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Line 25: − If the end of a narrow capillary tube is placed in a wetting fluid, net adhesive forces draw the fluid into the tube (Figure 2). The wetting phase rises in the capillary above the original interface or ''free surface'' until adhesive and gravitational forces are balanced. Because the wetting and nonwetting fluids have different densities, they also have different pressure gradients (Figure 2). ''Capillary pressure'' (P<sub>c</sub>) is defined as the difference in pressure across the meniscus in the capillary tube. Put another way, capillary pressure is the amount of extra pressure required to force the nonwetting phase to displace the wetting phase in the capillary. Capillary+ − + − '''Fig. 1. Effects of interaction of adhesive and cohesive forces on [[wettability]]. (a) If adhesive forces are greater than the cohesive forces, the fluid spreads out on the surface and is termed ''''''''wetting. ''''''''(b) If cohesive forces exceed adhesive forces, the liquid beads up and is termed nonwetting. The measure of relative [[wettability]] is the contact angle (θ), which is measured through the denser phase.''' pressure can be calculated as follows:+ Line 33:
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verbatim after fixing more bugs
| part = Laboratory methods
| part = Laboratory methods
| chapter = Capillary pressure
| chapter = Capillary pressure
| frompg = 221
| topg = 225
| author = Charles L. Vavra, John G. Kaldi, Robert M. Sneider
| author = Charles L. Vavra, John G. Kaldi, Robert M. Sneider
| link = http://archives.datapages.com/data/specpubs/methodo1/data/a095/a095/0001/0200/0221.htm
| link = http://archives.datapages.com/data/specpubs/methodo1/data/a095/a095/0001/0200/0221.htm
Capillary pressure results from interactions of forces acting within and between fluids and their bounding solids. These include both ''cohesive'' forces (surface and interfacial tension) and ''adhesive'' (liquid-solid) forces. When adhesive forces are greater than cohesive forces, the liquid is said to be ''wetting'' (Figure 1a). When cohesive forces exceed adhesive forces, the liquid is ''nonwetting'' (Figure 1b). The relative [[wettability]] of the fluids is described by the ''contact angle'' (θ), which is the angle between the solid and the fluid-fluid interface as measured through the denser fluid (Figure 1). (For information on the measurement of [[wettability]], see the chapter on [[Wettability]]in Part 5.)
Capillary pressure results from interactions of forces acting within and between fluids and their bounding solids. These include both ''cohesive'' forces (surface and interfacial tension) and ''adhesive'' (liquid-solid) forces. When adhesive forces are greater than cohesive forces, the liquid is said to be ''wetting'' (Figure 1a). When cohesive forces exceed adhesive forces, the liquid is ''nonwetting'' (Figure 1b). The relative [[wettability]] of the fluids is described by the ''contact angle'' (θ), which is the angle between the solid and the fluid-fluid interface as measured through the denser fluid (Figure 1). (For information on the measurement of [[wettability]], see the chapter on [[Wettability]]in Part 5.)
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.png|thumb|{{figure_number|1}}Effects of interaction of adhesive and cohesive forces on [[wettability]]. (a) If adhesive forces are greater than the cohesive forces, the fluid spreads out on the surface and is termed </strong>'''''wetting. '''''<strong>(b) If cohesive forces exceed adhesive forces, the liquid beads up and is termed nonwetting. The measure of relative [[wettability]] is the contact angle (θ), which is measured through the denser phase.]]
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.png|thumb|The wetting phase rises above the original or free surface in the capillary tube experiment until adhesive and gravitational forces balance. Capillary pressure (P<sub>c</sub>) is the difference in pressure measured across the interface in the capillary (P<sub>c</sub> = ''P''<sub>nw</sub> - ''P''<sub>w</sub>). This pressure results from the contrast in pressure gradients caused by the different densities of the nonwetting (ρ<sub>nw</sub>) and wetting (ρ<sub>w</sub>) phases (right).]]
