IRREDUCIBLE WATER We have already seen how, on a molecular level, the interaction between clay and water results in lower resistivity values. Now we will step back somewhat, and readjust our sights for a microscopic examination of the pores in a pay zone. At this level, we will see that water, rather than clay, is a prime factor contributing to low resistivity pays. In this section, we will describe a number of inter-related factors, each of which are intimately tied to the amount of non-producible bound-water that a reservoir can hold .Though not produced, this bound-water is none-the-less detected and measured by resistivity tools, which do not distinguish between freely produced water and immovable water. We will start with a brief review of the concepts of porosity and saturation, and will take a closer look at permeability and capillarity as they relate to bound-water. We will see that structural position also plays an important role, along with rock-fluid interactions and fluid-fluid interactions, in determining whether a low-resistivity pay zone will produce water or hydrocarbons. Porosity Porosity is the ratio of pore space in the rock to the bulk volume of the rock. It is expressed as a fraction or as a percent of the bulk volume. In equation form, where: ø = porosity in fraction Vp = pore volume Vb = bulk volume Vp and Vb can be expressed in any consistent units. Porosity Classification In terms of production, three types of porosity are recognized: · total porosity refers to all pore space in a rock. · effective porosity refers only to that portion of the total porosity consisting of interconnected pore spaces; more specifically, effective porosity is that portion of the total porosity which will allow fluid flow under normal recovery processes in the reservoir. Effective porosity is a dimensionless quantity, defined as the ratio of interconnected pore volume to the bulk volume. · non-effective porosity is the remaining portion of total porosity which occurs either as isolated pore spaces or as microporosity. The difference between these porosities may be significant in highly vuggy or fractured reservoirs, where some vugs or fractures may be isolated. The presence of clay also complicates the definition of rock porosity. Although the layer of closely bound surface water on the clay particle can represent a very significant amount of porosity, it is not available as potential reservoir porosity for hydrocarbons. Thus, a shale or shaly formation may exhibit a high total porosity, while actually having a low effective porosity as a potential hydrocarbon reservoir. Bound water is held by non-effective porosity. When we calculate water saturation for producibility estimations we are must be sure to use effective porosity. Microporosity Microporosity refers to pore spaces which are so small in diameter (4 µ or less) that they trap and hold water immobile through capillary action. Microporosity is commonly associated with authigenic clay minerals whose open structure is able to trap water. Another example is chalk, which commonly exhibits a large percentage of microporosity, with very high total porosity but low matrix permeability. Microporosity is considered non-effective porosity as far as the production potential of the reservoir is concerned. If it is not recognized as such, microporosity can lead to optimistic predictions of potential reservoir porosity. On the other hand, bound water associated with extensive microporosity can lower resistivity readings and lead to pessimistic estimations of water saturation. Saturation Saturation is a measure of the relative volume of each fluid in the pores. Thus, oil saturation is defined as the ratio of the volume of the oil in a porous rock to the pore volume of the same rock. It is expressed in fraction or in percent, and ranges from 0 to nearly 100%. Water is always present in all reservoirs, and its saturation is always greater than zero. In contrast, the oil saturation is zero in gas reservoirs, and the gas saturation is zero in oil reservoirs when the pressure is above the bubble-point. Oil or gas saturation is calculated by subtracting the water saturation from unity (in two-phase reservoirs). Irreducible Water Saturation Irreducible water saturation (sometimes called critical water saturation) defines the maximum water saturation that a formation with a given permeability and porosity can retain without producing water. This water, although present, is held in place by capillary forces and will not flow. Critical water saturations are usually determined through special core analysis. The critical water value should be compared to the reservoirs in-place water saturation calculated from downhole electric logs. If the in-place water saturation does not exceed the critical value, then the well will produce only hydrocarbons. These saturation comparisons are particularly important in low permeability reservoirs, where critical water saturation can exceed 60% while still producing only hydrocarbons. Using Magnetic Resonance To Obtain Bound Water Saturations After describing total, effective, and non-effective porosity (above), we can now define the saturation of non-producible bound water in terms of effective and total porosity through the following equation: where Swb is bound water saturation fT is total porosity fE is effective porosity In essence, this bound water saturation equation divides non-effective porosity by total porosity. Total and effective porosity measurements