Reservoir Categorization of Tight Gas Sands by Combining Petrophysicas with Core-Measured Capillary Pressure
Digital Formation, Inc, Denver, CO
Tight gas sands have the characteristics of medium to low porosity, low to very low permeability and variable porosity/saturation relations. Often a free water level is difficult or impossible to identify in the wellbore. Erratically changing profiles of porosity and saturation are difficult to interpret with respect to identification of pay intervals. A technique presented here involves linking capillary pressure saturation/depth profiles with petrophysically-defined porosity and saturation depth profiles. Source core capillary pressure data should be from the same reservoir sequence, but not necessarily from the same well. Core samples, showing a range of porosity/permeability relationships, are analyzed to yield a spectrum of saturation/height relationships, linked to porosity. Integration into petrophysically-defined saturation/porosity profiles involves first a choice of the free water level interpreted to control the gas within a continuous hydraulic unit. This level may be below the total depth of the well. Then, a spectrum of saturation/height curves are calculated, specific to the petrophysically-defined porosity profile. Finally, a comparison with petrophycially-determined saturation permits an automatic definition of rock quality, mobile vs. immobile water and permeability. By incorporating relative permeability concepts, profiles of effective permeability to each fluid (gas and water) can be estimated. Flow units can be differentiated from barriers. Results can be compared with geologic descriptions of the reservoir and frequently directly correlate with changing depositional environment. The data can also be used to identify which intervals should be completed, and which zones should be isolated from one another. Examples from the Piceance Basin, NW Colorado, are included.