Changes

If purely hydrodynamic in origin, the fluid contact tilt can be extrapolated across the field as a flat plane that intersects the contact elevation in a minimum of three control wells. Regional fluid pressure data can be used to extrapolate the fluid contacts from the contacts measured in one or two wells. Only corrected [[Pressure transient testing#Pressure buildup tests|shut-in pressure]]s unaffected by nearby production should be used for this evaluation.

If purely hydrodynamic in origin, the fluid contact tilt can be extrapolated across the field as a flat plane that intersects the contact elevation in a minimum of three control wells. Regional fluid pressure data can be used to extrapolate the fluid contacts from the contacts measured in one or two wells. Only corrected [[Pressure transient testing#Pressure buildup tests|shut-in pressure]]s unaffected by nearby production should be used for this evaluation.

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

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

where

where

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

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

Potentiometric elevations are mapped and contoured to determine the change in Potentiometric elevation per unit distance, called the ''Potentiometric gradient''. The hydrodynamic tilt of a fluid contact can be estimated from the Potentiometric gradient and fluid densities by the following relationship<ref name=pt06r56>Hubbert, M. K., 1953, [http://archives.datapages.com/data/bulletns/1953-56/data/pg/0037/0008/1950/1954.htm Entrapment of petroleum under hydrodynamic conditions]: AAPG Bulletin, v. 37, p. 1954–2026.</ref><ref name=pt06r21>Dahlberg, E. C., 1982, Applied Hydrodynamics in Petroleum Exploration: New York, Springer Verlag, 161 p.</ref>:

Potentiometric elevations are mapped and contoured to determine the change in potentiometric elevation per unit distance, called the ''potentiometric gradient''. The hydrodynamic tilt of a fluid contact can be estimated from the potentiometric gradient and fluid densities by the following relationship<ref name=pt06r56>Hubbert, M. K., 1953, [http://archives.datapages.com/data/bulletns/1953-56/data/pg/0037/0008/1950/1954.htm Entrapment of petroleum under hydrodynamic conditions]: AAPG Bulletin, v. 37, p. 1954–2026.</ref><ref name=pt06r21>Dahlberg, E. C., 1982, Applied Hydrodynamics in Petroleum Exploration: New York, Springer Verlag, 161 p.</ref>:

[[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|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).]]

:<math>h_{\rm B} - h_{\rm C}/2 \mbox{ mi}  = 17 \mbox{ ft/mi}</math>

:<math>h_{\rm B} - h_{\rm C}/2 \mbox{ mi}  = 17 \mbox{ ft/mi}</math>

The Potentiometric gradient is approximately constant along the section at 17 ft/mi. Calculating the contact dip from Equation (2), we have

The potentiometric gradient is approximately constant along the section at 17 ft/mi. Calculating the contact dip from Equation (2), we have

:<math>\mbox{oil--water tilt}  = 1.0/(1.0 - 0.8) \times 17  = 85 \mbox{ ft/mi}</math>

:<math>\mbox{oil--water tilt}  = 1.0/(1.0 - 0.8) \times 17  = 85 \mbox{ ft/mi}</math>