PNG 301
Introduction to Petroleum and Natural Gas Engineering

4.3: Drive Mechanisms in Oil Reservoirs


As with all gases and liquids in nature (weather fronts, sea and air currents, etc.), crude oil in the reservoir flows from locations of high pressure (the interior of the reservoir) to locations of low pressure (production wells). It is this pressure differential that is the driving force for fluid flow and production from wells. To start our discussion on fluid movement, we will begin with a discussion of the Drive Mechanisms in an oil reservoir. Drive mechanisms are the physical phenomena that occur in the reservoir that help to keep the reservoir pressures high.

There are five drive mechanisms that are associated with the Primary Production (production that occurs without any pressure maintenance supplied by fluid injection or by use of chemical, miscible, or thermal enhanced recovery methods) of a crude oil reservoir. These are:

Rock and fluid expansion occur due to the slightly compressible nature of crude oil, Interstitial (or Connate) Water, and reservoir rock. Interstitial, or connate, water is the initial water saturation in the reservoir at discovery. In Lesson 3, we saw that as pressure is reduced the compressibility of the rock and fluids (Equation 3.17, Equation 3.26, Equation 3.30, and Equation 3.43a) causes the volumes of the oil and water to expand and the pore-volume to shrink (equivalent to the rock grain volume expanding). All of these phenomena cause the pressure to remain higher than it would otherwise have been had they not been occurring (engineering analysis would indicate that if the fluids are expanding and the pore-volume is shrinking, then the in-situ fluids will be displaced to areas of low pressure).

We can think of rock and fluid expansion with the simple analogy of a water (or oil) filled balloon. If we fill the balloon with water, then the size of the balloon increases due to the increased pressure required to force the water into the balloon. In addition, if we pinch down on the balloon opening, then the water would remain in place inside of the balloon. In this example, the pore-volume in the reservoir is analogous to the water filled space in the balloon and the in-place fluid is the high-pressure water. Now, if we were to release the balloon opening to the low pressure atmosphere, then the pore-volume in the balloon would shrink and, to a lesser extent, the water inside the balloon would increase. These two effects cause the water to flow out of the balloon to the atmosphere. One conceptual issue with this analogy is the highly compressible nature of the rubber balloon. In a reservoir, the rock grains are many orders of magnitude less than the compressibility of rubber. Consequently, the flow of fluids from a hydrocarbon reservoir will not be as dramatic as that presented in this example.

Rock and fluid expansion occurs in most reservoirs; however, due to the small changes in volume associated with the slightly compressible nature of oil and water, and the low compressibilities associated with most reservoir rock, this drive mechanism has a very low recovery efficiency and typically accounts for less than five percent recovery of the STOOIP. In addition, in the presence of a free gas phase, its impact is dwarfed by the highly compressible nature of gas (note: gas expansion is excluded from rock and fluid expansion drive because the expansion of gas is included as separate drive mechanisms in solution gas drive and gas cap drive). Consequently, rock and fluid expansion may only be significant in undersaturated crude oil reservoirs (oil reservoirs discovered at pressures above the bubble-point pressure of the crude oil, p b .

Solution gas drive is caused by the solubility of natural gases in crude oils. This was discussed in Lesson 3 and is quantified with the oil property of the solution gas-oil ratio, R s . In undersaturated oil reservoirs, oil is found as a single-phase hydrocarbon fluid at discovery. As wells are drilled and put into production, the reservoir pressure declines (but supported by rock and fluid expansion) until it reaches the bubble-point pressure. At this time, gas comes out of solution and also begins to expand. It is the expansion of the gas that was originally in solution in the oil phase that we refer to as solution gas drive.

An analogy that we can use for solution gas drive is a bottle full of a carbonated beverage. If we were to shake a bottle of carbonated beverage with our thumb covering the bottle opening, the beverage would remain in the bottle. Now, if we were to remove our thumb from the bottle opening, then the gas in the beverage would come out of solution and expand in the bottle. This expansion of the liberated gas would drive both the beverage (and any gas remaining in solution in the beverage) and the free gas out of the bottle.

Typically, solution gas drive accounts for between 15 – 20 percent recovery of the STOOIP in normal oil reservoirs.

Gas cap drive is similar to solution gas drive; however, it only occurs in saturated oil reservoirs (oil reservoirs discovered below the bubble-point pressure of the crude oil). In saturated oil reservoirs, the free gas forms a Gas Cap (portion of the reservoir overlain by free gas due to gravity segregation). For example, the red colored region of the Numbi field in Figure 3.01 is a gas cap. As wells are drilled and put into production, the pressure declines (again, other drive mechanisms may provide support to partially maintain the reservoir pressure), and the gas cap begins to expand. It is the expansion of the gas that was originally free in the reservoir that we refer to as gas cap drive.

Please note that during pressure decline, gas will also come out of solution. The expansion of this liberated gas is still referred to as solution gas drive. Thus, in this situation, we would have combined drives occurring simultaneously in the reservoir including gas cap drive and solution gas drive, and, to a lesser extent, rock and fluid expansion.

Gas cap drive can account for up to 30 percent recovery of the STOOIP depending on the size of the original gas cap.

Gravity drainage is another drive mechanism that can occur in both saturated and undersaturated oil reservoirs. In very thick reservoirs or in highly dipping reservoirs, gravity drainage can be a very effective drive mechanism and may account for up to 40 percent recovery of the STOOIP. In order to be effective, wells must be completed deep in the reservoir and must have a large Oil Column (reservoir depth containing oil) above the completion.

The last drive mechanism associated with oil reservoirs is aquifer drive, or water encroachment. If a reservoir is in contact with a water-bearing aquifer, then as the reservoir pressure declines, the rock and water in the aquifer expand and water is expelled from the aquifer and into the reservoir. This encroachment of water into the reservoir provides pressure support and helps to displace oil from the regions of the reservoir in contact with the aquifer to production wells. Aquifer drive may account for 35 – 45 percent recovery of the STOOIP depending on the size of the aquifer.

As previously discussed, these drive mechanisms commonly act simultaneously. When this occurs, we refer to the reservoir as a reservoir undergoing combined drive. Table 4.01 shows the drive mechanisms typically found in crude oil reservoirs and the maximum Recovery Factors (percentage of STOOIP recovered) typically observed in the field.

Table 4.01: Naturally Occurring Drive Mechanisms and Associated Recovery Factors in Oil Reservoirs
Recovery Mechanism Typical Recovery Efficiencies (Percent STOOIP)
Rock and Fluid Expansion Up to 5 percent
Solution Gas Drive 20
Gas Cap Drive 30
Gravity Drainage 40
Aquifer Drive (Weak Aquifer) 35
Aquifer Drive (Strong Aquifer) 45
Combined Drive Mechanisms 60 – very rarely this high

The recovery factors shown in Table 4.01 may be a little deceptive since they represent the maximum recovery factors that can be expected from the reservoir for the different drive mechanisms. Typically, overall (combined) recovery factors from primary production rarely exceed 30 – 35 percent recovery of the STOOIP of the reservoir.