can be obtained through magnetic resonance logging. For more information on magnetic resonance logging (NMR) in low resistivity pay zones, see the section of this module entitled Advances in Logging. Ostroff, Shorey, and Georgi (1999) use a variation on the Hill, Shirley, and Klein formula (1979) to show how magnetic resonance log measurements can relate bound water saturation to cation exchange capacity and in-situ flushed zone water salinity: where Qv is the cation exchange capacity per unit volume Co is the salinity of equilibrated saturant brine in equivalents/liter Swb is the NMR-derived clay bound water saturation, which equals CBW / ftotal where CBW is NMR-derived clay bound water. Wettability and Interfacial Tension The principal fluids in a petroleum reservoir are water, oil and gas. When they exist as free phases, they are generally immiscible. When these immiscible fluids co-exist within the pore spaces of a reservoir, their interactions with one another and with the enclosing rock will control their spatial distribution and movement. The two principal properties used to quantify these interactions are wettability, which pertains to rock-fluid interactions, and interfacial tension, which relates to fluid-fluid interactions. Wettability Wettability is the tendency for a fluid to spread or adhere to a solid (rock) surface in the presence of other immiscible fluids. For example, in a hydrocarbon reservoir, we are primarily concerned with water-oil-solid, gas-oil-solid, or gas-water-solid systems. In those systems involving two liquid phases (oil and water), one of the liquid phases will preferentially wet the surface, and hence is called the wetting phase, whereas the other is the non-wetting phase. In those systems involving gas, the liquid is usually wetting, whereas the gas is non-wetting. Interfacial Tension The wettability of a surface is determined by the interaction of interfacial energies that act on the fluids and the surface. For two immiscible co-existing fluids in a porous media, the one with the lower interfacial tension is the wetting phase, while the other is the non-wetting phase. Interfacial tension is a measure of the surface energy per unit area of the interface between two immiscible fluids, such as water and crude oil, or oil and gas. The lower the solid-fluid interfacial tension, the lower the surface energy and the higher the tendency for the fluid to wet that surface. Permeability Permeability is a measure of the ability of porous rock to transmit fluid. Permeability Classification Permeability is further classified as either absolute or effective, depending on whether one or more fluids occupy the pore spaces of the rock. Absolute permeability occurs when only one fluid is present in the rock. It is independent of the fluid used in the measurement. This assumes that the fluid does not interact with the rock. Effective permeability is the measured permeability of a porous medium to one fluid, when other fluids are present. Effective permeability depends on the relative proportion of the fluids present (fluid saturation). Consider the case of oil and water together in a pore system. Under a given pressure gradient, the oil and water flow through a pore system together. Based on Darcys equation, we find that: for oil - for water - where: k = permeability q = flow rate m = fluid viscosity Dp = pressure differential L = length A = cross-sectional area Furthermore, we find that the total flow rate (Qt,) is expressed by the equation: Qt = (Qo + Qw), Qt is less than the flow rate that either phase would have if it were at 100% saturation. Thus it appears as though the two phases interfere with each others progress through the pore system. A useful way to quantify this phenomenon is to define the relative permeability, (kr). Relative Permeability Darcys definition of permeability was for a porous medium which was 100% saturated with the flowing phase (the phase was water). Hydrocarbon reservoirs normally have two and perhaps three phases present: both water and oil; or water and gas; or water, oil, and gas sharing the pore space of the rock. We have seen that having more than one phase present in the pores reduces the ability of the rock to transmit any one of the fluid phases. For this reason, we define the effective permeability as the permeability to one phase when there is more than one phase present in the pore space. Its value decreases as the phases saturation decreases. There is an effective permeability value for each phase present. Usually the effective permeability is expressed as a fraction of the absolute permeability, which is the permeability at 100% saturation of the flowing fluid. This ratio of effective to absolute permeability is termed the relative permeability, and can be displayed as a set of curves as shown in Figure 2, for an oil and water system. Graph shows that the relative permeability to oil decreases as the oil saturation decreases and the water saturation increases above its irreducible (or connate) value. Conversely, the relative permeability to water increases, reaching a maximum when the oil saturation is at its residual saturation. This same general principle applies to any two-or three-phase system. The graph shows that relative permeability is also a function of fluid saturation. When multiple, immiscible fluid phases flow in a rock, the sum of the effective permeabilities of the various fluids will commonly be significantly less than the absolute permeability measured