Oil Reservoirs description:

Oil can be recovered from the pore spaces of a reservoir rock, only to the extent that the volume originally occupied by the oil is invaded or occupied in some way. There are several ways in which oil can be displaced and produced from a reservoir, and these may be termed mechanisms or “drives”. Where one replacement mechanism is dominant, the reservoir may be said to be operating under a particular “drive”. Possible sources of replacement for produced fluids are:

  • Expansion of undersaturated oil above the bubble point.
  • Expansion of Rock and connate water.
  • Expansion of gas released from soltion in the oil below the bubble point.
  • Invasion of the original oil bearing reservoir by the expansion of the gas from a free gas cap.
  • Invasion of the original oil bearing reservoir by the expansion of the water from an adjacent or underlying aquifer.

Since all replacement processes are related to expansion mechanisms, a reduction in pressure in the original oil zone is essential. The pressure drops may be small if gas caps and aquifers are large and permeable, and, under favourable circumstances, pressure may stabilise at constant or declining reservoir off take rates. The compressibilities of undersaturated oil, rock and connate water are so small that pressures in undersaturated oil reservoirs will rapidly fall to the bubble point if there is no aquifer to provide water.


So these expansion mechanisms are not usually considered separately, and the three principal categories of reservoir are:

  • Solution gas drive ( or depletion drive) reservoir.
  • Gas cap expansion drive reservoirs.
  • Water drive reservoirs.

Frequently two or all three mechanisms ( together with rock/ connate water expansion) occur simultaneously.

Solution Gas Drive Reservoirs:

If a resevoir at its bubble point is put on production, the pressure will fall below the bubble point pressure and gas will come out of solution. Initially this gas may be a disperse, dicontinuous phase, but, in any case, gas will be essentially immobile until some minimum saturation- the equilibrium, or critical gas saturation, is attained.

The actual order of values for critical saturation are in some doubt, but there is considerable evidence to support the view that values may be very low- in the order of 1% to 2% of the pore volume.


Once the critical gas saturation has been established gas will be mobile, and will flow under whatever potential gradients may be established in the reservoir- towards producing wells if the pressure gradient is dominat- segregation vertically if the gravitational gradient is dominant. Segregation will bee affected by vertical permeability variations in layers, but is known to occur even under apparently unfavourable conditions.

Initially ,the gas-oil ratio of a well producing from a closed reservoir will equal solution GOR. At early times, as pressure declines and gas comes out of solution, but cannot flow to producing wells, the producing GOR will decline. When the critical gas saturation is established and if the potential gradients permit, gas will flow towards producing wells.

The permeability to oil will be lower than at intial conditions, and there will be a finite permeability to gas so that the producing gas oil ratio will rise. As more gas comes out of solution, and gas saturations increase, permeability to gas increases, permeability to oil diminishes and this trend accelerates. Ultimately, as reservoir pressure declines towards abandonment pressure, the change in gas formation volume factor offsets the increasing gas to oil mobility ratio and the gas oil ratio trend is reversed, i.e, although the reservoir GOR may continue to increase, in terms of standard volumes, the ratio standardcubic ft/stock tank barrel may decline. In addition to the effect of gas on saturation of, and permeability to, oil, the loss of gas from solution also increases the viscosity of the oil and decreases the foramtion volume factor of trhe oil.

Gas Cap Expansion Reservoirs:

The general behaviour of gas drive reservoirs is similar to that of solution gas drive reservoirs, except that the presence of free gas retards the decline in pressure. By definition the oil must be saturated at the gas oil contact,


so that decline in pressure will cause the release of gas from solution, but the rate of release of gas from solution, and the build up of gas saturation and of gas permeability, will be retarded. At higher prevailing pressures, oil viscosities are lower (due to entrained gas) and provided that the free gas phase can be controlled, and not produced directly from producing wells, better well productivities and lower producing gas oil ratios can be maintained.

Under residual conditions the stock tank oil left in place is So/Bo and the smaller this factor the greater will be the oil recovery. Consequently the higher the pressure at abandonment, the greater the value of Bo, and the smaller this term becomes. In addition abandonment of wells and reservoirs depends primarily upon an “economic limit” – the rate of production required to pay for operating costs, and direct overheads – and an oil flow rate, which depends upon Ko/ mo Which be greater at any given saturation (and so given Ko) under pressure maintenance conditions due to the lower oil viscosity than under depletion conditions.


Water Drive Reservoir:

If a reservoir is underlain by, or is continuous with a large body of water saturated rock (an aquifer) then reduction in pressure in the oil zone, will cause a reduction in pressure in the aquifer.


Although the compressibility of water is small ( ± 3 x 10 -6 psi -1), the total compressibility of an aquifer includes the rock pore compressibility ( ± 5 x 10 -6 psi -1) making the total compressibility in the order of 8 x 10 -6 .psi -1. The apparent compressibility of an aquifer can be substantially greater if some accumulation of hydrocarbons exist in small structural traps throughout the aquifer. An efficient water driven reservoir requires a large aquifer body with a high degree of transmissivity allowing large volumes of water to move across the oil-water contact in response to small pressure drops.

This replacement mechanism has two particular characteristics – first there must be pressure drops in order to have expansion, and secondly, the aquifer response may lag substantially, particularly if transmissivity deteriorates in the aquifer (through diagenesis).

A water drive reservoir is then particularly rate sensitive, and so the reservoir may behave almost as a depletion reservoir for a long period if off-take rates are very high, or as an almost complete pressure maintained water drive reservoir if off-take rates are low, for the given aquifer. Because of the similarity in oil and water viscosities (for light oils at normal depths)


the displacement of oil by water is reasonably efficient, and provided that localised channelling, fingering or coning of water does not occur, water drive generally represents the most efficient of the natural producing mechanisms for oil reservoirs.

As with gas cap drive reservoirs, the maintained pressures lead to lower viscosities and higher Bo values at any given saturation, reducing the saturation and minimising the term So/Bo hence the stock tank oil left at any given economic limit. While reservoir drive mechanisms may be classified into the three categories we have discussed, most often two or more of these mechanisms act simultaneously in a combination drive.

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