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.
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.
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.
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