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Positions of initial fluid contacts are critical for field reserve estimates and for field development. Typically, the position of fluid contacts are first determined within control wells and then extrapolated to other parts of the field.

[[file:fluid-contacts_fig1.png|thumb|300px|{{figure number|1}}Contact definitions and relationship of contacts in a pool (right) to reservoir capillary pressure and fluid production curves (left). The free water surface is the highest elevation with the same oil and water pressure (zero capillary pressure). The oil-water contact corresponds to the [[displacement pressure]] (DP) on the capillary pressure curve. The transition zone is the interval with co-production of water and hydrocarbons. The fraction of co-produced water is shown by the dashed line on the left. The gas-oil contact is controlled by the volume of gas in the trap, not the capillary properties.]]

Definitions of fluid contacts are based on comparison to [[capillary pressure]] curves ([[:file:fluid-contacts_fig1.png|Figure 1]]). The ''[[free water surface]]'' is the highest elevation at which the pressure of the hydrocarbon phase is the same as that of water. The ''hydrocarbon-water'' (''[http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=oil-water%20contact oil-water]'' or ''[http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=gas-water+contact gas-water]'') ''contact'' is the lowest elevation at which mobile hydrocarbons occur. The ''[[What is a reservoir system?#Waste and transition zones|transition zone]]'' is the elevation range in which water is coproduced with hydrocarbons. The ''[http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=gas-oil%20contact gas-oil contact]'' is the elevation above which gas is the produced hydrocarbon phase.

Positions of initial [http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=fluid%20contact fluid contacts] are critical for field reserve estimates and for field development. Typically, the position of fluid contacts are first determined within control wells and then extrapolated to other parts of the field.

[[file:Core-handling_large.png|thumb]]

Definitions of fluid contacts are based on comparison to [[capillary pressure]] curves ([[:file:fluid-contacts_fig1.png|Figure 1]]). The ''[[free water level]]'' is the highest elevation at which the pressure of the hydrocarbon phase is the same as that of water. The ''hydrocarbon-water'' (''[http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=oil-water%20contact oil-water]'' or ''[http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=gas-water+contact gas-water]'') ''contact'' is the lowest elevation at which mobile hydrocarbons occur. The ''[[What is a reservoir system?#Waste and transition zones|transition zone]]'' is the elevation range in which water is coproduced with hydrocarbons. The ''[http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=gas-oil%20contact gas-oil contact]'' is the elevation above which gas is the produced hydrocarbon phase.

 

[[file:fluid-contacts_fig1.png|thumb|{{figure number|1}}Contact definitions and relationship of contacts in a pool (right) to reservoir capillary pressure and fluid production curves (left). The free water surface is the highest elevation with the same oil and water pressure (zero capillary pressure). The oil-water contact corresponds to the displacement pressure (DP) on the capillary pressure curve. The transition zone is the interval with co-production of water and hydrocarbons. The fraction of co-produced water is shown by the dashed line on the left. The gas-oil contact is controlled by the volume of gas in the trap, not the capillary properties.]]

==Methods for determining fluid contacts==

==Methods for determining fluid contacts==

[[file:fluid-contacts_fig2.png|thumb|{{figure number|2}}Geometries of fluid contacts. (a) Horizontal contacts indicative of hydrostatic conditions in homogeneous reservoir rock. (b) Tilted, flat contacts resulting from hydrodynamic conditions. (c) Contact elevation is constant for each lithology type, but pool contact is irregular due to reservoir heterogeneity. (d) Irregular contacts due to semipermeable barrier in an otherwise homogeneous reservoir.]]

[[file:fluid-contacts_fig2.png|thumb|300px|{{figure number|2}}Geometries of fluid contacts. (a) Horizontal contacts indicative of hydrostatic conditions in homogeneous reservoir rock. (b) Tilted, flat contacts resulting from hydrodynamic conditions. (c) Contact elevation is constant for each lithology type, but pool contact is irregular due to reservoir heterogeneity. (d) Irregular contacts due to semipermeable barrier in an otherwise homogeneous reservoir.]]

