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Capillary pressure concepts can be used by geologists, petrophysicists, and petroleum engineers to evaluate the following:

Capillary pressure concepts can be used by geologists, petrophysicists, and [[petroleum]] engineers to evaluate the following:

* Reservoir rock quality

* Reservoir rock quality

* Pay versus nonpay

* Pay versus nonpay

* Expected fluid saturations

* Expected fluid saturations

* Seal capacity (thickness of hydrocarbon column a seal can hold before it leaks)

* Seal capacity (thickness of [[hydrocarbon column]] a seal can hold before it leaks)

* Depth of the reservoir [[fluid contacts]]

* Depth of the reservoir [[fluid contacts]]

* Thickness of the transition zone

* Thickness of the transition zone

==Capillary pressure concepts==

==Capillary pressure concepts==

[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|thumb|300px|{{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 '''''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.]]

[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|thumb|300px|{{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 '''''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.]]

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'' ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|Figure 1a]]). When cohesive forces exceed adhesive forces, the liquid is ''nonwetting'' ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|Figure 1]]).

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'' ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|Figure 1a]]). When cohesive forces exceed adhesive forces, the liquid is ''nonwetting'' ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|Figure 1]]).

[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.jpg|300px|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_c) is the difference in pressure measured across the interface in the capillary (''P''_c = ''P''_nw - ''P''_w). This pressure results from the contrast in pressure gradients caused by the different densities of the nonwetting (''ρ''_nw) and wetting (''ρ''_w) phases (right).]]

[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.jpg|300px|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_c) is the difference in pressure measured across the interface in the capillary (''P''_c = ''P''_nw - ''P''_w). This pressure results from the contrast in pressure gradients caused by the different densities of the nonwetting (''ρ''_nw) and wetting (''ρ''_w) 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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.jpg||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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.jpg|Figure 2]]). ''Capillary pressure'' (''P''_c) 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:

If the end of a narrow capillary tube is placed in a wetting fluid, net adhesive forces draw the fluid into the tube ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.jpg|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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_2.jpg|Figure 2]]). ''Capillary pressure'' (''P''_c) 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>P_\mathrm{c} = (\rho_\mathrm{w} - \rho_\mathrm{nw}) g h</math>, or

:<math>P_\mathrm{c} = (\rho_\mathrm{w} - \rho_\mathrm{nw}) g h</math>, or

These equations show that capillary pressure increases with greater height above the free surface and with smaller capillary size.

These equations show that capillary pressure increases with greater height above the free surface and with smaller capillary size.

The importance of capillary pressure in reservoir studies is that many reservoir rocks can be approximated by a bundle of capillaries, with formation water being the wetting phase and hydrocarbons the nonwetting phase. As hydrocarbons begin to migrate into a rock, displacing the pore water, the hydrocarbons first enter the pores with the largest pore throats (capillaries), leaving the wetting phase (water) in the pores with smaller throats or in small nooks and crannies (surface roughness). As the hydrocarbon column increases, the height above the surface where ''P''_c = 0, called the free surface or ''free water level'' (FWL), becomes greater and the capillary pressure increases, allowing hydrocarbons to enter pores with smaller and smaller throats. This process continues until one of several things occurs:

The importance of capillary pressure in reservoir studies is that many reservoir rocks can be approximated by a bundle of capillaries, with formation water being the wetting phase and hydrocarbons the nonwetting phase. As hydrocarbons begin to migrate into a rock, displacing the pore water, the hydrocarbons first enter the pores with the largest pore throats (capillaries), leaving the wetting phase (water) in the pores with smaller throats or in small nooks and crannies (surface roughness). As the hydrocarbon column increases, the height above the surface where ''P''_c = 0, called the free surface or ''[[free water level]]'' (FWL), becomes greater and the capillary pressure increases, allowing hydrocarbons to enter pores with smaller and smaller throats. This process continues until one of several things occurs:

# generation or migration ends,

# [[Petroleum generation|generation]] or migration ends,

# the trap reaches its spill point, or

# the trap reaches its spill point, or

# capillary pressure is sufficient to force hydrocarbons into the seal (displacement pressure is exceeded), allowing the seal to leak.

# capillary pressure is sufficient to force hydrocarbons into the seal ([[top seal displacement pressure|displacement pressure]] is exceeded), allowing the seal to leak.

==Measuring capillary pressure==

==Measuring capillary pressure==

# Mercury injection, which simulates the premigration wetting characteristics of the reservoir

# Mercury injection, which simulates the premigration wetting characteristics of the reservoir

The mercury injection method is recommended to evaluate the initial static distributions of reservoir fluids prior to production because these distributions are typically controlled by the premigration wetting characteristics. Mercury injection is also favored because it is simpler, cheaper, and less time consuming than porous plate or centrifuge methods. In addition, mercury injection can be conducted on cuttings or sidewall samples. Mercury injection capillary pressure data can also be converted to the reservoir fluid system. Although this involves a number of assumptions on [[wettability]] and the effects of cleaning and extracting the core are largely ignored, the cost and time benefits typically favor mercury injection.