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.png|thumb|{{figure_number|2}}The wetting phase rises above the original or free surface in the capillary tube experiment until adhesive and gravitational forces balance. Capillary pressure (P<sub>c</sub>) is the difference in pressure measured across the interface in the capillary (P<sub>c</sub> = ''P''<sub>nw</sub> - ''P''<sub>w</sub>). This pressure results from the contrast in pressure gradients caused by the different densities of the nonwetting (ρ<sub>nw</sub>) and wetting (ρ<sub>w</sub>) phases (right).]]
If the end of a narrow capillary tube is placed in a wetting fluid, net adhesive forces draw the fluid into the tube (Figure 2). The wetting phase rises in the capillary above the original interface or ''free surface'' until adhesive and gravitational forces are balanced. Because the wetting and nonwetting fluids have different densities, they also have different pressure gradients (Figure 2). ''Capillary pressure'' (P<sub>c</sub>) is defined as the difference in pressure across the meniscus in the capillary tube. Put another way, capillary pressure is the amount of extra pressure required to force the nonwetting phase to displace the wetting phase in the capillary. Capillary pressure can be calculated as follows:
:<math>\mathbf{Equation}</math>
:<math>\mathbf{Equation}</math>
where
where
* ''ρ<sub>w</sub>'' = density of the wetting nonwetting fluid<br>ρ<sub>nw</sub> = density of the nonwetting fluid
* ''ρ<sub>w</sub>'' = density of the wetting nonwetting fluid
* ''ρ<sub>nw</sub>'' = density of the nonwetting fluid
* ''g'' = gravitational constant
* ''g'' = gravitational constant
* ''* h'' = height above the free surface<br>σ = interfacial tension<br>θ = contact angle between the fluids and the capillary tube
* ''* h'' = height above the free surface
* ''σ'' = interfacial tension
* ''θ'' = contact angle between the fluids and the capillary tube
* ''r<sub>c</sub>'' = radius of the capillary
* ''r<sub>c</sub>'' = radius of the capillary
Mercury injection capillary pressure data are acquired by injecting mercury into an evacuated, cleaned, and extracted core plug. Mercury injection pressure is increased in a stepwise manner, and the percentage of rock pore volume saturated by mercury at each step is recorded after allowing sufficient time for equilibrium to be reached. The pressure is then plotted against the mercury saturation (Figure 3), resulting in the injection curve (which is also called the drainage curve because the wetting phase is being drained from the sample).
Mercury injection capillary pressure data are acquired by injecting mercury into an evacuated, cleaned, and extracted core plug. Mercury injection pressure is increased in a stepwise manner, and the percentage of rock pore volume saturated by mercury at each step is recorded after allowing sufficient time for equilibrium to be reached. The pressure is then plotted against the mercury saturation (Figure 3), resulting in the injection curve (which is also called the drainage curve because the wetting phase is being drained from the sample).
The pressure at which mercury first enters the sample (after the mercury has filled any surface irregularities on the sample) is termed the ''displacement pressure'' (P<sub>d</sub>). The percentage of pore volume saturated by mercury at the maximum pressure is the ''maximum saturation'' (S<sub>max</sub>). The unsaturated pore volume at that pressure is the ''minimum unsaturated pore volume'' (u<sub>min</sub>) (Figure 3). This is sometimes incorrectly referred to as irreducible saturation. This term is inappropriate for the air-mercury system because saturation depends on applied pressure and on the duration of the experiment (Wardlaw and<ref name=Wardlaw_etal_1976>Wardlaw, N. C., and R. P. Taylor, 1976, Mercury capillary pressure curves and the interpretation of pore structures and capillary behavior in reservoir rocks: Bulletin of Canadian Petroleum Geology, v. 24, p. 225-262.</ref>.
The pressure at which mercury first enters the sample (after the mercury has filled any surface irregularities on the sample) is termed the ''displacement pressure'' (P<sub>d</sub>). The percentage of pore volume saturated by mercury at the maximum pressure is the ''maximum saturation'' (S<sub>max</sub>). The unsaturated pore volume at that pressure is the ''minimum unsaturated pore volume'' (u<sub>min</sub>) (Figure 3). This is sometimes incorrectly referred to as irreducible saturation. This term is inappropriate for the air-mercury system because saturation depends on applied pressure and on the duration of the experiment (Wardlaw and<ref name=Wardlaw_etal_1976 />.
