Page 80 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

68 Reservoir Engineering

sealed to prevent leakage and the entrance of oxygen. In a second method, the
cores are wrapped in Saran or polyethylene film and aluminum foil, and then
coated with wax or strippable plastic. Cores obtained by either of these methods
are referred to as preserved, native-state, or fresh cores, and are preferred for
many laboratory tests.
For certain laboratory tests, it may be possible to clean reservoir cores with
solvents and resaturate with reservoir fluids to restore the original wetting con-
ditions. Details of preparing such restored-state or extracted cores are discussed
subsequently in the section “Coring and Core Analysis.’’ The concept of the method
is to clean the core thoroughly until it is water-wet, saturate with reservoir brine,
flush with crude oil, and age for over 1,000 hours at reservoir temperature.
Regardless of the method of core handling employed, the rock samples used
in the laboratory should have a surface state as close as possible to that present
in the reservoir. If preserved cores are used, it is essential they be stored under
air-free conditions because exposure to air for as little as 6-8 hours can cause
water evaporation and other changes in core properties. If extracted cores are
used, drying of the cores can be very critical when hydratable minerals, capable
of breaking down at low temperatures are present. Contamination from core
holders that contain certain types of rubber sleeves can be prevented by using
an inner liner of tubular polyethylene film. Because of the instability of many
oilfield waters, it is usually desirable to prepare synthetic brines to prevent core
plugging caused by deposition of insolubles.
When possible, tests should be made under reservoir conditions of temperature
and pressure using live reservoir oil. This is an improvement over room con-
dition techniques where tests are made at atmospheric conditions with refined
laboratory oils. Use of the live crude exposes the rock to compounds present
in the oil that might influence wettability, and establishes an environment as
close as possible to reservoir conditions. Cores evaluated at atmospheric con-
ditions may be more oil-wet than similar tests at reservoir conditions because
of the decreased solubility of wettability-altering compounds at lower temperatures
and pressures [107,123]. In a recent contact angle study [93] with calcium
carbonate crystals and a crude oil containing 27.3% resins and 2.2% asphaltenes,
a complete reversal from a predominantly oil-wet system at lower temperatures
to a predominantly water-wet system at higher temperatures was found. While
pressure alone had little effect on the wettability of the system, the study
speculated that the addition of gas-in-solution with increasing pressure should
favor a more water-wet situation than would be indicated from laboratory tests
at atmospheric conditions. Even when all precautions have been taken, there is
no absolute assurance that reservoir wettability has been duplicated.

Capillary Pressure
Curvature at an interface between wetting and nonwetting phases causes a
pressure difference that is called capillary pressure. This pressure can be viewed
as a force per unit area that results from the interaction of surface forces and
the geometry of the system.
Based on early work in the nineteenth century of Laplace, Young, and Plateau
(e.g., Reference 94), a general expression for capillary pressure, Pc, as a function
of interfacial tension, 0, and curvature of the interface is [19]:
P, =.($+$) (5-74)