Naked Science Forum
Non Life Sciences => Geology, Palaeontology & Archaeology => Topic started by: charliyorkie on 26/03/2009 22:10:28
-
Can anyone tell me what happens to the hole that is left we human beings drill millions of barrels of oil out of the earth. Why does the earth not cave in as the gap where the oil was must be vast.
-
Can anyone tell me what happens to the hole when millions of barrels of oil have been taken from the earth.?
Why does the earth not cave in the area left void of oil must be vast.
-
This is definitely JimBob's field of expertise- but I'll give it a shot!
The oil is not in great voids, caves or empty spaces underground. The oil exists in tiny pore spaces in surrounding rocks- so there is nothing to collapse as the oil is removed. The pore spaces will eventually fill with either water, gas or oil.
JimBob can better address underground pressures and how they respond to oil production...
-
Interesting question.
We know the volume of oil we extract, and we should probably add a little extra to account for the gas that's released too. It might just come down to being insignificant in terms of volume over the area affected though. I look forward to seeing an informed answer to this. I know it can be a factor in coal mining but I can't recall hearing of subsidence problems in connection with oil extraction.
-
Rocks are mostly solid. Most production of oil and gas comes from rocks that have an average porosity (percent of holes) of about 13%. That is also the average porosity of most concrete. So in 99.9995% of all wells drilled there is no effect of the fluid withdrawal. The particles of the rock hold the total rock together as if nothing has happened.
As well, when oil or gas is produced, something needs to fill the voids. As nature will not tolerate a vacuum, water fills in the space. All pore space in rocs are normally filled by fluid - either gas oir oil; gas is treated as if it were a fluid since in many cases it exists as such underground.) These rocks are under pressure of the overburden - the material above them, 1,000's of feet of rocks. So the fluid in the pore space also has the same pressure on it. As oil or gas is produced, the remaining fluid fills the space with a slightly lower pressure until the water begins to be produced.
When a well goes "dry" it does not mean that the well has ceased producing fluid. It has started to produce too much water to be economically produced. There is still a lot of oil left behind. The amount can be up to 95% of original in-place oil, usually dependent on the shale content of the rock. There is a lot of oil still to be extracted in old oil fields. Gas fields are somewhat different. But I have been involved in going into old oil fields and drilling new wells to extract oil that has been by-passed.
This is by no means a comprehensive review but only hits the high points. When I get up tomorrow, I will review this for major points I might have missed. I am rather tired.
-
Tell it to Long Beach, CA, where the land subsided substantially before they pumped water in. Sure, when you pump something out, either something new replaces it at pressure or the layers above will eventually subside. I think they often pump in steam or something to get the oil out. Off Norway I think they are sequestering CO2 that way. Put concrete under a few thousand feet of rock and it will compress too if it contains voids.
-
Long Beach oil fields are a special case - the sand from where the production is coming is an unconsolidated sand, unlike the consolidated sands discussed in my first post in this thread. As a result of being unconsolidated, when oil is withdrawn the sand grains can move. As a result of the overburden the UNCONSOLIDATED sand moves and compacts, unlike the vast majority of sandstone reservoirs. This requires special sand screens to keep the sand from flowing up with the oil. There are instances of this same thing happening on the Gulf Coast near Corpus Christi, Texas.
But these instances are the exception, not the rule.
Steam flooding is used to get high viscosity oil to move out of the pore spaces. The steam heats the oil, lowering it viscosity, and the lower viscosity allows the oil to flow more freely. Water and gas injection into fields has been done since the late 30's, once the reservoir engineering of oil and gas fields became understood. The purpose it to attempt to maintain as much energy in the reservoir so that the maximum amount of oil can be produced. By doing this from the beginning of exploitation of a field significantly better cumulative production amounts can be achieved.
-
When a well goes "dry" it does not mean that the well has ceased producing fluid. It has started to produce too much water to be economically produced. There is still a lot of oil left behind. The amount can be up to 95% of original in-place oil, usually dependent on the shale content of the rock. There is a lot of oil still to be extracted in old oil fields.
Over time, would this remaining oil re-consolidate (separate out from the water) into viable extractable oil by simply reopening old wells?