After the maximum pressure is reached, the pressure is reduced in steps and air (the wetting phase) is allowed to imbibe into the sample. The amount of mercury expelled from the sample at each pressure is expressed as a percentage of total pore volume or bulk volume. Again, pressure is plotted against mercury saturation in the withdrawal curve (Figure 3). The volume of pore space still saturated with mercury after pressure is reduced to the minimum is called ''the residual mercury saturation'' (S<sub>R</sub>).
After the maximum pressure is reached, the pressure is reduced in steps and air (the wetting phase) is allowed to imbibe into the sample. The amount of mercury expelled from the sample at each pressure is expressed as a percentage of total pore volume or bulk volume. Again, pressure is plotted against mercury saturation in the withdrawal curve (Figure 3). The volume of pore space still saturated with mercury after pressure is reduced to the minimum is called ''the residual mercury saturation'' (S<sub>R</sub>).
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.png|thumb|Mercury injection capillary pressure curve terminology.]]
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.png|thumb|{{figure_number|3}}Mercury injection capillary pressure curve terminology.]]
Data from the mercury injection curve can be used to approximate the distribution of pore volume accessible by throats of given effective radii (in cm) using the following equation:
Data from the mercury injection curve can be used to approximate the distribution of pore volume accessible by throats of given effective radii (in cm) using the following equation:
where
where
* ''σ'' = interfacial tension of the air-mercury system (480 dynes/cm)<br>θ = air/mercury/solid contact angle (140°)
* ''σ'' = interfacial tension of the air-mercury system (480 dynes/cm)
* ''θ'' = air/mercury/solid contact angle (140°)
* ''P<sub>c</sub>'' = capillary pressure in dynes/cm<sup>2</sup> (1 psi = 69035 dynes/cm<sup>2</sup>)
* ''P<sub>c</sub>'' = capillary pressure in dynes/cm<sup>2</sup> (1 psi = 69035 dynes/cm<sup>2</sup>)
Withdrawal efficiency in the air-mercury system is controlled exclusively by pore geometry, which can be interpreted from the capillary pressure curves and by direct observation of the rock or an epoxy resin pore cast. Critical pore geometry factors affecting withdrawal efficiency include effective pore throat heterogeneity; the ratio of pore body to pore throat size (r<sub>b</sub>/r<sub>t</sub>); and the number of throats connecting each pore (coordination number). Table 1 shows the effect of these parameters on withdrawal efficiency.
Withdrawal efficiency in the air-mercury system is controlled exclusively by pore geometry, which can be interpreted from the capillary pressure curves and by direct observation of the rock or an epoxy resin pore cast. Critical pore geometry factors affecting withdrawal efficiency include effective pore throat heterogeneity; the ratio of pore body to pore throat size (r<sub>b</sub>/r<sub>t</sub>); and the number of throats connecting each pore (coordination number). Table 1 shows the effect of these parameters on withdrawal efficiency.
Relating withdrawal efficiency in the air-mercury system to recovery efficiency in the hydrocarbon-water system is dependent on properties of the fluids as well as properties of the pore system. Fluid properties that affect recovery include viscosity, density, interfacial tension, [[wettability]], contact angle hysteresis, and rate of displacement (Wardlaw and<ref name=Wardlaw_etal_1978>Wardlaw, N. C., and J. P. Cassan, 1978, Estimation of recovery efficiency by visual observation of pore systems in reservoir rocks: Bulletin of Canadian Petroleum Geology, v. 26, p. 572-585.</ref>. Nevertheless, for a given range of fluid properties in a water wet reservoir, the same pore geometry factors that contribute to increased mercury withdrawal efficiency also increase hydrocarbon recovery efficiency.
Relating withdrawal efficiency in the air-mercury system to recovery efficiency in the hydrocarbon-water system is dependent on properties of the fluids as well as properties of the pore system. Fluid properties that affect recovery include viscosity, density, interfacial tension, [[wettability]], contact angle hysteresis, and rate of displacement (Wardlaw and<ref name=Wardlaw_etal_1978 />. Nevertheless, for a given range of fluid properties in a water wet reservoir, the same pore geometry factors that contribute to increased mercury withdrawal efficiency also increase hydrocarbon recovery efficiency.