Methods for determining initial fluid contacts are listed in Table 1 and are discussed by Bradley.<ref name=pt10r3>Bradley, H. B., ed., 1987, Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref> These include fluid sampling methods, saturation estimation from [http://wiki.seg.org/wiki/Dictionary:Wireline_log wireline logs], estimation from conventional and sidewall cores, and pressure methods. Once initial fluid contact elevations in control wells are determined, the contacts in other parts of the reservoir can be estimated. Initial fluid contacts within most reservoirs having a high degree of continuity are almost horizontal, so the reservoir fluid contact elevations are those of the control wells.

Methods for determining initial fluid contacts are listed in Table 1 and are discussed by Bradley.<ref name=pt10r3>Bradley, H. B., ed., 1987, Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref> These include fluid sampling methods, saturation estimation from [http://wiki.seg.org/wiki/Dictionary:Wireline_log wireline logs], estimation from conventional and sidewall cores, and pressure methods. Once initial fluid contact elevations in control wells are determined, the contacts in other parts of the reservoir can be estimated. Initial fluid contacts within most reservoirs having a high degree of continuity are almost horizontal, so the reservoir fluid contact elevations are those of the control wells.

! Method || Description || Advantages || Limitations

! Method || Description || Advantages || Limitations

|-

|-

| rowspan = 3 | Fluid sampling: [[Production testing|production tests]] [[Drill stem testing|drill stem tests]] [[Repeat formation tester|RFT]] tests || rowspan = 3 | Directly determines fluid contacts by measuring recovered fluids || rowspan = 3 | Direct measure of fluid contact || Rarely closely spaced, so contacts must be interpolated

| rowspan = 3 | Fluid sampling: [[Production testing|production tests]], [[Drill stem testing|drill stem tests]], [[Wireline formation testers|Repeat formation tester(RFT)]] tests || rowspan = 3 | Directly determines fluid contacts by measuring recovered fluids || rowspan = 3 | Direct measure of fluid contact || Rarely closely spaced, so contacts must be interpolated

|-

|-

| Problems with filtrate recovery on DST and RFT

| Problems with filtrate recovery on DST and RFT

| [[Production problems#Water-gas coning|Coning]], [[degassing]], etc. may lead to anomalous recoveries

| [[Production problems#Water-gas coning|Coning]], [[degassing]], etc. may lead to anomalous recoveries

|-

|-

| rowspan = 2 | [[Calculating Sw from the Archie equation|Saturation determination: well logs]] || Estimates fluid contacts from changes in fluid saturations or mobility with depth || Low cost Accurate in simple lithologies || Saturation must be calibrated to production

| rowspan = 2 | [[Calculating Sw from the Archie equation|Saturation determination: well logs]] || Estimates fluid contacts from changes in fluid saturations or mobility with depth || Low cost Accurate in simple lithologies || rowspan = 2 | Saturation must be calibrated to production

|-

|-

| Rapid High resolution || Unreliable in complex lithologies or low resistivity sands

| Rapid High resolution || Unreliable in complex lithologies or low resistivity sands

| Saturation can be related to petro-physical properties || Usually not continuously cored, so saturation profile is not as complete

| Saturation can be related to petro-physical properties || Usually not continuously cored, so saturation profile is not as complete

|-

|-

| Pressure profiles: [[Repeat formation tester|RFT]] tests

| rowspan = 3 | Pressure profiles: [[[[Wireline formation testers|Repeat formation tester|RFT]] tests || rowspan = 3 | Estimates [[Free water level|free water surface]] from inflections in pressure versus depth curve || rowspan = 3 | Little affected by lithology or [[Production problems#Water-gas coning|coning]]

| Estimates [[free water surface]] from inflections in pressure versus depth curve

| Little affected by lithology or [[Production problems#Water-gas coning|coning]]

| Imprecise; data usually require correction

| Imprecise; data usually require correction

|-

|-

| Only useful for thick hydrocarbon columns

| Only useful for thick hydrocarbon columns

|-

|-

| Most reliable for gas contacts Requires many pressure measurements for profile Requires accurate pressures

| Most reliable for gas contacts Requires many pressure measurements for profile Requires accurate pressures

|-

|-

| Pressure profiles: reservoir tests [[Production testing|production tests]] [[Drill stem testing|drill stem tests]]