with only a single fluid in the rock. A different way of stating this is that the sum of the relative permeabilities for all the fluids in the rock will commonly be less than one. Relative permeability is the ratio of the effective permeability of the rock to one phase divided by the absolute permeability, and it is quoted at some particular saturation value: kro = kr / k krw = kw / k Relative Permeability And Irreducible Water Saturation Another important relative permeability concept is that of the irreducible or residual saturation. If two fluid phases, A and B, are flowing in a rock, the relative permeability of fluid phase A will decrease as the saturation of fluid A decreases. At some non-zero saturation of fluid A (commonly 5% to 4%), fluid A will cease to flow, and only fluid B will continue to flow in the rock. The saturation at that point is termed the irreducible or residual saturation of fluid A for the A-B two phase flow system in this rock. Relative permeability to oil at irreducible water saturation is 100% or 1, and as water saturation increases, kro decreases until it effectively reaches zero at some high water saturation corresponding to Sor, the residual oil saturation. Relative permeability to water, on the other hand, commences effectively at zero when the rock is at irreducible water saturation Swi, and thereafter increases as Sw increases. It should also be noted that in an oil-wet system, kro is always less at a given Sw than in a water-wet system. Conversely, krw is always greater in an oil-wet system than in a water-wet one. Many workers in this field have proposed generalized empirical equations to relate kro and krw to Sw, Swi, and Sor Of particular note are those cited in Honarpour, Koederitz, and Harvey (1982), Molina (1983), and Pirson, Boatman, and Nettle (1964). A commonly used approximation gives Structural Position If a well is completed above the transition zone where the reservoir is at irreducible water saturation (krw = 0), then water will not be produced. Capillary Pressure In everyday experience, water levels in two or more connected containers have the same level if exposed to the same atmospheric conditions. But when it comes to spaces of capillary size (like those we encounter in porous media), we cannot take this rule so literally. To illustrate, consider what happens when a tube of capillary size is dipped in a larger container filled with water (Figure 3) The water in the capillary tube rises above the water level in the container to a height that depends on capillary size. Although strictly speaking, the water still finds its level, it does so in such a way as to maintain an overall minimum surface energy. In this situation, the adhesion force allows water to rise up in the capillary tube while gravity acts in the opposite direction. The water rises until there is a balance between these two opposing forces. The differential force between adhesion and gravity is the capillary force. This force per unit area is the capillary pressure. Capillary pressure is defined as the pressure difference between two fluid phases (e.g., oil and water) at the same point in the reservoir. It is a measure of the rock-fluid adhesion and fluid-fluid interfacial tension forces that act to hold one fluid phase (e.g., water) at a particular location in the reservoir (e.g., above the oil-water contact) against the force of gravity. Capillary pressure is a complex function of the nature of the contained fluids, the saturation of the fluid phases, the wettability of the rock, and the pore size distribution of the rock. As we might surmise from observations of the capillary tube illustrated in the Figure above, there is a relationship between capillary pressure, Pc , and the interfacial tension between the two fluids (in this example -water and air). where Pc = capillary pressure gwn = wetting/non-wetting phase interfacial tension r = radius of the tube q = angle of contact between the solid surface and liquid Capillary Fluid Rise An alternative way to express capillary pressure is in terms of height above a free water surface. Capillary pressure is equal to the product of the height above the free water surface and the density difference between the two fluid phases at reservoir conditions. In a reservoir, the relationship between water saturation and height above an oil-water or gas-water contact is, of course, strongly dependent on the rock pore system, as well as on the wettability and interfacial tension properties of the rock-fluid system. We will again use Figure 3 of the capillary tube to illustrate fluid height. The capillary tube of radius r will support a column of water of height h. If the density of the air is ra and the density of the water is rw, then the pressure differential at the air-water contact is simply (rw -ra)h. This pressure differential acting across the cross-sectional area of the capillary is exactly counterbalanced by the surface tension, T, of the water film acting around the inner circumference of the capillary tube. If the contact angle is q at the interface between the water and the glass face of the capillary tube, then at equilibrium we have: 2prT cosq = (rw -ra)h . pr2 Force = Pressure . Area By simplifying and rearranging this expression we see that height is expressed as: As the capillary tube radius (r ) decreases, the height (h) of the water column increases; therefore, the height of fluid rise above a free water surface in a capillary tube is inversely proportional to