==Reservoir applications==
==Reservoir applications==
===Conversion from Air-Mercury to Brine-Hydrocarbon System===
===Conversion from air-mercury to brine-hydrocarbon system===
Before mercury injection data can be applied to reservoirs, the data must be converted from the air-mercury system to the brine-hydrocarbon system of the reservoir using the following relationship:
Before mercury injection data can be applied to reservoirs, the data must be converted from the air-mercury system to the brine-hydrocarbon system of the reservoir using the following relationship:
* ''P<sub>Cb</sub>hc/'' = capillary pressure in the brine-hydrocarbon system of the reservoir
* ''P<sub>Cb</sub>hc/'' = capillary pressure in the brine-hydrocarbon system of the reservoir
* ''P<sub>Ca</sub>m/'' = capillary pressure in the air-mercury system<br>σ<sub>b</sub>hc/ = interfacial tension of the brine-hydrocarbon system<br>σ<sub>a</sub>m/ = interfacial tension of air-mercury system<br>θ<sub>b</sub>hc/ = contact angle of the brine-hydrocarbon-solid system<br>θ<sub>a</sub>m/ = contact angle of the air-mercury-solid system
* ''P<sub>Ca</sub>m/'' = capillary pressure in the air-mercury system
* ''σ<sub>b</sub>hc/'' = interfacial tension of the brine-hydrocarbon system
* ''σ<sub>a</sub>m/'' = interfacial tension of air-mercury system
* ''θ<sub>b</sub>hc/'' = contact angle of the brine-hydrocarbon-solid system
* ''θ<sub>a</sub>m/'' = contact angle of the air-mercury-solid system
Ideally, values for brine-hydrocarbon contact angle, surface tension, and fluid densities at reservoir temperature and pressure should be determined in the laboratory using actual reservoir fluids. However, these measurements are difficult and expensive, so approximations such as those given in Tables 2 and 3 are commonly used.
Ideally, values for brine-hydrocarbon contact angle, surface tension, and fluid densities at reservoir temperature and pressure should be determined in the laboratory using actual reservoir fluids. However, these measurements are difficult and expensive, so approximations such as those given in Tables 2 and 3 are commonly used.
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_4.png|thumb|Idealized mercury injection capillary pressure curve shapes. Note that all of the curves have identical displacement pressures and minimum unsaturated pore volumes, but that the saturation profiles would differ dramatically due to differences in pore throat size distributions.]]
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_4.png|thumb|{{figure_number|4}}Idealized mercury injection capillary pressure curve shapes. Note that all of the curves have identical displacement pressures and minimum unsaturated pore volumes, but that the saturation profiles would differ dramatically due to differences in pore throat size distributions.]]
[[File:table_charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.png|thumb|Pore geometry factors affecting recovery efficiency (RE)]]
[[File:table_charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.png|thumb|{{table_number|1}}Pore geometry factors affecting recovery efficiency (RE)]]
===Height above the free water level===
===Height above the free water level===
Having converted the capillary pressure data to the hydrocarbon-brine system of the reservoir and knowing the hydrocarbon and brine densities from laboratory analysis, we can now calculate the amount of hydrocarbon column required (height above the free water level or level where ''P''<sub>c</sub> = 0) to attain a pressure of interest:
Having converted the capillary pressure data to the hydrocarbon-brine system of the reservoir and knowing the hydrocarbon and brine densities from laboratory analysis, we can now calculate the amount of hydrocarbon column required (height above the free water level or level wlate the amount of hydrocarbon column required (height above the free water level or level where ''P''<sub>c</sub> = 0) to attain a pressure of interest:
:<math>\mathbf{Equation}</math>
:<math>\mathbf{Equation}</math>
* ''h'' = height above the free water level (in ft)
* ''h'' = height above the free water level (in ft)
* ''P<sub>c</sub>'' = hydrocarbon-brine capillary pressure (in psi)<br>ρ<sub>b</sub> = specific density of brine at ambient conditions (in gm/cm<sup>3</sup>)<br>ρ<sub>hc</sub> = specific density of hydrocarbons at ambient conditions (in gm/cm<sup>3</sup>)
* ''P<sub>c</sub>'' = hydrocarbon-brine capillary pressure (in psi)
* ''ρ<sub>b</sub>'' = specific density of brine at ambient conditions (in gm/cm<sup>3</sup>)
* ''ρ<sub>hc</sub>'' = specific density of hydrocarbons at ambient conditions (in gm/cm<sup>3</sup>)
* ''0.433'' = the gradient of pure water at ambient conditions
* ''0.433'' = the gradient of pure water at ambient conditions
Capillary pressure data can also be applied to help distinguish reservoir from nonreservoir and pay from nonpay (see [[Effective pay determination]]). Several workers have attempted to correlate capillary pressure data and brine or air permeabilities. Purcell related capillary pressures empirically to air [[permeability]] through the graphical integral of the curve of mercury saturation versus reciprocal capillary pressure squared. Swanson (1981)<ref name=Swanson_1981>Swanson, R. G., 1981, Sample examination manual:AAPG Methods in Exploration Series, 35 p.</ref> proposed a simple nomograph whose application improved estimation of brine [[permeability]] from capillary pressure measurements on sidewall cores and ditch cuttings.
