Page 168 - Principles of Applied Reservoir Simulation 2E

Part II: Reservoir Simulation 153

In summary, a representation of the reservoir is quantified in the reservoir
flow simulator. The representation is validated during the history matching
process, and forecasts of reservoir performance are then made from the validated
reservoir representation.

15.5 Simulator Selection

The selection of a reservoir simulator depends on such factors as the
objectives of the study, fluid type, and dimensionality of the system. For
purposes of illustration, we focus our attention on a study which uses either a
black oil or a compositional simulator. Standard black oil and compositional
simulators assume isothermal flow and mass transfer within a block is instanta-
neous. A compositional simulator represents the fluid as a mixture of hydrocar-
bon components. Black oil simulators may be viewed as compositional
simulators with two components. They can have gas dissolved in the oil phase,
as well as oil dissolved in the gas phase. Black oil simulators need both saturated
and under-saturated fluid property data, as discussed in Chapter 13.
Black oil and compositional simulators usually assume fluids have a
minimal effect on rock properties. Thus, standard versions of the simulators will
not model changes in rock properties due to effects like grain dissolution, tar
mat formation, or gel formation resulting from a vertical conformance treatment.
Special purpose simulators or special options within a standard simulator must
be obtained to solve such problems.
Fluid type is needed to decide if the reservoir should be modeled using
either a black oil simulator or a compositional simulator. Well logs can
distinguish between oil and gas, but are less useful in further classifying fluid
type. A pressure-temperature diagram is useful for determining reservoir fluid
type, but its preparation requires laboratory work with a fluid sample. A simpler
way that is often sufficient for classifying a fluid is to look at solution gas-oil
ratio. Table 13-1 shows typical solution GOR ranges for each fluid type. As a
rule of thumb, compositional models should be used to model volatile oil and
condensate fluids, while black oil and dry gas fluids are most effectively