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Abstract

This paper uses case histories to introduce a graphical method for easily quantifying reservoir flow units based on geologic framework, petrophysical rock/pore types, storage capacity, flow capacity, and reservoir process speed. Using these parameters and four graphical tools, this paper outlines a quantitative approach to transform rock-type-based zonations into petrophysically based flow units that can be input into a numerical flow simulator. This method provides a tool for determining the minimum number of flow units to input into a numerical flow simulator that honors the foot-by-foot characteristics at the wellbore.

A flow unit is a stratigraphically continuous interval of similar reservoir process speed that maintains the geologic framework and characteristics of rock types. Rock types are representative reservoir units with a distinct porosity-permeability relationship and a unique water saturation for a given height above free water level.

The ideal data for this method is continuous core porosity, permeability, and saturation information drawn from throughout the entire reservoir. If such a data set is not available, it is necessary to calibrate wireline log data with core information to produce reliable estimates of porosity, permeability, and saturation. A full discussion of these data transforms are beyond the scope of this paper.

The four graphical tools used to determine flow units are: Winland porosity-permeability cross plot, Stratigraphic Flow Profile (SFP), Stratigraphic Modified Lorenz Plot (SMLP) and Modified Lorenz Plot (MLP).

This method begins by establishing rock types within a geologic framework. The geologic framework allows the flow units to be interpreted within a sequence stratigraphic model determining well-to-well correlation strategies. The key flow unit characteristics to be identified are barriers (seal to flow), speed zones (conduits), and baffles (zones that throttle fluid movement).

This integrated, petrophysically based method of determining flow units has been successfully used in a wide array of reservoirs. We have applied it to young, unconsolidated sediments; structurally complex naturally fractured/vuggy carbonates; low permeability "tight" formation gas sands; diagenetically altered carbonates; complex mixed lithologies; and interbedded sand-shale sequences.

The earlier in the life of a reservoir this process is used, the greater the understanding of future reservoir performance. This method allows the user to employ the least number of flow units and honor the character of the foot by foot data for simulation studies.

Key Definitions

Due to various working definitions of some of these terms in the literature, it is necessary to define the key terms used in this approach:

Rock Types

Rock/Pore Types - are units of rock deposited under similar conditions which experienced similar diagenetic processes resulting in a unique porosity-permeability relationship, capillary pressure profile and water saturation for a given height above free water in a reservoir.

Winland Plot - a semi-log crossplot of permeability (mD) versus porosity (%), with isopore throat lines (R35 Ports). R35 Ports correspond to the calculated pore throat radius (microns) at 35% mercury saturation from a mercury injection capillary pressure test. They can be calculated directly from Winland's equation (eq. 1) or other equations based on permeability and porosity. In equation 1, permeability is input in millidarcies and porosity in percent.

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