Secondary Recovery Technique

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Secondary recovery technique

The term secondary recovery technique refers to any method for removing oil from a reservoir after all natural recovery methods have been exhausted. The term has slightly different meanings depending on the stage of recovery at which such methods are used.

The oil trapped in an underground reservoir is typically mixed with water, natural gas , and other gases. When a well is sunk into the reservoir, oil may flow up the well pipe to the earth's surface at a rate determined by the concentration of these other substances. If the gas pressure is high, for example, the oil may be pushed out in a fountain-like gusher.

Flow out of the reservoir continues under the influence of a number of natural factors, such as gravity, pressure of surrounding water, and gas pressure. Later, flow is continued by means of pumping. All such recovery approaches that depend primarily on natural forces are know as primary recovery techniques.

Primary recovery techniques normally remove no more than about 30% of the oil in a reservoir. Petroleum engineers have long realized that another fraction of the remaining oil can be forced out by fluid injection. The process of fluid injection involves the drilling of a second hole into the reservoir at some distance from the first hole through which oil is removed. Some gas or liquid is then pumped down into the second hole, increasing pressure on the oil remaining in the reservoir. The increased pressure forces more oil out of the reservoir and into the recovery pipe.

The single most common secondary recovery technique is water flooding . When water is pumped into the second well, it diffuses out into the oil reservoir and tends to displace oil from the particles to which it is absorbed. This process forces more of the residual oil up into the recovery pipe.

Water flooding was used as early as 1900, but did not become legal until 1921. A common practice was to drill a series of wells , some of which were still producing and others of which employed water injection. As the former became exhausted, they were converted to water injection wells and another group of producer wells were drilled. The process was repeated until all available oil was recovered from the field.

Recently, more sophisticated approaches to fluid injection have been developed from a reservoir. The two fluids that have been used most extensively in these approaches are liquid hydrocarbons and carbon dioxide . The principle behind liquid hydrocarbons is to find some material that will mix completely with oil and then push the oil-mixture that is formed out of the reservoir into the recovery pipe. A commonly used hydrocarbon for this process is liquified petroleum gas (LPG), which is completely miscible with oil.

Since LPG is fairly expensive, only a small volume is actually used. It is pumped down into the reservoir and followed by a "pusher gas." The pusher gas, often methane , is inexpensive and can be used in larger volume. The pusher gas forces LPG into the reservoir where it (the LPG) mixes with residual oil.

This system has worked well in the laboratory, but not so well in actual practice. The LPG has a tendency to get lost in the reservoir to an extent that it does not effectively remove very much residual oil.

The most effective fluid now available for injection appears to be carbon dioxide. A mixture of carbon dioxide and water is pumped down into the reservoir and followed by an injection of pure water that drives the carbon dioxide-water mixture through the reservoir. As carbon dioxide comes into contact with oil, it dissolves in the oil, causing it to expand and break loose from surrounding rock. The oil-carbon dioxide-water is then pumped out of the recovery pipe where the carbon dioxide is removed from the mixture and re-used in the next recovery pass.

The carbon dioxide process has been effective in removing oil after water flooding has already been used and only 25% of the oil in a reservoir still remains. In most cases, however, it is more efficiently used with reservoirs containing a larger fraction of residual oil.

Fluid injection is one type of secondary recovery technique. Another whole group of methods can also be used to extract the remaining oil from a reservoir. If these methods are employed after fluid injection has been tried, they are often referred to as tertiary recovery techniques. If they are used immediately after primary recovery, they are known as secondary recovery techniques. A whole set of recovery techniques can be called by different names, therefore, depending on the stage at which they are used. It is becoming more common today to refer to any method for removing the residual oil from a reservoir as an enhanced recovery technique.

Another technique for removing residual oil from a reservoir makes use of surfactants. A surfactant is a substance whose molecules are attracted to water at one end and oil at the other end. The most familiar surfactants are probably the soaps and detergents found in every home.

If surfactants are injected into an oil reservoir, they will form emulsions between the oil and water in the reservoir. The oil is essentially washed off particles of rock in the reservoir the way grease is washed off a pan by a household detergent. The emulsion that is formed is then pushed through the reservoir and out the producer pipe by a flood of water pushed down the injection pipe.

The surfactant method works well in the laboratory, although it has been less successful in the field. Surfactants tend to adsorb on rock particles and get left behind as the water pushes forward. Methods for overcoming this problem are now being explored.

One of the fundamental problems with recovering residual oil in a reservoir is that oil droplets often have difficulty in squeezing through the small openings between adjacent rock particles. The use of surfactants is one way of helping the oil particles slip through those openings more easily. Another approach is to increase the temperature of the oil in the reservoir, thereby reducing its viscosity (tendency to flow). As it becomes less viscous, the oil can more easily force its way through pores in the reservoir.

One of the earliest applications of this principle, the steam soak method, was first used in Venezuela in 1959. In this method, steam is injected into one part of the reservoir and the producer pipe is closed off. After a few days, the pipe is reopened, and the loosened oil flows out. This process is repeated a few times before a change is made in the method and steam is piped in continuously while the producer pipe remains open.

Steam injection works especially well with heavy oils that are not easily displaced by other secondary recovery techniques. It is now used commercially in a number of fields, primarily in Venezuela and California.

A dramatic form of secondary recovery is in situ (in place) combustion . The principle involved is fairly simple. A portion of the oil in the reservoir is set on fire. The heat from that fire then warms the remaining residual oil and reduces its viscosity, forcing it up the producer pipe.

In practice, the fire can sometimes be made to ignite spontaneously simply by pumping air down the injection well .In some cases, however, the oil must actually be ignited at the bottom of the well. The temperature produced in this process may reach 650–1200°F (350–650°C) and the region of burning oil may creep through the rock at a speed of 1–12 in (3–30 cm) per day. As the fire continues, air, and usually water, are continually pumped into the injection well to keep the combustion zone moving. Under the best of circumstances, in situ combustion has recovered up to half of all the oil remaining in a reservoir.

Research has demonstrated that each recovery method is suitable for particular kinds of reservoirs. Oil viscosity, rock porosity, depth of the reservoir, and amount of oil remaining in the reservoir are all factors in determining which method to use. To date, however, the only method that has proved to be practical in actual field situations is steam injection.

[David E. Newton ]