Page 147 - Principles of Applied Reservoir Simulation 2E

132 Principles of Applied Reservoir Simulation

compared to a laboratory measurement of permeability using a six-inch core
sample. The modeling team often has to make judgements about the relative
merits of contradictory data. The history matching process recognizes this source
of uncertainty, as is discussed in subsequent chapters.
The most common types of reservoir rock are listed in Table 14-1. One
of the most fundamental properties of rock that must be included in a reservoir
model is porosity. Porosity is the fraction of a porous medium that is void space.
If the void space is connected and communicates with a wellbore, it is referred
to as effective porosity, otherwise the void space is ineffective porosity. The
original porosity resulting from sediment deposition is called primary porosity.
Secondary porosity is an incremental increase in primary porosity due to the
chemical dissolution of reservoir rocks, especially carbonates. Primary and
secondary porosity can be both effective and ineffective. Total porosity is a
combination of ineffective porosity and effective (interconnected) porosity.
Table 14-1
Common Reservoir Rocks

Sandstones Compacted sediment
Conglomerate

Shales Laminated sediment
Predominantly clay

Carbonates Produced by chemical and biochemical sources
Limestone

Porosity values depend on rock type, as shown in Table 14-2. There are
two basic techniques for directly measuring porosity: core analysis in the
laboratory and well logging. Laboratory measurements tend to be more accurate,
but sample only a small fraction of the reservoir. Changes in rock properties may
also occur when the core is brought from the reservoir to the surface. Well log
measurements sample a much larger portion of the reservoir than core analysis,
but typically yield less accurate values. Ideally, a correlation can be established
between in situ measurements such as well logging and surface measurements
such as core analysis.