Capillary pressure data can also be applied to help distinguish reservoir from nonreservoir and pay from nonpay (see [[Effective pay determination]]). Several workers have attempted to correlate capillary pressure data and brine or air permeabilities. Purcell related capillary pressures empirically to air [[permeability]] through the graphical integral of the curve of mercury saturation versus reciprocal capillary pressure squared. Swanson (1981)<ref name=Swanson_1981>Swanson, R. G., 1981, Sample examination manual:AAPG Methods in Exploration Series, 35 p.</ref> proposed a simple nomograph whose application improved estimation of brine [[permeability]] from capillary pressure measurements on sidewall cores and ditch cuttings.
Another type of mercury test involves injecting mercury to a saturation less than the maximum, withdrawing the mercury to some residual wetting phase saturation, and then reinjecting the mercury. This process, repeated several times to progressively higher maximum pressures, produces hysteresis loops. These loops, wherein mercury is partially withdrawn and then reinjected, can be used to investigate withdrawal efficiency at various initial saturations (Morrow, 1970<ref name=Morrow_1970>Morrow, N. R., 1970, Irreducible wetting phase saturations in porous media: Chemical Engineering Science, v. 25, p. 1799-1815.</ref>; Melrose and Brandner, 1974<ref name=Melrose_etal_1974>Melrose, J. C., and C. F. Brandner, 1974, Role of capillary forces in determining microscopic displacement efficiency for oil recovery by [[waterflooding]]: Journal Canadian Petroleum Technology, v. 13, p. 54-62.</ref>; Wardlaw and Taylor, 1976<ref name=Wardlaw_etal_1976 />; Wardlaw and Cassan, 1978<ref name=Wardlaw_etal_1978 />; Wardlaw et al., 1988<ref name=Wardlaw_etal_1988 />). Results suggest that the higher the initial saturation of the nonwetting phase, the greater the withdrawal efficiency. Porosimetry uses hysteresis loops to interpret pore body and pore throat size distributions and their patial arrangement (Dullien and Dhawan, 1974<ref name=Dullien_etal_1974>Dullien, F. A. L., and G. K. Dhawan, 1974, Characterization of pore structure by a combination of quantitative photomicrography and mercury porosimetry: Journal Colloid and Interface Science, v. 47, p. 337-349.</ref>; Wardlaw et al., 1988<ref name=Wardlaw_etal_1988 />).
