Evaluación de las enzimas hepáticas al administrar extractos

Section 6.6 provided the basic definitions and the measurements of gas, oil, and water saturations in a reservoir rock. These definitions allowed us to define the distribution of pore space or pore volume of a reservoir rock into the individual fluid phases of gas, oil, and water. However, three special types of fluid satura-tions are important, or rather the magnitude of these saturasatura-tions associated with

104 Petroleum Reservoir Rock and Fluid Properties

gas, oil, and water phases are of particular importance and interest in reservoir engineering. These are called

1. Critical gas saturation 2. Residual oil saturation 3. Irreducible water saturation

The three saturations play a key role in understanding the flow of multiphase fluids in porous media and the recovery of hydrocarbon fluids from petroleum reservoirs. As addressed in Chapter 9, these three saturations in fact constitute the end points of the relative permeability curves. Therefore, it is appropriate and logical to discuss these saturations here and hence set the groundwork for relative permeability.

6.7.1 CRITICALGAS SATURATION

Hydrocarbon fluids in a petroleum reservoir normally exist at high pressure and high temperature conditions. Due to this high pressure, hydrocarbon gas is normally dis-solved in the liquid phase. Because production from a petroleum reservoir is initiated, the reservoir pressure begins to decrease, while the reservoir temperature generally remains constant. The steadily declining reservoir pressure results in the evolution of a gas phase (gas saturation increases from 0) when pressure falls below a certain solu-bility limit, known as bubble point pressure. Subsequently, the saturation of the gas phase increases as the depletion of reservoir pressure continues. This gas phase, how-ever, remains immobile or is trapped until its saturation exceeds a certain saturation value, called critical gas saturation and denoted by S_gc. The gas phase then begins to move above this critical gas saturation. The entire process is attributed to the physical process of the gas phase becoming continuous through the system in order to flow.

A typical sequence of events related to critical gas saturation is depicted in Figure  6.6. Critical gas saturation can significantly impact the production of oil from petroleum reservoirs. In primary oil production, solution gas drive (hydrocar-bon gas phase dissolved in the hydrocar(hydrocar-bon liquid phase) is the chief mechanism of oil production because gas comes out of solution and expels the oil. Since gas is quite compressible, it maintains the reservoir pressure high enough to cause recovery.

However, when the gas saturation reaches a critical value, it begins to flow thus reduc-ing the reservoir pressure, hamperreduc-ing oil production. Accordreduc-ing to Donaldson et al.,³ the critical gas saturation is directly related to the relative permeability behavior of the gas in the reservoir (depending on the characteristics of the porous media). The gas phase thus created and rendered mobile has considerably lower viscosity than oil and bypasses (by fingering, channeling, etc.) the oil, particularly in high permeability zones, thus resulting in isolated oil ganglia or globules in the low permeability zones.

6.7.2 RESIDUALOIL SATURATION

Residual oil saturation generally is denoted by S_or, and is basically the oil that remains in the pore space after a certain displacement process. Basically, the S_or can

105 Fluid Saturation

be construed in two different ways: (1) oil saturation remaining in the reservoir at the conclusion of primary production or after either the gas or water displacement process, which is normally the target for EOR, and (2) the final or remaining oil saturation in a reservoir rock core sample at the end of a laboratory gas displacement or water displacement process. Laboratory core-derived values of gas or water dis-placement-based S_or’s can be scaled up with microscopic displacement efficiencies to estimate the values at the reservoir scale.⁴ The concept of residual oil saturation from a laboratory core flood viewpoint can be best described by a simple core plug displacement experiment discussed in the following text.

Figure 6.7a considers a core plug that is initially 100% saturated with a hydro-carbon liquid or oil phase and into which either gas or water is injected. As soon as the displacing phase, either gas or water, is injected in the core, it will start replacing the oil phase from the pore spaces, and oil will be produced from the opposite end of the core plug. As the process continues, more and more oil is produced; however, at a certain point in time, the oil production declines (as the displacing phase is also produced) and eventually ceases and only the displacing phase is produced from the opposite end. If cumulative oil production is now plotted as a function of time, the plot shows a horizontal or a plateau after a certain time, which basically signifies the maxi-mum amount of oil that can be produced from this core plug by either gas or water

Pore space initially filled with oil Rock grains

(a) (b)

(c) (d)

FIGURE 6.6 Schematic representation of events leading to critical gas saturation. (a) Gas phase is dissolved in oil, Sg = 0, (b) evolution of gas phase, Sg is more than zero, (c) gas bubbles grow in size, more gas appears, S_g keeps increasing, and (d) gas phase becomes continuous, S_g = S_gc.

