if we put a restriction on the flow of fluid out of the well (such as when you put your finger over the end of a garden hose so that the stream becomes smaller and shoots out further) we can increase the pressure in the well.

For those who want to know why, if the same volume has to go through a smaller hole in the same amount of time it has to go faster. This means it has to be pushed harder. Bernoulli explained it, and there is an animation available that helps explain it.

What it means is that by adjusting the flow out of the hole, the driller can adjust the internal pressure, and thus "kill the kick", or if gets to be too much of a problem, “kill the well”. But it is not completely that simple. Bear in mind that there is all the drilling and rotating equipment on the rig floor connected to the drill pipe at the top of the well. None of this can stand much pressure. So we need to place another piece of equipment between the drilling rig, and the top of the well.

Blow-out preventer (Schlumberger )

This is the Blow-out Preventer(BOP), which is essentially a ram that very rapidly shuts off fluid flow at the top of the well. These have to be well designed, since they are generally the line of last defense against a blowout, and when they fail as the pictures show serious problems arise. They also form the basis for the well-known structures, often referred to as Christmas Trees, that sit at the top of producing wells. By themselves, however, these aren't enough, since their main function is just to slam the door shut, before all the oil gets out and we have a gusher.

The more critical tools are the chokes on the well. (Below the rams in the picture above). There are generally several, both hydraulically operated and manual (in case the power dies) which are simply large valves that can be turned to increase or reduce the size of the flow path out of the well over to the mud pits. By adjusting these, in real time, the driller can control the well pressure, and thus the dynamics of the behavior at the bottom of the well. And after the rig leaves, an operator can adjust well pressure, and thereby the production from the well and its long-term performance.

If the operator is well trained (and you find drilling simulator equipment in Petroleum Engineering Departments so that students can understand how to do this (I last tried some decades ago) the well pressure will be controlled, so that any kicks can be handled, and the drill can now penetrate safely into the rock containing the oil/gas, which we call the reservoir, or the pay.

. . . . . . .
To return to the present it appears that the blow-out preventers, which are located on the sea bed, did not work as they should, in this case. Whether that is because the pressure of the surrounding water (they are at a depth of around 5,000 ft and thus there is about 2,500 psi pressure, which is significant, but these days not an insurmountable level) or because of some other failure is unclear. But since the gas and oil seems to have come straight up to the platform where it ignited, then it logically must have gone up the pipe or riser that would carry oil from the well to the surface. Thus it had to pass through the BOP. Both manual and remote attempts to activate the BOP did not work.

The risers have now collapsed, and the area around the well completion is now a mess of wreckage, so that access to the area is not easy. Further the robotic vehicles sent in to try and get the BOP to work effectively haven’t been able to do their job. And the leak may now be coming from a larger area than just the top of the well casing.

The current plans are to contain the spill and to drill an intersecting well that can seal the original flow path, and contain the oil, through BOP on the second well. But that will take some time to put in place.

There are additional bits of information in the technical posts that I have written in the past, and that are listed on the right side of the page.