| rowspan = 2 | Pressure profiles: reservoir tests [[Production testing|production tests]] [[Drill stem testing|drill stem tests]] || rowspan = 2 | Estimates [[Free water level|free water surface]] from pressures and fluid density measurements || rowspan = 2 | Makes use of widely available pressure data

| Estimates [[free water surface]] from pressures and fluid density measurements

| Makes use of widely available pressure data

| Imprecise; data usually require significant correction Only useful for thick hydrocarbon columns

| Imprecise; data usually require significant correction Only useful for thick hydrocarbon columns

|-

|-

| Most reliable for gas contacts Requires pressure tests from both fluid zones and assumed or measured fluid densities to estimate contact Requires accurate pressures

| Most reliable for gas contacts Requires pressure tests from both fluid zones and assumed or measured fluid densities to estimate contact Requires accurate pressures

|}

|}

===Hydrodynamic gradients===

===Hydrodynamic gradients===

[[file:fluid-contacts_fig3.png|thumb|{{figure number|3}}Example of calculating hydrodynamic fluid contacts from pressure data. Pressure elevations are shown by arrows. Calculated fluid contacts are shown by thin lines.]]

[[file:fluid-contacts_fig3.png|300px|thumb|{{figure number|3}}Example of calculating hydrodynamic fluid contacts from pressure data. Pressure elevations are shown by arrows. Calculated fluid contacts are shown by thin lines.]]

A common type of nonhorizontal oil-water contact is tilting in response to hydrodynamics, the movement of water in the reservoir interval. Hydrodynamic conditions that affect fluid contacts are usually associated with active [[meteoric aquifer]]s at relatively shallow depths. Indications of active [[meteoric flow]] include low salinity water, high topographic relief, and proximity to [[recharge]] areas.

A common type of nonhorizontal oil-water contact is tilting in response to hydrodynamics, the movement of water in the reservoir interval. Hydrodynamic conditions that affect fluid contacts are usually associated with active [[meteoric aquifer]]s at relatively shallow depths. Indications of active [[meteoric flow]] include low salinity water, high topographic relief, and proximity to [[recharge]] areas.

Hydrodynamic potential (''h'') is usually measured as the elevation to which water would rise in an open borehole, called the ''potentiometric elevation''. It is calculated from the reservoir pressure by the following relationship (Equation 1):

Hydrodynamic potential (''h'') is usually measured as the elevation to which water would rise in an open borehole, called the ''potentiometric elevation''. It is calculated from the reservoir pressure by the following relationship (Equation 1):

:<math>h = P/(\rho_{\rm w} \times C) + (E_{\rm m} - E_{\rm r})</math>

:<math>h = \frac{P}{(\rho_{\rm w} \times C)} + (E_{\rm m} - E_{\rm r})</math>

where

where

* ''P'' = corrected shut-in pressure

* ''P'' = corrected shut-in pressure

* ''C'' = pressure gradient constant (0.433 psi/ft or 0.1 kg/cm²/m)

* ''C'' = pressure gradient constant (0.433 psi/ft or 0.1 kg/cm²/m)

* ''ρ''_''w'' = specific gravity of water

* ''ρ''_''w'' = specific [[gravity]] of water

* ''E''_m = elevation of pressure measurement

* ''E''_m = elevation of pressure measurement

* ''E''_r = reference elevation (not subsurface depth)

* ''E''_r = reference elevation (not subsurface depth)

:<math>\mbox{gas--oil tilt}    = 1.0/(1.0 - 0.15) \times 17 = 20 \mbox{ ft/mi}</math>

:<math>\mbox{gas--oil tilt}    = 1.0/(1.0 - 0.15) \times 17 = 20 \mbox{ ft/mi}</math>

The fluid contacts are graphically projected away from well B at the calculated dips to determine the contact elevations along the cross section.

The fluid contacts are graphically projected away from well B at the calculated dips to determine the contact elevations along the [[cross section]].

