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Petroleum reservoir fluid properties (view source)
Revision as of 19:18, 30 June 2014
, 19:18, 30 June 2014Inserted image for geological time
| isbn = 0891816607
| isbn = 0891816607
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[[file:Geological_time_spiral.png|thumb|400px|The geologic time spiral.<ref name=USGS_2008>United States Geological Survey, 2008, Joseph Graham, William Newman, and John Stacy, [http://pubs.usgs.gov/gip/2008/58/ The geologic time spiral—A path to the past] (ver. 1.1): U.S. Geological Survey General Information Product 58.</ref>]]
Petroleum reservoirs may contain any of the three fluid phases—water (brine), oil, or gas. The initial distribution of phases depends on depth, temperature, pressure, composition, historical migration, type of geological trap, and reservoir heterogeneity (that is, varying rock properties). The forces that originally distribute the fluids are gravity, capillary, molecular diffusion, thermal convection, and pressure gradients. It is generally assumed that reservoir fluids are in a static state when discovered or, more correctly, that fluids are moving at a very slow rate relative to the time required to extract the fluids (10 to 50 years). Clearly the fluids may still be in a dynamic state in terms of geological time.
Petroleum reservoirs may contain any of the three fluid phases—water (brine), oil, or gas. The initial distribution of phases depends on depth, temperature, pressure, composition, historical migration, type of geological trap, and reservoir heterogeneity (that is, varying rock properties). The forces that originally distribute the fluids are gravity, capillary, molecular diffusion, thermal convection, and pressure gradients. It is generally assumed that reservoir fluids are in a static state when discovered or, more correctly, that fluids are moving at a very slow rate relative to the time required to extract the fluids (10 to 50 years). Clearly the fluids may still be in a dynamic state in terms of geological time.