Another type of mercury test involves injecting mercury to a saturation less than the maximum, withdrawing the mercury to some residual wetting phase saturation, and then reinjecting the mercury. This process, repeated several times to progressively higher maximum pressures, produces hysteresis loops. These loops, wherein mercury is partially withdrawn and then reinjected, can be used to investigate withdrawal efficiency at various initial saturations (Morrow, 1970<ref name=Morrow_1970>Morrow, N. R., 1970, Irreducible wetting phase saturations in porous media: Chemical Engineering Science, v. 25, p. 1799-1815.</ref>; Melrose and Brandner, 1974<ref name=Melrose_etal_1974>Melrose, J. C., and C. F. Brandner, 1974, Role of capillary forces in determining microscopic displacement efficiency for oil recovery by [[waterflooding]]: Journal Canadian Petroleum Technology, v. 13, p. 54-62.</ref>; Wardlaw and Taylor, 1976<ref name=Wardlaw_etal_1976>Wardlaw, N. C., and R. P. Taylor, 1976, Mercury capillary pressure curves and the interpretation of pore structures and capillary behavior in reservoir rocks: Bulletin of Canadian Petroleum Geology, v. 24, p. 225-262.</ref>; Wardlaw and Cassan, 1978<ref name=Wardlaw_etal_1978>Wardlaw, N. C., and J. P. Cassan, 1978, Estimation of recovery efficiency by visual observation of pore systems in reservoir rocks: Bulletin of Canadian Petroleum Geology, v. 26, p. 572-585.</ref>; Wardlaw et al., 1988<ref name=Wardlaw_etal_1988>Wardlaw, N. C., M. McKellar, and Y. Li, 1988, Pore and throat size distribution determined by mercury porosimetry and by direct observation: Carbonates and Evaporites, v. 3, p. 1-15.</ref>). Results suggest that the higher the initial saturation of the nonwetting phase, the greater the withdrawal efficiency. Porosimetry uses hysteresis loops to interpret pore body and pore throat size distributions and their patial arrangement (Dullien and Dhawan, 1974<ref name=Dullien_etal_1974>Dullien, F. A. L., and G. K. Dhawan, 1974, Characterization of pore structure by a combination of quantitative photomicrography and mercury porosimetry: Journal Colloid and Interface Science, v. 47, p. 337-349.</ref>; Wardlaw et al., 1988<ref name=Wardlaw_etal_1988 />). Pore sizes have also been evaluated with rate-controlled mercury injection (Yuan and<ref name=Yuan_etal_1986>Yuan, H. H., and B. F. Swanson, 1986, Resolving pore space characteristics by rate-controlled porosimetry: 5th Symposium on [[Enhanced oil recovery]] of the Society of Petroleum Engineers and the Department of Energy, April, SPE/DOE 14892, 9 p.</ref>.
It should be noted that although these more specialized procedures are quite informative, especially for approximating hydrocarbon recovery efficiencies, they are also relatively labor intensive and expensive when compared to routine mercury injection tests.
It should be noted that although these more specialized procedures are quite informative, especially for approximating hydrocarbon recovery efficiencies, they are also relatively labor intensive and expensive when compared to routine mercury injection tests.
[[File:table_charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.png|thumb|Typical contact angle and surface tension values]]
[[File:table_charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.png|thumb|{{table_number|2}}Typical contact angle and surface tension values]]
[[File:table_charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.png|thumb|Typical fluid density ranges]]
[[File:table_charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.png|thumb|{{table_number|3}}Typical fluid density ranges]]
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_5.png|thumb|Effect of capillary pressure (left) on water saturation (right). At any given height above the free water level, water saturations vary widely among rock types (A-E) due to diffferences in capillarity. For example, at 50 ft above free water level, water saturations vary from 18% (rock type A) to 95% (rock type E). A well drilled into an interbedded sequence of these rock types would show multiple oil-water contacts and a highly irregular vertical saturation profile. Note also the wide transition zone in rock type B caused by poor sorting of the pore throats.]]
[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_5.png|thumb|{{figure_number|5}}Effect of capillary pressure (left) on water saturation (right). At any given height above the free water level, water saturations vary widely among rock types (A-E) due to diffferences in capillarity. For example, at 50 ft above free water level, water saturations vary from 18% (rock type A) to 95% (rock type E). A well drilled into an interbedded sequence of these rock types would show multiple oil-water contacts and a highly irregular vertical saturation profile. Note also the wide transition zone in rock type B caused by poor sorting of the pore throats.]]
==See also==
==See also==
* [[Overview of routine core analysis]]
* [[Overview of routine core analysis]]
* [[Core-log transformations and porosity-permeability relationships]]
* [[Core-log transformations and porosity-permeability relationships]]
* [[Rock-water reaction]]
* [[Sem, xrd, cl, and xf methods]]
* [[Sem, xrd, cl, and xf methods]]