106 Petroleum Reservoir Rock and Fluid Properties

injection (see Figure 6.7b). However, as seen in Figure 6.7c, a 100% recovery of oil from this core plug is not possible by injection of either gas or water, since some oil still remains trapped inside the pore spaces of this core plug sample. This particular trapped oil or remaining oil is nothing but the residual oil saturation. In summary, if gas or water injection is continued further, it simply bypasses this trapped oil and only the displacing phase is produced at the opposite end of the sample. For a simple experiment of this nature, the residual oil saturation can be easily determined from the following equation:

S_or (PV cumulative vol. of oil produced) PV

trapped oil in the samp

= − = lle

PV (6.17)

Injection of gas or water

(a)

(b)

(c)

Production of oil Core plug 100% saturated with oil

Rock grain

Water phase

Trapped oil 12

10

8

6

Oil produced, cc

4

2

0

0 10,000 20,000 30,000 40,000 50,000 Time, s

60,000 70,000 80,000 90,000

FIGURE 6.7 Schematic representation of events leading to residual oil saturation.

107 Fluid Saturation

Depending on the type of displacing phase used (i.e., gas or oil), the S_or in Equation 6.17 is further categorized as S_org (gas flood residual oil saturation) or S_orw (water-flood residual oil saturation). As outlined in Chapter 9, the S_or defined by Equation 6.17 is in fact somewhat analogous to the end point saturation of the relative per-meability curves. Finally, whichever manner one looks at residual oil saturation, probably it is the most important term in the petroleum industry as this signifies how much oil can be ultimately recovered or how much is left behind. Despite the fact that laboratory core floods give a fairly reasonable indication of S_or for a particular formation, it should be noted that these tests may be affected by a number of factors such as the type of test conducted, test conditions and procedures, rock types, and properties of the displaced oil and the displacing phases.

6.7.3 IRREDUCIBLEWATER SATURATION

The terms irreducible water saturation, connate water saturation, and critical water saturation, generally denoted by S_wi (or S_iw), are extensively used interchange-ably to define the water saturation at which the water phase remains immobile.⁵ The other commonly used terms for irreducible water saturation are interstitial water saturation, initial water saturation, or capillary-bound water. Frequently, these terms are used interchangeably in petroleum engineering literature.

To understand the concept of irreducible water saturation, first consider an idealized petroleum reservoir showing gas, oil, and water distribution, as shown in Figure  6.8. The fluids in most petroleum reservoirs, shown in Figure 6.8, have reached a state of equilibrium and have become somewhat separated as per their densities, that is, gas on top followed by the oil phase, and underlain by water. It is believed that in most hydrocarbon-bearing formations, the rock was fully saturated with water prior to the invasion and trapping of hydrocarbons.⁶ However, due to the competition between capillary and gravity forces, during this migration process, complete gravity segregation between the fluid phases never takes place and the con-nate water is distributed throughout the gas and oil zones, as shown in Figure 6.8.

The water in these zones is reduced to some irreducible minimum that is nothing but the irreducible water saturation, S_wi. Tissot and Welte⁷ state that a certain minimum amount of water is left behind in the pore spaces of the reservoir rock as a water film coating the mineral surfaces, which they define as the irreducible minimum amount of connate water found in all hydrocarbon-filled reservoirs.

Gas cap

FIGURE 6.8 Schematic representation of irreducible water saturation in an idealized gravity-capillary equilibrated petroleum reservoir.

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The forces retaining the water in the gas and oil zones are referred to as capillary forces because they are important only because of the tiny pore spaces of capillary size.

Once this entire process was complete, the petroleum reservoirs reached the state of equilibrium known as capillary–gravity equilibrium. The irreducible water saturation is generally not uniformly distributed throughout the reservoir but varies with perme-ability, lithology, height above the free water table, and most importantly with the mag-nitude of capillary and gravity forces in a petroleum reservoir.

Irreducible water saturation can be addressed in a laboratory scenario with a core flooding experiment similar to the one discussed in the Section 6.7.2, but the fluids used must be switched. Initially the core plug sample is 100% water saturated in which either gas or oil is injected until no more water is produced; that is, the core plug sample is flooded down to irreducible water saturation. The numerical value of S_wi can be determined by changing the terms in Equations 6.17 to cumulative volume of water produced or water remaining in the sample. However, one remarkably distinguishing feature between the laboratory-obtained S_wi and one found in gas and oil zones in the petroleum reservoirs is that the former is capillary-viscous based, while the latter is capillary-gravity based. Therefore, S_wi achieved in the laboratory is relative, and per-haps the term irreducible water saturation is somewhat imprecise because it depends on the final drive pressure or viscous pressure drop when flowing gas or oil.

In summary, whichever manner is used, S_wi is a very important parameter because it reduces the amount of space available for the hydrocarbon phase of either gas or oil. Additionally, unlike critical gas saturation or residual oil saturation that can be construed as an artificially created saturation, irreducible water saturation in petro-leum reservoirs, on the other hand, is an entirely mother nature-driven process and is influenced only by the competition between the capillary and gravity forces. A range of 20%–40% in irreducible water saturation in petroleum reservoirs is rather com-mon; however, values ranging from as low as 5% to those as high as 60% (depending on the capillary properties of rocks) have also been reported for some North Sea chalk reservoirs.⁸