Page 151 - Principles of Applied Reservoir Simulation 2E

136 Principles of Applied Reservoir Simulation

realize that the relative permeability curves used in a flow model are most
representative of the type of experiment that was used to measure the curves.
Applying these curves to another type of displacement mechanism can introduce
significant error.
Several procedures exist for averaging relative permeability data [for
example, Schneider, 1987; Mattax and Dalton, 1990; Blunt, 1999]. In practice,
relative permeability is one of the most useful physical quantities available for
performing a history match. The curves that are initially entered into a reservoir
model are often modified during the history matching process. The rationale for
changing relative permeability curves is based on the observation that relative
permeability curves are usually obtained by flooding core in the laboratory.
Laboratory floods correspond to a much smaller scale than flow through the
drainage area of a well. Therefore, it is easy to argue that the laboratory curves
are not representative of flow on the reservoir scale. In the absence of measured
data, correlations such as Honarpour, et al. [1982] give a reasonable starting
point for estimating relative permeability. Relative permeability hysteresis
effects can also be included in reservoir simulation using a procedure presented
byKillough[1976].
Capillary pressure is usually included in reservoir simulators. The relation-
ship between capillary pressure and elevation is used to establish the initial
transition zone in the reservoir. The oil-water transition zone, for example, is
the zone between water-only flow and oil-only flow. It represents that part of
the reservoir where 100% water saturation grades into oil saturation with
irreducible water saturation. Similar transition zones may exist at the interface
between any pair of immiscible phases.
Capillary pressure data is used primarily for determining initial fluid
contacts and transition zones. It is also used in fractured reservoir models for
controlling the flow of fluids between the fracture and the rock matrix. If
capillary pressure is neglected, transition zones are not included in the model.
This is illustrated in Figure 14-2. Figure 14-3 shows the effect of neglecting
capillary pressure when a grid is used to represent the reservoir. The fluid content
of the block is determined by the location of the block mid-point relative to a
contact between two phases. The block mid-point is shown as a dot in the center