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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

[[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:

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

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

# the trap reaches its spill point, or

# the trap reaches its spill point, or

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 [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 />

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).

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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

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|-

| 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===

[[Category:Laboratory methods]]

[[Category:Laboratory methods]]