The mercury injection method is recommended to evaluate the initial static distributions of reservoir fluids prior to production because these distributions are typically controlled by the premigration wetting characteristics. Mercury injection is also favored because it is simpler, cheaper, and less time consuming than porous plate or centrifuge methods. In addition, mercury injection can be conducted on cuttings or sidewall samples. Mercury injection capillary pressure data can also be converted to the reservoir fluid system. Although this involves a number of assumptions on [[wettability]] and the effects of [[Core handling|cleaning and extracting the core]] are largely ignored, the cost and time benefits typically favor mercury injection.

==Terminology and mercury injection systematics==

==Terminology and mercury injection systematics==

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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|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''_d). The percentage of pore volume saturated by mercury at the maximum pressure is the ''maximum saturation'' (''S''_max). The unsaturated pore volume at that pressure is the ''minimum unsaturated pore volume'' (''u''_min) ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|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.<ref name=Wardlaw_etal_1976 />

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''_d). The percentage of pore volume saturated by mercury at the maximum pressure is the ''maximum saturation'' (''S''_max). The unsaturated pore volume at that pressure is the ''minimum unsaturated pore volume'' (''u''_min) ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|Figure 3]]). This is sometimes incorrectly referred to as [http://petrowiki.org/Glossary%3AIrreducible_water_saturation irreducible saturation]. This term is inappropriate for the air-mercury system because saturation depends on applied pressure and on the duration of the experiment.<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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|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_R).

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 ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|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_R).

[[File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_4.jpg|thumb|300px|{{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:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_4.jpg|thumb|300px|{{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.]]

Note that this equation calculates the radius of a cylindrical capillary tube; however, real pore throats have very complex geometries. Therefore, the calculated values represent the ''effective'' radii of the pore throats, which may not equal their actual dimensions. Samples dominated by throats of similar size (well sorted) have broad, flat plateaus ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_4.jpg|Figure 4]]). As sorting becomes poorer, the plateau steepens then disappears and the slope of the curve approaches 45&deg; (unsorted).

Note that this equation calculates the radius of a cylindrical capillary tube; however, real pore throats have very complex geometries. Therefore, the calculated values represent the ''effective'' radii of the pore throats, which may not equal their actual dimensions. Samples dominated by throats of similar size (well sorted) have broad, flat plateaus ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_4.jpg|Figure 4]]). As [[Core_description#Maturity|sorting] becomes poorer, the plateau steepens then disappears and the slope of the curve approaches 45&deg; (unsorted).

Data from the mercury withdrawal (air imbibition) curve can provide information regarding the efficiency with which the nonwetting phase can be withdrawn from the pore system. ''Withdrawal efficiency'' (''W''_E) is defined as the ratio of the mercury saturation in the sample at minimum pressure after pressure is reduced (''S''_R) to the saturation at maximum pressure (''S''_max) ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|Figure 3]]).<ref name=Wardlaw_etal_1976 /> Because few samples reach 100% mercury saturation at routinely available injection pressures, data are normalized by the following equation:

Data from the mercury withdrawal (air imbibition) curve can provide information regarding the efficiency with which the nonwetting phase can be withdrawn from the pore system. ''Withdrawal efficiency'' (''W''_E) is defined as the ratio of the mercury saturation in the sample at minimum pressure after pressure is reduced (''S''_R) to the saturation at maximum pressure (''S''_max) ([[:File:charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|Figure 3]]).<ref name=Wardlaw_etal_1976 /> Because few samples reach 100% mercury saturation at routinely available injection pressures, data are normalized by the following equation:

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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.<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.

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.<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==

| Air–mercury || 140&deg; || 480

| Air–mercury || 140&deg; || 480

|-

|-

| Crude oil–water || 0&deg; || 35

| [[Crude oil]]–water || 0&deg; || 35

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''<small>* Contact angle is measured on a quartz plane during drainage</small>''

''<small>* Contact angle is measured on a [[quartz]] plane during drainage</small>''

{| class="wikitable"

{| class="wikitable"

* ''P_dS'' = brine-hydrocarbon displacement pressure of the seal (in psi)

* ''P_dS'' = brine-hydrocarbon displacement pressure of the seal (in psi)

* ''P_dR'' = brine-hydrocarbon displacement pressure of the reservoir rock (in psi)

* ''P_dR'' = brine-hydrocarbon displacement pressure of the reservoir rock (in psi)

===Additional applications===

===Additional applications===

==See also==

==See also==

 

* [[Relative permeability and pore type]]

* [[Relative permeability and pore type]]

* [[Wettability]]

* [[Wettability]]

[[Category:Laboratory methods]]

[[Category:Laboratory methods]]