the radius of the tube. We can draw an analogy between the capillary tube radius and the radii of pore throats in the rock matrix. In the above example, we can correlate the air to oil, water with water, and the tube with pore throats. Translating this laboratory observation in terms of reservoir conditions, we can see that water can be drawn up into what would otherwise be a 100% oil column by the capillary effect resulting from small pores in the rock system. Thus the maximum height, h, to which water can be raised is controlled by the following factors: · the surface tension, T, between the two phases (oil and water) · the contact angle, q , between the wetting fluid (water) and the rock · the radius of the pore throats (r) · the density difference between phases (rw -ro in this case) In summary, the capillary rise will be greater in a rock with smaller pore throats than in one with large pore throats. Length Of Transition Zone Given the above factors, it is easy to characterize the relative length of a transition zone in a reservoir. Reservoirs with large pore throats and high permeability have short transition zones, and the transition zone at a gas-oil contact will be shorter than that at an oil-water contact simply because of the inter-phase density differences involved (Figure 4 ). Since a pore system is made up of a variety of pore sizes and shapes, no single pore throat radius can be assigned to a reservoir. Depending on the size and distribution of the pore throats, certain available pore channels will raise water above the free-water level. The water saturation above the top of the transition zone will thus be a function of porosity and pore-size distribution. In a water-wet system, the water will wet the surface of each grain or will line the walls of the capillary tubes. At the time oil migrates into the reservoir, the capillary pressure effects will be such that the downward progress of oil in the reservoir is most strongly resisted in the smallest capillaries. A particular elevation will limit the amount of oil that can be expected to fill the pores. Large-diameter pores offer little resistance (capillary pressure, Pc, is low because pore radius, r, is large). Small-diameter pores offer greater resistance (Pc is high because r is small). For a given reservoir, ro and rw determine the pressure differential that an oil-water meniscus can support. Capillary Pressure And Irreducible Water Saturation Maximum oil saturation is controlled by the relative number of small and large capillaries or pore throats. This maximum possible oil saturation, if expressed in terms of water saturation, translates into a minimum possible water saturation, and this is referred to as the irreducible water saturation, Swi. Shaly, silty, low-permeability rocks with their attendant small pore throats and high capillary pressures, tend to have very high irreducible water saturations. Just the opposite is true for clean sands of high permeability, which have low irreducible water saturations. Figure 5 illustrates this important concept by comparing capillary pressure curves for four rock systems of different porosity and permeability. Structural Position within the Reservoir We all know that gravity segregation causes a natural stratification of reservoir fluids, with gas on top of oil, and oil over water. In the absence of rock pores, the gas, oil, and water will form distinct layers, with sharp contacts between each phase. In a reservoir, however, the contacts between each phase are less distinct, as illustrated in the Figure 6: Reservoir containing oil and water. This diagram divides the reservoir into three levels. The upper level is mainly oil; the lower level is all water, while the middle level shows ever-increasing concentrations of water as depth increases. Plotted on the right-hand side is a curve of water saturation, together with a plot of fluid pressure in the pore spaces. When a formation is above the transition zone, i.e., at irreducible water saturation, the product of f and Sw is a constant. Variations of porosity are normal on a local scale, caused both by changes in the depositional environment and by subsequent diagenesis. If porosity is reduced locally, then either a greater proportion of pore throats will be small or there will be simply fewer pore throats. Either way, the mean radius of the pore throat r will be smaller; thus Pc will be larger, and more water can be held in the pore maintaining the constant: f . Swi After a zone has been analyzed on a foot-by-foot basis for porosity and water saturation, a plot of f versus Sw reveals the presence or absence of a transition zone. Figure 7 shows a log-log plot, where points at irreducible saturation plot along a straight line (the red line denoting Zero Water Production in this graphic), and the points in the transition zone plot to the right of the irreducible line. By plotting the product of . Swi, it is possible to predict certain production characteristics. For points below irreducible saturation, some portion of water production is to be expected, depending on the mobility ratio, (kwµo/koµw), for the particular fluids present. On the other hand, in a low-porosity, low-permeability formation, we again see that surprisingly high water saturations can be tolerated without fear of water production. Conversely, in other formations that exhibit good porosity and permeability, even moderate values of Sw will mean that water production should be expected. Again, since both