===Reservoir heterogeneity===

===Reservoir heterogeneity===

[[file:fluid-contacts_fig4.png|thumb|{{figure number|4}}Effect of reservoir heterogeneity on fluid contacts. (a) [[Capillary pressure]] curves for facies A and B within the reservoir. The dashed line corresponds to the saturation trend of the well In part (b). Sharp changes in saturation correspond to elevations of facies changes. (b) Oil-water contact corresponding to capillary pressure curves. The free water surface (''f''_w) is the same for all facies, but the different displacement pressure results in different oil-water contact elevations (thick arrows). The transition zones will also have different thicknesses due to different [[relative permeability]] characteristics not shown here. The vertical line is the well position corresponding to the saturation profile shown in part (a).]]

[[file:fluid-contacts_fig4.png|300px|thumb|{{figure number|4}}Effect of reservoir heterogeneity on fluid contacts. (a) [[Capillary pressure]] curves for facies A and B within the reservoir. The dashed line corresponds to the saturation trend of the well In part (b). Sharp changes in saturation correspond to elevations of facies changes. (b) Oil-water contact corresponding to capillary pressure curves. The free water surface (''f''_w) is the same for all facies, but the different displacement pressure results in different oil-water contact elevations (thick arrows). The transition zones will also have different thicknesses due to different [[relative permeability]] characteristics not shown here. The vertical line is the well position corresponding to the saturation profile shown in part (a).]]

[[file:fluid-contacts_fig5.png|thumb|{{figure number|5}}Irregular contact caused by semipermeable barriers in a reservoir. (a) Capillary behavior of the reservoir and barriers A, B, and C. (b) Fluid contact elevations result from charging of the reservoir from the left. Each compartment of the reservoir has a different free water surface and oil-water contact. The displacement pressure of bed A causes the contact elevation difference between contacts 1 and 2. The displacement pressure of fault B results in the elevation difference between contacts 1 and 3. The displacement pressure of the mineralized fracture C results in the difference in elevation between contacts 3 and 4. The gas column is not thick enough to invade across the fault.]]

[[file:fluid-contacts_fig5.png|300px|thumb|{{figure number|5}}Irregular contact caused by semipermeable barriers in a reservoir. (a) Capillary behavior of the reservoir and barriers A, B, and C. (b) Fluid contact elevations result from charging of the reservoir from the left. Each compartment of the reservoir has a different free water surface and oil-water contact. The displacement pressure of bed A causes the contact elevation difference between contacts 1 and 2. The displacement pressure of fault B results in the elevation difference between contacts 1 and 3. The displacement pressure of the mineralized fracture C results in the difference in elevation between contacts 3 and 4. The gas column is not thick enough to invade across the fault.]]

Reservoir rocks may have substantially different [[Pore system shapes|pore structures]] in different parts of a field. These heterogeneities may result in significant variations in hydrocarbon-water contacts, especially in low-permeability reservoirs ([[:file:fluid-contacts_fig4.png|Figure 4]]). Where all reservoir facies are very porous, heterogeneity of [[depositional environments]] does not significantly affect fluid contact elevation.

Reservoir rocks may have substantially different [[Pore system shapes|pore structures]] in different parts of a field. These heterogeneities may result in significant variations in hydrocarbon-water contacts, especially in low-permeability reservoirs ([[:file:fluid-contacts_fig4.png|Figure 4]]). Where all reservoir facies are very porous, heterogeneity of [[depositional environments]] does not significantly affect fluid contact elevation.

Fluid contact elevations in different control wells can be empirically related to lithofacies at the contact. Where critical lithofacies are not penetrated at the fluid contact, the contact elevation of the lithofacies can be predicted from [[capillary pressure]] and [[Relative permeability and pore type|relative permeability]] tests. The greater the difference in capillary pressure and relative permeability behavior for different lithologies within a reservoir, the greater the potential for fluid contact differences caused by heterogeneity. Because [http://en.wikipedia.org/wiki/Surface_tension surface tension] between oil and gas is usually low in subsurface reservoirs,<ref name=pt06r63>Katz et al., 1957, Handbook of Natural Gas Engineering: New York, McGraw-Hill, 802 p.</ref> the effect of reservoir heterogeneity on oil-gas contacts is usually small.

