Irreducible Water Saturation

If the NMR response is capable of estimating the pore size distribution, then it also has the potential to estimate the fraction of the pore space that is capable of being occupied by the hydrocarbon and the remaining fraction that will only be occupied by water. The Free Fluid Index (FFI) is an estimate of the amount of potential hydrocarbons in the rock when saturated to a given capillary pressure. It is expressed as a fraction of the rock bulk volume. The Bulk Volume Irreducible (BVI) is the fraction of the rock bulk volume that will be occupied by water at the same capillary pressure. The fraction of the rock pore volume that will only be occupied by water is called the irreducible water saturation (Siwr = BVI/cj ). The amount of water that is irreducible is a function of the driving force to displace water, i.e., the capillary pressure. Usually the specified driving force is an air-water capillary pressure of 0.69 MPa (100 psi). 

Interpretation for irreducible water saturation assumes that the rock is water-wet or mixed-wet (water-wet during drainage but the pore surfaces contacted by oil becomes oil-wet upon imbibition). If a porous medium is water-wet and a nonwetting fluid displaces the water (drainage), then the non-wetting fluid will first occupy the larger pores and will enter the smaller pores only as the capillary pressure is increased. This process is similar to the accumulation of oil or gas in the pore space of a reservoir. Thus it is of interest to estimate the irreducible water saturation that is retained by capillarity after the hydrocarbon accumulates in an oil or gas reservoir. The FFI is an estimate of the amount of potential hydrocarbon in 

The observation that the irreducible water occupies the pores with the shorter relaxation times suggests that it may be possible to determine a relaxation time 

The concept of a T2 cut-off that partitions the relaxation time distribution between the pores which can be displaced and those that cannot does not always apply. An exception is when there is significant diffusional coupling between the micropores that retain water at a high capillary pressure and the macropores in close proximity to the microporous system [26, 27]. A spectral BVI model or a forward model has been suggested to interpret these systems [30, 31, 53]. 

---

Vertical interval in the reservoir, whose length depends on porosity and permeability, in which the water saturation changes from 100 per cent at the bottom to irreducible water saturation at the top. In the transition zone, two phases (water or oil, and gas) are movable. 

Accurate interpretation of the formation properties (porosity, permeability and irreducible water saturation) requires reliable estimates of NMR fluid properties or the relationship between diffusivity and relaxation time. Estimation of oil viscosity and solution-gas content require their correlation with NMR measurable fluid properties. These include the hydrogen index, bulk fluid relaxation time and bulk fluid diffusivity [8]. 

Interpretation of NMR well logs is usually made with the assumption that the formation is water-wet such that water occupies the smaller pores and oil relaxes as the bulk fluid. Examination of crude oil, brine, rock systems show that a mixed-wet condition is more common than a water-wet condition, but the NMR interpretation may not be adversely affected [47]. Surfactants used in oil-based drilling fluids have a significant effect on wettability and the NMR response can be correlated with the Amott-Harvey wettability index [46]. These surfactants can have an effect on the estimation of the irreducible water saturation unless compensated by adjusting the T2 cut-off [48]. 

NMR has proven to be a valuable tool for formation evaluation by well logging, downhole fluid analysis and laboratory rock characterization. It gives a direct measure of porosity as the response is only from the fluids in the pore space of the rock. The relaxation time distribution correlates with the pore size distribution. This correlation makes it possible to estimate permeability and irreducible water saturation. When more than one fluid is present in the rock, the fluids can be identified based on the difference in the fluid diffusivity in addition to relaxation times. Interpretation of NMR responses has been greatly advanced with the ability to display two distributions simultaneously. 

J. Chen, G. J. Hirasaki, M. Flaum 2004, Effects of OBM Invasion on Irreducible Water Saturation Mechanisms and Modifications of NMR Interpretation, SPE 90141 presented at SPE ATC E, Houston, TX, 26-29 September, 2004. 

Procedure. Core floods were carried out in horizontally mounted Berea sandstone cores of length 61 cm and diameter 5 cm. Porosity varied from 18 to 25% and brine permeability from 100 to 800 Jim2. The cores were coated with a thin layer of epoxy and cast in stainless steel core holders using molten Cerrobend alloy (melting point 70°C). The ends of the cores were machined flush with the core holder and flanges were bolted on. Pore volume was determined by vacuum followed by imbibition of brine. Absolute permeability and porosity were determined. The cores were initially saturated with brine (2% NaCl). An oil flood was then started at a rate of lOm/day until an irreducible water saturation (26-38%) was established. 

Wettability. Wettability of the porous medium controls the flow, location, and distribution of fluids inside a reservoir (7, 28). It directly affects capillary pressure, relative permeability, secondary and tertiary recovery performances, irreducible water saturations, residual oil saturations, and other properties. 

Figure 18. Relative permeability to water at residual oil saturation in clean and wettability-modified Berea cores containing different oils, calculated relative to the effective permeability to oil at irreducible water saturation.

Porous Medium. Ottawa sand was used as the porous medium for flow experiments. The porosity and absolute permeability to the water were determined prior to the start of flow experiments (Table I), and the core was then resaturated with live oil by displacing the water. During the resaturation process, almost 98% of the water was displaced. This value of irreducible water saturation (2%), although much lower than the field values, is not exceptional in laboratory tests of this nature. 

Amott Test A measure of wettability based on a comparison of the amounts of water or oil imbibed into a porous medium spontaneously and by forced displacement. Amott test results are expressed as a displacement-by-oil (60) ratio and a displacement-by-water ratio (Sw). In the Amott-Harvey test, a core is prepared at irreducible water saturation and then an Amott test is run. The Amott-Harvey relative displacement (wettability) index is then calculated as 6W — 60, with values ranging from — 1.0 for complete oil-wetting to 1.0 for complete water-wetting. See also reference 8, Wettability, Wettability Index. 

