Each reservoir is composed of a unique combination of geometric form, geological rock properties, fluid characteristics, and primary drive mechanism. Although no two reservoirs are identical in all aspects, they can be grouped according to the primary recovery mechanism by which they produce. It has been observed that each drive mechanism has certain typical performance characteristics in terms of:

  • Ultimate recovery factor.
  • Pressure decline rate.
  • Gas-Oil ratio.
  • Water Production.


For a proper understanding of reservoir behavior and predicting future performance, it is necessary to have knowledge of the driving mechanisms that control the behavior of fluids within reservoirs.

The overall performance of oil reservoirs is largely determined by the nature of the energy, i.e., driving mechanism, available for moving the oil to the wellbore. There are basically six driving mechanisms that provide the natural energy necessary for oil recovery:

  • Rock and Liquid Expansion Drive.
  • Depletion Drive.
  • Water Drive.
  • Gas Cap Drive.
  • Gravity Drainage Drive.
  • Combination Drive.


When an oil reservoir initially exists at a pressure higher than its bubble point pressure, the reservoir is called an “undersaturated oil reservoir.” At pressures above the bubble point pressure, crude oil, connate water, and rock are the only materials present. As the reservoir pressure declines, the rock and fluids expand due to their individual compressibilities. The reservoir rock compressibility is the result of two factors:

  1. Expansion of the individual rock grains.
  2. Formation compaction.

Both of these factors are the results of a decrease of fluid pressure within the pore spaces, and both tend to reduce the pore volume through the reduction of the porosity. As the expansion of the fluids and reduction in the pore volume occur with decreasing reservoir pressure, the crude oil and water will be forced out of the pore space to the wellbore. Because liquids and rocks are only slightly compressible, the reservoir will experience a rapid pressure decline. The oil reservoir under this driving mechanism is characterized by a constant gas–oil ratio that is equal to the gas solubility at the bubble point pressure.

This driving mechanism is considered the least efficient driving force and usually results in the recovery of only a small percentage of the total oil-in-place.


This driving form may also be reffered to by the following various terms:

  • Solution Gas Drive.
  • Dissolved Gas Drive.
  • Internal Gas Drive.
In this type of reservoir, the principal source of energy is a result of gas liberation from the crude oil and the subsequent expansion of the solution gas as the reservoir pressure is reduced.


As pressure falls below the bubble point pressure, gas bubbles are liberated within the microscopic pore spaces. These bubbles expand and force the crude oil out of the pore space. Cole (1969) suggests that a depletion drive reservoir can be identified by the following characteristics:

Pressure behavior: The reservoir pressure declines rapidly and continuously. This reservoir pressure behavior is attributed to the fact that no extraneous fluids or gas caps are available to provide a replacement of the gas and oil withdrawals.

Water production: The absence of a water drive means there will be little or no water production with the oil during the entire producing life of the reservoir. A depletion drive reservoir is characterized by a rapidly increasing gas–oil ratio from all wells, regardless of their structural position. After the reservoir pressure has been reduced below the bubble point pressure, gas evolves from solution throughout the reservoir. Once the gas saturation exceeds the critical gas saturation, free gas begins to flow toward the wellbore and the gas–oil ratio increases. The gas will also begin a vertical movement due to gravitational forces, which may result in the formation of a secondary gas cap. Vertical permeability is an important factor in the formation of a secondary gas cap.

Unique oil recovery: Oil production by depletion drive is usually the least efficient recovery method. This is a direct result of the formation of gas saturation throughout the reservoir. Ultimate oil recovery from depletion drive reservoirs may vary from less than 5% to about 30%. The low recovery from this type of reservoir suggests that large quantities of oil remain in the reservoir and, therefore, depletion drive reservoirs are considered the best candidates for secondary recovery applications.


Gas cap drive reservoirs can be identified by the presence of a gas cap with little or no water drive. Due to the ability of the gas cap to expand, these reservoirs are characterized by a slow decline in the reservoir pressure.


The natural energy available to produce the crude oil comes from the following two sources:

  •  Expansion of the gas cap gas.
  • Expansion of the solution gas as it is liberated.

Cole (1969) and Clark (1969) presented a comprehensive review of the characteristic trends associated with gas cap drive reservoirs. These characteristic trends are summarized below:

Reservoir pressure: The reservoir falls slowly and continuously. Pressure tends to be maintained at a higher level than in a depletion drive reservoir. The degree of pressure maintenance depends upon the volume of gas in the gas cap compared to the oil volume.

Water production: Absent or negligible water production.

Gas–oil ratio: The Gas-Oil Ratio rises continuously in upstructure wells. As the expanding gas cap reaches the producing intervals of upstructure wells, the gas–oil ratio from the affected wells will increase to high values.

