The reservoir drive mechanism is the method by which the reservoir provides the energy for fluid production. There are a number of drive mechanisms and a reservoir may be under the influence of one or more of these mechanisms simultaneously.
Reservoir Drive Mechanism – Gas DriveType
- Solution Gas Drive Mechanism
Solution Gas Reservoir Drive Mechanism – If a reservoir contains oil initially above its bubble point then, as production continues, the removal from the reservoir of the produced oil will be compensated for by an expansion of the oil left in place within the reservoir. This will by necessity lead to a reduction in pressure and eventually the pressure within the reservoir will drop below the bubble point. Gas will then come out of solution and any subsequent production of fluids will lead to an expansion of both the oil and gas phases within the reservoir
The gas will come out of solution as dispersed bubbles throughout the reservoir wherever the pressure is below the bubble point but will be concentrated in areas of low pressure such as the rear wellbore area around production wells. However, as discussed previously, the relative permeability to the gas will not be significant until the gas saturation within the pore space increases. Thus, until this happens, gas which has come out of solution will build up in the reservoir until its saturation allows it to produce more easily and this will be evident in a reduction in the volumetric ratio of gas to oil produced at surface, ie, the GOR in the short term. Eventually, as gas saturation increases, free gas will be produced in increasing quantities associated with he produced oil. Further the gas may migrate to above the top of the oil in the reservoir and form a free gas cap if the vertical permeability permits and sufficient time is allowed for gravity segregation. The produced GOR may be observed to decline at surface once the bubble point is reached due to the retention of gas in the pore space once liberated. The other effect will be a reduction in the oil production rate because as the gas comes out of solution from the oil, the viscosity and density of the oil phase increases and its formation volume factor decreases (ie, less shrinkage will occur with production). In addition, as the gas saturation in the pore space increases, the relative permeability to oil will decline. Later the observed production GOR will steadily increase due to increased gas saturation and mobility
- Gas-Cap Expansion Drive / Gas Cap Drive
Gas-Cap Expansion Reservoir Drive / Gas Cap Drive – Frequently, if reservoir pressure is initially equal to or at some later stage falls to the
bubble point pressure for the oil, the gas released from solution may migrate upwards to form a gas cap on top of the oil. As previously discussed, the loss of the gas from being in solution within the oil, will lead to the oil having a higher viscosity and lower
mobility. With the solution gas drive mechanism, the production of fluids occurred primarily with gas expansion as it moved towards the wellbore. The performance of a gas cap drive reservoir in terms of the oil production rate and GOR will vary from that of a
solution gas drive as shown in Figure below.
The pressure in the reservoir will in general decline more slowly, due to the capacity for expansion within the gas cap. The volume of the gas cap will depend upon:
(i) average reservoir pressure
(ii) bubble point pressure
(iii) GOR and gas composition
For such a reservoir, allowing reservoir pressure to drop should maximise the size of the gas cap and provide maximum expansion capability; however, it will also reduce oil mobility. Hence, there are two opposing effects. The ultimate performance of a gas cap drive reservoir is not only influenced by the above, but also by the operational capacity to control gas cusping into the well and thus retain its volume in the gas cap.
Water Drive Mechanism
Water Drive Mechanism – In a reservoir with a water drive mechanism for maintaining reservoir energy, the production of fluids from the reservoir unit is balanced by either aquifer expansion or, via injection of water into the reservoir. The water normally contained within an aquifer system can be defined as edge or bottom water drive depending upon the structural shape, dip angle and OWC within the reservoir (Figures 4/5). The net effect of water influx into the reservoir may be to prevent reservoir pressure dropping and, given the relatively low compressibility, for this to occur without depletion of the aquifer pressure, the aquifer volume must be very large. In the majority of cases, the aquifer is of a finite size and accordingly both the reservoir and aquifer pressure will decline in situations where the production rate is significant. If the production rate is small compared to the aquifer volume, then the compensating expansion of the aquifer may lead to no noticeable depletion for part of the production life of the field.
The expansion of the aquifer into the depleting oil zone in the reservoir will lead to a steady elevation in the oil water contact (OWC) and this may effect the zone within the reservoir from which production is required, e.g., the perforated section. In most cases, the rise in the OWC may not be uniform and, especially in the locality of a significant pressure drawdown, the water may rise above the average aquifer level towards the perforations. This phenomenon is referred to as coning. In addition, fingering due to heterogeneities may occur and this could lead to preferential movement through the more conductive layers and water accessing the wellbore
prematurely. Although water drive is frequently encountered as a naturally occurring drive mechanism, many fields, particularly in the North Sea, are artificially placed on water drive through water injection at an early stage in their development. This extends the
period of production above the bubble point, maximise rates and improves recovery by immiscible displacement (Figure 6). Although water is less compressible than oil or gas and hence less able to provide the expansion volume required in the reservoir to compensate for the removal of fluid by production, it offers advantages in terms of ease of reinjection, safety, availability and safer handling compared to gas as well as powerful economic arguments.
Gravity Drive – Efficient gravity drive within a reservoir, although being an ideal recovery mechanism, is less common. In gravity drive, the hydrostatic pressure due to the oil column and pressure of the gas cap provides the drive downdip to a producing well system
(Figure7).In addition the stable upwards expansion of the underlying aquifer supports the oil rim compression although in many cases the aquifer is small or non existent.For such a system to be effective requires maximum structural dip, low oil viscosity, good vertical and horizontal permeability, preferably an active gas cap and negligible aquifer activity.
Compaction Drive Mechanism
Compaction Drive – The oil within the reservoir pore space is compressed by the weight of overlying sediments and the pressure of the fluids they contain. If fluid is withdrawn from the reservoir, then it is possible that the pressure depletion in the pore space attributable to the production of fluid can be compensated for by the overlying sediments compacting lower sediments such as those of the reservoir production zone. The impact of this is to create a reduction in porosity and thus a potential compression effect. Such a mechanism known as compaction drive will cause a compensating compression of the fluid in the reservoir pore system. Compaction probably occurs to some limited extent in many reservoirs but the compactional movement of the land surface or seabed is rarely measurable except in certain cases
Combination Drive – In the majority of reservoirs the production of fluids is not controlled by one but often by several drive mechanisms in combination. In such situations the response of the reservoir to production is less predictable.