Figure 1. Plots of permeability, Ar, versus intercommunicating (open) porosity, specific surface area (per unit of pore volume) and irreducible water saturation, are considered in the data fitting, showing both the measured and fitted data for VuktyPskiy gas-condensate deposit, USSR. 

The use of multi-variable linear regression analysis enabled the author to demonstrate experimentally that the permeability can accurately be estimated from the other petrophysical properties. It was shown that besides porosity, specific surface area and irreducible water saturation are important factors for such permeability estimations. Such experimental relations should be established for other reservoir rocks. 

Initially, the cores were evacuated under a vacuum pressure of 20-millitorr for at least twelve hours, and then saturated with PW. The initial oil saturation (S -) and irreducible water saturation conditions in each core... 

The pore volume (later referred to as PV or t) and the porosity, ( ) of the dry packed core is first determined from the weight and measured grain density of the Ottawa sand (2.65 g/cc) and the bulk volume of the core. The permeability of the sandpack to gas is then measured in a N2 permeameter from a minimum of six values of pressure drop versus flowrate. The core is placed in a multifluid flow displacement apparatus for saturation with brine or fresh water. The saturated core is oil flooded to irreducible water saturation, at rates which make the capillary pressure... 

The scale varies from positive for water-wet conditions, through zero for intermediate-wet conditions, to negative for oil-wet conditions. The scale is believed to be independent of the pore geometry since the influence of the pore geometry, which is similar for the imbibition and drainage curves, cancels out on taking the ratio of areas. This scale, then, is a measure of the number and distribution of pores which are oil-wet and water-wet over the saturation range from irreducible water saturation to residual oil saturation. 

The significance of the increased recovery at a flood velocity of 3 ft/day was uncertain because the recovery efficiency of oil from a water-wet medium could very well be a function of the irreducible water saturation,... 

For example, let us consider a sample with a perfectly water-wet surface (i.e., the contact angle measured through the water is equal to zero) which has been saturated with brine and, subsequently, driven down with oil to irreducible water saturation. It is usually assumed that at this stage there is still left a film of water covering the entire solid surface. Let us suppose that an imbibition-type relative permeability test is started at this point. The question may be asked whether in the vicinity of the irreducible water saturation all, or only a portion of the water contained in the sample will flow. 

The first oil flow in the drainage experiment was measured at 31% pore volume Soltrol saturation, the irreducible water saturation... 

I. Oil recovery tests at irreducible water saturation. Before each oil recovery test, the permeability of the sandpack to brine was determined. Next, oil was pumped through the sandpack until irreducible water saturation was reached. The total volume of displaced brine was determined volumetrically. A regular brineflood was carried out in the oil saturated sandpack. After the brineflood, the sandpacks were resaturated with oil. The polymerflood was carried out in the resaturated sandpack. 

Experimental evidence [35] snggests that, in the presence of foam, the irreducible phase saturations of water and oil (S rg, Soj.g) can be lowered significantly. Thus, the irreducible water saturation, Swrg, can actnally be lower in the presence of foam than the measnred valne of 46%, determined from the gasAvater relative permeability experiment (Appendix). For all of the foam simnlations, an irreducible water saturation of 30% was chosen. Since the in-sitn water saturation was not measnred, the critical water saturation valne (set to 0.35) conld not be determined accurately. 

An initially brine saturated core was flooded with oil to irreducible water saturation (S c), and subsequently waterflooded. During the water-flooding stage, the pressure drop and oil productions were continuously monitored until the residual oil saturation was reached. In Figure 27 the comparison between experimental and simulated values of the waterflood recovery and concurrent pressure drop (across the core) is made. The history matched relative permeability curves are shown in Figure 28 the corresponding parameters are listed here ... 

The relative permeabilities are functions of the water saturation and typical behavior is shown in Figure 8.32. For this case the oil phase relative permeability goes to zero at = 0.62 so that 38 percent of the oil remains trapped in the reservoir. This means that there is a residual oil saturation of 38 percent. Also, the relative water permeability goes to zero at = 0.48. This means that there is an irreducible water saturation of 48 percent. The residual oil saturation and irreducible water saturation vary from reservoir to reservoir. 

The eapillary pressure versus brine saturation curves for four dolomite samples is shown in Figure 2. For thirteen studied carbonate samples the irreducible water saturations Swi (no water flow zone) range from 0.21 to 0.87 (table 1). 

Figure 6 shows the normalized measured coupling coefficient Cm(Sw < 1) / Cm(Sw =1) versus brine saturation. We observe that the relative streaming potential eoupling coefficient decreases while the water saturation decreases. The streaming potential coupling coefficient falls to zero when the water saturation reaches the irreducible water saturation S i. 

I ig. 6. Normalized coupling coefficient Cra(Swwater saturation i br four oarbtmte porous systems, i iwinio Minimum irreducible water saturation Maximum irreducible water saturation. 

Eq. 1 is similar to the expression commonly used to relate the relative mobility of the water bank at residual oil saturation to oil-bank mobility at irreducible water saturation ... 

Fig. 4 summarizes relative permeability measurements derived from displacement studies conducted on one lower and two upper reservoir rock samples. Reservoir oil and synthesized formation water were the displaced and displacing fluids. Relative permeabilities of oil and water were calculated for the complete saturation range from floodout history. Results exhibit relatively good agreement with end-point measurements of water permeability and residual oil saturation. The lower sandstone sample is not considered representative of that reservoir in view of the anomalously low residual oil saturation. Relative permeability to water is expressed as a fraction of relative permeability to oil at irreducible water saturation. 

---