Ultimate oil recovery: Oil recovery by gas cap expansion is actually a frontal drive displacing mechanism which, therefore, yields considerably larger recovery efficiency than that of depletion drive reservoirs. This larger recovery efficiency is also attributed to the fact that no gas saturation is being formed throughout the reservoir at the same time. The ultimate oil recovery froma gas cap drive reservoir will vary depending largely on the following six important parameters:

  1. Size of the original gas cap.
  2. Vertical permeability.
  3. Oil Viscosity.
  4. Degree of conservation of the gas.
  5. Oil Production rate.
  6. Dip Angle.

Well behavior: Because of the effects of gas cap expansion on maintaining reservoir pressure and the effect of decreased liquid column weight as it is produced out the well, gas cap drive reservoirs tend to flow longer than depletion drive reservoirs.


Many reservoirs are bounded on a portion or all of their peripheries by water-bearing rocks called aquifers. The aquifers may be so large compared to the reservoir they adjoin as to appear infinite for all practical purposes, and they may range down to those so small as to be negligible in their effects on the reservoir performance.


The aquifer itself may be entirely bounded by impermeable rock so that the reservoir and aquifer together form a closed (volumetric) unit. On the other hand, the reservoir may outcrop at one or more places where it may be replenished by surface water.

It is common to speak of edge water or bottom water in discussing water influx into a reservoir. Bottom water occurs directly beneath the oil and edge water occurs off the flanks of the structure at the edge of the oil. Regardless of the source of water, the water drive is the result of water moving into the pore spaces originally occupied by oil, replacing the oil and displacing it to the producing wells.


The mechanism of gravity drainage occurs in petroleum reservoirs as a result of differences in densities of the reservoir fluids. The effects of gravitational forces can be simply illustrated by placing a quantity of crude oil and a quantity of water in a jar and agitating the contents. After agitation, the jar is placed at rest, and the more dense fluid (normally water) will settle to the bottom of the jar, while the less


dense fluid (normally oil) will rest on top of the denser fluid. The fluids have separated as a result of the gravitational forces acting on them. The fluids in petroleum reservoirs have all been subjected to the forces of gravity, as evidenced by the relative positions of the fluids, i.e., gas on top, oil underlying the gas, and water underlying oil.

Due to the long periods of time involved in the petroleum accumulation and migration process, it is generally assumed that the reservoir fluids are in equilibrium. If the reservoir fluids are in equilibrium then the gas–oil and oil–water contacts should be essentially horizontal. Although it is difficult to determine precisely the reservoir fluid contacts, the best available data indicates that, in most reservoirs, the fluid contacts actually are essentially horizontal. Gravity segregation of fluids is probably present to some degree in all petroleum reservoirs, but it may contribute substantially to oil production in some reservoirs.


The driving mechanism most commonly encountered is one in which both water and free gas are available in some degree to displace the oil toward the producing wells. The most common type of drive encountered, therefore, is a combination drive mechanism. Two combinations of driving forces are usually present in combination drive reservoirs:

    • Depletion drive and weak water drive.
    • Depletion drive with a small gas cap and a weak water drive.
In addition, gravity segregation can also play an important role in any of these two drives. In general, combination drive reservoirs can be recognized by the occurrence of a combination of some of the following factors.
Reservoir Pressure: These types of reservoirs usually experience a relatively


rapid pressure decline. Water encroachment and/or external gas cap expansion are insufficient to maintain reservoir pressures.

Water Production: The producing wells that are structurally located near the initial oil–water contact will slowly exhibit increasing water producing rates due to the increase in the water encroachment from the associated aquifer.

Gas–oil ratio: If a small gas cap is present the structurally high wells will exhibit continually increasing gas–oil ratios, provided the gas cap is expanding. It is possible that the gas cap will shrink due to production of excess free gas, in which case the structurally high wells will exhibit a decreasing gas–oil ratio. This condition should be avoided whenever possible, as large volumes of oil can be lost as a result of a shrinking gas cap.

Ultimate oil recovery: As a substantial percentage of the total oil recovery may be due to the depletion drive mechanism, the gas–oil ratio of structurally low wells will also continue to increase, due to evolution of solution gas from the crude oil throughout the reservoir as pressure is reduced. Ultimate recovery from combination drive reservoirs is usually greater than recovery from depletion drive reservoirs but less than recovery from water drive or gas cap drive reservoirs. Actual recovery will depend upon the degree to which it is possible to reduce the magnitude of recovery by depletion drive. In most combination drive reservoirs it will be economically feasible to institute some type of pressure maintenance operation, either gas injection or water injection, or both gas and water injection, depending upon the availability of the fluids.

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