-
That has been my experience. In fact it doesn't take all that long, especially where the oil is in a rather broad structure with a lot of porosity underneath the oil, thus a lot of water under the oil. As a well depletes the oil around the well bore there is more pressure from below than from the sides to push oil towards the well bore to fill the voids left by the oil thaat has been produced. This causes "coning." "Coning" is a condition where the water is differentially lifted from the bottom and a cone is formed in the water from the top of the perforations downward from the well.
Once the well "waters out" the cone is still there. As a development geologist, you can do two things - drill wells between the original, now useless wells or waiting 50-60 years until the cone has been reduced some and re-entering the original well bore - if the casing hasn't been pulled.
-
What you describe here, JB, is something I have never seen addressed by the exhibitors at the PETEX exhibition (Petroleum Exploration).
I can grasp how this conning works and presume that a field would have numerous cones according to the number and position of each individual bore.
Now let me display my ignorance. Would it not be better to make first bores into a new field close to the edges of that field so the conning progressively pushes the remaining oil toward the center of the field.
[diagram=440_0]
Blue = Oil field
Green = 1st bore cones
Yellow = 2nd bore cones
Red = Final bore cones
Ignore the silly red dots.
Would this result in the early water-out of a bore?
-
Does the oil field have measles???
No, unfortunately not, Don.
(What a can of worms this question opens! I am going to spend a bit of time answering this one!)
First, let's go back to how the oil exists in a reservoir. There are two primary types of reservoirs in which oil and gas are found. These are sandstones and carbonates. In carbonates, the porosity is formed primarily by solution cavities or entrapped water preventing the original holes being filled in. Most of the porosity comes from solution after deposition. In sandstones, the porosity is formed by the packing of the sand grains. Except in a few rare instances, the oil and gas migrated into the reservoir after it was formed, displacing the water that originally filled all of the pore space. This means that when you begin to produce the oil, the holes are filed with a film of water on the surface of the grains or holes and then by oil in the remaining spaces. Migrating oil cannot displace all of the water because the surface tension causes the water to differentially cling to the surfaces of the grain/pores. The amount of oil is variable and depends on several factors - roundness, sorting of size, the amount of clay in the rock (both carbonates and sands,) size distribution skewness - on and on. These factors are important as they dictate the way and the rate at which oil is extracted. A reservoir with a low oil saturation is harder to produce as a.) you need to somehow dispose of the water and B.) it needs to be produced more slowly, although most people do not consider the latter when they begin producing a well. I know of reservoirs that have not been produced because of the inability to dispose of the water. These are actually brines, not pure water. As such they cannot be dumped into the hydrological regiment but must be re-injected deep into the ground where they have no possibility of contaminating the ground or surface water.
There are two things that may occur, depending on the geometry of the oil reservoir. If the reservoir is relatively thin, 10's of feet, the water will encroach from the sides only. In a thicker reservoir, there is BETTER pressure maintenance as there is more surface area pushing on the interstitial fluids. (Remember, the fluid in a reservoir is not in a cavity but is in pores that need to be treated differently for different conditions.) Also, reservoirs are not isotropic in their composition. There are different layers with different characteristics, thus "wetness" - or the amount of water bound to the rock - and there are also variations within each layer.
This leads to another concept - transmissiblity. Obviously if the hole space is larger there is a greater ability for water to pass through, right? - Wrong. The ability of the a rock to transmit fluid depends on the "interconnectedness" of the pores as well as the size of the pores. It is also dependent on the amount of bound water, the viscosity of the oil - lower viscosity oil moves more poorly than higher viscosity oil, etc. Thus, within a reservoir that is 10 feet thick and is driven dominantly by water displacement energy, (as opposed to the energy derived from gas that is in solution) water can displace oil differentially. This is the edge-water drive, as shown in the two figures below.
(https://www.thenakedscientists.com/forum/proxy.php?request=http%3A%2F%2Fi38.photobucket.com%2Falbums%2Fe111%2Fgeezer69%2FReservoir-thin.jpg&hash=2a41f967b15083ea7ec9cc58fbe6a9cf)
(https://www.thenakedscientists.com/forum/proxy.php?request=http%3A%2F%2Fi38.photobucket.com%2Falbums%2Fe111%2Fgeezer69%2Fedge-water-drive.jpg&hash=f214b374957f7d5790fb886202f05037)
As can be seen above, water moves in on the edges of the reservoir, thus the sub-division "edge-water drive." But the movement of oil is different depending on the properties of the sand or carbonate layer. The larger the sand grains or holes in the carbonate, the better the water is able to "sweep" the oil in front of it. The finer the grain of sand or the more shale and silt in the rock, the harder it is to sweep the oil in front of the water. A thin layer of shale can separate the sand body into two distinct reservoirs, as shown. There is the probability that these shale layers do not extend throughout the entire body, so the layers communicate vertically, complicating the mechanics of the drive mechanism even more. In an edge-water drive this isn't as critical as it is in a bottom water drive, shown below. On the left, the shale layer is absent and the bottom layer is more efficiently swept by the water drive.