capillary pressure and relative permeability data are a strong function of pore size distribution and geometry (among other factors), they will, in turn, often fall into groups that correlate with specific reservoir facies (Morgan and Gordon 1970). Two samples representing two different reservoir facies may show very different relative permeability relationships - even though their other reservoir properties (porosity or permeability) may be very similar. Figure 8 shows water-oil relative permeability curves for two samples with almost identical permeabilities, taken from two different geologic facies. The difference in the measured relative permeabilities illustrates the importance of pore system configuration in determining fluid flow characteristics. One important observation to be derived from evaluating capillary pressure and relative permeability for individual geologic facies is the determination of the producing oil-water (or gas-water) contact elevation throughout various parts of a reservoir. This elevation can vary across a reservoir, and can be substantially different from the free water surface elevation. The free water surface should be at a constant elevation throughout the reservoir, providing the reservoir is in a state of gravity-capillary equilibrium with no significant flow occurring. The producing oil-water contact is often taken as the highest elevation where 100% water is produced. This depth will not necessarily be the same at all points in the reservoir, even under equilibrium conditions. It will strongly depend on local capillary pressure (water saturation versus height above the free water surface) and the relative permeability characteristics of the rock. Capillary Pressure And Geologic Facies A relationship between geologic facies and capillary pressure curves is illustrated graphically in Figure 9. Three geologic facies (A, B, C) are shown, each having a different capillary pressure versus water saturation relationship. On the right side of the graph, increasing capillary pressure has been expressed in terms of height above an oil-water contact (the conversion is for a specific set of assumed rock and fluid properties and is not a general correlation). Note that each of the curves becomes asymptotic to some minimum water saturation value (the irreducible water saturation), in spite of large increases in capillary pressure (or height above the oil-water contact). The three different geologic facies in this graphic also have greatly contrasting permeabilities, although their porosities are similar. Capillary pressure versus saturation data often correlate very strongly with permeability because both properties are strongly dependent on pore throat size distribution. As illustrated in this graphic, at a measured capillary pressure of 10 psi (equivalent to a height of almost 25 ft (7.6 m) above the oil-water contact in this example) the water saturation in Facies A has been reduced to the irreducible water saturation of less than 10%. At the same height above the oil-water contact, the water saturation in Facies B could be almost 40%. Note that this is above the irreducible water saturation of about 30% for Facies B. At points in the reservoir where the shaly limestone Facies C is present at the same height above the oil-water contact, the water saturation could be over 95%! In fact, the capillary pressure versus water saturation curve for Facies C indicates that this facies would probably NOT be considered as pay in this reservoir. Putting It All Together - Geology and Fluids We have just reviewed a number of factors which influence the Irreducible Water Saturation within a formation. These factors include interactions between fluids and rock, as well as interactions between different fluids. By examining porosity, relative permeability, and capillary pressure relationships, along with rock texture and structural position, it is possible to determine whether a well having high Sw calculations will actually produce water, or instead, will produce water-free. For example, as we move toward the top of a fining-upward sequence, the decrease in sand grain diameter will produce a corresponding decrease in pore throat radius. This decrease in pore throat radius is accompanied by an increase in capillary pressure, thus increasing the amount of water that can be imbibed into the system. If we add clay or silt to this example, we can expect that microporosity will constitute a substantial percentage of total porosity. Such a setting is bound to produce high values of irreducible water saturations. Both irreducible water and residual hydrocarbon saturations are strongly influenced by rock texture, which is controlled by depositional environment. Fine-grained sediments, usually characteristic of low-energy depositional environments, tend to have high irreducible water with high residual hydrocarbon saturations; coarse-grained sediments, characteristic of high-energy environments, tend to have low irreducible water saturation and low residual hydrocarbon saturation. In addition, fine-grained sediments tend to have lower permeability than coarse-grained sediments. These factors must all be considered together when analyzing low resistivity pay zones. Porosity, capillarity, relative permeability, structural position and grain size will all influence the final evaluation of irreducible water saturation in a low resistivity pay zone.
Posted on: Tue, 25 Nov 2014 21:22:27 +0000
Trending Topics
Recently Viewed Topics
© 2015