Drive Mechanisms in Reservoirs

The fluids in reservoir rocks are trapped within the pores of the rocks and will require sustained drive (i.e. energy) to be produced or flow out of the rocks. This energy is commonly referred to as natural or primary energy, which is a result of all the events that occurred during the reservoir formation process. To overcome the resistance imposed by porous channels and to displace towards the wellbore, reservoir fluids should hold a determined pressure, which is the most sensible mean of energy in the reservoir.

Production occurs when a drive is initiated within the reservoir system as a result of changes naturally or artificially created within the system which causes fluid movement. In general, this is due to decompression and fluid displacement. The combination of factors that unleash these effects is called drive mechanisms.

The production of hydrocarbons only by the natural energy of the reservoir is called primary recovery. According to (Ahmed, 2010), each drive mechanism has its own typical performance in terms of:

  • Ultimate Recovery Factor
  • Pressure Decline Rate
  • Gas-Oil Ratio
  • Water Production

A driving mechanism is responsible for moving the reservoir fluids (oil, gas and water) from the reservoir to the wellbore. In order to properly understand the nature of a reservoir and to make predictions about its performance, it is necessary to evaluate how those mechanisms control fluids behavior. (Ahmed, 2010) points out six types of drive mechanisms that provide natural energy sources for hydrocarbons recovery:


At pressures above the bubble-point, the reservoir is said to be an undersaturated-oil reservoir. As pressure declines, the rock and fluids expand due to their compressibilities. The rock compressibility is a function of the expansion of the grains and formation compaction. The withdrawal of liquid or gas from a reservoir results in a decline of the fluid pressure followed by a consequent increase in the grain pressure. Both factors tend to reduce the pore volume and the fluids will be forced out towards the wellbore. During this phenomena, reservoir pressure will face a rapid drop as the rock and fluids are slightly compressible. The reservoir which experiences this drive mechanism is outlined by a constant gas-oil ratio and is said to be the least in terms of efficiency, given that it does not result in a considerable recovery factor.


Also referred to as solution gas drive, it occurs in a reservoir which contains no initial gas cap or active aquifer to support pressure. Therefore, the main source of energy in this drive mechanism comes from the gas liberation from the oil and subsequent solution expansion, both caused by reservoir pressure decline which happens rapidly and continuously due to low oil compressibility. As depletion occurs and the reservoir pressure has been reduced below the bubble-point pressure, gases evolves from the solution and their expansion forces the oil out of the pore space. Once the liberated gas has overcome a critical gas saturation in the pores, free gas flows towards the wellbore under the influence of hydrodynamic forces, hence increasing the gas-oil ratio.

Cole (1969) suggests that a depletion-drive reservoir can be identified by the following factors:

  • Rapid and continuous pressure decline, provided that there are no fluids to replace oil and gas withdrawals.
  • Little or no production of water due to the absence of aquifers.
  • A depletion-gas drive is characterized by a rapidly increasing gas-oil ratio once the pressure drops below the bubble-point.

For these reasons, depletion-drive reservoirs are said to have low efficiency in terms of ultimate oil-recovery, ranging from 5 to 30%, depending largely on the absolute reservoir pressure, the solution GOR of the crude, abandonment conditions, and the reservoir dip (Jahn et al., 2003). Depletion-drive reservoirs are good candidates for the application of secondary recovery methods with the aim of maintaining reservoir pressure and prolonging both plateau and decline periods.

Figure 1. Production profile for solution gas drive reservoir (Modified from Jahn et al., 2003)

Hydrocarbons can experience an equilibrium of phases, depending on the pressure and temperature conditions. In many cases, the vapour phase is less dense compared to the liquid, which leads to the accumulation of gas in the upper portions of the porous media forming a gas-cap. In the gas-cap mechanism, the energy comes from its expansion: as oil is produced, the gas-cap expands pushing the gas-oil contact downwards. As gases have high compressibilities, this expansion occurs without significant pressure decrease. Thus, in terms of well positioning, perforations might occur as far as away from the gas cap but not so close to the   water-oil contact to avoid significant water production by coning. According to Ahmed [2], the recovery factor from a gas-cap normally will be 20 to 40% – it can be up to 60% in some cases- and the mechanism is dependant upon the following factors:

Size of the gas cap: the degree of pressure maintenance depends upon the gas volume in the gas cap compared to the oil volume.

Vertical permeability: a good vertical permeability will permit the oil moving downward with less bypassing of the gas.

Oil viscosity: an increase of oil viscosity will lead to lower recovery factors, due to the increase in the amount of gas bypassing.

Degree of gas conservation: it is necessary to shut down wells which are producing excessive gas.

Oil Production Rate: lower producing rates will maximize the amount of free gas in the oil zone to migrate to the gas cap which will increase recovery.

Dip angle: steep angle of dip allows better oil drainage.

The recovery factor is higher than for depletion drive mechanisms, given that no gas saturation is formed throughout the reservoir at the same time. Additionally, gas cap reservoirs produce very little or no water.

Figure 2. Gas-cap drive reservoir (Modified from Clark, N.J., Elements of Petroleum Reservoirs, SPE, 1969)

Many reservoirs have their peripheries bounded by water-bearing rocks called aquifers. A pressure decrease due to oil production will be transmitted to the aquifer, which responds through its expansion and pore volume reduction. As a result, the additional water volume moves to the oil zone to replace the voidage created by produced fluid, hence displacing oil to the producer wells and maintaining the reservoir pressure, in a phenomena known as water influx.