(https://www.thenakedscientists.com/forum/proxy.php?request=http%3A%2F%2Fi38.photobucket.com%2Falbums%2Fe111%2Fgeezer69%2FReservoir-thick.jpg&hash=3ad97296f4b7c1d6c261e70394b65d11)
(https://www.thenakedscientists.com/forum/proxy.php?request=http%3A%2F%2Fi38.photobucket.com%2Falbums%2Fe111%2Fgeezer69%2Ffull-water-drive.jpg&hash=0e9e1ae9a26e640eb9ce62dbf20af369)
The dissolved gases in the reservoir also complicate the coning problem. It reduces the importance of the water drive but increases the need for pressure maintenance.
The best way to combat coning is to institute a pressure maintenance system and also not be greedy. A producer can "pull" a well too much. When I first started work in the oil business, in 1969, the State of Texas has a limit on how much an operator could produce a certain well or field. It was at about 40-45% of the absolute open flow (or the maximum amount a well could produce.) On an open choke, a well wastes a lot of energy that is contained in the reservoir by too rapid an expansion of the gases in the oil. If there is no re-injection of the gas or the gas was flared - as it commonly was at that time; gas was worth only $0.11 per thousand cubic feet - it was not re-injected into the reservoir to maintain the pressure within that reservoir. Only in the larger oil fields was it common to find re-injection of gas for pressure maintenance. The unfortunate problem was, and still is, that most people in the business did not have any understanding of how a reservoir worked. As I was thrown into the lion's den of reservoirs during my first summer job while in university, I had to become educated quickly in these things - BUT back to the discussion.
Pressure maintenance can be done in several ways. Injection of fluids of different types or by re-injection of fluids. I am using fluids in the broad sense, various gases, including CO2, methane and the higher carbon-hydrogen chain gases such as ethane, pentane, butane, etc, produced with the oil, and water or even oil-miscible fluids.
As you can see, the choices are numerous and need to be designed for the specific demands presented by each oil field. This branch of petroleum geology is actually geological engineering. Ideally a petroleum reservoir engineer and a reservoir geologist work together to design each pressure maintenance system. The advent of computer modeling has greatly enhanced the ability to design these programs. But an engineer must have mastery of the geology to design the models properly. Unfortunately, this is only given cursory attention by most small to medium sized companies.
Well, that only took a few hours while picking on the Beaver. Any more questions?
-
Thanks for this explanation JB. I shan't insult you by saying I have a full understanding of oil extraction now, but rather that I have a better understanding of the difficulties faced by the engineers and geologists charged with the job.
Some of what you have said I can relate to the exhibits I see on the PETEX show, such as seismic mapping, so when the show comes around again next year, perhaps I won't look quite so dumbfounded at the technology.
PETEX 2008 website http://www.pesgb.org.uk/pesgb/S3/S3_pet08_general.asp?Section=3 (http://www.pesgb.org.uk/pesgb/S3/S3_pet08_general.asp?Section=3)
-
Thanks for the time and effort you put in to that reply.
-
Thinking laterally, so drilling oil kind of compensates for the ice caps melting and increasing the ocean levels? As it puts water in the place of oil....
Drill for oil in the sea -> create void -> let sea water gush in and fill the void -> ocean level reduces -> burn gas -> green house effect -> Polar ice cap melts
Balance provided by nature for our drilling?
-
Thinking laterally, so drilling oil kind of compensates for the ice caps melting and increasing the ocean levels? As it puts water in the place of oil....
Drill for oil in the sea -> create void -> let sea water gush in and fill the void -> ocean level reduces -> burn gas -> green house effect -> Polar ice cap melts
Balance provided by nature for our drilling?
None of the above. The oil and gas reservoirs are closed systems. The influx of water - or anything - must come from within the system as the pressure is reduced.