Fluid contact elevations in different control wells can be empirically related to [[lithofacies]] at the contact. Where critical lithofacies are not penetrated at the fluid contact, the contact elevation of the lithofacies can be predicted from [[capillary pressure]] and [[Relative permeability and pore type|relative permeability]] tests. The greater the difference in capillary pressure and relative permeability behavior for different lithologies within a reservoir, the greater the potential for fluid contact differences caused by heterogeneity. Because [http://en.wikipedia.org/wiki/Surface_tension surface tension] between oil and gas is usually low in subsurface reservoirs,<ref name=pt06r63>Katz et al., 1957, Handbook of Natural Gas Engineering: New York, McGraw-Hill, 802 p.</ref> the effect of reservoir heterogeneity on oil-gas contacts is usually small.

Fluid contacts can be extrapolated from control wells if distribution of different reservoir rock types and their capillary properties can be mapped. In many cases, the distribution of rock types within heterogeneous reservoirs is poorly characterized during initial development, so the largest uncertainty in mapping the fluid contact is the uncertainty in the distribution of the lithofacies. The position of the hydrocarbon-water contact may need to be confirmed by well penetration.

Fluid contacts can be extrapolated from control wells if distribution of different reservoir rock types and their capillary properties can be mapped. In many cases, the distribution of rock types within heterogeneous reservoirs is poorly characterized during initial development, so the largest uncertainty in mapping the fluid contact is the uncertainty in the distribution of the lithofacies. The position of the hydrocarbon-water contact may need to be confirmed by well penetration.

==Anomalously thick transition zones==

==Anomalously thick transition zones==

The [[What is a reservoir system?#Waste and transition zones|transition zones]] calculated for homogeneous reservoirs may be relatively thin, particularly in coarse-grained reservoirs. However, thick transition zones are observed in many fields due to reservoir heterogeneity. Interbedded lithologies with different [[Capillary pressure|capillary behaviors]] may result in a thick transition zone in which some lithologies produce hydrocarbons and others produce water. Rocks with complex [[Pore system shapes|pore networks]] (such as combined fracture and matrix [[porosity]]) may also have a thick transition zone, with different fluid types produced from different pore types. The cause of thick transition zones may be evaluated by combined core examination and capillary pressure tests. Some intervals within transition zones characterized by interbedded lithologies may be brought into low water production by [[selective perforation]].

The [[What is a reservoir system?#Waste and transition zones|transition zones]] calculated for homogeneous reservoirs may be relatively thin, particularly in coarse-grained reservoirs. However, thick transition zones are observed in many fields due to reservoir heterogeneity. Interbedded lithologies with different [[Capillary pressure|capillary behaviors]] may result in a thick transition zone in which some lithologies produce hydrocarbons and others produce water. Rocks with complex [[Pore system shapes|pore networks]] (such as combined [[fracture]] and matrix [[porosity]]) may also have a thick transition zone, with different fluid types produced from different pore types. The cause of thick transition zones may be evaluated by combined core examination and capillary pressure tests. Some intervals within transition zones characterized by interbedded lithologies may be brought into low water production by [[selective perforation]].

Upward movement of hydrocarbon-water contacts may leave a zone of [[residual saturation|residual hydrocarbon saturation]] below the present transition zone. The hydrocarbons might be interpreted as part of a transition zone from well log or [[Overview of routine core analysis#Residual fluid saturation|core analysis]], leading to an erroneous approximation of fluid contacts or rock properties. The presence of residual hydrocarbon saturation below an oil pool can sometimes be detected by the presence of two inflections in the plot of hydrocarbon saturation against depth, one at the present transition zone and another at the original transition zone.

Upward movement of hydrocarbon-water contacts may leave a zone of [[residual saturation|residual hydrocarbon saturation]] below the present transition zone. The hydrocarbons might be interpreted as part of a transition zone from well log or [[Overview of routine core analysis#Residual fluid saturation|core analysis]], leading to an erroneous approximation of fluid contacts or rock properties. The presence of residual hydrocarbon saturation below an oil pool can sometimes be detected by the presence of two inflections in the plot of hydrocarbon saturation against depth, one at the present transition zone and another at the original transition zone.

[[Category:Geological methods]]

[[Category:Geological methods]]