The pressure decline observed in this mechanism is gradual (Figure 3). This is explained by the fact that the hydrocarbons produced are almost completely replaced by water encroaching the oil zone. As pressure keeps up high levels, the gas-oil ratio has approximately the same magnitude as the mixture solubility ratio. Besides, as fluid is withdrawn from the reservoir, pressure will drop and the water encroaching from the aquifer is not sufficient to keep the pressure high enough, hence why waterflooding is mostly deployed for voidage and pressure maintenance. In addition, the water-oil ratio increases continuously, starting from the wells located in the lower parts of the reservoir. The same correlation can be applied to the water cut, which increases significantly over the field life and is usually the main reason for abandonment. In this way, the wells must be completed in the oil zone far from the water-oil contact (WOC) to avoid an immature water breakthrough. High levels of water-oil ratio may facilitate the occurrence of fingering, which leaves oil behind the reservoir and leads to irreducible oil saturation. Therefore, it might be necessary to perform well interventions.

Figure 3. Production profile for water drive reservoir (Jahn et al., 2003)

The recovery factor from water drive reservoirs is usually much larger than recovery under any other producing mechanism (35 to 75%), even though the exact performance strongly depends on the strength of the aquifer, reservoir structure, oil viscosity and production rate. The rate of water advancement is normally faster in areas of high permeability, and it will result in high water-oil ratios and consequently, earlier economic limits.


The fluids in petroleum reservoirs are naturally subjected to gravity forces; hence the density differences between oil, gas and water result in their natural segregation in the reservoir. This process can be used as a drive mechanism but is relatively weak; instead, it is used to make improvements in other mechanisms. The best conditions for gravity drainage are said to be thick oil zones and high vertical permeabilities. As such, in a solution-gas mechanism, the density difference between oil and gas can lead to the formation of a secondary gas cap, which depends upon factors such as reservoir structural geometry, vertical permeability and production rate (Rosa et al., 2006). This might effectively increase the ultimate recovery factor.

Figure 4. Initial distribution of fluids in a reservoir (Modified from Clark, N.J., Elements of Petroleum Reservoirs, SPE, 1969)

A reservoir can produce under various mechanisms without any preponderant influence of one mechanism on another. In this sense, production is said to be a result of a combined mechanism in which both water and free gas are available to some degree to displace the oil. From the standpoint of Ahmed, two combinations of driving forces can be present in those reservoirs: 1) depletion drive and a weak water drive; 2) depletion drive with a small gas cap and a weak water drive. In both cases, pressure will decrease rapidly given that water encroachment and gas-cap expansion are not enough to maintain reservoir pressure. It is worth mentioning that depletion drive will play an important role in a determined stage of production, given that the reservoir pressure will be reduced below the bubble-point pressure causing the displacement of gas from the solution. Besides, gravity segregation indeed plays an important role in any of the cited drives. The recovery factor for combined mechanisms is greater than recovery for depletion-drive mechanism but less than recovery from water drive and gas-cap drive reservoirs. The ultimate recovery will depend upon the capacity to reduce the strength of recovery by depletion drive. In most cases, it is economically profitable to employ pressure maintenance operations such as gas and/or water injections.

Figure 5. Combination drive-reservoir (Modified from Clark, N.J., Elements of Petroleum Reservoirs, SPE, 1969)

Prediction of Reservoir Drive Mechanism – Production Performance Analysis
Kraken’s integrated data visualization capabilities enables engineers to analyze production variables in order to assess primary and secondary recovery mechanisms contribution through the well’s inflow and outflow performance. This is performed by evaluating the features and trends of those variables and comparing them to the behaviors imposed by the different driving mechanisms. The following example features the production data of a single well (B-1H) analyzed using Kraken’s time plot visualization feature as shown in Figure 6.

Figure 6. Production Parameters (Well B-1H)

Initially, data acquired from production is characterized by maintaining the pressure at high levels, with little water production and low gas-oil ratios. It might suggest that production is driven by a gas-cap mechanism with a considerable contribution of secondary recovery methods such as water/gas injections. As production ensues, the water production rate increases to appreciable amounts, gas-oil ratio increases to a maximum and then declines, and pressure drops sharply. These events may imply that production is driven by depletion drive mechanisms in view of the low oil production rate. Also, the high levels of water production implies that water breakthrough has reached due to previous water injections. Subsequently, the sudden increase in the pressure suggests that secondary recovery methods governs; however, from an economic standpoint, the reduced oil production is not sufficient to justify the efforts leading to the well abandonment.

Producing hydrocarbons in a cost effective way is a challenging assignment for oil companies. In order to effectively produce them, it is imperative for reservoir engineers understanding the drive mechanisms moving hydrocarbons towards the wellbore. This supports the development of production strategies which will maximize assets recovery and consequently projects’ profitability.


  1. After Clark, N.J., “Elements of Petroleum Reservoirs”, SPE, 1969)
  2. Ahmed, T. “Reservoir Engineering Handbook – 4th Edition”. Burlington: Elsevier/GGP, Gulf Professional Publication., 2010.
  3. Cole, F.W. (1969). Reservoir Engineering Manual, Gulf Publ. Co., Houston, Texas, pp. 285.
  4. Jahn, F., Cook, M., Graham, M. “Hydrocarbon Exploration and Production”. Elsevier Science, 2008.
  5. Rosa, A. J., Carvalho, R. S., Xavier, J. A. D. “Engenharia de Reservatórios de Petróleo”. Editora Interciência, Rio de Janeiro, 2006.